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, 20122013
Commission file number 1-5153
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
|
| | |
| Delaware | | 25-0996816 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
5555 San Felipe Street, Houston, TX 77056-2723
(Address of principal executive offices)
(713) 629-6600
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
|
| | |
| Title of each class | | Name of each exchange on which registered |
| Common Stock, par value $1.00 | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ RNo ¨£
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 ¨ £No þR
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 þR No ¨£
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 þR No ¨£
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. þR
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.
Large accelerated filer þR Accelerated filer ¨£ Non-accelerated filer ¨£ Smaller reporting company ¨£
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨£ No þR
The aggregate market value of Common Stock held by non-affiliates as of June 29, 2012: $17,991 million.28, 2013: $24,462 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 707,709,281696,944,638 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 20132014.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 20132014 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 III, Items 10-14 of this report.
MARATHON OIL CORPORATION
Unless the context otherwise indicates, references to "Marathon Oil," "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 Oil exerts significant influence by virtue of its ownership interest).
Table of Contents
Definitions
Throughout this report, the following company or industry specific terms and abbreviations are used.
AECO – Alberta Energy Company, a Canadian natural gas benchmark price.
AMPCO – Atlantic Methanol Production Company LLC, a company located in Equatorial Guinea in which we own a 45 percent equity interest.
AOSP – Athabasca Oil Sands Project, an oil sands mining, transportation and upgrading joint venture located in Alberta, Canada, in which we hold a 20 percent interest.
bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
bbld – Barrels per day.
bboe – Billion barrels of oil equivalent. Natural gas is converted to a barrel of oil equivalent based on the energy equivalent, which on a dry gas basis is six thousand cubic feet of gas per one barrel of oil equivalent.
bcf – Billion cubic feet.
boe – Barrels of oil equivalent.
boed – Barrels of oil equivalent per day.
BOEMRE – United States Bureau of Ocean Energy Management, Regulation and Enforcement.
btu – British thermal unit, an energy equivalence measure.
DD&A – Depreciation, depletion and amortization.
Developed acreage – The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Downstream business – The refining, marketing and transportation (RM&T)("RM&T") operations, spun-off on June 30, 2011 and now treated as discontinued operations.
Drilling Moratorium – As a result of an explosion and significant spill from a deepwater rig in the Gulf of Mexico, the United States Department of the Interior issued a drilling moratorium on May 30, 2010 to suspend the drilling of deepwater wells, and prohibit drilling any new deepwater wells. The moratorium was lifted on October 12, 2010.
Dry well – A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion.
E.G. – Equatorial Guinea.
EGHoldings – Equatorial Guinea LNG Holdings Limited, ana liquefied natural gas production company located in E.G. in which we own a 60 percent equity interest.
E&P – Our Exploration and Production segment which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.
EPA – Environmental Protection Agency.
Exit rate – The average daily rate of production from a well or group of wells in the last month of the period stated.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive in another reservoir.
Farmout – An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
FASB – Financial Accounting Standards Board.
FPSO – Floating production, storage and offloading vessel.
IFRS – International Financial Reporting Standards.
IGInternal Losses –Production losses attributed to factors that are within our control which can be either planned, such as a planned turnaround, or unplanned, such as equipment failure.
International E&P – Our Integrated GasInternational Exploration and Production ("Int'l E&P") segment which explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas and methanol, in E.G.
IRS – United States Internal Revenue Service.
KRG – Kurdistan Regional Government.
Liquid hydrocarbon – Collectively, crude oil, condensate and natural gas liquids.
LNG – Liquefied natural gas.
LPG – Liquefied petroleum gas.
Light sweet crude - A crude oil with an American Petroleum Institute ("API") gravity of 38 degrees or more and a sulfur content of less than 0.5 percent.
Liquid hydrocarbons or liquids – Collectively, crude oil, condensate and natural gas liquids.
Marathon – The consolidated company prior to the June 30, 2011 spin-off of the downstream business.
Marathon Oil – The company as it exists following the June 30, 2011 spin-off of the downstream business.
Marathon Petroleum Corporation ("MPC") – The separate independent company which now owns and operates the downstream business.
mbbl – Thousand barrels.
mbbld – Thousand barrels per day.
mboe – Thousand barrels of oil equivalent.
mboed – Thousand barrels of oil equivalent per day.
mcf – Thousand cubic feet.
mmbbl – Million barrels.
mmboe – Million barrels of oil equivalent.
mmbtu – Million British thermal units.
mmcfd – Million cubic feet per day.
mmt – Million metric tonnes.
mmta – Million metric tonnes per annum.
mtd – Thousand metric tonnes per day.
Net acres or Net wells – The sum of the fractional working interests owned by us in gross acres or gross wells.
NGL or NGLs – Natural gas liquid or natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, that can be collectively removed from produced natural gas, separated into these substances and sold.
North America E&P ("N.A. E&P") – Our North America Exploration and Production segment which explores for, produces and markets liquid hydrocarbons and natural gas in North America.
OECD – Organization for Economic Cooperation and Development.
Oklahoma Resource Basins – Areas in Oklahoma including the Anadarko Woodford shale, the Mississippi Sooner lime, the Granite wash, the Tonkawa, the Cleveland, and the Marmaton plays.
OPEC – Organization of Petroleum Exporting Countries.
OSM – Our Oil Sands Mining segment 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.
Operational Availability –A term used to measure the ability of an asset to produce to its maximum capacity over a specified period of time. This measurement considers Internal Losses that are within our control.
Productive well – A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
Proved reserves – Proved oil,liquid hydrocarbon, natural gas and synthetic crude oil reserves are those quantities of oil,liquid hydrocarbons, natural gas and synthetic crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible.
Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or infor which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
PSC – Production sharing contract.
Quest CCS – Quest Carbon Capture and Storage project at the AOSP in Alberta, Canada.
Reserve replacement ratio – A ratio which measures the amount of proved reserves added to our reserve base during the year relative to the amount of oilliquid hydrocarbons, natural gas and gassynthetic crude oil produced.
Royalty interest – An interest in an oil or natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.
SAGE – United Kingdom Scottish Area Gas Evacuation system composed of a pipeline and processing terminal.
SAR or SARs – Stock appreciation right or stock appreciation rights.
SCOOP – South Central Oklahoma Oil Province.
SEC – United States Securities and Exchange Commission.
Seismic – An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures and 4-D factors in changes that occurred over time).
Total depth ("TD") – The bottom of a drilled hole, where drilling is stopped, logs are run and casing is cemented.
Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.
U.K. – United Kingdom.
Undeveloped acreage – Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
U.S. – United States of America.
U.S. GAAP – Accounting principles generally accepted in the U.S.
WCS – Western Canadian Select, an oil index benchmark price.
Working interest ("WI") – The interest in a mineral property which gives the owner that share of production from the property. A working interest owner bears that share of the costs of exploration, development and production in return for a share of production. Working interests are typicallysometimes burdened by overriding royalty interest or other interests.
WTI – West Texas Intermediate crude oil, an oil index benchmark price.
Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures aboutAbout Market Risk, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 Annual Report on Form 10-K may include, but are not limited to:to statements that relate to (or statements that are subject to risks, contingencies or uncertainties that relate to): levels of revenues, income from operations, net income or earnings per share; levels of liquidity and the availability of financing options; budgets or levels of capital, exploration, environmental, construction or maintenance expenditures; the success or timing of completion of ongoing or anticipated capital, exploration, construction or maintenance projects; volumes of production or sales of liquid hydrocarbons, natural gas, and synthetic crude oil; levels of worldwide prices of liquid hydrocarbons and natural gas; levels of liquid hydrocarbon, natural gas and synthetic crude oil reserves; the acquisition or divestiture of assets; the effect of restructuring or reorganization of business components; quantitative or qualitative factors about market risk; the potential effect of judicial proceedings on our business and financial condition; levels of common share repurchases; the impact of government legislation and budgetary and tax measures; and the anticipated effects of actions of third parties such as competitors, or federal, foreign, state or local governments and regulatory authorities.
PART I
Item 1. Business
General
Marathon Oil Corporation was incorporated in 2001 and is an international energy company engaged in the exploration, production and marketing of liquid hydrocarbons and natural gas, production and marketing of products manufactured from natural gas and oil sands mining and integrated gas with operations in the U.S., Angola, Canada, E.G., Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq, Libya, Norway Poland and the U.K. We are based in Houston, Texas with our corporate headquarters at 5555 San Felipe Street, Houston, Texas 77056-2723 and a telephone number of (713) 629-6600.
On June 30, 2011, the spin-off of Marathon's downstream business was completed, creating two independent energy companies: Marathon Oil and MPC. Marathon stockholders at the close of business on the record date of June 27, 2011 received one share of MPC common stock for every two shares of Marathon common stock held. A private letter ruling received in June 2011 from the IRS affirmed the tax-free nature of the spin-off. Activities related to the downstream business have been treated as discontinued operations in 2011 and 2010,for all periods prior to the spin-off with additional information in Item 8. Financial Statements and Supplementary Data - Note 3 to the consolidated financial statements.
Strategy and Results Summary
Our strategic imperatives are:
Assets within•Uncompromising focus on core values to protect our license to operate and drive business performance
Investment in our people to grow and maintain our capabilities and competencies to ensure shareholders access to the full global opportunity set
Relentless pursuit of operational and capital efficiency and recognition as the partner / operator of choice
Acceleration of resource development to optimize value, grow profitable volumes and replace reserves
Rigorous portfolio management integrated with robust capital allocation
Quality resource capture through a focused exploration program and opportunistic business development
Competitive shareholder value through disciplined long-term focus
We continue to focus on liquid hydrocarbon reserves and production worldwide, realizing significant increases in our three segments are at various stages in their lifecycle: base, growth or exploration. We have a stable group of base assets, which include our OSM and IG segments and E&P assets in E.G., Libya, Norway, the U.K. and certain U.S. operations. These assets generate much of the cash that will be available for investment in our growth assets and exploration projects. Growth assets are where we expect to make significant investment in order to realize oil and gas production and reserve increases. We are focused on U.S. liquid hydrocarbon growth by developingkey unconventional liquids-rich plays includingin 2013: the Eagle Ford, Bakken and Bakken shales,Oklahoma resource basins. In 2014, approximately 60 percent of our capital, investment and exploration spending budget is allocated to these areas and includes co-development of adjacent formations in parallel with the Oklahoma Resource Basins. In addition to the U.S. shale plays, growth assets include deepwater discoveries and developments offshore Angola, our Canadian in-situ assets, certain Gulf of Mexico blocks and the Kurdistan Region of Iraq. We also investmain horizons. Our exploration program includes prospects in exploration prospects that have significant value potential. Our areas of exploration are E.G., Ethiopia, Gabon, the Gulf of Mexico, Kenya and the Kurdistan Region of Iraq, Libya, Norway and Poland. We continually evaluate ways to optimize our portfolio through acquisitions and divestitures, with a previously stated goal of divesting between $1.5 billion and $3.0 billion of non-core assets over the period of 2011 through 2013. For the two-year period ended December 31, 2012, we entered into agreements for approximately $1.3 billion in divestitures, of which $785 million were completed. The remaining $545 million in asset sales were completed by February 22, 2013.Iraq.
We ended 20122013 with proved reserves of 2approximately 2.2 bboe, a 12an 8 percent increase over 2011. Average sales volumes2012. Proved reserve replacement was 194 percent, excluding dispositions.
During 2013, our cash additions to property, plant and equipment were 282 mbbld of liquid hydrocarbon, 902 mmcfd of natural gas$5.0 billion, including those related to discontinued operations, and 47 mbbld of synthetic crude oil, with 62 percent of our liquid hydrocarbon sales volumes from international operations, for which average realizations have exceeded WTI crude prices. During 2012, we invested in the development of assets totaling $5.4 billion in capital, investment and exploration spending and made acquisitions of approximately $1 billion.$74 million. We expect continued spending, primarily funded with cash flow from operations or portfolio optimization, in exploration and development activities in order to realize continued reserve and sales volume growth. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Outlook,Operations - Outlook, for discussion of our $5.2$5.9 billion capital, investment and exploration spending budget for 2014.
We continually evaluate ways to optimize our portfolio through acquisitions and divestitures and have exceeded our previously stated goal of divesting between $1.5 billion and $3.0 billion of assets over the period of 2011 through 2013,. by closing or entering into agreements for approximately $3.5 billion in divestitures, of which $2.1 billion is from the sales of our Angola assets. The sale of our interest in Angola Block 31 closed in February 2014 and the sale of our interest in Angola Block 32 is expected to close in the first quarter of 2014. Additionally, in December 2013, we commenced efforts to market our assets in the North Sea, both in the U.K. and Norway, which would simplify and concentrate our portfolio to higher margin growth opportunities and increase our production growth rate.
The above discussion of strategy and results includes forward-looking statements with respect to the goalsale of divesting between $1.5 billionour interest in Angola Block 32, the possible sale of our U.K. and $3.0 billion of non-coreNorway assets between 2011 and 2013projected spending and expected investment in exploration and development activities.activities under the 2014 capital, investment and exploration budget. Some factors that could potentially affect the divestiture of non-core assets and expected investment in exploration and development activities include changes in prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, occurrence of acquisitions or dispositions of oil and natural gas properties, future financial condition,conditions, operating results and economic and/or regulatory factors affecting our businesses,businesses. The timing of closing
the sale of our interest in Angola Block 32 is subject to customary closing conditions. The possible sale of our U.K. and Norway assets is subject to the identification of one or more buyers, for non-core assetssuccessful negotiations, board approval and execution of definitive agreements. The projected spending under the negotiation of acceptable prices2014 capital, investment and other terms, as well as other customary closing conditions.exploration spending budget is a good faith estimate, and therefore, subject to change. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
The map below illustrates the locations of our worldwide operations.
Segment and Geographic Information
For operating segment and geographic financial information, see Item 8. Financial Statements and Supplementary Data – Note 8 to the consolidated financial statements.
Exploration and Production Segment
In the discussion that follows regarding our North America E&P, operations,International E&P and Oil Sands Mining segments, references to net wells, acres, sales or investment indicate our ownership interest or share, as the context requires.
North America E&P Segment
We are engaged in oil and gas exploration, development and/or production activities in the U.S., Angola, Canada, Ethiopia, E.G., Gabon, Kenya, the Kurdistan Region of Iraq, Libya, Norway, Poland, and the U.K.Canada.
Liquids-Rich ShaleUnconventional Resource Plays
Eagle Ford - As of December 31, 20122013, we have 230,000had approximately 211,000 net acres in the core of the Eagle Ford shale, with an additional 100,000 non-core acres. In the fourth quarter of 2011, we made our most significant investmentin south Texas and 655 gross (493 net) operated producing wells in the Eagle Ford, shale playAustin Chalk and Pearsall formations. With approximately 90 percent pad drilling in 2013, we continued to improve efficiencies and reduce development costs per well. The average spud-to-TD time per well decreased to 13 days during the last quarter of south Texas whenthe year compared to 15 days in the same period of 2012. We reached TD on 299 gross operated wells and brought 307 gross operated wells to sales in 2013.
Throughout 2013, we closed several acquisitions for a total cash considerationevaluated the potential of $4.5 billion. Throughout 2012, we rationalized our positiondownspacing to 40-acre and 60-acre spacing with several acquisitions totaling $1 billionpilot programs. Overall, wells drilled in these programs at closer spacing showed improved completion efficiency which helped offset impacts due to tighter well spacing. Continued focus on stimulation design contributed to incremental improvements in well performance across our area of activity. Approximately 39 percent of our 2014 capital, investment and select divestitures of acreage located outside the core ofexploration budget is dedicated to the Eagle Ford shale. See Item 8. Financial Statements and Supplementary DataFord. Our accelerated drilling plans include drilling 250 - Note 5 to the consolidated financial statements for additional information about these acquisitions.260 net wells (385 - 405 gross, of which we will operate 340 - 355) in 2014, an increase of almost 20 percent over 2013.
As of December 31, 2012, we had 379 gross (262 net) producing wells in the Eagle Ford shale. We realized significant efficiencies in drilling during 2012, reducing the average drilling time per well to 23 days, reaching TD on 248 gross (178 net)operated wells and brought 215 gross (154 net) operated wells to sales. Approximately one-third of our 2013 capital budget is dedicated to the Eagle Ford shale. Our plans include drilling and completing 275 - 320 gross (215 - 250 net) operated wells in 2013. We have undertaken a number of pilot tests across the acreage to assist in identifying appropriate spacing, landing zones and completion techniques for the Eagle Ford. Results from vertical landing zone pilots and completions pilots are ongoing and incorporated into operations continuously. Initial analysis of spacing pilot results are expected by the end of 2013 and may result in improvements to our overall development plans for the field.
Eagle Ford average net sales for 20122013 were 3481 mboed, composed of 2351 mbbld of crude oil 5and condensate, 14 mbbld of NGLs and 3794 mmcfd of natural gas.gas, compared to 34 mboed in 2012, a 136 percent increase. Our 20122013 exit rate of production was over 6598 mboed, which is fourfolda 50 percent increase over December 2011. We are2012. In 2013, we were able to transport approximately 6070 percent of our Eagle Ford production by pipeline. We anticipate the volume of oil sold into pipelines will remain high, with the actual volume fluctuating from quarter to quarter as additional infrastructure to service the area is constructed and commensurate commitments for transportation are executed. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and additional contract negotiations and facility designs are underway.lessen our environmental footprint.
Evaluation of the Austin Chalk and Pearsall formations across our Eagle Ford acreage position in south Texas included four Austin Chalk wells and one well in the Pearsall formation in 2013. Early Austin Chalk production results suggest that the mix of crude oil and condensate, NGLs and natural gas is similar to Eagle Ford condensate wells. We plan to drill 5 to 12 additional gross wells in the Austin Chalk and Pearsall formations in 2014. We will continue to buildevaluate the Pearsall formation in 2014. Ongoing Austin Chalk and Eagle Ford co-development is planned, pending results from our early wells. Co-development will leverage the infrastructure investments we have made to support our liquid hydrocarbon and natural gas production growth across the Eagle Ford operating area.
Approximately 370193 miles of gathering lines were installed in 2012, and 12 new2013 for a total of over 700 miles of operated gathering pipeline in the area. We now have 24 central gathering and treating facilities, were commissioned, with 7 additional facilities in various stagesaggregate capacity of planning or construction.over 275 mboed. We also own and operate the Sugarloaf gathering system, a 42-mile37-mile natural gas pipeline through the heart of our acreage in Karnes, Atascosa, and Bee Counties of south Texas.
Bakken – We hold approximately 410,000370,000 net acres in the Bakken shale oil play in North Dakota and eastern Montana. Throughout 2012,Montana, where we have been operating since 2006. Since inception, we have continuously sought improvement in efficiency and well performance through optimizing completion techniques. Our average time to drill a well continued selective acreage acquisitions and leasing, further expanding a new prospect area.to improve, averaging 15 days spud-to-TD in the last quarter of 2013, compared to 18 days in the same period of 2012. We moved from 20-stagehave identified additional improvements to the 30-stage hydraulic fracturing designs put in 2011place in 2012, which are expected to further increase both production rates and estimated ultimate recovery from our Bakken shale wells. We also continued to alter completion techniques seeking continuous improvementwells beyond the increases that were attained in well performance.2012 and 2013. We reached TD on 8876 gross (76 net) operated wells and brought to sales 9877 gross (84 net) operated wells in 2012.2013. Our Bakken shale program includes plans to drill 19080 - 90 net wells (200 - 220 gross, (65 - 70 net) wells in 2013, of which 60we will operate 75 - 70 net85) in 2014. In addition, we plan to recomplete 22 - 26 gross wells will be operated by us.to the stage design optimized in 2013.
Our net sales from the Bakken shale averaged 2939 mboed in 2013, composed of 2735 mbbld of crude oil 1and condensate, 2 mbbld of NGLs and 813 mmcfd of natural gas, in 2012, a 7034 percent increase on a barrel of oil equivalent basis over 2011.29 mboed in 2012. Our production exit rate for 20122013 was approximately 3538 mboed. We sell our Bakken production primarily into variouslocal North Dakota markets via truck railcaror pipeline in efforts to optimize price realizations and such production could be transported to other marketing options. We have, and continue to secure, long-term agreements to transport portionsareas of our current and forecasted liquid hydrocarbon production to market via third-party gathering systems.the U.S. by the purchaser.
Oklahoma Resource Basinsresource basins – InWe hold 209,000 net acres in unconventional Oklahoma resource basins, namely the Anadarko Woodford shale play in Oklahoma, we hold 163,000 net acres(including the SCOOP), the Southern Mississippi Trend, and the Granite Wash, of which approximately 100,000147,000 net acres are held by production. We continued to add incremental acres to our SCOOP position in 2013. In 2012,the Anadarko Woodford shale, we executed an operated drilling program focused on the liquids-rich areas of the play, reached TD on 2510 gross (20 net) operated wells and brought nine gross operated wells to sales 29in 2013. An additional four net non-operated Woodford wells were brought to sales. We spud three additional operated Woodford wells in the SCOOP near the end of the year. We drilled two gross (25 net) operated wells. Inwells in the Southern Mississippi Trend and brought both wells to sales in the fourth quarter of 2013. We also participated in two gross non-operated Southern Mississippi Trend wells in 2013. Lastly, we spud our first operated well in the unconventional Granite Wash play near the end of 2013.
Sales from our Oklahoma resource basin plays in 2013 we plan to drill 42 - 50 gross (15 - 19 net) wells, of which 12 - 14 net wells will be operated. Thewere primarily from the Anadarko Woodford shale and averaged 14 mboed, composed of 2 mbbld of crude oil and condensate, 4 mbbld of NGLs and 48 mmcfd of natural gas, for an increase of 68 percent over 2012 net sales of 8 mboed, composed of 1 mbbld of crude oil, 2 mbbld of NGLs and 29 mmcfd of natural gas, during 2012, a more than threefold increase over 2011 on a barrel of oil equivalent basis.mboed. Our 2012 exit rate of production was 10 mboed.
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 inaccelerated drilling plans for the Oklahoma Resource Basins willresource basins include drilling and completing 14 - 20 net (21 - 27 gross) operated wells in 2014, approximately double our 2013 program. Approximately six net non-operated wells are also expected to be dependent upon the recovery of natural gas and natural gas liquids prices. completed.
See below for additional discussion of our conventional, primarily natural gas, production operations in Oklahoma.
Other United States
Alaska – In April 2012, we entered into an agreement to sell all of our assets in Alaska in a transaction valued at $375 million before closing adjustments. Those assets include operated and non-operated interests in 10 natural gas fields in the Cook Inlet and adjacent Kenai Peninsula of Alaska and majority ownership in four operated natural gas pipelines totaling 140 miles. The transaction closed in January 2013 for proceeds of $195 million subject to a six-month escrow of $50 million for various indemnities. Net sales from Alaska averaged 92 mmcfd in 2012.
Colorado – We hold leases with natural gas production in the Piceance Basin of Colorado, located in the Greater Grand Valley field complex and 154,000 net acres in the liquids-rich Niobrara shale located in the DJ Basin of northern Colorado, southeastern Wyoming and Nebraska. We drilled 17 gross (12 net) operated wells in the DJ Basin during 2012. Net sales from these two areas averaged 3 mboed in 2012. We have no plans for operated drilling in Colorado in 2013.
Oklahoma – We have long-established operated and non-operated conventional production in several Oklahoma fields from which 2012 sales averaged 2 mbbld of liquid hydrocarbons and 51 mmcfd of natural gas. In 2012, we participated in 11 gross (1 net), non-operated wells in the state. We also drilled 1 operated well. Plans for 2013 include drilling 11 gross (2 net) wells, targeting liquids.
Texas/North Louisiana/New Mexico – In east Texas and north Louisiana, we hold 184,000 net acres. Approximately 20,000 of the acres are in the Haynesville and Bossier natural gas shale plays. Most of the acreage in these shale plays is held by production. We participated in 5 gross (1 net) non-operated wells in the area during 2012. Conventional production was primarily from the Mimms Creek, Pearwood and Oletha fields in 2012, with net sales averaging 6 mboed.
We also participate in several non-operated Permian Basin fields in west Texas and New Mexico. Net sales from this area averaged 7 mboed in 2012. We plan continued carbon dioxide flood programs in the Seminole and Vacuum fields during 2013.
Wyoming – We have ongoing enhanced oil recovery waterflood projects at the mature Bighorn Basin and Wind River Basin fields and initiated an additional enhanced oil recovery project at our 100 percent owned and operated Pitchfork field in 2012. We have conventional natural gas operations in the Greater Green River Basin and unconventional coal bed natural gas operations in the Powder River Basin. In 2012, we drilled 2 gross (2 net) operated development wells in Wyoming, which included 1 wellbore re-entry. We plan to drill 1 gross (1 net) operated well in 2013.
Our Wyoming net sales averaged 17 mbbld of liquid hydrocarbons and 68 mmcfd of natural gas during 2012. In addition, we own and operate the 420-mile Red Butte Pipeline. This crude oil pipeline connects Silvertip Station on the Montana/Wyoming state line to Casper, Wyoming.
Over the next two years, we plan to plug and abandon over 600 wells in the Powder River Basin as we wind down those operations due to poor economics. See Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for impairments of our Powder River Basin asset taken in recent years due to declining natural gas prices and reduced development plans.
Gulf of Mexico – Production
– On December 31, 2012,2013, we held materialsignificant interests in 711 producing fields, 4 of which are company-operated. Average net sales for 20122013 from the Gulf of Mexico were 2217 mbbld of liquid hydrocarbons and 1914 mmcfd of natural gas. Operational availability for our operated properties was strong at 97 percent, with internal unplanned losses of three percent.
We operate and have a 65 percent operated working interest in the Ewing Bank Block 873 platform which is located 130 miles south of New Orleans, Louisiana. The platform serves as a production hub for the Lobster, Oyster and Arnold fields on Ewing Bank blocksBlocks 873, 917 and 963. The facility also processes third-party production via subsea tie-backs. In 2012, seismic data that was acquired
We have a 100 percent operated working interest in 2011the Droshky development located on Blocks 873Green Canyon Block 244 and 917 was processeda 68 percent operated working interest in order to refine existing opportunitiesOzona which is located on Garden Banks Block 515. The Ozona development ceased production in the first quarter of 2013 and to identify othersis scheduled for a development drilling campaign that is planned to startabandonment in 2015.2014.
We ownhave a 50 percent working interest in the non-operated Petronius field on Viosca Knoll Blocks 786 and 830, located 130 miles southeast of New Orleans, which includes 14 producing wells. The Petronius platform is also capable of providing processing and transportation services to nearby third-party fields. During 2012, we acquired 4-D seismic dataA well side track project was successfully completed in order to identify potential future drilling opportunities.2013 and a similar project is planned for 2014.
We hold a 30 percent working interest in the non-operated Neptune field located on Atwater Valley Block 575, 120 miles off the coast of Louisiana. The development includes seven subsea wells tied back to a stand-alone platform. A well that had been producing from a deeper horizon was recompleted to the main producing zone in 2012.side track project is planned for 2014.
The Droshky and Ozona developments off the coast of Louisiana are both expected to reach abandonment pressures in the first half of 2013. We have a 100an 18 percent operated working interest in the Droshkynon-operated Gunflint field development located on GreenMississippi Canyon Block 244Blocks 948, 949, 992(N/2) and a 68 percent operated working interest993(N/2). The discovery well was drilled in Ozona which is located on Garden Banks Block 515.
In February 2013, we sold our 34 percent non-operated interest2008 and encountered pay in the Neptune gas plant thatMiddle Miocene reservoirs. Two subsequent appraisal wells were drilled and evaluated in 2012 and 2013. First oil from this subsea tie-back development project is located onshore Louisiana. The transaction value, before closing adjustments, was $170 million.expected in 2016.
Gulf of Mexico – Exploration
– We have a portfolio of over 1817 prospects with multiple drilling opportunities in the Gulf of Mexico. As we evaluate these opportunities for drilling, we plan to seek partners to reduce our exploration risk on individual projects.
A successful deepwater oil discovery well was drilled onWe have a 60 percent operated working interest in the GunflintKey Largo prospect located on Mississippi CanyonWalker Ridge Block 948,578. The Key Largo prospect will be the first well drilled with a new ultra deep-water drillship for which we and another operator have recently secured a three-year contract. Drilling is expected to commence in 2008. We own a 15 percent non-operatedthe third quarter of 2014.
Prior to commencing drilling in September 2013, we reduced our working interest in this prospect. One appraisalthe Madagascar prospect, located on De Soto Canyon Block 757, from 100 percent to 40 percent as a result of two farm-outs, which included drilling cost carries. Our operated exploration well was drilledon the Madagascar prospect did not encounter commercial hydrocarbons and the well costs and related unproved property were charged to exploration expense in 2012 confirming expected reservoir properties and establishing the commercial viability of the field. An additional appraisal well began drilling in February 2013. Development planning is ongoing.
In the first quarter of 2009, we participated in aA deepwater oil discovery on the Shenandoah prospect, located on Walker Ridge Block 52.52, was drilled in 2009. We own a 10 percent non-operated working interest in this non-operated prospect. The first appraisal well beganon the Shenandoah prospect reached total depth in 2013. This appraisal well encountered more than 1,000 net feet of oil pay in multiple high-quality Lower Tertiary-aged reservoirs. Additional appraisal drilling is anticipated to begin in 2014.
In 2013, we were awarded 100 percent working interest leases in two Gulf of Mexico blocks: Keathley Canyon Block 153, an extension to the Meteor prospect on our existing Keathley Canyon Block 196 lease, and Keathley Canyon Block 340 on the Colonial prospect. Both of these blocks are inboard-Paleogene prospects.
Colorado – We hold leases with natural gas production in the Piceance Basin of Colorado, located in the Greater Grand Valley field complex, and held 154,000 net acres in the Niobrara shale located in the DJ Basin that were sold in June 2013. Net sales from Colorado averaged 2 mboed in 2013. We have no plans for operated drilling in June 2012, has reached TDColorado in 2014.
Oklahoma – We have long-established operated and non-operated conventional production in several Oklahoma fields from which 2013 sales averaged 1 mbbld of liquid hydrocarbons and 43 mmcfd of natural gas. In 2013, we participated in seven gross non-operated wells in the state.
Texas/North Louisiana/New Mexico – We hold 268,000 net acres in these areas of which approximately 20,000 of the acres are in the Haynesville and Bossier natural gas shale plays. Most of the acreage in these shale plays is currently being evaluated.held by production. We participated in three gross non-operated wells in the Haynesville shale play during 2013. Conventional production was primarily from the Mimms Creek, Pearwood and Oletha fields in 2013, with net sales averaging 5 mboed.
We also participate in several non-operated Permian Basin fields in west Texas and New Mexico. Net sales from this area averaged 7 mboed in 2013. We plan continued carbon dioxide flood programs in the Seminole and Vacuum fields during 2014.
Wyoming – We have ongoing enhanced oil recovery waterflood projects at the mature Bighorn Basin and Wind River Basin fields and at our 100 percent owned and operated Pitchfork field. We have conventional natural gas operations in the Greater Green River Basin and unconventional coal bed natural gas operations in the Powder River Basin. As of December 31, 2013, we had plugged and abandoned 376 of the total 600 wells in the Powder River Basin and expect production to cease in March 2014 as we wind down those operations.
Our Wyoming net sales averaged 16 mbbld of liquid hydrocarbons and 48 mmcfd of natural gas during 2013. We drilled 2 gross operated development wells in Wyoming in 2013 and plan to drill 10 gross operated wells in 2014. In addition, we own
Inand operate the third quarter of 2012, we resumed drilling an exploratory well420-mile Red Butte Pipeline. This crude oil pipeline connects Silvertip Station on the Innsbruck prospect located on Mississippi Canyon Block 993 which had been temporarily suspended under the federal government's Drilling Moratorium. Upon reaching TD in November 2012, the well was determinedMontana/Wyoming state line to be dry. The well costs and related unproved property costs were charged to exploration expense in 2012. We have a 45 percent operated working interest in Innsbruck.Casper, Wyoming.
Canada
We hold interests in both operated and non-operated exploration stage oil sand leases in Alberta, Canada, which would be developed using in-situ methods of extraction. These leases cover approximately 142,000 gross (54,000 net) acres in four project areas: Namur, in which we hold a 3070 percent non-operated working interestoperated interest; Birchwood, in Green Canyon Blocks 403 and 404 in the Kilchurn prospect. The operator commenced drilling in the Kilchurn prospect in December 2011. In the second quarter of 2012, the well was determined to be dry. The well costs and related unproved property costs were charged to exploration expense in 2012.
In October 2011,which we received approval of an exploration plan from the BOEMRE for the Key Largo prospect located on Walker Ridge Block 578. We have a 60 percent working interest and are the operator of this prospect. Drilling is expected in 2014.
We currently hold a 100 percent operated workinginterest; Ells River, in which we hold a 20 percent non-operated interest; and Saleski in which we hold a 33 percent non-operated interest.
During the first quarter of 2012, we submitted a regulatory application relating to our Canada in-situ assets at Birchwood, for a proposed 12 mbbld steam assisted gravity drainage ("SAGD") demonstration project. We expect to receive regulatory approval for this project by the end of 2014. Upon receiving this approval, we will further evaluate our development plans.
Acquisitions and Dispositions
In July 2013, we acquired 4,800 net undeveloped acres in the core of the Eagle Ford shale in a transaction valued at $97 million, including carried interest of $23 million.
In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.
In February 2013, we closed the sale of our interest in the Madagascar prospectNeptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain was recorded in the first quarter of 2013.
In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on DeSoto Canyon Block 757. Ourthis transaction was recorded in the first quarter of 2013.
In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million. A pretax gain of $55 million was recorded in 2013.
The above discussions include forward-looking statements with respect to accelerated rig and drilling activity in the Eagle Ford, Bakken, and Oklahoma resource basins, possible increased recoverable resources from improvements to the 30-stage hydraulic fracturing designs in the Bakken resource play, infrastructure improvements in the Eagle Ford resource play, potential development plans for the Austin Chalk and Pearsall formations in the Eagle Ford resource play and for the Petronius and Neptune fields in the Gulf of Mexico, anticipated future exploratory and development drilling activity, projected spending under the 2014 capital, investment and exploration plan was approved byspending budget, planned use of carbon dioxide flood programs, the BOEMREabandonment of the Powder River Basin in 2012. We expectWyoming, the abandonment of the Ozona development in the Gulf of Mexico, the timing of first oil from the Gunflint development in the Gulf of Mexico, and the timing of project sanction for the the SAGD project. The average times to drill a well may not be indicative of future drilling times. Current production rates may not be indicative of future production rates. Some factors which could possibly affect these forward-looking statements include pricing, supply and demand for liquid hydrocarbons and natural gas, the firstamount of capital available for exploration well onand development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, other risks associated with construction projects, the prospectinability to obtain or delay in 2013 atobtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, natural disasters, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. The projected spending under the 2014 capital, investment and exploration spending budget is a lower working interest.good faith estimate, and therefore, subject to change. The SAGD project may further be affected by board approval and transportation logistics. 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.
International E&P Segment
We are engaged in oil and gas exploration, development and/or production activities in Angola, E.G., Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq, Libya, Norway, and the U.K. We also include the results of our natural gas liquefaction operations and methanol production operations in E.G. in our International E&P segment.
Africa
Equatorial Guinea- – Production – We own a 63 percent operated working interest under a PSC in the Alba field which is offshore E.G. During 2012,2013, E.G. net liquid hydrocarbon sales averaged 3634 mbbld and net natural gas sales averaged 428442 mmcfd. Operational availability from our company-operated facilities continues to be excellent and averaged 99 percent in 2013, with internal unplanned losses of one percent. A compression project designed to maintain the production plateau two additional years and extend field life up to six years is underway and is expected to be operational in mid-2016.
Dry natural gas from the Alba field, which remains after the condensate and LPG are removed by Alba Plant LLC, as discussed below, is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Because of the location and limited local demand for 2012 averaged 95 percent.natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. Any dry gas not sold is returned offshore and reinjected into the Alba field for later production.
Equatorial Guinea – Exploration – We hold a 63 percent operated working interest in the Deep Luba discovery on the Alba Block and an 80 percent operated working interest in the Corona well on Block D. We plan to develop Block D through a unitization with the Alba field, which is expected in late 2013 or early 2014.
currently being negotiated. We also have an 80 percent operated working interest in exploratory Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. We have secured a rig to drill at least two exploration prospects and one Alba field infill well in 2014.
Equatorial Guinea – Gas Processing –We also own a 52 percent interest in Alba Plant LLC, an equity method investee, that operates an onshore LPG processing plant located on Bioko Island. Alba field natural gas is processed by the LPG plant. Under a long-term contract at a fixed price per btu, the LPG plant extracts secondary condensate and LPG from the natural gas stream and uses some of the remaining dry natural gas in its operations. During 2012,2013, the gross quantity of natural gas supplied to the LPG production facility was 863866 mmcfd, and 7from which 6 mbbld of secondary condensate and 2021 mbbld of LPG were produced by Alba Plant LLC. Our share
We also own 60 percent of the income ultimately generated by the subsequent export of secondary condensateEGHoldings and LPG produced by Alba Plant LLC is reflected in our E&P segment.
As part of our IG segment, we own 45 percent of AMPCO, and 60 percent of EGHoldings, both of which are accounted for as equity method investments. AMPCO operates a methanol plant and EGHoldings operates an LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. DryThese facilities allow us to monetize natural gas reserves from the Alba field, which remains after the condensate and LPG are removed by Alba Plant LLC, 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 E.G., 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 methanol produced by AMPCO and LNG produced by EGHoldings is reflected in our IG segment as discussed below. During 2012, the gross quantities of dry natural gas supplied to the methanol plant to thefield.
EGHoldings' 3.7 mmta LNG production facility sells LNG under a 3.4 mmta, or 460 mmcfd, sales and purchase agreement through 2023. The purchaser under the agreement takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index, regardless of destination. Gross sales of LNG from this production facility totaled 3.98 mmta in 2013. Operational availability was 97 percent in 2013, including a planned turnaround, while internal unplanned losses were 119 mmcfdless than one percent.
AMPCO had gross sales totaling 1.01 mmt in 2013. Operational availability for this methanol plant was 90 percent in 2013 and 639 mmcfd. Any remaining dry gasinternal unplanned losses were 10 percent. Production from the plant is returned offshoreused to supply customers in Europe and reinjected into the Alba field for later production.U.S.
Libya- – We hold a 16 percent non-operated working interest in the Waha concessions, which encompass almost 13 million acres located in the Sirte Basin of eastern Libya. DuringBeginning in the third quarter of 2013, our Libya production operations were impacted by third-party labor strikes at the Es Sider oil terminal. We have had no oil liftings since July 2013. Uncertainty around production and sales levels from Libya have existed since the first quarter of 2011 allwhen production operations in Libya were suspended due to civil unrest. Inuntil the fourth quarter of 2011, limited production resumed fromthat year. We and our partners in the Waha concessions but we made no deliveriescontinue to assess the situation and the condition of hydrocarbons. Sales resumedour assets in the first quarter of 2012 and averaged 45 mboed in 2012.Libya.
Angola – OffshoreDuring 2013, we entered into agreements to sell our Angola we hold 10 percent working interests in Blocks 31 and 32, bothassets. See discussion of which are non-operated. The discoveries on Blocks 31 and 32 represent several potential development hubs. In 2008, we received approval to proceed with the first deepwater development project, called the PSVM development, which includes the Plutao, Saturno, Venus and Marte discoveries and one successful appraisal welltransactions in the northeastern portion of Block 31. The PSVM development utilizes a FPSO with a total of 48 productionAcquisitions and injection wells. Development drilling began in 2010 and first production was in the fourth quarter of 2012, with first sales in February 2013. Our plans include continued development drilling with tie-in to the FPSO in order to reach a production plateau of 14 net mboed in the first half of 2014 which is expected to last through 2017.Dispositions
Front-end engineering and design for the Kaombo development, located in the southeastern portion of Block 32, is underway. The development is expected to consist of two-105 mbbld FPSO. Project sanction is expected mid-2013 so that production from the Kaombo development is possible in 2016. We continue to assess other discoveries on Blocks 31 and 32 for development potential.section below.
Gabon- – We hold a 2121.25 percent non-operated working interest in the Diaba License G4-223 and its related permit offshore Gabon, which covers 2.2 million gross (467,500(476,000 net) acres. The start of exploration drilling is expectedDiaman-1B well reached total depth in the firstthird quarter of 2013.2013, encountering 160-180 net feet of hydrocarbon pay in the deepwater pre-salt play. Preliminary analysis suggests that the hydrocarbons are natural gas with condensate content, pending results of ongoing analysis of well data. Multiple additional pre-salt prospects have been identified on this License.
In late October 2013, we were the high bidder as operator of two deepwater blocks in the pre-salt play offshore Gabon. One of the blocks has since been withdrawn by the government. Award of the other block is subject to government approval and negotiation of an exploration and production sharing contract.
Kenya- – We hold a 50 percent non-operated working interest in Block 9, and a 15 percent non-operated working interest in Block 12A which are locatedconsisting of 3.9 million gross (1.9 million net) acres in northwest Kenya, covering 12.3 million gross (4.4 million net) acres. Seismic has been acquired on Block 9 and seismic acquisition on Block 12A is underway.Kenya. The first exploratory well on Block 9, the Bahasi-1, completed drilling in the fourth quarter of 2013 and was plugged and abandoned. The Sala-1 exploration well is expected to begin drillingspud in February 2014 on the eastern side of Block 9, where previous wells drilled in the second quarter of 2013.sub-basin confirmed a working petroleum system. We have the right to assume the role of operator on Block 9 if a commercial discovery is made.
We also hold a 15 percent non-operated working interest in Block 12A, covering 5 million gross (750,000 net) acres, which is also located in northwest Kenya. Seismic acquisition on Block 12A began in 2013 and will be completed in the first quarter of 2014.
Ethiopia- In January 2013, government approval was received for our acquisition of – We hold a 20 percent non-operated interest in the onshore South Omo concessionBlock in Ethiopia. The concession has an area of approximately 7.35.4 million gross (1.5(1.1 million net) acres. The Sabisa 1Sabisa-1 exploration well began drillingencountered reservoir quality sands, oil and heavy gas shows and a thick shale section. The presence of oil prone source rocks, reservoir sands and good seals is encouraging for the numerous fault bounded traps identified in Januarythe basin. Because of mechanical issues, the well was abandoned before a full evaluation could be completed. The Tultule-1 exploration well was also drilled in 2013, approximately two miles from the Sabisa-1 well in a frontier rift basin and was plugged and abandoned. At least two additional exploration wells are planned for the eastern side of the block in 2014 to test multiple sub-basins. The first of those wells, Shimela-1, is expected to take approximately 60 days to reach the planned TD of 8,500 ft.spud in March 2014.
Europe
As discussed above, we commenced efforts in December 2013 to market our assets in the North Sea, including Norway and the U.K.
Norway – Production – At the end of 2012,2013, we operated 109 licenses and held interests in six6 non-operated licenses, which encompass approximately 240,000286,000 net acres offshore on the offshore Norwegian continental shelf. In 2012,2013, net sales from Norway averaged 8171 mbbld of liquid hydrocarbons and 5351 mmcfd of natural gas.
Our production operations in Norway are centered around the Alvheim complex which consists of an FPSO with subsea infrastructure tied to several producing developments. Produced oil is transported by shuttle tanker and produced natural gas is transported to the SAGE system by pipeline. Production in 2013 continued to benefit from slower than expected decline as a result of infill well success, reservoir management techniques, extended drilling capability and technology application. We safely completed a planned turnaround in nine days in 2013 on time and on budget. Operational availability continued to be a strong factor in 2013 performance with a rate of 96 percent and internal unplanned losses of one percent.
The Alvheim development is comprised of the Kameleon, East Kameleon and Kneler fields (PL 036C, PL 088BS and PL 203), in each of which we have a 65 percent operated working interest, and the Boa field, in which we have a 58 percent operated working interest. It is produced to the Alvheim complex which consists of a FPSO with subsea infrastructure. In 2011 and 2012, due to debottlenecking efforts, capacity of the FPSO increased by 15 mbbld gross. Peak oil production of 157 mbbld gross (94 mbbld net) was reached in the first quarter of 2012. During 2012 operational availability of the Alvheim development was 96 percent including planned maintenance activities, while unplanned downtime was minimal at 3 percent. Produced oil is transported by shuttle tanker and produced natural gas is transported to the SAGE system by pipeline. At the end of 2012,2013, the Alvheim development included 1412 producing, wells3 temporarily shut-in and 2 water disposal wells. One infill well is planned for 2014 along with several well workovers.
In October 2012, we took over operatorship of the nearbyThe Vilje field (PL 036D), in which we own a 47 percent operated working interest, which began producing through the Alvheim complex in August 2008. AtVilje has two subsea templates and two production wells, and is tied back through a 12-mile pipeline to the end of 2012, 2 wells were producing and an additional development,Alvheim FPSO. A third production well, Vilje Sor, had been approved.will be developed as a subsea tieback to the Vilje field. Production from Vilje Sorstart-up is estimated to begin nearexpected in the endfirst half of 2013.2014.
The Volund field (PL 150 and PL 150BS) is tied back to150B), located five miles south of the Alvheim complex which is five miles to the north. The Volund development, in which we own a 65 percent operated working interest, consists of threefour production wells and one water injection well at December 31, 2012. The drilling of an additional development well at Volund was completed2013. We own a 65 percent operated working interest in the fourth quarter 2012 and first production commenced in January 2013.Volund.
The Viper/Kobra (PL 203)Viper oil discovery, in the immediate vicinity of the Volund Field, was announced in November 2009. We hold a 65 percent operated working interest in Viper/Kobra. Along with our partners, we are evaluating a possible tie-back to the Alvheim complex.complex of the Viper discovery as a combined development with the 1997 Kobra discovery. Both discoveries are within PL203 where we hold a 65 percent operated working interest.
Norway – Exploration – The Boyla field (PL 340), formerly the Marihone discovery, (PL 340) is located approximately 17 miles south of Alvheim.the Alvheim complex. In October 2012, the Norwegian Ministry of Petroleum and Energy approved the plan for the development and operation of the Boyla field in which we hold a 65 percent operated working interest. FirstFurther development drilling is planned in the Boyla field in 2014, with first production from Boyla is expected in the fourth quarter of 2014.early 2015. Near Boyla, is the Caterpillar discovery (PL340BS), which was(PL 340BS) made in 2011. It is being2011 continues to be evaluated as a tie-back to the Alvheim complex through Boyla.
Also offshore Norway, theThe Darwin (formerly Velsemoy)Veslemoy) exploration well is expected to begin drilling latewas drilled in the first quarter of 2013 on PL 531, in which we hold a 10 percent non-operated fully-carried working interest. Drilling is also expected to commenceinterest, and was plugged and abandoned. The 30 percent non-operated Sverdrup exploration well on PL 330 offshore Norway was drilled in the third quarter of 2013 on the Sverdrup well on PL 330 where we hold a 30 percent non-operated working interest.and has been plugged and abandoned.
In January 2013, we were awarded a 20 percent non-operated working interest in PL 694, which consists of three blocks, south of the Sverdrup prospect area, in the Norwegian Sea.area. We were also awarded additional acreage in the North Sea, north of the Alvheim area in PL 203B. Our 65 percent working interest and role as operator are the same as PL 203. In addition, effective Januaryin 2013 we withdrew from twothree licenses (PL505, PL505BS and PL505B)PL570). In 2013, we will operate 9 licenses and have an interest in approximately 225,000 net acres.
United Kingdom – Net sales from the U.K. averaged 1615 mbbld of liquid hydrocarbons and 4832 mmcfd of natural gas in 2012.2013. 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 39 percent working interest in the East Brae field. The Brae Alpha platform and facilities host the South, Central and West Brae fields. The North Brae and East Brae fields are natural gas condensate fields which are produced via the Brae Bravo and the East Brae platform,platforms, respectively. The East Brae platform also hosts the nearby Braemar field in which we have a 28 percent working interest. Two development wells were completed atare in the West Brae program, with the first to be spud in early 20112014. Operational availability was 92 percent and we continue to pursue Brae complex projects designed to maximize natural gas recovery and maintain deliverability rates to the U.K. market.internal unplanned losses were eight percent.
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 twenty-five30 third-party fields are contracted to use the Brae system and 6762 mboed are being processed or transported through the Brae infrastructure. In addition to generating processing and pipeline tariff revenue, this third-party business optimizes infrastructure usage.
The working interest owners of the Brae group ownsarea producing assets collectively own a 50 percent interest in the non-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 bcf per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE pipeline as well as approximately 1 bcf per day of third-party natural gas.
In the U.K. Atlantic Margin west of the Shetland Islands, weWe own an average 30 percent working interestinterests in the non-operated Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, a 47 percent working interest in East Foinaven and a 20 percent working interest in the T35 and T25 fields. The export of Foinaven liquid hydrocarbons is via shuttle tanker from the FPSO to market. All natural gas sales are to the non-operated Magnus platform for use as injection gas. An ongoing upgrade of equipment on the FPSO is expected to extend the life of the fields from 2017 to 2021. Additionally, the planned installation of replacement flowlines should secure the long-term integrity of the subsea infrastructure.
Poland – AsAfter an extensive evaluation of December 31, 2012, we hold a 51 percent working interestour exploration activities in 9 concessions, an 85 percent working interest in one concessionPoland and a 100 percent interest in one concession for a totalunsuccessful attempts to find commercial levels of approximately 1.2 million net acres. We are operator under all licenses. In 2012, we reached TD on 5 gross (3 net) operated wells and in 2013 have reached TD on one more gross (0.85 net) well. Since late 2011,hydrocarbons, we have conducted a continuous drill, core and diagnostic fluid injection test program ("DFIT"). Following these DFIT evaluations, we planelected to hydraulically fracture select wells. We are evaluating all data collected through drilling in addition to proprietary 2-D seismic acquired in 2011, 2012, and 2013.
Canada
We hold interests in both operated and non-operated exploration stage oil sand leases in Alberta, Canada, which would be developed using in-situ methods of extraction. These leases cover approximately 143,000 gross acres (52,000 net) in four project areas: Namur, in which we hold a 60 percent operated interest; Birchwood, in which we hold a 100 percent operated interest; Ells River, in which we hold a 20 percent non-operated interest and Saleski in which we hold a 33 percent non-operated interest.
During the first quarter of 2012, we submitted a regulatory application for a proposed 12 mbbld steam assisted gravity drainage ("SAGD") project at Birchwood. Pending regulatory approval, project sanction is expected in 2014, with first oil projected in 2017. Exploration activities leading up to this application included drilling approximately 100 stratigraphic test wellsconclude operations in the wintercountry. During 2013, we relinquished 7 of 2010our 11 operated concessions to 2011the government and a 3-D seismic surveyare in 2012.the process of relinquishing the remainder.
Other International
Kurdistan Region of Iraq- – In aggregate, we have access to approximately 215,000145,000 net acres in the Kurdistan Region of Iraq. We have interests in two non-operated blocks located north-northwest of Erbil: Atrush in which ourwith 15 percent working interest is 20 percent, and Sarsang in which ourwith 25 percent working interest. We also have a 45 percent operated working interest is 25 percent. Through December 31, 2012, discoveries have been made in eachthe Harir block andlocated northeast of Erbil.
On the non-operated Atrush block, following the successful appraisal program and a declaration of commerciality, a plan for field development was approved by the Kurdistan Ministry of Natural Resources in September 2013. The development project will consist of drilling three production wells were drilled and tested on both blocks during 2012, includingconstructing a central processing facility. We expect first production by early 2015 with estimated initial gross production of approximately 30 mbbld of oil. The approval of the discoveryfield development plan for Phase 1 provides for a 25-year production period. Subject to further drilling and testing results, and partner and government approvals, a potential Phase 2 development could add an additional gross 30 mbbld facility. Within the potential Phase 2 development area, the Atrush-3 appraisal well, located approximately four miles east of additional hydrocarbon-bearing zones. Further appraisalexisting wells, confirmed the extension of the oil bearing reservoirs and development drilling is planned for 2013. Additional exploration drilling is proceedinghas been suspended as a potential future producer. Testing has commenced on the Sarsang block. Two exploration wells commencedAtrush-4 development well, spud in late 2012October 2013, with results expectedanticipated completion in the first quarter of 2014. The Atrush-5 development well is expected to spud in the second quarter of 2014.
On the non-operated Sarsang block, tests have been completed on the Gara well. All zones were water-wet and the well was plugged and abandoned in August 2013. AOn the Mangesh well, five drill stem tests have been completed and further testing is planned. The East Swara Tika exploration well, which began in July 2013, has been drilled to a depth of 5,300 feet toward a planned total depth of 11,000 feet. This well will betest additional resource potential to the northeast of the Swara Tika discovery.
On the operated Harir block, we announced the Mirawa-1 discovery in October 2013. The Mirawa-1 was drilled during 2013.
to a total depth of approximately 14,000 feet and encountered multiple stacked oil and natural gas producing zones with equipment constrained test flow rates of more than 11 mbbld of oil, 72 mmcfd of non-associated natural gas and 1,700 bbld of condensate. We have suspended the well for potential future use as a producing well. The exploration and appraisal workJisik-1 prospect, located nine miles to the northwest of the Mirawa-1 discovery, will test a similar structure. Drilling on the Atrush block resultedJisik-1 prospect commenced in a declaration of commerciality being submitted by the operator in November 2012. A field development plan will be submitted for government approval in May 2013. This plan will outline the forward commitments requiredDecember 2013 and is expected to develop the fieldreach total depth in the most economic way.second quarter of 2014. The multiple prospects on the Sarsang block require additional exploration andMirawa-2 appraisal work through 2013.
We also have PSCs for operatorship of the Harir and Safen blocks located northeast of Erbil. After selling down a portion of our interestwell is expected to spud in the third quarter of 20122014, subject to balance our portfolio, our working interest is 45 percent in each block. We have completed an extensive 2-D seismic program on both blocks. The first exploration well ongovernment approval of the Harir block commenced drilling in July 2012, reached TD in December 2012, was tested and deemed to be dry. We plan to start an exploration well on the Safen block and a second exploration well on the Harir block in the first half of 2013.Mirawa appraisal plan.
Acquisitions and Dispositions
We continually evaluate ways to optimize our portfolio through acquisitionsIn June and dispositions, with a previously stated goal of divesting between $1.5 billion and $3 billion of non-core assets over the period of 2011 through 2013. For the two-year period ended December 31, 2012,2013, we entered into agreements, for approximately $1.3 billionvalued in divestitures, of which $785 million were completed. The remaining $545 million in asset sales were completed by February 22, 2013. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for additional information about the acquisitions and Note 6 for additional information about the dispositions.
Acquisitions
In the second half of 2012, we closed acquisitions of approximately 25,000 net acres in the core of the Eagle Ford shaletotal at transaction values totaling approximately $1$2.1 billion before closing adjustments.adjustments, to sell our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32. The acquisitions included wells producing 12 net mboed at closing.sale of our interest in Block 31 closed in February 2014 and the sale of our interest in Block 32 is expected to close in the first quarter of 2014. Our Angola operations are reported as discontinued operations for all periods presented.
In October 2012,of 2013, 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. Ethiopian government approval was received and this transaction closed in January 2013 for cash consideration of $40 million, before closing adjustments, plus an additional payment of $10 million due upon declaration of a commercial discovery.
In July 2012, we entered into an agreement to acquire non-operated positions in two onshore exploration blocks in northwest Kenya. Upon closing the $32 million transaction in October 2012, we now hold a 50transfered our 45 percent working interest in Block 9 and a 15 percent working interest in Block 12A.
In June 2012, we entered an agreement to acquire a 21 percent non-operated working interestoperatorship in the Diaba License G4-223 and its related permit onshore Gabon. The transaction closed in October 2012.
During June 2012, we signed a new production sharing contract with the government of E.G. for the exploration ofSafen 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.
Dispositions
In February 2013, we entered an agreement to convey our interests in the Marcellus natural gas shale play to the operator.
In December 2012, we entered into an agreement to sell our E&P segment's interest in the Neptune gas plant, located onshore Louisiana. The transaction, with a value of $170 million before closing adjustments, closed in February 2013.
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 June 2012, we agreed to sell-down our interests in the Harir and Safen blocks in the Kurdistan Region of Iraq. The transaction subsequently closed and we received cash proceedsIraq at a pretax loss of $140 million before closing adjustments, so that we now have a 45 percent working interest in each of the two blocks.
In May 2012, we executed agreements to relinquish our operatorships of, and participating interests in, the Bone Bay and Kumawa exploration licenses in Indonesia. 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.
In April 2012, we entered into an agreement to sell all of our assets in Alaska in a transaction valued at $375 million before closing adjustments. The transaction closed in January 2013 for proceeds of $195 million subject to a six-month escrow of $50 million for various indemnities.$17 million.
In January 2012, we closed on the sale2013, government approval was received for our acquisition 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 recordeda 20 percent non-operated interest in the first quarter of 2012.onshore South Omo concession in Ethiopia.
The above discussions include forward-looking statements with respect to the timing and levels of future liquid hydrocarbon and natural gas production, anticipated future exploratory and development drilling activity expectations for improvements to development plans from the optimization of well spacing in the Eagle Ford shale play, planned useKurdistan Region of carbon dioxide flood programs,Iraq, Ethiopia, Kenya, Norway, the U.K., and E.G., the anticipated start-up date of the
compression project in E.G., the unitization of Block D and the Alba field in E.G., the award of one block in Gabon, plans to exit Poland, the possible sale of our U.K. and Norway assets, the timing of reaching abandonment pressures forfirst production from the Droshky and Ozona developments, the expected life extension of the Foinaven fields,Boyla field, the timing of project sanction and first oilproduction from the SAGD project,Atrush development, a potential Phase 2 development in the Atrush block, other potential development projects and the goalsale of divesting between $1.5 and $3.0 billion of non-core assets over the period of 2011 through 2013. The projected asset dispositions through 2013 are based on current expectations, estimates, and projections and are not guarantees of future performance.our interest in Angola Block 32. Some factors which could possibly affect
these forward-looking statements include pricing, supply and demand for petroleum products,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, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, natural disasters, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. The SAGD project may further be affected byaward of the block in Gabon is subject to government approval and negotiation of an exploration and production sharing contract. The possible sale of our U.K. and Norway assets is subject to the identification of one or more buyers, successful negotiations, board approval transportation logistics, availabilityand execution of materials and labor, and other risks associated with construction projects.definitive agreements. The timing of closing the sale of our interest in Block 32 is subject to customary closing conditions. 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.
Productive and Drilling Wells
For our North America E&P segment,and International E&P segments and discontinued operations combined, the following tables set forth gross and net productive wells and service wells as of December 31, 2013, 2012, 2011 and 20102011 and drilling wells as of December 31, 2012.2013.
| | | | Productive Wells(a) | | | | | | | | | Productive Wells(a) | | | | | | | | |
| | Oil | | Natural Gas | | Service Wells | | Drilling Wells | Oil | | Natural Gas | | Service Wells | | Drilling Wells |
| Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| 2013 | | | | | | | | | | | | | | | | |
| U.S. | | 6,632 |
| | 2,568 |
| | 2,763 |
| | 1,482 |
| | 2,349 |
| | 744 |
| | 58 |
| | 28 |
|
| E.G. | | — |
| | — |
| | 16 |
| | 11 |
| | 2 |
| | 1 |
| | — |
| | — |
|
| Other Africa | | 1,072 |
| | 175 |
| | 7 |
| | 1 |
| | 99 |
| | 16 |
| | 8 |
| | 1 |
|
| Total Africa | | 1,072 |
| | 175 |
| | 23 |
| | 12 |
| | 101 |
| | 17 |
| | 8 |
| | 1 |
|
| Total Europe | | 77 |
| | 34 |
| | 40 |
| | 16 |
| | 28 |
| | 11 |
| | — |
| | — |
|
| Total Other International | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | 1 |
|
| Worldwide | | 7,781 |
| | 2,777 |
| | 2,826 |
| | 1,510 |
| | 2,478 |
| | 772 |
| | 68 |
| | 30 |
|
| 2012 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| U.S. | 6,191 |
| | 2,315 |
| | 3,208 |
| | 1,906 |
| | 2,328 |
| | 736 |
| | 66 |
| | 30 |
| 6,191 |
| | 2,315 |
| | 3,208 |
| | 1,906 |
| | 2,328 |
| | 736 |
| | | | |
| E.G. | — |
| | — |
| | 14 |
| | 9 |
| | 4 |
| | 3 |
| | — |
| | — |
| — |
| | — |
| | 14 |
| | 9 |
| | 4 |
| | 3 |
| | | | |
| Other Africa | 1,050 |
| | 171 |
| | 6 |
| | 1 |
| | 101 |
| | 16 |
| | 5 |
| | 1 |
| 1,050 |
| | 171 |
| | 6 |
| | 1 |
| | 101 |
| | 16 |
| | | | |
| Total Africa | 1,050 |
| | 171 |
| | 20 |
| | 10 |
| | 105 |
| | 19 |
| | 5 |
| | 1 |
| 1,050 |
| | 171 |
| | 20 |
| | 10 |
| | 105 |
| | 19 |
| | | | |
| Total Europe | 77 |
| | 34 |
| | 40 |
| | 16 |
| | 28 |
| | 11 |
| | 1 |
| | 1 |
| 77 |
| | 34 |
| | 40 |
| | 16 |
| | 28 |
| | 11 |
| | | | |
| Total Other International | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | 1 |
| |
| Worldwide | 7,318 |
| | 2,520 |
| | 3,268 |
| | 1,932 |
| | 2,461 |
| | 766 |
| | 76 |
| | 33 |
| 7,318 |
| | 2,520 |
| | 3,268 |
| | 1,932 |
| | 2,461 |
| | 766 |
| |
|
| |
|
|
| 2011 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| U.S. | 5,809 |
| | 2,058 |
| | 3,121 |
| | 1,876 |
| | 2,313 |
| | 734 |
| | | | | 5,809 |
| | 2,058 |
| | 3,121 |
| | 1,876 |
| | 2,313 |
| | 734 |
| | | | |
| E.G. | — |
| | — |
| | 14 |
| | 9 |
| | 4 |
| | 3 |
| | | | | — |
| | — |
| | 14 |
| | 9 |
| | 4 |
| | 3 |
| | | | |
Other Africa(b) | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | | | | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | | | |
| Total Africa | — |
| | — |
| | 14 |
| | 9 |
| | 5 |
| | 3 |
| | | | | — |
| | — |
| | 14 |
| | 9 |
| | 5 |
| | 3 |
| | | | |
| Total Europe | 73 |
| | 31 |
| | 40 |
| | 16 |
| | 28 |
| | 10 |
| | | | | 73 |
| | 31 |
| | 40 |
| | 16 |
| | 28 |
| | 10 |
| | | | |
| Worldwide | 5,882 |
| | 2,089 |
| | 3,175 |
| | 1,901 |
| | 2,346 |
| | 747 |
| |
|
| |
|
| 5,882 |
| | 2,089 |
| | 3,175 |
| | 1,901 |
| | 2,346 |
| | 747 |
| | | | |
| 2010 | | | | | | | | | | | | | | | | |
| U.S. | 4,818 |
| | 1,860 |
| | 3,145 |
| | 1,905 |
| | 2,466 |
| | 746 |
| | | | | |
| E.G. | — |
| | — |
| | 13 |
| | 9 |
| | 5 |
| | 3 |
| | | | | |
Other Africa | 1,022 |
| | 168 |
| | 3 |
| | — |
| | 94 |
| | 16 |
| | | | | |
| Total Africa | 1,022 |
| | 168 |
| | 16 |
| | 9 |
| | 99 |
| | 19 |
| | | | | |
| Total Europe | 71 |
| | 30 |
| | 40 |
| | 16 |
| | 29 |
| | 11 |
| | | | | |
| Worldwide | 5,911 |
| | 2,058 |
| | 3,201 |
| | 1,930 |
| | 2,594 |
| | 776 |
| | | | | |
| |
(a) | Of the gross productive wells, wells with multiple completions operated by us totaled 204, 188, and 168 and 164as of December 31, 2013, 2012, 2011 and 2010.2011. Information on wells with multiple completions operated by others is unavailable to us. |
| |
(b) | As operations were resuming in Libya at December 31, 2011, an accurate count of productive wells was not possible; therefore no Libyan wells are included in this number. |
Drilling Activity
For our North America E&P segment,and International E&P segments and discontinued operations combined, the following table sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed in each of the last three years.
| | | | Development | | Exploratory | | Total | Development | | Exploratory | | Total |
| Oil | | Natural Gas | | Dry | | Total | | Oil | | Natural Gas | | Dry | | Total | | | Oil | | Natural Gas | | Dry | | Total | | Oil | | Natural Gas | | Dry | | Total | | |
| 2013 | | | | | | | | | | | | | | | | | | |
| U.S. | | 237 |
| | 20 |
| | — |
| | 257 |
| | 73 |
| | 13 |
| | 3 |
| | 89 |
| | 346 |
|
| Total Africa | | 4 |
| | — |
| | — |
| | 4 |
| | 1 |
| | — |
| | 2 |
| | 3 |
| | 7 |
|
| Total Europe | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
| | 2 |
|
| Total Other International | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
|
| Worldwide | | 241 |
| | 20 |
| | — |
| | 261 |
| | 74 |
| | 13 |
| | 8 |
| | 95 |
| | 356 |
|
| 2012 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| U.S. | 172 |
| | 21 |
| | 2 |
| | 195 |
| | 117 |
| | 13 |
| | 9 |
| | 139 |
| | 334 |
| 172 |
| | 21 |
| | 2 |
| | 195 |
| | 117 |
| | 13 |
| | 9 |
| | 139 |
| | 334 |
|
| Total Africa | 4 |
| | — |
| | — |
| | 4 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 5 |
| 4 |
| | — |
| | — |
| | 4 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 5 |
|
| Total Europe | 3 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| 3 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Total Other International | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Worldwide | 179 |
| | 21 |
| | 2 |
| | 202 |
| | 118 |
| | 13 |
| | 9 |
| | 140 |
| | 342 |
| 179 |
| | 21 |
| | 2 |
| | 202 |
| | 118 |
| | 13 |
| | 9 |
| | 140 |
| | 342 |
|
| 2011 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| U.S. | 46 |
| | 17 |
| | 3 |
| | 66 |
| | 37 |
| | 4 |
| | 1 |
| | 42 |
| | 108 |
| 46 |
| | 17 |
| | 3 |
| | 66 |
| | 37 |
| | 4 |
| | 1 |
| | 42 |
| | 108 |
|
Total Africa(a) | 2 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| 2 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Total Europe | 2 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| 2 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Total Other International | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
|
| Worldwide | 50 |
| | 17 |
| | 3 |
| | 70 |
| | 37 |
| | 4 |
| | 2 |
| | 43 |
| | 113 |
| 50 |
| | 17 |
| | 3 |
| | 70 |
| | 37 |
| | 4 |
| | 2 |
| | 43 |
| | 113 |
|
| 2010 | | | | | | | | | | | | | | | | | | |
| U.S. | 35 |
| | 46 |
| | 1 |
| | 82 |
| | 20 |
| | 11 |
| | 3 |
| | 34 |
| | 116 |
| |
| Total Africa | 5 |
| | — |
| | — |
| | 5 |
| | 1 |
| | — |
| | — |
| | 1 |
| | 6 |
| |
| Total Europe | 2 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| |
| Total Other International | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | 2 |
| | 2 |
| |
| Worldwide | 42 |
| | 46 |
| | 1 |
| | 89 |
| | 22 |
| | 11 |
| | 4 |
| | 37 |
| | 126 |
| |
| |
(a) | Activity in Libya through February 2011. |
Acreage
We believe we have satisfactory title to our North America E&P and International E&P properties in accordance with standards generally accepted in the industry; nevertheless, we can be involved in title disputes from time to time which may result in litigation. In the case of undeveloped properties, an investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. Our title to properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the industry. In addition, our interests may be subject to obligations or duties under applicable laws or burdens such as net profits interests, liens related to operating agreements, development obligations or capital commitments under international PSCs or exploration licenses.
The following table sets forth, by geographic area, the gross and net developed and undeveloped E&P acreage held in our North America E&P segmentand International E&P segments and discontinued operations combined as of December 31, 2012.2013.
| | | | Developed | | Undeveloped | | Developed and Undeveloped | Developed | | Undeveloped | | Developed and Undeveloped |
| (In thousands) | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net |
| U.S. | 1,703 |
| | 1,271 |
| | 1,298 |
| | 1,036 |
| | 3,001 |
| | 2,307 |
| 1,720 |
| | 1,289 |
| | 695 |
| | 523 |
| | 2,415 |
| | 1,812 |
|
| Canada | — |
| | — |
| | 143 |
| | 55 |
| | 143 |
| | 55 |
| — |
| | — |
| | 142 |
| | 54 |
| | 142 |
| | 54 |
|
| Total North America | 1,703 |
| | 1,271 |
| | 1,441 |
| | 1,091 |
| | 3,144 |
| | 2,362 |
| 1,720 |
| | 1,289 |
| | 837 |
| | 577 |
| | 2,557 |
| | 1,866 |
|
| E.G. | 45 |
| | 29 |
| | 183 |
| | 164 |
| | 228 |
| | 193 |
| 45 |
| | 29 |
| | 183 |
| | 164 |
| | 228 |
| | 193 |
|
| Other Africa | 12,922 |
| | 2,109 |
| | 16,069 |
| | 4,856 |
| | 28,991 |
| | 6,965 |
| 12,921 |
| | 2,109 |
| | 18,549 |
| | 4,463 |
| | 31,470 |
| | 6,572 |
|
| Total Africa | 12,967 |
| | 2,138 |
| | 16,252 |
| | 5,020 |
| | 29,219 |
| | 7,158 |
| 12,966 |
| | 2,138 |
| | 18,732 |
| | 4,627 |
| | 31,698 |
| | 6,765 |
|
| Total Europe | 186 |
| | 91 |
| | 3,131 |
| | 1,487 |
| | 3,317 |
| | 1,578 |
| 179 |
| | 88 |
| | 2,030 |
| | 748 |
| | 2,209 |
| | 836 |
|
| Other International | — |
| | — |
| | 571 |
| | 195 |
| | 571 |
| | 195 |
| — |
| | — |
| | 466 |
| | 145 |
| | 466 |
| | 145 |
|
| Worldwide | 14,856 |
| | 3,500 |
| | 21,395 |
| | 7,793 |
| | 36,251 |
| | 11,293 |
| 14,865 |
| | 3,515 |
| | 22,065 |
| | 6,097 |
| | 36,930 |
| | 9,612 |
|
In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future. If production is not established or we take no other action to extend the terms of the leases, licenses, or concessions, undeveloped acreage listed in the table below will expire over the next three years. We plan to continue the terms of many of these licenses and concession areas or retain leases through operational or administrative actions. For leases expiring in 2014 that we do not intend to extend or retain, unproved property impairments were recorded in 2013.
| | | | Net Undeveloped Acres Expiring | Net Undeveloped Acres Expiring |
| (In thousands) | 2013 | | 2014 | | 2015 | | 2014 | | 2015 | | 2016 | |
| U.S. | 436 |
| | 189 |
| | 130 |
| | 145 |
| | 60 |
| | 46 |
| |
| Canada | — |
| | — |
| | — |
| | |
| Total North America | 436 |
| | 189 |
| | 130 |
| | |
| E.G. | — |
| | 36 |
| | — |
| | |
E.G. (a) | | 36 |
| | — |
| | — |
| |
| Other Africa | 858 |
| | — |
| | 189 |
| | 189 |
| | 2,605 |
| | 189 |
| |
| Total Africa | 858 |
| | 36 |
| | 189 |
| | 225 |
| | 2,605 |
| | 189 |
| |
| Total Europe | — |
| | 216 |
| | 1,155 |
| | 216 |
| | 372 |
| | 1 |
| |
| Other International | — |
| | — |
| | 49 |
| | — |
| | 20 |
| | — |
| |
| Worldwide | 1,294 |
| | 441 |
| | 1,523 |
| | 586 |
| | 3,057 |
| | 236 |
| |
(a) An exploratory well is planned on this acreage in 2014.
Oil Sands Mining Segment
We hold a 20 percent non-operated interest in the AOSP, an oil sands mining and upgrading joint venture located in Alberta, Canada. The joint venture produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and upgrades the bitumen to synthetic crude oils and vacuum gas oil.
The AOSP’s mining and extraction assets are located near Fort McMurray, Alberta and include the Muskeg River and the Jackpine mines. Gross design capacity of the combined mines is 255,000 (51,000 net to our interest) barrels of bitumen per day. The AOSP operations use established processes to mine oil sands deposits from an open-pit mine, extract the bitumen and upgrade it into synthetic crude oils. Ore is mined using traditional truck and shovel mining techniques. The mined ore passes through primary crushers to reduce the ore chunks in size and is then sent to rotary breakers where the ore chunks are further reduced to smaller particles. The particles are combined with hot water to create slurry. The slurry moves through the extraction process where it separates into sand, clay and bitumen-rich froth. A solvent is added to the bitumen froth to separate out the remaining solids, water and heavy asphaltenes. The solvent washes the sand and produces clean bitumen that is required for the upgrader to run efficiently. The process yields a mixture of solvent and bitumen which is then transported from the mine to the Scotford upgrader via the approximately 300-mile Corridor Pipeline.
The AOSP's Scotford upgrader is at Fort Saskatchewan, northeast of Edmonton, Alberta. The bitumen is upgraded at Scotford using both hydrotreating and hydroconversion processes to remove sulfur and break the heavy bitumen molecules into lighter products. Blendstocks acquired from outside sources are utilized in the production of our saleable products. The upgrader produces synthetic crude oils and vacuum gas oil. The vacuum gas oil is sold to an affiliate of the operator under a long-term contract at market-related prices, and the other products are sold in the marketplace.
As of December 31, 2013, we own or have rights to participate in developed and undeveloped leases totaling approximately 159,000 gross (32,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. Synthetic crude oil sales volumes for 2013 were 48 mbbld and net-of-royalty production was 42 mbbld.
In December 2013, a Jackpine mine expansion project received conditional approval from the Canadian government. The project includes additional mining areas, associated processing facilities and infrastructure. The government conditions relate to wildlife, the environment and aboriginal health issues. We will begin evaluating the potential expansion project and government conditions after current debottlenecking activities are complete and reliability improves.
The governments of Alberta and Canada have agreed to partially fund Quest CCS for 865 million Canadian dollars. In the third quarter of 2012, the Energy and Resources Conservation Board ("ERCB"), Alberta's primary energy regulator at that time, conditionally approved the project and the AOSP partners approved proceeding to construct and operate Quest CCS. Government funding has commenced and will continue to be paid as milestones are achieved during the development, construction and operating phases. Failure of the AOSP to meet certain timing, performance and operating objectives may result in repaying some of the government funding. Construction and commissioning of Quest CCS is expected to be completed by late 2015.
In May 2013, we announced that we terminated our discussions with respect to a potential sale of a portion of our 20 percent outside-operated interest in the AOSP.
The above discussion contains forward-looking statements with regard to the Jackpine mine expansion and Quest CCS. Some factors that could affect the Jackpine mine expansion include the inability to obtain or delay in obtaining third-party approvals and permits. The Quest CCS is subject to the inability to obtain or delay in obtaining government funds, the availability of materials and labor, unforeseen hazards such as weather conditions and other risks customarily associated with these types of 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 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.
Reserves
Estimated Reserve Quantities
The following table sets forth estimated quantities of our proved liquid hydrocarbon, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2013, 2012 and 2011. Included in our liquid hydrocarbon reserves are NGLs which represent approximately 7 percent, 6 percent and 5 percent of our total proved reserves on an oil equivalent barrel basis as of December 2013, 2012 and 2011. Approximately 72 percent, 63 percent and 40 percent of those NGL reserves are associated with our U.S. unconventional resource plays as of December 31, 2013, 2012 and 2011.
Reserves are disclosed by continent and by country if the proved reserves related to any geographic area, on an oil equivalent barrel basis, represent 15 percent or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent, or a continent. Due to the agreements entered in 2013 to sell our Angola assets, estimated proved reserves for Angola are reported as discontinued operations ("Disc Ops") for all presented periods. Approximately 73 percent of our December 31, 2013 proved reserves are located in OECD countries.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| December 31, 2013 | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| Proved Developed Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 292 |
| | — |
| | 292 |
| | 55 |
| | 176 |
| | 231 |
| | 78 |
| | 19 |
| | 620 |
|
Natural gas (bcf) | 540 |
| | — |
| | 540 |
| | 823 |
| | 95 |
| | 918 |
| | 41 |
| | — |
| | 1,499 |
|
Synthetic crude oil (mmbbl) | — |
| | 674 |
| | 674 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 674 |
|
Total proved developed reserves (mmboe) | 382 |
| | 674 |
| | 1,056 |
| | 193 |
| | 192 |
| | 385 |
| | 84 |
| | 19 |
| | 1,544 |
|
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 324 |
| | — |
| | 324 |
| | 43 |
| | 39 |
| | 82 |
| | 11 |
| | 9 |
| | 426 |
|
Natural gas (bcf) | 485 |
| | — |
| | 485 |
| | 497 |
| | 110 |
| | 607 |
| | 80 |
| | — |
| | 1,172 |
|
Synthetic crude oil (mmbbl) | — |
| | 6 |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
Total proved undeveloped reserves (mmboe) | 405 |
| | 6 |
| | 411 |
| | 125 |
| | 57 |
| | 182 |
| | 25 |
| | 9 |
| | 627 |
|
| Total Proved Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 616 |
| | — |
| | 616 |
| | 98 |
| | 215 |
| | 313 |
| | 89 |
| | 28 |
| | 1,046 |
|
Natural gas (bcf) | 1,025 |
| | — |
| | 1,025 |
| | 1,320 |
| | 205 |
| | 1,525 |
| | 121 |
| | — |
| | 2,671 |
|
Synthetic crude oil (mmbbl) | — |
| | 680 |
| | 680 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 680 |
|
Total proved reserves (mmboe) | 787 |
| | 680 |
| | 1,467 |
| | 318 |
| | 249 |
| | 567 |
| | 109 |
| | 28 |
| | 2,171 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| December 31, 2012 | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| Proved Developed Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 198 |
| | — |
| | 198 |
| | 68 |
| | 168 |
| | 236 |
| | 84 |
| | — |
| | 518 |
|
Natural gas (bcf) | 546 |
| | — |
| | 546 |
| | 980 |
| | 99 |
| | 1,079 |
| | 28 |
| | — |
| | 1,653 |
|
Synthetic crude oil (mmbbl) | — |
| | 653 |
| | 653 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 653 |
|
Total proved developed reserves (mmboe) | 289 |
| | 653 |
| | 942 |
| | 231 |
| | 185 |
| | 416 |
| | 88 |
| | — |
| | 1,446 |
|
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 277 |
| | — |
| | 277 |
| | 42 |
| | 41 |
| | 83 |
| | 5 |
| | 18 |
| | 383 |
|
Natural gas (bcf) | 497 |
| | — |
| | 497 |
| | 444 |
| | 110 |
| | 554 |
| | 75 |
| | — |
| | 1,126 |
|
Total proved undeveloped reserves (mmboe) | 360 |
| | — |
| | 360 |
| | 116 |
| | 59 |
| | 175 |
| | 18 |
| | 18 |
| | 571 |
|
| Total Proved Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 475 |
| | — |
| | 475 |
| | 110 |
| | 209 |
| | 319 |
| | 89 |
| | 18 |
| | 901 |
|
Natural gas (bcf) | 1,043 |
| | — |
| | 1,043 |
| | 1,424 |
| | 209 |
| | 1,633 |
| | 103 |
| | — |
| | 2,779 |
|
Synthetic crude oil (mmbbl) | — |
| | 653 |
| | 653 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 653 |
|
Total proved reserves (mmboe) | 649 |
| | 653 |
| | 1,302 |
| | 347 |
| | 244 |
| | 591 |
| | 106 |
| | 18 |
| | 2,017 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| December 31, 2011 | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| Proved Developed Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 141 |
| | — |
| | 141 |
| | 78 |
| | 179 |
| | 257 |
| | 84 |
| | — |
| | 482 |
|
Natural gas (bcf) | 551 |
| | — |
| | 551 |
| | 1,104 |
| | 104 |
| | 1,208 |
| | 40 |
| | — |
| | 1,799 |
|
Synthetic crude oil (mmbbl) | — |
| | 623 |
| | 623 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 623 |
|
Total proved developed reserves (mmboe) | 233 |
| | 623 |
| | 856 |
| | 262 |
| | 196 |
| | 458 |
| | 91 |
| | — |
| | 1,405 |
|
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 138 |
| | — |
| | 138 |
| | 39 |
| | 43 |
| | 82 |
| | 13 |
| | 18 |
| | 251 |
|
Natural gas (bcf) | 321 |
| | — |
| | 321 |
| | 467 |
| | — |
| | 467 |
| | 79 |
| | — |
| | 867 |
|
Total proved undeveloped reserves (mmboe) | 191 |
| | — |
| | 191 |
| | 117 |
| | 43 |
| | 160 |
| | 26 |
| | 18 |
| | 395 |
|
| Total Proved Reserves | | | | |
|
| | | | | |
|
| | | | | |
|
|
Liquid hydrocarbons (mmbbl) | 279 |
| | — |
| | 279 |
| | 117 |
| | 222 |
| | 339 |
| | 97 |
| | 18 |
| | 733 |
|
Natural gas (bcf) | 872 |
| | — |
| | 872 |
| | 1,571 |
| | 104 |
| | 1,675 |
| | 119 |
| | — |
| | 2,666 |
|
Synthetic crude oil (mmbbl) | — |
| | 623 |
| | 623 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 623 |
|
Total proved reserves (mmboe) | 424 |
| | 623 |
| | 1,047 |
| | 379 |
| | 239 |
| | 618 |
| | 117 |
| | 18 |
| | 1,800 |
|
The increase in proved reserves from 2012 to 2013 was primarily due to drilling programs in our U.S. unconventional shale plays and better than expected performance in Norway. Synthetic crude oil reserves also increased due to approval of an improved recovery project and price and cost changes.
The above estimated quantities of proved liquid hydrocarbon and natural gas reserves are forward-looking statements and are based on a number of assumptions, including (among others) commodity prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, technology developments, future drilling success, industry economic conditions, levels of cash flow from operations, production experience and other operating considerations. The above estimated quantities of proved synthetic crude oil reserves are forward-looking statements and are based on presently known physical data, economic recoverability and operating conditions. To the extent these assumptions prove inaccurate, actual recoveries and development costs could be different than current estimates. For additional details of the estimated quantities of proved reserves
at the end of each of the last three years, see Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities.
Preparation of Reserve Estimates
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Liquid hydrocarbon, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group, which includes our Director of Corporate Reserves and his staff of Reserve Coordinators. Liquid hydrocarbon and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs"). QREs are engineers or geoscientists with at least a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed Marathon Oil's QRE training course. Reserve Coordinators screen all fields with proved reserves of 20 mmboe or greater, every year, to determine if a field review will be performed. Any change to proved reserve estimates in excess of 1 mmboe on a total field basis, within a single month, must be approved by a Reserve Coordinator.
Our Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in petroleum engineering and is a registered Professional Engineer in the State of Texas. In his 26 years with Marathon Oil, he has held numerous engineering and management positions, most recently managing our OSM segment. He is a member of the Society of Petroleum Engineers ("SPE") and a former member of the Petroleum Engineering Advisory Council for the University of Texas at Austin.
Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants ("GLJ") of Calgary, Canada, third-party consultants. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The team lead responsible for the estimates of our synthetic crude oil reserves has over 35 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 1986. He is a member of SPE and served as regional director from 1998 through 2001. The second GLJ team member has 13 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 2009. Both are registered Practicing Professional Engineers in the Province of Alberta.
Audits of Estimates
Third-party consultants are engaged to provide independent estimates for fields that comprise 80 percent of our total proved reserves over a rolling four-year period for the purpose of auditing and validating our internal reserve estimates. We exceeded this percentage for the four-year period ended December 31, 2013. We have established a tolerance level of 10 percent such that initial estimates by the third-party consultants are accepted if they are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, both parties re-examine the information provided, request additional data and refine their analysis if appropriate. This resolution process is continued until both estimates are within 10 percent. In the very limited instances where differences outside the 10 percent tolerance cannot be resolved by year end, a plan to resolve the difference is developed and senior management consent is obtained. The audit process did not result in any significant changes to our reserve estimates for 2013, 2012 or 2011.
During 2013, 2012 and 2011, Netherland, Sewell & Associates, Inc. ("NSAI") prepared a certification of the prior year's reserves for the Alba field in E.G. The NSAI summary reports are filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have many years of industry experience, having worked for large, international oil and gas companies before joining NSAI. The senior technical advisor has over 35 years of practical experience in petroleum geosciences, with over 16 years experience in the estimation and evaluation of reserves. The second team member has over 9 years of practical experience in petroleum engineering, with over 4 years experience in the estimation and evaluation of reserves. Both are registered Professional Engineers in the State of Texas.
Ryder Scott Company ("Ryder Scott") also performed audits of several of our fields in 2013, 2012 and 2011. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 22 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He is a member of SPE, where he served on the Oil and Gas Reserves Committee, and is a registered Professional Engineer in the State of Texas.
Changes in Proved Undeveloped Reserves
As of December 31, 2013, 627 mmboe of proved undeveloped reserves were reported, an increase of 56 mmboe from December 31, 2012. The following table shows changes in total proved undeveloped reserves for 2013:
|
| | |
| (mmboe) | |
| Beginning of year | 571 |
|
| Revisions of previous estimates | 4 |
|
| Improved recovery | 7 |
|
| Purchases of reserves in place | 16 |
|
| Extensions, discoveries, and other additions | 142 |
|
| Dispositions | (4 | ) |
| Transfer to Proved Developed | (109 | ) |
| End of year | 627 |
|
Significant additions to proved undeveloped reserves during 2013 included 72 mmboe in the Eagle Ford and 49 mmboe in the Bakken shale plays due to development drilling. Transfers from proved undeveloped to proved developed reserves included 57 mmboe in the Eagle Ford, 18 mmboe in the Bakken and 7 mmboe in the Oklahoma resource basins due to producing wells. Costs incurred in 2013, 2012 and 2011 relating to the development of proved undeveloped reserves, were $2,536 million, $1,995 million and $1,107 million.
A total of 59 mmboe was booked as a result of reliable technology. Technologies included statistical analysis of production performance, decline curve analysis, rate transient analysis, reservoir simulation and volumetric analysis. The statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved undeveloped locations establish the reasonable certainty criteria required for booking reserves.
Projects can remain in proved undeveloped reserves for extended periods in certain situations such as large development projects which take more than five years to complete, or the timing of when additional gas compression is needed. Of the 627 mmboe of proved undeveloped reserves at December 31, 2013, 24 percent of the volume is associated with projects that have been included in proved reserves for more than five years. The majority of this volume is related to a compression project in E.G. that was sanctioned by our Board of Directors in 2004. The timing of the installation of compression is being driven by the reservoir performance with this project intended to maintain maximum production levels. Performance of this field since the Board sanctioned the project has far exceeded expectations. Estimates of initial dry gas in place increased by roughly 10 percent between 2004 and 2010. During 2012, the compression project received the approval of the E.G. government, allowing design and planning work to progress towards implementation, with completion expected by mid-2016. The other component of Alba proved undeveloped reserves is an infill well approved in 2013 and to be drilled late 2014.
Proved undeveloped reserves for the North Gialo development, located in the Libyan Sahara desert, were booked for the first time as proved undeveloped reserves in 2010. This development, which is anticipated to take more than five years to be developed, is being executed by the operator and encompasses a continuous drilling program including the design, fabrication and installation of extensive liquid handling and gas recycling facilities. Anecdotal evidence from similar development projects in the region led to an expected project execution of more than five years from the time the reserves were initially booked. Interruptions associated with the civil unrest in 2011 and third-party labor strikes in 2013 have extended the project duration. There are no other significant undeveloped reserves expected to be developed more than five years after their original booking.
As of December 31, 2013, future development costs estimated to be required for the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves related to continuing operations for the years 2014 through 2018 are projected to be $2,894 million, $2,567 million, $2,020 million, $1,452 million and $575 million.
The timing of future projects and estimated future development costs relating to the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves are forward-looking statements and are based on a number of assumptions, including (among others) commodity prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, technology developments, future drilling success, industry economic conditions, levels of cash flow from operations, production experience and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries, timing and development costs could be different than current estimates.
Net Production Sold
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| 2013 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mbbld)(a) | 149 |
| | — |
| | 149 |
| | 34 |
| | 24 |
| | 58 |
| | 86 |
| | 10 |
| | 303 |
|
Natural gas (mmcfd)(b)(c) | 312 |
| | — |
| | 312 |
| | 442 |
| | 22 |
| | 464 |
| | 76 |
| | — |
| | 852 |
|
Synthetic crude oil (mbbld)(d) | — |
| | 42 |
| | 42 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 42 |
|
Total production sold (mboed) | 201 |
| | 42 |
| | 243 |
| | 107 |
| | 27 |
| | 134 |
| | 99 |
| | 10 |
| | 486 |
|
| 2012 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mbbld)(a) | 107 |
| | — |
| | 107 |
| | 36 |
| | 42 |
| | 78 |
| | 97 |
| | — |
| | 282 |
|
Natural gas (mmcfd)(b)(c) | 358 |
| | — |
| | 358 |
| | 428 |
| | 15 |
| | 443 |
| | 86 |
| | — |
| | 887 |
|
Synthetic crude oil (mbbld)(d) | — |
| | 41 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 41 |
|
Total production sold (mboed) | 166 |
| | 41 |
| | 207 |
| | 108 |
| | 44 |
| | 152 |
| | 111 |
| | — |
| | 470 |
|
| 2011 | | | | | | | | | | | | | | | |
|
Liquid hydrocarbons (mbbld)(a) | 75 |
| | — |
| | 75 |
| | 38 |
| | 5 |
| | 43 |
| | 101 |
| | — |
| | 219 |
|
Natural gas (mmcfd)(b)(c) | 326 |
| | — |
| | 326 |
| | 443 |
| | — |
| | 443 |
| | 81 |
| | — |
| | 850 |
|
Synthetic crude oil (mbbld)(d) | — |
| | 38 |
| | 38 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 38 |
|
Total production sold (mboed) | 129 |
| | 38 |
| | 167 |
| | 112 |
| | 5 |
| | 117 |
| | 115 |
| | — |
| | 399 |
|
| |
(a) | The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons. |
| |
(b) | U.S. natural gas volumes exclude volumes produced in Alaska prior to our disposal of those assets in 2013 that were stored for later sale in response to seasonal demand, although our reserves had been reduced by those volumes. |
| |
(c) | Excludes volumes acquired from third parties for injection and subsequent resale. |
| |
(d) | Upgraded bitumen excluding blendstocks. |
Average Sales Price per Unit
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| (Dollars per unit) | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| 2013 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 85.20 |
| | $ | — |
| | $ | 85.20 |
| | $ | 60.34 |
| | $ | 122.92 |
| | $ | 86.29 |
| | $ | 112.60 |
| | $ | 104.77 |
| | $ | 93.83 |
|
Natural gas (mcf) | 3.84 |
| | — |
| | 3.84 |
| | 0.24 |
| (a) | 5.44 |
| | 0.49 |
| | 12.13 |
| | — |
| | 2.75 |
|
Synthetic crude oil (bbl) | — |
| | 87.51 |
| | 87.51 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 87.51 |
|
| 2012 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 85.80 |
| | $ | — |
| | $ | 85.80 |
| | $ | 64.33 |
| | $ | 127.31 |
| | $ | 98.52 |
| | $ | 115.16 |
| | $ | — |
| | $ | 99.46 |
|
Natural gas (mcf) | 3.92 |
| | — |
| | 3.92 |
| | 0.24 |
| (a) | 5.76 |
| | 0.43 |
| | 10.45 |
| | — |
| | 2.80 |
|
Synthetic crude oil (bbl) | — |
| | 81.72 |
| | 81.72 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 81.72 |
|
| 2011 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 92.55 |
| | $ | — |
| | $ | 92.55 |
| | $ | 67.70 |
| | $ | 112.56 |
| | $ | 73.21 |
| | $ | 115.55 |
| | $ | — |
| | $ | 99.37 |
|
Natural gas (mcf) | 4.95 |
| | — |
| | 4.95 |
| | 0.24 |
| (a) | 0.70 |
| | 0.24 |
| | 9.75 |
| | — |
| | 2.96 |
|
Synthetic crude oil (bbl) | — |
| | 91.65 |
| | 91.65 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 91.65 |
|
| |
(a) | Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P Segment. |
Average Production Cost per Unit(a)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| (Dollars per boe) | U.S. | | Canada(b) | | Total | | E.G. | | Other(c) | | Total | | Total | | Disc Ops | | Grand Total |
| 2013 | $ | 13.60 |
| | $ | 55.42 |
| | $ | 20.79 |
| | $ | 2.88 |
| | $ | 7.40 |
| | $ | 3.80 |
| | $ | 13.68 |
| | $ | 11.89 |
| | $ | 14.47 |
|
| 2012 | 13.61 |
| | 53.61 |
| | 21.51 |
| | 3.59 |
| | 3.57 |
| | 3.59 |
| | 9.62 |
| | — |
| | 12.91 |
|
| 2011 | 16.51 |
| | 59.04 |
| | 25.97 |
| | 2.92 |
| | 12.22 |
| | 3.34 |
| | 8.85 |
| | — |
| | 14.42 |
|
| |
(a) | Production, severance and property taxes are excluded from the production costs used in this calculation. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Production Activities for more information regarding production cost. |
| |
(b) | Production costs in 2011 include a $64 million water abatement accrual. |
| |
(c) | Production operations ceased in Libya in February 2011, resuming in 2012, but ceased again in the third quarter of 2013. Fixed costs continue to be incurred in these periods of downtime. |
Marketing and Midstream
Our E&P segment includesoperating segments include activities related to the marketing and transportation of substantially all of our liquid hydrocarbon, synthetic crude oil and natural gas production. These activities include the transportation of production to market centers, the sale of commodities to third parties and the storage of production. We balance our various sales, storage and transportation positions through what we call supply optimization, which can include the purchase of commodities from third parties for resale. Supply optimization servesin order to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. Such activities can include the purchase of commodities from third parties for resale.
As discussed previously, we currently own and operate gathering systems and other midstream assets in some of our production areas. We are continually evaluating value-addedcontinue to evaluate midstream infrastructure investments in midstream infrastructure or in capacity in third-party systems.connection with our development plans.
Delivery CommitmentsPreparation of Reserve Estimates
We have committed to deliver quantitiesAll estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Liquid hydrocarbon, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group, which includes our Director of Corporate Reserves and his staff of Reserve Coordinators. Liquid hydrocarbon and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs"). QREs are engineers or geoscientists with at least a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed Marathon Oil's QRE training course. Reserve Coordinators screen all fields with proved reserves of 20 mmboe or greater, every year, to customers underdetermine if a varietyfield review will be performed. Any change to proved reserve estimates in excess of contracts. 1 mmboe on a total field basis, within a single month, must be approved by a Reserve Coordinator.
Our Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in petroleum engineering and is a registered Professional Engineer in the State of Texas. In his 26 years with Marathon Oil, he has held numerous engineering and management positions, most recently managing our OSM segment. He is a member of the Society of Petroleum Engineers ("SPE") and a former member of the Petroleum Engineering Advisory Council for the University of Texas at Austin.
Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants ("GLJ") of Calgary, Canada, third-party consultants. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The team lead responsible for the estimates of our synthetic crude oil reserves has over 35 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 1986. He is a member of SPE and served as regional director from 1998 through 2001. The second GLJ team member has 13 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 2009. Both are registered Practicing Professional Engineers in the Province of Alberta.
Audits of Estimates
Third-party consultants are engaged to provide independent estimates for fields that comprise 80 percent of our total proved reserves over a rolling four-year period for the purpose of auditing and validating our internal reserve estimates. We exceeded this percentage for the four-year period ended December 31, 2013. We have established a tolerance level of 10 percent such that initial estimates by the third-party consultants are accepted if they are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, both parties re-examine the information provided, request additional data and refine their analysis if appropriate. This resolution process is continued until both estimates are within 10 percent. In the very limited instances where differences outside the 10 percent tolerance cannot be resolved by year end, a plan to resolve the difference is developed and senior management consent is obtained. The audit process did not result in any significant changes to our reserve estimates for 2013, 2012 or 2011.
During 2013, 2012 and 2011, Netherland, Sewell & Associates, Inc. ("NSAI") prepared a certification of the prior year's reserves for the Alba field in E.G. The NSAI summary reports are filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have many years of industry experience, having worked for large, international oil and gas companies before joining NSAI. The senior technical advisor has over 35 years of practical experience in petroleum geosciences, with over 16 years experience in the estimation and evaluation of reserves. The second team member has over 9 years of practical experience in petroleum engineering, with over 4 years experience in the estimation and evaluation of reserves. Both are registered Professional Engineers in the State of Texas.
Ryder Scott Company ("Ryder Scott") also performed audits of several of our fields in 2013, 2012 and 2011. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 22 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He is a member of SPE, where he served on the Oil and Gas Reserves Committee, and is a registered Professional Engineer in the State of Texas.
Changes in Proved Undeveloped Reserves
As of December 31, 2012, those contracts2013, 627 mmboe of proved undeveloped reserves were reported, an increase of 56 mmboe from December 31, 2012. The following table shows changes in total proved undeveloped reserves for fixed and determinable amounts relate primarily2013:
|
| | |
| (mmboe) | |
| Beginning of year | 571 |
|
| Revisions of previous estimates | 4 |
|
| Improved recovery | 7 |
|
| Purchases of reserves in place | 16 |
|
| Extensions, discoveries, and other additions | 142 |
|
| Dispositions | (4 | ) |
| Transfer to Proved Developed | (109 | ) |
| End of year | 627 |
|
Significant additions to Eagle Ford liquid hydrocarbon production. A minimum of 54 mbbld is to be delivered at variable pricing through mid-2017 under two contracts. Our current production rates and proved undeveloped reserves related toduring 2013 included 72 mmboe in the Eagle Ford shale are sufficient to meet these commitments, but the contracts also provide for a monetary shortfall penalty or delivery of third-party volumes.
Oil Sands Mining Segment
We hold a 20 percent non-operated interestand 49 mmboe in the AOSP,Bakken shale plays due to development drilling. Transfers from proved undeveloped to proved developed reserves included 57 mmboe in the Eagle Ford, 18 mmboe in the Bakken and 7 mmboe in the Oklahoma resource basins due to producing wells. Costs incurred in 2013, 2012 and 2011 relating to the development of proved undeveloped reserves, were $2,536 million, $1,995 million and $1,107 million.
A total of 59 mmboe was booked as a result of reliable technology. Technologies included statistical analysis of production performance, decline curve analysis, rate transient analysis, reservoir simulation and volumetric analysis. The statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved undeveloped locations establish the reasonable certainty criteria required for booking reserves.
Projects can remain in proved undeveloped reserves for extended periods in certain situations such as large development projects which take more than five years to complete, or the timing of when additional gas compression is needed. Of the 627 mmboe of proved undeveloped reserves at December 31, 2013, 24 percent of the volume is associated with projects that have been included in proved reserves for more than five years. The majority of this volume is related to a compression project in E.G. that was sanctioned by our Board of Directors in 2004. The timing of the installation of compression is being driven by the reservoir performance with this project intended to maintain maximum production levels. Performance of this field since the Board sanctioned the project has far exceeded expectations. Estimates of initial dry gas in place increased by roughly 10 percent between 2004 and 2010. During 2012, the compression project received the approval of the E.G. government, allowing design and planning work to progress towards implementation, with completion expected by mid-2016. The other component of Alba proved undeveloped reserves is an oil sands mininginfill well approved in 2013 and upgrading joint ventureto be drilled late 2014.
Proved undeveloped reserves for the North Gialo development, located in Alberta, Canada. The joint venture produces bitumenthe Libyan Sahara desert, were booked for the first time as proved undeveloped reserves in 2010. This development, which is anticipated to take more than five years to be developed, is being executed by the operator and encompasses a continuous drilling program including the design, fabrication and installation of extensive liquid handling and gas recycling facilities. Anecdotal evidence from oil sands depositssimilar development projects in the Athabasca region utilizing mining techniquesled to an expected project execution of more than five years from the time the reserves were initially booked. Interruptions associated with the civil unrest in 2011 and upgradesthird-party labor strikes in 2013 have extended the bitumenproject duration. There are no other significant undeveloped reserves expected to synthetic crude oils and vacuum gas oil. The AOSP’s mining and extraction assets are located near Fort McMurray, Alberta and include the Muskeg River and the Jackpine mines. Gross design capacity of the combined mines is 255,000 (51,000 net to our interest) barrels of bitumen per day. The AOSP base and expansion 1 Scotford upgrader is at Fort Saskatchewan, northeast of Edmonton, Alberta. be developed more than five years after their original booking.
As of December 31, 2012, we own or have rights2013, future development costs estimated to participate in developed and undeveloped leases totaling approximately 216,000 gross (43,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta.
The five year AOSP Expansion 1 was completed in 2011. The Jackpine mine commenced production under a phased start-up in the third quarter of 2010 and began supplying oil sands ore to the base processing facility in the fourth quarter of 2010. The upgrader expansion was completed and commenced operations in the second quarter of 2011. Synthetic crude oil sales volumes for 2012 were 47 mbbld and net of royalty production was 41 mbbld. Phase one of debottlenecking opportunities was approved in 2011 and is expected to be completed in the second quarter of 2013. Future expansions and additional debottlenecking opportunities remain under review with no formal approvals expected until 2014.
Current AOSP operations use established processes to mine oil sands deposits from an open-pit mine, extract the bitumen and upgrade it into synthetic crude oils. Ore is mined using traditional truck and shovel mining techniques. The mined ore passes through primary crushers to reduce the ore chunks in size and is then sent to rotary breakers where the ore chunks are further reduced to smaller particles. The particles are combined with hot water to create slurry. The slurry moves through the extraction
process where it separates into sand, clay and bitumen-rich froth. A solvent is added to the bitumen froth to separate out the remaining solids, water and heavy asphaltenes. The solvent washes the sand and produces clean bitumen that is required for the upgrader to run efficiently. The process yields a mixturedevelopment of solvent and bitumen which is then transported from the mine to the Scotford upgrader via the approximately 300 mile Corridor Pipeline.
The bitumen is upgraded at Scotford using both hydrotreating and hydroconversion processes to remove sulfur and break the heavy bitumen molecules into lighter products. Blendstocks acquired from outside sources are utilized in the production of our saleable products. The upgrader produces synthetic crude oil and vacuum gas oil. The vacuum gas oil is sold to an affiliate of the operator under a long term contract at market-related prices, and the other products are sold in the marketplace.
In the fourth quarter of 2012, regulatory hearings were completed to consider the AOSP Jackpine mine expansion project.The regulatory application was submitted in 2007 and describes a potential oil sands mining development project of 100,000 gross bbld and includes additional mining areas, associated processing facilities utilities and infrastructure. A regulatory decision is expected to be published in the second quarter of 2013.
The governments of Alberta and Canada have agreed to partially fund Quest CCS for 865 million Canadian dollars. Financing has begun to be received over a period of 15 years, including development, construction and 10 years of operations. However, the funding is subject to conditions of achieving certain performance objectives. In the third quarter of 2012, the Energy and Resources Conservation Board ("ERCB"), Alberta's primary energy regulator, conditionally approved and the AOSP partners made a final investment decision on Quest CCS.
As announced in October 2012, we have engaged in discussions with respect to a potential sale of a portion of our 20 percent interest in the AOSP. 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.
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 and the application for the Jackpine mine expansion. The potential sale of a portion of our interest in the AOSP is subject to successful negotiations and execution of definitive agreements. The Jackpine mine expansion could be affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits. 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.
Reserves
Estimated Reserve Quantities
The following table sets forth estimated quantities of our proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves based upon an unweighted average of closing pricesrelated to continuing operations for the first dayyears 2014 through 2018 are projected to be $2,894 million, $2,567 million, $2,020 million, $1,452 million and $575 million.
The timing of each month infuture projects and estimated future development costs relating to the 12-month periods ended December 31, 2012, 2011 and 2010. Included in ourdevelopment of proved undeveloped liquid hydrocarbon, reserves, are NGLs which represent approximately 6 percent of our total proved reserves on an oil equivalent basis. Approximately 70 percent of those NGLs reserves are associated with our U.S. unconventional liquids-rich plays.
Reserves are disclosed by continent, by country, if the proved reserves related to any geographic area, on an oil-equivalent barrel basis represent 15 percent or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent, or a continent. Approximately 70 percent of our proved reserves are located in OECD countries.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | |
| December 31, 2012 | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Grand Total |
| Proved Developed Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 198 |
| | — |
| | 198 |
| | 68 |
| | 168 |
| | 236 |
| | 84 |
| | 518 |
|
Natural gas (bcf) | 546 |
| | — |
| | 546 |
| | 980 |
| | 99 |
| | 1,079 |
| | 28 |
| | 1,653 |
|
Synthetic crude oil (mmbbl) | — |
| | 653 |
| | 653 |
| | — |
| | — |
| | — |
| | — |
| | 653 |
|
Total proved developed reserves (mmboe) | 289 |
| | 653 |
| | 942 |
| | 231 |
| | 185 |
| | 416 |
| | 88 |
| | 1,446 |
|
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 277 |
| | — |
| | 277 |
| | 42 |
| | 59 |
| | 101 |
| | 5 |
| | 383 |
|
Natural gas (bcf) | 497 |
| | — |
| | 497 |
| | 444 |
| | 110 |
| | 554 |
| | 75 |
| | 1,126 |
|
Total proved undeveloped reserves (mmboe) | 360 |
| | — |
| | 360 |
| | 116 |
| | 77 |
| | 193 |
| | 18 |
| | 571 |
|
| Total Proved Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 475 |
| | — |
| | 475 |
| | 110 |
| | 227 |
| | 337 |
| | 89 |
| | 901 |
|
Natural gas (bcf) | 1,043 |
| | — |
| | 1,043 |
| | 1,424 |
| | 209 |
| | 1,633 |
| | 103 |
| | 2,779 |
|
Synthetic crude oil (mmbbl) | — |
| | 653 |
| | 653 |
| | — |
| | — |
| | — |
| | — |
| | 653 |
|
Total proved reserves (mmboe) | 649 |
| | 653 |
| | 1,302 |
| | 347 |
| | 262 |
| | 609 |
| | 106 |
| | 2,017 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | |
| December 31, 2011 | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Grand Total |
| Proved Developed Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 141 |
| | — |
| | 141 |
| | 78 |
| | 179 |
| | 257 |
| | 84 |
| | 482 |
|
Natural gas (bcf) | 551 |
| | — |
| | 551 |
| | 1,104 |
| | 104 |
| | 1,208 |
| | 40 |
| | 1,799 |
|
Synthetic crude oil (mmbbl) | — |
| | 623 |
| | 623 |
| | — |
| | — |
| | — |
| | — |
| | 623 |
|
Total proved developed reserves (mmboe) | 233 |
| | 623 |
| | 856 |
| | 262 |
| | 196 |
| | 458 |
| | 91 |
| | 1,405 |
|
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 138 |
| | — |
| | 138 |
| | 39 |
| | 61 |
| | 100 |
| | 13 |
| | 251 |
|
Natural gas (bcf) | 321 |
| | — |
| | 321 |
| | 467 |
| | — |
| | 467 |
| | 79 |
| | 867 |
|
Total proved undeveloped reserves (mmboe) | 191 |
| | — |
| | 191 |
| | 117 |
| | 61 |
| | 178 |
| | 26 |
| | 395 |
|
| Total Proved Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 279 |
| | — |
| | 279 |
| | 117 |
| | 240 |
| | 357 |
| | 97 |
| | 733 |
|
Natural gas (bcf) | 872 |
| | — |
| | 872 |
| | 1,571 |
| | 104 |
| | 1,675 |
| | 119 |
| | 2,666 |
|
Synthetic crude oil (mmbbl) | — |
| | 623 |
| | 623 |
| | — |
| | — |
| | — |
| | — |
| | 623 |
|
Total proved reserves (mmboe) | 424 |
| | 623 |
| | 1,047 |
| | 379 |
| | 257 |
| | 636 |
| | 117 |
| | 1,800 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | |
| December 31, 2010 | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Grand Total |
| Proved Developed Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 124 |
| | — |
| | 124 |
| | 86 |
| | 180 |
| | 266 |
| | 89 |
| | 479 |
|
Natural gas (bcf) | 591 |
| | — |
| | 591 |
| | 1,186 |
| | 104 |
| | 1,290 |
| | 43 |
| | 1,924 |
|
Synthetic crude oil (mmbbl) | — |
| | 433 |
| | 433 |
| | — |
| | — |
| | — |
| | — |
| | 433 |
|
Total proved developed reserves (mmboe) | 222 |
| | 433 |
| | 655 |
| | 284 |
| | 198 |
| | 482 |
| | 96 |
| | 1,233 |
|
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 49 |
| | — |
| | 49 |
| | 33 |
| | 59 |
| | 92 |
| | 10 |
| | 151 |
|
Natural gas (bcf) | 154 |
| | — |
| | 154 |
| | 465 |
| | 1 |
| | 466 |
| | 73 |
| | 693 |
|
Synthetic crude oil (mmbbl) | — |
| | 139 |
| | 139 |
| | — |
| | — |
| | — |
| | — |
| | 139 |
|
Total proved undeveloped reserves (mmboe) | 75 |
| | 139 |
| | 214 |
| | 110 |
| | 59 |
| | 169 |
| | 22 |
| | 405 |
|
| Total Proved Reserves | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mmbbl) | 173 |
| | — |
| | 173 |
| | 119 |
| | 239 |
| | 358 |
| | 99 |
| | 630 |
|
Natural gas (bcf) | 745 |
| | — |
| | 745 |
| | 1,651 |
| | 105 |
| | 1,756 |
| | 116 |
| | 2,617 |
|
Synthetic crude oil (mmbbl) | — |
| | 572 |
| | 572 |
| | — |
| | — |
| | — |
| | — |
| | 572 |
|
Total proved reserves (mmboe) | 297 |
| | 572 |
| | 869 |
| | 394 |
| | 257 |
| | 651 |
| | 118 |
| | 1,638 |
|
The significant increase in proved reserves from 2011 to 2012 was primarily due to drilling programs within our shale playsnatural gas and Eagle Ford acquisitions. Syntheticsynthetic crude oil reserves also increased due to revised technical assessment and a change in royalty related to lower prices.
The above estimated quantities of proved liquid hydrocarbon and natural gas reserves are forward-looking statements and are based on a number of assumptions, including (among others) commodity prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, technology developments, future drilling success, industry economic conditions, levels of cash flow from operations, production experience and other operating considerations. The above estimated quantities of synthetic crude oil reserves are forward-looking statements and are based on presently known physical data, economic recoverability and operating conditions. To the extent these assumptions prove inaccurate, actual recoveries, timing and development costs could be different than current estimates. For additional details
Net Production Sold
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| 2013 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mbbld)(a) | 149 |
| | — |
| | 149 |
| | 34 |
| | 24 |
| | 58 |
| | 86 |
| | 10 |
| | 303 |
|
Natural gas (mmcfd)(b)(c) | 312 |
| | — |
| | 312 |
| | 442 |
| | 22 |
| | 464 |
| | 76 |
| | — |
| | 852 |
|
Synthetic crude oil (mbbld)(d) | — |
| | 42 |
| | 42 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 42 |
|
Total production sold (mboed) | 201 |
| | 42 |
| | 243 |
| | 107 |
| | 27 |
| | 134 |
| | 99 |
| | 10 |
| | 486 |
|
| 2012 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mbbld)(a) | 107 |
| | — |
| | 107 |
| | 36 |
| | 42 |
| | 78 |
| | 97 |
| | — |
| | 282 |
|
Natural gas (mmcfd)(b)(c) | 358 |
| | — |
| | 358 |
| | 428 |
| | 15 |
| | 443 |
| | 86 |
| | — |
| | 887 |
|
Synthetic crude oil (mbbld)(d) | — |
| | 41 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 41 |
|
Total production sold (mboed) | 166 |
| | 41 |
| | 207 |
| | 108 |
| | 44 |
| | 152 |
| | 111 |
| | — |
| | 470 |
|
| 2011 | | | | | | | | | | | | | | | |
|
Liquid hydrocarbons (mbbld)(a) | 75 |
| | — |
| | 75 |
| | 38 |
| | 5 |
| | 43 |
| | 101 |
| | — |
| | 219 |
|
Natural gas (mmcfd)(b)(c) | 326 |
| | — |
| | 326 |
| | 443 |
| | — |
| | 443 |
| | 81 |
| | — |
| | 850 |
|
Synthetic crude oil (mbbld)(d) | — |
| | 38 |
| | 38 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 38 |
|
Total production sold (mboed) | 129 |
| | 38 |
| | 167 |
| | 112 |
| | 5 |
| | 117 |
| | 115 |
| | — |
| | 399 |
|
| |
(a) | The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons. |
| |
(b) | U.S. natural gas volumes exclude volumes produced in Alaska prior to our disposal of those assets in 2013 that were stored for later sale in response to seasonal demand, although our reserves had been reduced by those volumes. |
| |
(c) | Excludes volumes acquired from third parties for injection and subsequent resale. |
| |
(d) | Upgraded bitumen excluding blendstocks. |
Average Sales Price per Unit
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| (Dollars per unit) | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| 2013 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 85.20 |
| | $ | — |
| | $ | 85.20 |
| | $ | 60.34 |
| | $ | 122.92 |
| | $ | 86.29 |
| | $ | 112.60 |
| | $ | 104.77 |
| | $ | 93.83 |
|
Natural gas (mcf) | 3.84 |
| | — |
| | 3.84 |
| | 0.24 |
| (a) | 5.44 |
| | 0.49 |
| | 12.13 |
| | — |
| | 2.75 |
|
Synthetic crude oil (bbl) | — |
| | 87.51 |
| | 87.51 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 87.51 |
|
| 2012 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 85.80 |
| | $ | — |
| | $ | 85.80 |
| | $ | 64.33 |
| | $ | 127.31 |
| | $ | 98.52 |
| | $ | 115.16 |
| | $ | — |
| | $ | 99.46 |
|
Natural gas (mcf) | 3.92 |
| | — |
| | 3.92 |
| | 0.24 |
| (a) | 5.76 |
| | 0.43 |
| | 10.45 |
| | — |
| | 2.80 |
|
Synthetic crude oil (bbl) | — |
| | 81.72 |
| | 81.72 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 81.72 |
|
| 2011 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 92.55 |
| | $ | — |
| | $ | 92.55 |
| | $ | 67.70 |
| | $ | 112.56 |
| | $ | 73.21 |
| | $ | 115.55 |
| | $ | — |
| | $ | 99.37 |
|
Natural gas (mcf) | 4.95 |
| | — |
| | 4.95 |
| | 0.24 |
| (a) | 0.70 |
| | 0.24 |
| | 9.75 |
| | — |
| | 2.96 |
|
Synthetic crude oil (bbl) | — |
| | 91.65 |
| | 91.65 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 91.65 |
|
| |
(a) | Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P Segment. |
Average Production Cost per Unit(a)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | Europe | | | | |
| (Dollars per boe) | U.S. | | Canada(b) | | Total | | E.G. | | Other(c) | | Total | | Total | | Disc Ops | | Grand Total |
| 2013 | $ | 13.60 |
| | $ | 55.42 |
| | $ | 20.79 |
| | $ | 2.88 |
| | $ | 7.40 |
| | $ | 3.80 |
| | $ | 13.68 |
| | $ | 11.89 |
| | $ | 14.47 |
|
| 2012 | 13.61 |
| | 53.61 |
| | 21.51 |
| | 3.59 |
| | 3.57 |
| | 3.59 |
| | 9.62 |
| | — |
| | 12.91 |
|
| 2011 | 16.51 |
| | 59.04 |
| | 25.97 |
| | 2.92 |
| | 12.22 |
| | 3.34 |
| | 8.85 |
| | — |
| | 14.42 |
|
| |
(a) | Production, severance and property taxes are excluded from the production costs used in this calculation. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Production Activities for more information regarding production cost. |
| |
(b) | Production costs in 2011 include a $64 million water abatement accrual. |
| |
(c) | Production operations ceased in Libya in February 2011, resuming in 2012, but ceased again in the third quarter of 2013. Fixed costs continue to be incurred in these periods of downtime. |
Marketing and Midstream
Our operating segments include activities related to the marketing and transportation of substantially all of our liquid hydrocarbon, synthetic crude oil and natural gas production. These activities include the estimated quantitiestransportation of proved reserves atproduction to market centers, the endsale of eachcommodities to third parties and the storage of production. We balance our various sales, storage and transportation positions in order to aggregate volumes to satisfy transportation commitments and to achieve flexibility within product types and delivery points. Such activities can include the last three years, see Item 8. Financial Statementspurchase of commodities from third parties for resale.
As discussed previously, we currently own and Supplementary Data – Supplementary Information on Oiloperate gathering systems and Gas Producing Activities.other midstream assets in some of our production areas. We continue to evaluate midstream infrastructure investments in connection with our development plans.
Preparation of Reserve Estimates
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Liquid hydrocarbon, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group, which includes our Director of Corporate Reserves and herhis staff of Reserve Coordinators. Liquid hydrocarbon and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QRE"QREs"). QREQREs are engineers or geoscientists with a minimum ofat least a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed Marathon Oil's Qualified Reserve EstimatorQRE training course. Reserve Coordinators screen all fields with proved reserves of 20 mmboe or greater, every year, to determine if a field review will be performed. Any change to proved reserve estimates in excess of 2.51 mmboe on a total field basis, within a single month, must be approved by Corporate Reserves Group management. All other proved reserve changes must be approved by a Reserve Coordinator.
Our Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in petroleum engineering and is a Master of Business Administration. Her 38 years of experienceregistered Professional Engineer in the industry include 27State of Texas. In his 26 years with Marathon Oil. SheOil, he has held numerous engineering and management positions, most recently managing our OSM segment. He is active in industry and professional groups, having served ona member of the Society of Petroleum Engineers ("SPE") Oil and Gas Reserves Committee ("OGRC"), chairing in 2008 and 2009. As a former member of the OGRC, she participated inPetroleum Engineering Advisory Council for the developmentUniversity of the Petroleum Resource Management System. She chaired the development of the OGRC comments on the SEC's proposed modernization of oil and gas reporting and was a member of the American Petroleum Institute's Ad Hoc group that provided comments on the same topic.Texas at Austin.
Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants ("GLJ") of Calgary, Canada, third-party consultants. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The team lead responsible for the estimates of our OSMsynthetic crude oil reserves has 34over 35 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 1986. He is a member of SPE havingand served as regional director from 1998 through 2001. The second GLJ team member has 13 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 2009. Both are registered Practicing Professional Engineers in the Province of Alberta.
Audits of Estimates
Third-party consultants are engaged to provide independent estimates for fields that comprise 80 percent of our total proved reserves over a rolling four-year period for the purpose of auditing the in-houseand validating our internal reserve estimates. We metexceeded this goalpercentage for the four-year period ended December 31, 2012.2013. We have established a tolerance level of 10 percent such that initial estimates by the third-party consultants are accepted if they are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, both our team and the consultantsparties re-examine the information provided, request additional data and refine their analysis if appropriate. This resolution process is continued until both estimates are within 10 percent. In the very limited instances where differences outside the 10 percent tolerance cannot be resolved by year end, a plan to resolve the difference is developed and our senior management consent is informed. Thisobtained. The audit process did not result in any significant changes to our reserve estimates infor 2013, 2012 or 2011. There were no third-party audits performed in 2010.
During 2013, 2012 and 2011, Netherland, Sewell & Associates, Inc. ("NSAI") prepared a Certificationcertification of December 31, 2011the prior year's reserves for the Alba field in E.G. The NSAI summary report isreports are filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have many years of industry experience, having worked for large, international oil and gas companies before joining NSAI. The senior technical advisor has a Bachelorover 35 years of Science degreepractical experience in geophysics andpetroleum geosciences, with over 1516 years of experience in the estimation of and evaluation of reserves. The second team member has a Bachelorover 9 years of Science degreepractical experience in chemicalpetroleum engineering, and Master of Business Administration along with over 34 years of experience in the estimation and evaluation of reserves. Both are licensedregistered Professional Engineers in the stateState of Texas.
Ryder Scott Company ("Ryder Scott") also performed audits of several of our fields in 2013, 2012 and 2011. Their summary reports on audits performed in 2012 and 2011 are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 2022 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He has a Bachelor of Science degree in mechanical engineering, is a member of SPE, where he served on the Oil and Gas Reserves Committee, and is a registered Professional Engineer in the stateState of Texas.
Changes in Proved Undeveloped Reserves
As of December 31, 2012, 5712013, 627 mmboe of proved undeveloped reserves were reported, an increase of 17656 mmboe from December 31, 2011.2012. The following table shows changes in total proved undeveloped reserves for 2012:2013:
|
| | |
| (mmboe) | |
| Beginning of year | 395571 |
|
| Revisions of previous estimates | (134 | )
|
| Improved recovery | 27 |
|
| Purchases of reserves in place | 5616 |
|
| Extensions, discoveries, and other additions | 201142 |
|
| Dispositions | (4 | ) |
| Transfer to Proved Developed | (70109 | ) |
| End of year | 571627 |
|
Significant additions to proved undeveloped reserves during 2012 include 56 mmboe due to acquisitions in the Eagle Ford shale. Development drilling added 1242013 included 72 mmboe in the Eagle Ford 35 mmboe in the Bakken and 15 mmboe in the Oklahoma Resource Basins shale play. A gas sharing agreement signed with the Libyan government in 2012 added 19 mmboe. Additionally, 30 mmboe were transferred from proved undeveloped to proved developed reserves in the Eagle Ford and 1449 mmboe in the Bakken shale plays due to development drilling. Transfers from proved undeveloped to proved developed reserves included 57 mmboe in the Eagle Ford, 18 mmboe in the Bakken and 7 mmboe in the Oklahoma resource basins due to producing wells. Costs incurred in 2013, 2012 2011 and 20102011 relating to the development of proved undeveloped reserves, were $1,9952,536 million $1,107, $1,995 million and $1,463$1,107 million.
A total of 2759 mmboe was booked as a result of reliable technology. Technologies included statistical analysis of production performance, decline curve analysis, rate transient analysis, reservoir simulation and volumetric analysis. The statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved undeveloped locations establish the reasonable certainty criteria required for booking reserves.
Projects can remain in proved undeveloped reserves for extended periods in certain situations such as behind-pipe zones where reserves will not be accessed until the primary producing zone depletes, large development projects which take more than five years to complete, andor the timing of when additional gas compression is needed. Of the 571627 mmboe of proved undeveloped reserves at December 31, 2012, 252013, 24 percent of the volume is associated with projects that have been included in proved reserves for more than five years. The majority of this volume is related to a compression project in E.G. that was sanctioned by our Board of Directors in 2004. The timing of the installation of compression is being driven by the reservoir performance with this project intended to maintain maximum production levels. Performance of this field since the Board sanctioned the project has far exceeded expectations. Estimates of initial dry gas in place have increased by roughly 10 percent between 2004 and 2010. Production is now expected to experience a natural decline from facility-limited plateau production in 2014, or possibly 2015. During 2012, the compression project received the approval of the E.G. government, allowing design and planning work to progress towards implementation, with completion expected by mid-2016. The other component of Alba proved undeveloped reserves is an infill well approved in 2013 and to be drilled late 2014.
Proved undeveloped reserves for the North Gialo development, located in the Libyan Sahara desert, were booked for the first time as proved undeveloped reserves in 2010. This development, which is anticipated to take more than five years to be developed, is being executed by the operator and encompasses a continuous drilling program including the design, fabrication and installation of extensive liquid handling and gas recycling facilities. Anecdotal evidence from similar development projects in the region led to an expected project execution of more than five years from the time the reserves were initially booked. Interruptions associated with the civil unrest in 2011 and third-party labor strikes in 2013 have extended the project duration. There are no other significant undeveloped reserves expected to be developed more than five years after their original booking.
As of December 31, 2012,2013, future development costs estimated to be required for the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves related to continuing operations for the years 20132014 through 20172018 are projected to be $2,665$2,894 million, $2,726$2,567 million, $2,955$2,020 million, $2,132$1,452 million and $425$575 million.
The timing of future projects and estimated future development costs relating to the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves are forward-looking statements and are based on a number of assumptions, including (among others) commodity prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, technology developments, future drilling success, industry economic conditions, levels of cash flow from operations, production experience and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries, timing and development costs could be different than current estimates.
Net Production Sold
| | | | North America | | Africa | | Europe | | | North America | | Africa | | Europe | | | | |
| | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Grand Total | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| Year Ended December 31, 2012 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mbbld)(a) | 107 |
| | — |
| | 107 |
| | 36 |
| | 42 |
| | 78 |
| | 97 |
| | 282 |
| |
Natural gas (mmcfd)(b)(c) | 358 |
| | — |
| | 358 |
| | 428 |
| | 15 |
| | 443 |
| | 86 |
| | 887 |
| |
Synthetic crude oil (mbbld) | — |
| | 41 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | 41 |
| |
Total production sold (mboed) | 167 |
| | 41 |
| | 208 |
| | 108 |
| | 44 |
| | 152 |
| | 111 |
| | 471 |
| |
| Year Ended December 31, 2011 | | | | | | | | | | | | | | |
| |
| 2013 | | 2013 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mbbld)(a) | 75 |
| | — |
| | 75 |
| | 38 |
| | 5 |
| | 43 |
| | 101 |
| | 219 |
| 149 |
| | — |
| | 149 |
| | 34 |
| | 24 |
| | 58 |
| | 86 |
| | 10 |
| | 303 |
|
Natural gas (mmcfd)(b)(c) | 326 |
| | — |
| | 326 |
| | 443 |
| | — |
| | 443 |
| | 81 |
| | 850 |
| 312 |
| | — |
| | 312 |
| | 442 |
| | 22 |
| | 464 |
| | 76 |
| | — |
| | 852 |
|
Synthetic crude oil (mbbld) | — |
| | 38 |
| | 38 |
| | — |
| | — |
| | — |
| | — |
| | 38 |
| — |
| | 42 |
| | 42 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 42 |
|
Total production sold (mboed) | 129 |
| | 38 |
| | 167 |
| | 112 |
| | 5 |
| | 117 |
| | 115 |
| | 399 |
| 201 |
| | 42 |
| | 243 |
| | 107 |
| | 27 |
| | 134 |
| | 99 |
| | 10 |
| | 486 |
|
| Year Ended December 31, 2010 | | | | | | | | | | | | | | |
| |
| 2012 | | 2012 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (mbbld)(a) | 70 |
| | — |
| | 70 |
| | 38 |
| | 45 |
| | 83 |
| | 92 |
| | 245 |
| 107 |
| | — |
| | 107 |
| | 36 |
| | 42 |
| | 78 |
| | 97 |
| | — |
| | 282 |
|
Natural gas (mmcfd)(b)(c) | 364 |
| | — |
| | 364 |
| | 405 |
| | 4 |
| | 409 |
| | 87 |
| | 860 |
| 358 |
| | — |
| | 358 |
| | 428 |
| | 15 |
| | 443 |
| | 86 |
| | — |
| | 887 |
|
Synthetic crude oil (mbbld) | — |
| | 24 |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
| |
Synthetic crude oil (mbbld) | | — |
| | 41 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 41 |
|
Total production sold (mboed) | 131 |
| | 24 |
| | 155 |
| | 106 |
| | 45 |
| | 151 |
| | 106 |
| | 412 |
| 166 |
| | 41 |
| | 207 |
| | 108 |
| | 44 |
| | 152 |
| | 111 |
| | — |
| | 470 |
|
| 2011 | | 2011 | | | | | | | | | | | | | | | |
|
Liquid hydrocarbons (mbbld)(a) | | 75 |
| | — |
| | 75 |
| | 38 |
| | 5 |
| | 43 |
| | 101 |
| | — |
| | 219 |
|
Natural gas (mmcfd)(b)(c) | | 326 |
| | — |
| | 326 |
| | 443 |
| | — |
| | 443 |
| | 81 |
| | — |
| | 850 |
|
Synthetic crude oil (mbbld)(d) | | — |
| | 38 |
| | 38 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 38 |
|
Total production sold (mboed) | | 129 |
| | 38 |
| | 167 |
| | 112 |
| | 5 |
| | 117 |
| | 115 |
| | — |
| | 399 |
|
| |
(a) | The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons. |
| |
(b) | U.S. natural gas volumes exclude volumes produced in Alaska prior to our disposal of those assets in 2013 that arewere stored for later sale in response to seasonal demand, although our reserves havehad been reduced by those volumes. |
| |
(c) | Excludes volumes acquired from third parties for injection and subsequent resale. |
| |
(d) | Upgraded bitumen excluding blendstocks. |
Average Sales Price per Unit
| | | | North America | | Africa | | Europe | | | North America | | Africa | | Europe | | | | |
| (Dollars per unit) | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Grand Total | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Total | | Disc Ops | | Grand Total |
| Year Ended December 31, 2012 | | | | | | | | | | | | | | | | |
| 2013 | | 2013 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 85.80 |
| | $ | — |
| | $ | 85.80 |
| | $ | 64.33 |
| | $ | 127.31 |
| | $ | 98.52 |
| | $ | 115.16 |
| | $ | 99.46 |
| $ | 85.20 |
| | $ | — |
| | $ | 85.20 |
| | $ | 60.34 |
| | $ | 122.92 |
| | $ | 86.29 |
| | $ | 112.60 |
| | $ | 104.77 |
| | $ | 93.83 |
|
Natural gas (mcf) | 3.91 |
| | — |
| | 3.91 |
| | 0.24 |
| | 5.76 |
| | 0.43 |
| | 10.45 |
| | 2.80 |
| 3.84 |
| | — |
| | 3.84 |
| | 0.24 |
| (a) | 5.44 |
| | 0.49 |
| | 12.13 |
| | — |
| | 2.75 |
|
Synthetic crude oil (bbl) | — |
| | 81.72 |
| | 81.72 |
| | — |
| | — |
| | — |
| | — |
| | 81.72 |
| — |
| | 87.51 |
| | 87.51 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 87.51 |
|
| Year Ended December 31, 2011 | | | | | | | | | | | | | | | | |
| 2012 | | 2012 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 92.55 |
| | $ | — |
| | $ | 92.55 |
| | $ | 67.70 |
| | $ | 112.56 |
| | $ | 73.21 |
| | $ | 115.55 |
| | $ | 99.37 |
| $ | 85.80 |
| | $ | — |
| | $ | 85.80 |
| | $ | 64.33 |
| | $ | 127.31 |
| | $ | 98.52 |
| | $ | 115.16 |
| | $ | — |
| | $ | 99.46 |
|
Natural gas (mcf) | 4.95 |
| | — |
| | 4.95 |
| | 0.24 |
| | 0.70 |
| | 0.24 |
| | 9.75 |
| | 2.96 |
| 3.92 |
| | — |
| | 3.92 |
| | 0.24 |
| (a) | 5.76 |
| | 0.43 |
| | 10.45 |
| | — |
| | 2.80 |
|
Synthetic crude oil (bbl) | — |
| | 91.65 |
| | 91.65 |
| | — |
| | — |
| | — |
| | — |
| | 91.65 |
| — |
| | 81.72 |
| | 81.72 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 81.72 |
|
| Year Ended December 31, 2010 | | | | | | | | | | | | | | | | |
| 2011 | | 2011 | | | | | | | | | | | | | | | | |
Liquid hydrocarbons (bbl) | $ | 72.30 |
| | $ | — |
| | $ | 72.30 |
| | $ | 50.57 |
| | $ | 89.15 |
| | $ | 71.71 |
| | $ | 81.95 |
| | $ | 75.73 |
| $ | 92.55 |
| | $ | — |
| | $ | 92.55 |
| | $ | 67.70 |
| | $ | 112.56 |
| | $ | 73.21 |
| | $ | 115.55 |
| | $ | — |
| | $ | 99.37 |
|
Natural gas (mcf) | 4.71 |
| | — |
| | 4.71 |
| | 0.24 |
| | 0.70 |
| | 0.25 |
| | 7.04 |
| | 2.82 |
| 4.95 |
| | — |
| | 4.95 |
| | 0.24 |
| (a) | 0.70 |
| | 0.24 |
| | 9.75 |
| | — |
| | 2.96 |
|
Synthetic crude oil (bbl) | — |
| | 71.06 |
| | 71.06 |
| | — |
| | — |
| | — |
| | — |
| | 71.06 |
| — |
| | 91.65 |
| | 91.65 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 91.65 |
|
| |
(a) | Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P Segment. |
Average Production Cost per Unit(a)
| | | | North America | | Africa | | Europe | | | North America | | Africa | | Europe | | | | |
| (Dollars per boe) | U.S. | | Canada(b) |
| Total | | E.G. | | Other(c) |
| Total | | Total | | Grand Total | U.S. | | Canada(b) | | Total | | E.G. | | Other(c) | | Total | | Total | | Disc Ops | | Grand Total |
| Years ended December 31: | | | | | | | | | | | | | | | | |
| 2013 | | $ | 13.60 |
| | $ | 55.42 |
| | $ | 20.79 |
| | $ | 2.88 |
| | $ | 7.40 |
| | $ | 3.80 |
| | $ | 13.68 |
| | $ | 11.89 |
| | $ | 14.47 |
|
| 2012 | $ | 16.05 |
| | $ | 61.55 |
| | $ | 25.04 |
| | $ | 3.59 |
| | $ | 4.66 |
| | $ | 3.90 |
| | $ | 9.08 |
| | $ | 14.44 |
| 13.61 |
| | 53.61 |
| | 21.51 |
| | 3.59 |
| | 3.57 |
| | 3.59 |
| | 9.62 |
| | — |
| | 12.91 |
|
| 2011 | 16.42 |
| | 60.04 |
| | 26.13 |
| | 2.87 |
| | 17.16 |
| | 3.53 |
| | 8.24 |
| | 14.36 |
| 16.51 |
| | 59.04 |
| | 25.97 |
| | 2.92 |
| | 12.22 |
| | 3.34 |
| | 8.85 |
| | — |
| | 14.42 |
|
| 2010 | 14.16 |
| | 69.24 |
| | 22.58 |
| | 2.81 |
| | 4.18 |
| | 3.23 |
| | 7.49 |
| | 11.59 |
| |
| |
(a) | Production, severance and property taxes are excluded from the production costs used in the calculationthis calculation. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities - Results of this metric.Operations for Oil and Gas Production Activities for more information regarding production cost. |
| |
(b) | Production costs in 20102011 include costs associated with a major turnaround and $64 million for a water abatement accrual in 2011.accrual. |
| |
(c) | Production operations ceased in Libya in February 2011, resuming in 2012, but fixedceased again in the third quarter of 2013. Fixed costs continuedcontinue to be incurred. Production resumedincurred in 2012.these periods of downtime. |
Integrated GasMarketing and Midstream
Our IG operationsoperating segments include activities related to the marketing and transportation of substantially all of our liquid hydrocarbon, synthetic crude oil and natural gas liquefaction operationsproduction. These activities include the transportation of production to market centers, the sale of commodities to third parties and methanolthe storage of production. We balance our various sales, storage and transportation positions in order to aggregate volumes to satisfy transportation commitments and to achieve flexibility within product types and delivery points. Such activities can include the purchase of commodities from third parties for resale.
As discussed previously, we currently own and operate gathering systems and other midstream assets in some of our production operations. Also includedareas. We continue to evaluate midstream infrastructure investments in the financial resultsconnection with our development plans.
Delivery Commitments
We have committed to deliver quantities of the IG segment are the costs associated with ongoing development of projectscrude oil and synthetic crude oil to link stranded natural gas resources with key demand areas.
We hold a 60 percent interest in EGHoldings, which is accounted for under the equity method of accounting. EGHoldings has a 3.7 mmta LNG production facility on Bioko Island in E.G. LNG from the production facility is soldcustomers under a 3.4 mmta,variety of contracts. As of December 31, 2013, those contracts for fixed and determinable quantities were at variable, market-based pricing and related primarily to Eagle Ford and Bakken liquid hydrocarbon production and OSM synthetic crude oil production. A minimum of 54 mbbld of Eagle Ford liquid hydrocarbon production is to be delivered through mid-2017 under two contracts. Under a 6-year contract ending May 2016, 15 mbbld of Bakken liquid hydrocarbon production is to be delivered. Under a 3-year contract expected to commence mid-2014, 14 mbbld of synthetic crude oil production is to be delivered. Our current production rates and proved reserves are sufficient to meet these commitments. The Eagle Ford and OSM contracts also provide the options of delivering third-party volumes or 460 mmcfd, sales and purchase agreement ending in 2023.paying a monetary shortfall penalty if production is inadequate. The purchaser under the agreement takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index, regardless of destination. This production facility allows us to monetize our natural gas reserves from the Alba field, as natural gasBakken contract carries no penalty for the facility is purchased from the Alba field participants under a long-term natural gas supply agreement. Gross sales of LNG from this production facility totaled 3.8 mmt, 4.1 mmt and 3.7 mmt in 2012, 2011 and 2010. Operational availability for this LNG production facility was 95 percent including a planned turnaround, while unplanned downtime was minimal at 1.5 percent. The turnaround was completed four days ahead of schedule and 15 percent under budget. In 2012, we continued discussions with the government of E.G. and our partners regarding a potential second LNG production train on Bioko Island.shortfalls.
We own a 45 percent interest in AMPCO, which is accounted for under the equity method of accounting. AMPCO owns a methanol plant located on Bioko Island in E.G. Feedstock for the plant is supplied from our natural gas production from the Alba field. Gross sales of methanol from the plant totaled 1.06 mmt, 1.04 mmt and 0.85 mmt in 2012, 2011 and 2010. Operational availability for this plant was 91 percent in 2012. Production from the plant is used to supply customers in Europe and the U.S.
The above discussion of the IG segment contains forward-looking statements with respect to the possible expansion of the LNG production facility in E.G. Factors that could potentially affect the possible expansion of the LNG production facility include partner and government approvals, access to sufficient natural gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient reclassification capacity. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Competition and Market Conditions
Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of new reserves. We compete with major integrated and independent oil and gas companies, as well as national oil companies, for the acquisition of oil and natural gas leases and other properties. Based upon statistics compiled in the "2012"2013 Global Upstream Performance Review" published by IHS Herold Inc., we rank tenthninth among U.S.-based petroleum companies on the basis of 20112012 worldwide liquid hydrocarbon and natural gas production. See Item 1A. Risk Factors for discussion of specific areas in which we compete and related risks.
We also compete with other producers of synthetic and conventional crude oil for the sale of our synthetic crude oil to refineries primarily in North America. Additional synthetic crude oil projects are being contemplated by various competitors and, if undertaken and completed, these projects may result in a significant increase in the supply of synthetic crude oil to the market. Since not all refineries are able to process or refine synthetic crude oil in significant volumes, there can be no assurance that sufficient market demand will exist at all times to absorb our share of the synthetic crude oil production from the AOSP at economically viable prices.
Our operating results are affected by price changes in conventional andfor liquid hydrocarbons, synthetic crude oil and natural gas, and petroleum products, as well as changes in competitive conditions in the markets we serve. Generally, results from oil and gas production and OSM operations benefit from higher crude oil prices. Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and new and changing governmental regulations. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Overview – Market Conditions for additional discussion of the impact of prices on our operations.
Environmental, Health and Safety Matters
The Health, Environmental, Safety and Corporate Responsibility Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental, health and safety matters. Our Corporate Health, Environment,
Safety and Security organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations. Committees comprised of certain of our officers review our overall performance associated with various environmental compliance programs. We also have a Corporate Emergency Response Team which oversees our response to any major environmental or other emergency incident involving us or any of our properties.
Our businesses are subject to numerous laws and regulations relating to the protection of the environment, health and safety. These laws and regulations include the Occupational Safety and Health Act ("OSHA") with respect to the protection of the health and safety of employees, the Clean Air Act ("CAA") with respect to air emissions, the Federal Water Pollution Control Act (also known as the Clean Water Act ("CWA")) with respect to water discharges, the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") with respect to releases and remediation of hazardous substances, the Oil Pollution Act of 1990 ("OPA-90") with respect to oil pollution and response, the National Environmental Policy Act with respect to evaluation of environmental impacts, the Endangered Species Act with respect to the protection of endangered or threatened species, the Resource Conservation and Recovery Act ("RCRA") with respect to solid and hazardous waste treatment, storage and disposal and the U.S. Emergency Planning and Community Right-to-Know Act with respect to the dissemination of information relating to certain chemical inventories. In addition, many other states and countries in which where we operate have their own laws dealing with similar matters.
These laws and regulations could result in costs to remediate releases of regulated substances, including crude oil, into the environment, or costs to remediate sites to which we sent regulated substances for disposal. In some cases, these laws can impose strict liability for the entire cost of clean-up on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others (such as prior owners or operators of our assets) or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. New laws have been enacted and regulations are being adopted by various regulatory agencies on a continuing basis and the costs of compliance with these new rules can only be broadly appraised until their implementation becomes more defined. Based on regulatory trends, particularly with respect to the CAA and its implementing regulations, we have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.
For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.
Air
In August 2012, the U.S. EPA published final New Source Performance Standards ("NSPS") and National Emissions Standards for Hazardous Air Pollutants ("NESHAP") that amended existing NSPS and NESHAP standards for oil and gas facilities as well as created a new NSPS for oil and gas production, transmission and distribution facilities. These rules, which were updated in August 2013, have been challenged, and negotiations with the U.S. EPA over proposed changes to the rules continue. Compliance with these new rules will result in an increase in the costs of control equipment and labor and require additional notification, monitoring, reporting and recordkeeping for some of our facilities. The U.S. EPA was also notified in December 2012 that seven northeastern states intend to sue the U.S. EPA for failure to include methane standards in these rules. If successfully challenged, the addition of methane standards could further increase our costs to comply with this rule.these rules.
In July 2011, the U.S. EPA finalized a Federal Implementation Plan under the CAA that includes New Source Review ("NSR") regulations which apply to air emissions sources on Tribal Lands. This rule became effective on August 30, 2011, and requires the registration and/or pre-construction permitting of most of our facilities on Tribal Lands in Wyoming, Oklahoma and North Dakota. Rather than issueissuing pre-construction permits for our facilities on Tribal Lands in North Dakota, in August of 2012, the U.S. EPA finalized an Interim Final Rule under the CAA that requires certain control equipment, recordkeeping, monitoring, and reporting with respect to these facilities. Compliance with this new rule will result in an increase in the costs of control, equipment and labor and will require additional notification, monitoring, reporting and recordkeeping for our facilities on Tribal Lands in North Dakota.
The U.S. EPA is expected to propose the results of its 5-year review of the 2008 ozone National Ambient Air Quality Standards (“NAAQS”) in 2014, which are expected to encompass a proposal for a lower ozone NAAQS. A more stringent ozone NAAQS could result in additional areas being designated as non-attainment, including areas in which we operate, which may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with any regulation or other action by the U.S. EPA that lowers the ozone
NAAQS, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented.
At the end of 2013, the U.S. EPA indicated that, in addition to sources already regulated under the current NSPS subpart OOOO, the U.S. EPA is considering petitions from members of the public to address other sources of emissions from oil and gas operations such as pneumatics, equipment leaks, liquids unloading, and associated gas. At this time, it is uncertain how the U.S. EPA may address these sources (e.g., additional regulations or voluntary programs), what the scope may be, what emission control levels or technology are being considered or the U.S. EPA’s timing. Although there may be an adverse financial impact associated with any such regulation or other action by the U.S. EPA, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented.
Climate Change
In 2010, the U.S. EPA promulgated rules that require us to monitor and submit an annual report on our greenhouse gas emissions. Our first reports made pursuant to this rule were submitted in September 2012. Further, state, national and international requirements to reduce greenhouse emissions are being proposed and in some cases promulgated. These requirements apply or could apply in countries in which we operate. Potential legislation and regulations pertaining to climate change could also affect our operations. The cost to comply with these laws and regulations cannot be estimated at this time. For additional information, see Item 1A. Risk Factors. As part of our commitment to environmental stewardship, we estimate and publicly report greenhouse gas emissions from our operations. We are working to continuously improve the accuracy and completeness of these estimates. In addition, we continuously strive to improve operational and energy efficiencies through resource and energy conservation where practicable and cost effective.
Hydraulic Fracturing
Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. Hydraulic fracturing has been regulated at the state level through permitting and compliance requirements. State level initiatives in regions with substantial shale resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing. In addition, the U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process.process, including subjecting the process to regulation under the Safe Drinking Water Act. In the first quarter of 2010, the U.S. EPA announced its intention to conduct a comprehensive research study on the potential effects that hydraulic fracturing may have on water quality and public health. The U.S. EPA has issued an interima progress report in late 2012, and expects to issue a draft report for public comment and peer review in 2014, with a final report expected in 2014.2016.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal or state laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells.
Remediation
The AOSP operations use established processes to mine deposits of bitumen from an open-pit mine,mines, extract the bitumen and upgrade it into synthetic crude oils. Tailings are waste products created from the oil sands extraction process which are placed in ponds. The AOSP is required to reclaim its tailingtailings ponds as part of its ongoing reclamation work. The reclamation process uses developing technology and there is an inherent risk that the current process may not be as effective or perform as required in order to meet the approved closure and reclamation plan. The AOSP continues to develop its current reclamation technology and continues to investigate alternate tailings management technologies. In February 2009, the ERCB issued a directive which more clearly defines criteria for managing oil sands tailings. We believe that we are substantially in compliance with the directive at this time. We could incur additional costs if further new regulations are issued or if we fail to comply in a timely manner.
Concentrations of Credit Risk
We are exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. For the year2013, sales to British Petroleum and its affiliates accounted for more than 10 percent of our annual revenues. For 2012, sales to Statoil and to Shell Oil and its affiliates each accounted for more than 10 percent of our annual revenues. For the years 2011, and 2010, transactions with MPC accounted for more than 10 percent of our annual revenues. The majority of those transactions occurred while MPC was a wholly-owned subsidiary. In addition, sales of crude oil and natural gas produced in Libya to the Libyan National Oil Company accounted for more than 10 percent of our 2010 annual revenues.
Trademarks, Patents and Licenses
We currently hold a number of U.S. and foreign patents and have various pending patent applications. Although in the aggregate our trademarks, patents and licenses are important to us, we do not regard any single trademark, patent, license or group of related trademarks, patents or licenses as critical or essential to our business as a whole.
Employees
We had 3,3673,359 active, full-time employees as of December 31, 2012.2013. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.
Executive Officers of the Registrant
The executive officers of Marathon Oil and their ages as of February 1, 2013,2014, are as follows:
|
| | | | |
Clarence P. Cazalot, Jr.Lee M. Tillman | | 6252 | | Chairman, President and Chief Executive Officer |
Janet F. ClarkJohn R. Sult | | 5854 | | Executive Vice President and Chief Financial Officer |
| Sylvia J. Kerrigan | | 4748 | | Executive Vice President, General Counsel and Secretary |
| Annell R. Bay | | 5758 | | Vice President, Global Exploration |
Eileen M. Campbell | | 55 | | Vice President, Public Policy |
Steven P. Guidry | | 54 | | Vice President, Business Development |
| T. Mitch Little | | 4950 | | Vice President, International and Offshore Production Operations |
| Lance W. Robertson | | 40 | | Vice President, Eagle Ford Production Operations |
Michael K. Stewart | | 55 | | Vice President, Finance and Accounting, Controller and Treasurer |
Howard J. Thill | | 53 | | Vice President, Investor Relations and Public Affairs |
Gretchen H. Watkins | | 4441 | | Vice President, North America Production Operations |
| Howard J. Thill | | 54 | | Vice President, Corporate, Government and Investor Relations |
With the exception of Ms. Bay,Mr. Tillman, Mr. Sult and Mr. Robertson, and Ms. Watkins, all of the executive officers have held responsible management or professional positions with Marathon Oil or its subsidiaries for more than the past five years.
Mr. Cazalot was appointed chairman of the board of directors effective July 2011 andTillman was appointed president and chief executive officer effective January 2002.August 2013. Mr. Tillman is also a member of our Board of Directors. Prior to this appointment, Mr. Tillman served as vice president of engineering for ExxonMobil Development Company. Between 2007 and 2010, Mr. Tillman served as North Sea production manager and lead country manager for subsidiaries of ExxonMobil, located in Stavanger, Norway. Mr. Tillman began his career in the oil and gas industry at Exxon Corporation in 1989 as a research engineer and has extensive operations management and leadership experience.
Ms. ClarkMr. Sult was appointed executive vice president and chief financial officer effective January 2007. Ms. Clark joined Marathon Oil in January 2004September 2013. Prior to this appointment, Mr. Sult served as executive vice president and chief financial officer of El Paso Corporation from 2010 to 2012, senior vice president and chief financial officer.officer from 2009 until 2010, and senior vice president, chief accounting officer and controller from 2005 until 2009.
Ms. Kerrigan was appointed executive vice president, general counsel and secretary effective October 2012, and was appointed general counsel and secretary effective November 2009. Prior to these appointments, Ms. Kerrigan was assistant general counsel since January 2003.
Ms. Bay was appointed vice president, global exploration effective July 2011. Ms. Bay joined Marathon Oil in June 2008 as senior vice president, exploration for Marathon Oil Company. Before joining Marathon Oil, Ms. Bay served as vice president, exploration at Shell Exploration and Production Company since 2004.exploration.
Ms. CampbellMr. Little was appointed vice president, public policy effective June 2010. Prior to this appointment, Ms. Campbell was vice president, human resources since October 2000.
Mr. Guidry was appointed vice president, business development effective July 2011. Mr. Guidry previouslyinternational and offshore production operations in September 2013 and served as regional vice president for our Libya operations from November 2008 to June 2011. Prior to the Libya assignment, Mr. Guidry was regional vice president for Marathon Oil North American Production Operations from August 2006 to November 2008.
Mr. Little was appointed vice president, international production operations effective September 2012. Prior to this appointment, Mr. Little was resident manager for our Norway operations and served as general manager, worldwide drilling and completions. Mr. Little joined Marathon Oil in 1986 and has held a number of engineering and management positions of increasing responsibility.
Mr. Robertson was appointed vice president, North America production operations in September 2013 and served as vice president, Eagle Ford production operations effectivesince October 2012. Mr. Robertson joined Marathon Oil in October 2011 as regional vice president, South Texas/Eagle Ford. Between 2004 and 2011, Mr. Robertson held a number of senior engineering and operations management roles of increasing responsibility with Pioneer Natural Resources in the U.S. and Canada.
Mr. StewartThill was appointed vice president, financecorporate, government and accounting, controllerinvestor relations effective January 2014, and treasurer effective December 2011. Mr. Stewart previously served as vice president, accounting and controller from May 2006 to December 2011 and as controller from July 2005 to April 2006.
Mr. Thill was appointed vice president, investor relations and public affairs effective January 2008. Mr. Thill was previously director of investor relations from April 2003 to December 2007.
Ms. Watkins was appointed vice president, North America production operations effective September 2012. Previously, Ms. Watkins served as vice president, international production operations effective July 2011 and regional vice president effective November 2008. Ms. Watkins joined Marathon Oil in July 2008, as general manager Upstream. Before joining Marathon Oil, Ms. Watkins held a number of international leadership positions at BP.
Available Information
General information about Marathon Oil, including the Corporate Governance Principles and Charters for the Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating Committee and Health, Environmental, Safety and Corporate Responsibility Committee, can be found at www.marathonoil.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available at http://ir.marathonoil.com.marathonoil.com/Investor_Center/Corporate_Governance/.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the SEC. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the foregoing pages under "Disclosures Regarding Forward-Looking Statements" and other information included and incorporated by reference into this Annual Report on Form 10-K.
A substantial, extended decline in liquid hydrocarbon or natural gas prices would reduce our operating results and cash flows and could adversely impact our future rate of growth and the carrying value of our assets.
Prices for liquid hydrocarbons and natural gas fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our liquid hydrocarbons and natural gas. Historically, the markets for liquid hydrocarbons and natural gas have been volatile and may continue to be volatile in the future. Many of the factors influencing prices of liquid hydrocarbons and natural gas are beyond our control. These factors include:
worldwide and domestic supplies of and demand for liquid hydrocarbons and natural gas;
the cost of exploring for, developing and producing liquid hydrocarbons and natural gas;
the ability of the members of OPEC to agree to and maintain production controls;
political instability or armed conflict in oil and natural gas producing regions;
changes in weather patterns and climate;
natural disasters such as hurricanes and tornadoes;
the price and availability of alternative and competing forms of energy;
the effect of conservation efforts;
domestic and foreign governmental regulations and taxes; and
general economic conditions worldwide.
The long-term effects of these and other factors on the prices of liquid hydrocarbons and natural gas are uncertain.
Lower liquid hydrocarbon and natural gas prices may cause us to reduce the amount of these commodities that we produce, which may reduce our revenues, operating income and cash flows. Significant reductions in liquid hydrocarbon and natural gas prices could require us to reduce our capital expenditures or impair the carrying value of our assets.
Our offshore operations involve special risks that could negatively impact us.
Offshore exploration and development operations present technological challenges and operating risks because of the marine environment. Activities in deepwater areas may pose incrementally greater risks because of water depths that limit intervention capability and the physical distance to oilfield service infrastructure and service providers. Environmental remediation and other costs resulting from spills or releases may result in substantial liabilities.
Estimates of liquid hydrocarbon, natural gas and synthetic crude oil reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material changes in those conditions or other factors affecting those assumptions could impair the quantity and value of our liquid hydrocarbon, natural gas and synthetic crude oil reserves.
The proved reserve information included in this Annual Report on Form 10-K has been derived from engineering estimates. Estimates of liquid hydrocarbon and natural gas reserves were prepared by our in-house teams of reservoir engineers and geoscience professionals and were reviewed and approved by our Corporate Reserves Group. The synthetic crude oil reserves estimates were prepared by GLJ Petroleum Consultants, a third-party consulting firm experienced in working with oil sands. Reserves were valued based on the unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2013, 2012 2011 and 2010,2011, as well as other conditions in existence at those dates. Any significant future price change will have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in governmental regulation, among other things.
Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of liquid hydrocarbons, natural gas and bitumen that cannot be directly measured. (Bitumen is mined and then upgraded into synthetic crude oil.) Estimates of economically producible reserves and of future net cash flows depend on a number of variable factors and assumptions, including:
location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;
historical production from the area, compared with production from other comparable producing areas;
volumes of bitumen in-place and various factors affecting the recoverability of bitumen and its conversion into synthetic crude oil such as historical upgrader performance;
the assumed effects of regulation by governmental agencies;
assumptions concerning future operating costs, severance and excise taxes, development costs and workover and repair costs; and
industry economic conditions, levels of cash flows from operations and other operating considerations.
As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of proved reserves and future net cash flows based on the same available data. Because of the subjective nature of such reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:
the amount and timing of production;
the revenues and costs associated with that production; and
the amount and timing of future development expenditures.
The discounted future net revenuescash flows from our proved liquid hydrocarbon, natural gas and synthetic crude oil reserves reflected in this Annual Report on Form 10-K should not be considered as the market value of the reserves attributable to our properties. As required by SEC Rule 4-10 of Regulation S-X, the estimated discounted future net revenuescash flows from our proved liquid hydrocarbon, natural gas and synthetic crude oil reserves are based on an unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2013, 2012, 2011 and 2010,2011, and costs applicable at the date of the estimate, while actual future prices and costs may be materially higher or lower.
In addition, the 10 percent discount factor required by the applicable rules of the SEC to be used to calculate discounted future net revenuescash flows for reporting purposes is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the oil and natural gas industry in general.
If we are unsuccessful in acquiring or finding additional reserves, our future liquid hydrocarbon and natural gas production would decline, thereby reducing our cash flows and results of operations and impairing our financial condition.
The rate of production from liquid hydrocarbon and natural gas properties generally declines as reserves are depleted. Except to the extent we acquire interests in additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, optimize production performance or identify additional reservoirs not currently producing or secondary recovery reserves, our proved reserves will decline materially as liquid hydrocarbons and natural gas are produced. Accordingly, to the extent we are not successful in replacing the liquid hydrocarbons and natural gas we produce, our future revenues will decline. Creating and maintaining an inventory of prospects for future production depends on many factors, including:
obtaining rights to explore for, develop and produce liquid hydrocarbons and natural gas in promising areas;
drilling success;
the ability to complete long lead-time, capital-intensive projects timely and on budget;
the ability to find or acquire additional proved reserves at acceptable costs; and
the ability to fund such activity.
Future exploration and drilling results are uncertain and involve substantial costs.
Drilling for liquid hydrocarbons and natural gas involves numerous risks, including the risk that we may not encounter commercially productive liquid hydrocarbon and natural gas reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
fires, explosions, blowouts andor surface cratering;
lack of access to pipelines or other transportation methods; and
shortages or delays in the availability of services or delivery of equipment.
If we are unable to complete capital projects at their expected costs and in a timely manner, or if the market conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:
denial of or delay in receiving requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of components or construction materials;
increased costs or operational delays resulting from shortages of water;
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project’s debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
Any one or more of these factors could have a significant impact on our ongoing capital projects.
We may incur substantial capital expenditures and operating costs as a result of compliance with, andand/or changes in environmental, health, safety and security laws and regulations, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Our businesses are subject to numerous laws, regulations and other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment such as the venting or flaring of natural gas, waste management, pollution prevention, greenhouse gas emissions and the protection of endangered species as well as laws, regulations, and other requirements relating to public and employee safety and health and to facility security. We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws, regulations, and other requirements. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our operating results will be adversely affected. The specific impact of these laws, regulations, and other requirements may vary depending on a number of factors, including the age and location of operating facilities and production processes. We may also be required to make material expenditures to modify operations, install pollution control equipment, perform site cleanupsclean-ups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows. We may become subject to liabilities that we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws, regulations, and other requirements could result in civil penalties or criminal fines and other enforcement actions against us.
We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in countries where we operate, including the U.S., Canada, and Norway, and the European Union. Our operations result in these greenhouse gas emissions. Through 2012,2013, domestic legislative and regulatory efforts included proposed federal legislation and state actions to develop statewide or regional programs, each of which could impose reductions in greenhouse gas emissions. Further, in December 2012 at the Doha Climate Change Conference,
countries agreed to extend the Kyoto Protocol to 2020. However, the U.S. Senate has not ratified the Kyoto Protocol, nor is it clear whether the U.S. Senate plans to ratify this agreement in the future. If the U.S. does ratify the Kyoto Protocol in the future or signsigns a new international agreement, such actions could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls at our facilities, and costs to administer and manage any potential greenhouse gas emissions or carbon trading or tax programs. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for liquid hydrocarbons and natural gas, and create delays in our obtaining air pollution permits for new or modified facilities.
Although there may be adverse financial impact (including compliance costs, potential permitting delays and potential reduced demand for liquid hydrocarbons or natural gas) associated with any legislation, regulation, or other action by the U.S. EPA, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the fact that requirements have only recently been adopted and the present uncertainty regarding any additional measures and how they will be implemented. Private party litigation has also been brought against some emitters of greenhouse gas emissions.
The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.
Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. The U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process. Consideration of new federal regulation and increased state oversight continues to arise. The U.S. EPA announced in the first quarter of 2010 its intention to conductis conducting a comprehensive research study on the potential effects that hydraulic fracturing may have on water quality and public health. The U.S. EPA hashealth, issued an interima progress report in late 2012, and expects to issue a draft report for public comment and peer review in 2014, with a final report expected in 2014.2016. In addition, various state-level initiatives in regions with substantial shale gas resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of liquid hydrocarbons and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal or state laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new
oil and gas wells and increased compliance costs which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells.
Worldwide political and economic developments and changes in law could adversely affect our operations and materially reduce our profitability and cash flows.
Local political and economic factors in global markets could have a material adverse effect on us. A total of 6155 percent of our liquid hydrocarbon and natural gas sales volumes in 20122013 was derived from production outside the U.S. and 5247 percent of our proved liquid hydrocarbon and natural gas reserves as of December 31, 20122013 were located outside the U.S. All of our synthetic crude oil production and proved reserves are located in Canada. We are, therefore, subject to the political, geographic and economic risks and possible terrorist activities attendant to doing business with suppliers located within or outside of the U.S. There are many risks associated with operations in countries and in global markets, such as E.G., Angola, Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq and Libya, and in global markets including:
changes in governmental policies relating to liquid hydrocarbon or natural gas and taxation;
other political, economic or diplomatic developments and international monetary fluctuations;
political and economic instability, war, acts of terrorism and civil disturbances;
the possibility that a government may seize our property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens; and
fluctuating currency values, hard currency shortages and currency controls.
Since January 2010, there have been varying degrees of political instability and public protests, including demonstrations which have been marked by violence, within some countries in the Middle East including Bahrain, Egypt, Iraq, Libya, Syria, Tunisia and Yemen. Some political regimes in these countries are threatened or have changed as a result of such unrest.
If such unrest continues to spread, conflicts could result in civil wars, regional conflicts, and regime changes resulting in governments that are hostile to the U.S. These may have the following results, among others:
volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates and reduced demand for our products;
negative impact on the world crude oil supply if transportation avenues are disrupted;
security concerns leading to the prolonged evacuation of our personnel;
damage to, or the inability to access, production facilities or other operating assets; and
inability of our service and equipment providers to deliver items necessary for us to conduct our operations.
Continued hostilities in the Middle East and the occurrence or threat of future terrorist attacks could adversely affect the economies of the U.S. and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. These risks could lead to increased volatility in prices for liquid hydrocarbons and natural gas. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate.
Actions of governments through tax legislation and other changes in law, executive order and commercial restrictions could reduce our operating profitability, both in the U.S. and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries and will continue to do so in the future. Changes in law could also adversely affect our results, such asincluding new regulations resulting in higher costs to transport our production by pipeline, rail car, truck or vessel or the adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information or that could cause us to violate the non-disclosure laws of other countries.
Our commodity price risk management and trading activities may prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty risk.
To the extent that we engage in price risk management activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Our business could be negatively impacted by cyber-attacks targeting our computer and telecommunications systems and infrastructure.
ComputersOur business, like other companies in the oil and telecommunication devicesgas industry, has become increasingly dependent on digital technologies. Such technologies are integrated into our business operations and are used as a part of our liquid hydrocarbon and natural gas production and distribution systems in the U.S. and abroad, including those systems which are utilizedused to transport our production to market. A cyber-attack impacting these computersUse of the internet and telecommunication devices,other public networks for communications, services, and storage, including “cloud” computing, exposes users (including our business) to cybersecurity risks. While our information systems and related infrastructure experienced attempted and actual minor breaches of our cybersecurity in the past, we have not suffered any losses or the networks and infrastructurebreaches which had a material effect on which they rely, could damage critical production, distribution and/our business, operations or storage assets, delay or prevent delivery to markets and make it difficult or impossible to accurately account for production and settle transactions. Although we utilize various procedures and controls to mitigate our exposurereputation relating to such risk,attacks; however, there is no assurance that we will not suffer such losses or breaches in the future. As cyber-attacks are evolvingcontinue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and unpredictable. These attacks could include, but are not limited to, malicious software, attempts to gain unauthorized access to data, other electronicremediate any information systems and related infrastructure security breaches that could lead to disruptions in critical systems, the unauthorized release of protected information and the corruption or loss of data. The occurrence of such an attack could lead to financial losses and have a negative impact on our results of operations.vulnerabilities.
Our operations may be adversely affected by pipeline, rail and midstreamother transportation capacity constraints.
The marketability of our production depends in part on the availability, proximity, and capacity of pipeline facilities, railcarsrail cars, trucks and tanker transportation.vessels. If any pipelines, railcarsrail cars, trucks or tankersvessels become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport our liquid hydrocarbons and natural gas, which could increase the costs and/or reduce the revenues we might obtain from the sale of our production.
If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.
We typically seek the acquisition of crude oil and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we believe is diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor may they permit us to become sufficiently familiar with the properties in
order to fully assess possible deficiencies and potential problems. Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements. Moreover, there are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves (as previously discussed), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.
We operate in a highly competitive industry, and many of our competitors are larger and have available resources in excess of our own.
The oil and gas industry is highly competitive, and many competitors, including major integrated and independent oil and gas companies, as well as national oil companies, are larger and have substantially greater resources at their disposal than we do. We compete with these companies for the acquisition of oil and natural gas leases and other properties. We also compete with these companies for equipment and personnel, including petroleum engineers, geologists, geophysicists and other specialists, required to develop and operate those properties and in the marketing of crude oil and natural gas to end-users. Such competition can significantly increase costs and affect the availability of resources, which could provide our larger competitors a competitive advantage when acquiring equipment, leases and other properties. They may also be able to use their greater resources to attract and retain experienced personnel.
Many of our major projects and operations are conducted with partners, which may decrease our ability to manage risk.
We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production, oil sands mining or pipeline transportation, with partners in order to share risks associated with those operations. However, these arrangements also may decrease our ability to manage risks and costs, particularly where we are not the operator. We could have limited influence over and control of the behaviors and performance of these operations. In addition, misconduct, fraud, noncompliance with applicable laws and regulations or improper activities by or on behalf of one or more of our partners could have a significant negative impact on our business and reputation.
Our operations are subject to business interruptions and casualty losses. We do not insure against all potential losses and therefore we could be seriously harmed by unexpected liabilities and increased costs.
Our North America E&P and International E&P operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, spills, hurricanes and other adverse weather, tsunamis, earthquakes, volcanic eruptions or nuclear or other disasters, labor disputes and accidents. Our OSM operations are subject to business interruptions due to breakdown or failure of equipment or processes and unplanned events such as fires, earthquakes, explosions or other interruptions. These same risks can be applied to the third-parties
which transport crude oilour products from our facilities. A prolonged disruption in the ability of any pipelinepipelines, rail cars, trucks, or vessels to transport crude oilour production could contribute to a business interruption or increase costs.
Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. Various hazards have adversely affected us in the past, and damages resulting from a catastrophic occurrence in the future involving us or any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially large claims or in our being assessed potentially substantial fines by governmental authorities. We maintain insurance against many, but not all, potential losses or liabilities arising from operating hazards in amounts that we believe to be prudent. Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we have maintained insurance coverage for physical damage and resulting business interruption to our major onshore and offshore facilities, with significant self-insured retentions. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, due to hurricane activity in recent years, the availability of insurance coverage for our offshore facilities for windstorms in the Gulf of Mexico region has been reduced or, in many instances, it is prohibitively expensive. As a result, our exposure to losses from future windstorm activity in the Gulf of Mexico region has increased.
Litigation by private plaintiffs or government officials could adversely affect our performance.
We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, privacy laws, antitrust laws or any other laws or regulations that apply to our operations. In some cases the plaintiff or plaintiffs seek alleged damages involving large
classes of potential litigants, and may allege damages relating to extended periods of time or other alleged facts and circumstances. If we are not able to successfully defend such claims, they may result in substantial liability. We do not have insurance covering all of these potential liabilities. In addition to substantial liability, litigation may also seek injunctive relief which could have an adverse effect on our future operations.
In connection with our separation from MPC, MPC agreed to indemnify us for certain liabilities. However, there can be no assurance that the indemnity will be sufficient to protect us against the full amount of such liabilities, or that MPC’s ability to satisfy its indemnification obligations will not be impaired in the future.
Pursuant to the Separation and Distribution Agreement and the tax sharing agreementTax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities that MPC agreed to retain or assume, and there can be no assurance that the indemnification from MPC will be sufficient to protect us against the full amount of such liabilities, or that MPC will be able to fully satisfy its indemnification obligations. In addition, even if we ultimately succeed in recovering from MPC any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.
The spin-off could result in substantial tax liability.
We obtained a private letter ruling from the IRS substantially to the effect that the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). If the factual assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in any material respect, then we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whether a distribution such as the spin-off satisfies certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Rather, the private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling. In connection with the spin-off, we also obtained an opinion of outside counsel, substantially to the effect that, the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the Code. The opinion relied on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by MPC and us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion is not binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail.
If, notwithstanding receipt of the private letter ruling and opinion of counsel, the spin-off were determined not to qualify under Section 355 of the Code, each U.S. holder of our common stock who received shares of MPC common stock in the spin-off would generally be treated as receiving a taxable distribution of property in an amount equal to the fair market value of the shares of MPC common stock received. That distribution would be taxable to each such stockholder as a dividend to the extent of our
accumulated earnings and profits as of the effective date of the spin-off. For each such stockholder, any amount that exceeded those earnings and profits would be treated first as a non-taxable return of capital to the extent of such stockholder’s tax basis in its shares of our common stock with any remaining amount being taxed as a capital gain. We would be subject to tax as if we had sold all the outstanding shares of MPC common stock in a taxable sale for their fair market value and would recognize taxable gain in an amount equal to the excess of the fair market value of such shares over our tax basis in such shares.
Under the terms of the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC is generally responsible for any taxes imposed on MPC or us and our subsidiaries in the event that the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment as a result of actions taken, or breaches of representations and warranties made in the Tax Sharing Agreement, by MPC or any of its affiliates. However, if the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment because of actions or failures to act by us or any of our affiliates, we would be responsible for all such taxes.
We may issue preferred stock whose terms could dilute the voting power or reduce the value of Marathon Oil common stock.
Our restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such preferences, powers and relative, participating, optional and other rights, including preferences over Marathon Oil common stock respecting dividends and distributions, as our Board of Directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of Marathon Oil common stock. For example, we could grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of the common stock.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The location and general character of our principal liquid hydrocarbon and natural gas properties, oil sands mining properties and facilities, and other important physical properties have been described by segment under Item 1. Business.
Net liquid hydrocarbon, natural gas, and synthetic crude oil sales volumes are set forth in Item 8. Financial Statements and Supplementary Data – Supplemental Statistics. Estimated net proved liquid hydrocarbon, natural gas and synthetic crude oil reserves are set forth in Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves. The basis for estimating these reserves is discussed in Item 1. Business – Reserves.
Item 3. Legal Proceedings
We are defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.
Litigation
In March 2011, Noble Drilling (U.S.) LLC ("Noble"(“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble is seekingalleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an unspecified amountoffshore daywork drilling contract. The parties settled this litigation in the fourth quarter of damages. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial2013, and the settlement did not have a material adverse effect on us, remains uncertain. We do not believe an estimateour consolidated results of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.operations, financial position or cash flows.
Environmental Proceedings
The following is a summary of proceedings involving us that were pending or contemplated as of December 31, 2012,2013 under federal and state environmental laws. Except as described herein, it is not possible to predict accurately the ultimate outcome of these matters; however, management’s belief set forth in the first paragraph under Legal Proceedings above takes such matters into account.
We have been working with the North Dakota Department of Health to resolve voluntary disclosures we made in 2009 relating to potential Clean Air Act violations relating to our operations on state lands in the Bakken shale. The amount of the potential fine is estimated to be $185,000.
As of December 31, 2012,2013, we have sites across the country where remediation is being sought under environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation. Based on currently available information, which is in many cases preliminary and incomplete, we believe that total clean-up and remediation costs in connectionconnected with these sites will be less than $28$24 million, the majority of which have already been incurred.
The projected liability for clean-up and remediation provided in the preceding paragraph is a forward-looking statement. To the extent that our assumptions prove to be inaccurate, future expenditures may differ materially from those stated in the forward-looking statement.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The principal market on which Marathon Oil common stock is traded is the New York Stock Exchange ("NYSE"). As of January 31, 2013,2014, there were 43,35441,356 registered holders of Marathon Oil common stock.
The following table reflects high and low sales prices for Marathon Oil common stock and the related dividend per share by quarter for the past two years:
| | | | 2012 | | 2011* | 2013 | | 2012 |
| (Dollars per share) | High Price | | Low Price | | Dividends | | High Price | | Low Price | | Dividends | High Price | | Low Price | | Dividends | | High Price | | Low Price | | Dividends |
| Quarter 1 | $35.06 | | $30.47 | | $0.17 | | $53.31 | | $37.34 | | $0.25 | $35.71 | | $31.59 | | $0.17 | | $35.06 | | $30.47 | | $0.17 |
| Quarter 2 | $32.23 | | $23.32 | | $0.17 | | $54.17 | | $49.06 | | $0.25 | $36.38 | | $29.85 | | $0.17 | | $32.23 | | $23.32 | | $0.17 |
| Quarter 3 | $31.09 | | $24.09 | | $0.17 | | $34.07 | | $21.58 | | $0.15 | $37.83 | | $32.61 | | $0.19 | | $31.09 | | $24.09 | | $0.17 |
| Quarter 4 | $31.93 | | $29.30 | | $0.17 | | $29.34 | | $20.27 | | $0.15 | $37.93 | | $34.06 | | $0.19 | | $31.93 | | $29.30 | | $0.17 |
| Full Year | $35.06 | | $23.32 | | $0.68 | | $54.17 | | $20.27 | | $0.80 | $37.93 | | $29.85 | | $0.72 | | $35.06 | | $23.32 | | $0.68 |
| |
* | On June 30, 2011, Marathon completed the spin-off of the downstream business. The June 30, 2011 closing price of our common stock on the NYSE was $52.68. On July 1, 2011, the opening price of our common stock on the NYSE was $32.95. Our quarterly dividend was also adjusted to $0.15 per share. |
Dividends – Our Board of Directors intends to declare and pay dividends on Marathon Oil common stock based on the financial condition and results of operations of Marathon Oil, Corporation, although it has no obligation under Delaware law or the Restated Certificate of Incorporation to do so. In determining the dividend policy with respect to Marathon Oil common stock, the Board will rely on the consolidated financial statements of Marathon Oil. Dividends on Marathon Oil common stock are limited to our legally available funds.
Issuer Purchases of Equity Securities – The following table provides information about purchases by Marathon Oil and its affiliated purchaser, during the quarter ended December 31, 20122013, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:
|
| | | | | | | | | | | | |
| | Column (a) | | | Column (b) | | Column (c) | | Column (d) |
| Period | Total Number of Shares Purchased(a) | | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(c) | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(c) |
| 10/01/12 – 10/31/12 | 8,886 |
| | | $29.92 | | — |
| | $ | 1,780,609,536 |
|
| 11/01/12 – 11/30/12 | 5,006 |
| | | $30.22 | | — |
| | $ | 1,780,609,536 |
|
| 12/01/12 – 12/31/12 | 38,614 |
| (b) | | $30.50 | | — |
| | $ | 1,780,609,536 |
|
| Total | 52,506 |
| | | $30.38 | | — |
| | |
|
| | | | | | | | | | | | |
| | Column (a) | | | Column (b) | | Column (c) | | Column (d) |
| Period | Total Number of Shares Purchased(a) | | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(c) | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(c) |
| 10/01/13 – 10/31/13 | 9,404 |
| | | $35.07 | | — |
| | $ | 1,280,820,541 |
|
| 11/01/13 – 11/30/13 | 5,381 |
| | | $35.18 | | — |
| | $ | 1,280,820,541 |
|
| 12/01/13 – 12/31/13 | 33,682 |
| (b) | | $35.84 | | — |
| | $ | 2,500,000,000 |
|
| Total | 48,467 |
| | | $35.62 | | — |
| | |
| |
(a) | 22,20021,898 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
|
| |
(b) | 30,306In December 2013, 26,569 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the "Dividend Reinvestment Plan") by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon Oil.
|
| |
(c) | We announced aIn December 2013, our Board of Directors increased the authorization for repurchases of our common stock by $1.2 billion, bringing the remaining share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5authorization to $2.5 billion. As of December 31, 2012, 782013, we had repurchased 92 million common shares had been acquired at a cost of $3,222$3,722 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 6614 million shares had beenwere acquired at a cost of $500 million during the third quarter of 2013, 12 million shares at a cost of $300 million in the third quarter of 2011 and 66 million shares for $2,922 million prior to the spin-off of theour downstream business.
|
Item 6. Selected Financial Data
| | | (Dollars in millions, except per share data) | 2012(a) | | 2011(a)(b) | | 2010(a)(b) | | 2009(b)(c) | | 2008(b)(c)(d) | |
| (In millions, except per share data) | | 2013(a)(b) | | 2012(a)(b) | | 2011(a)(b) | | 2010(a)(b) | | 2009(b) |
Statement of Income Data(b) | | | | | | | | | | | | | | | | | | |
| Revenues | $ | 15,688 |
| | $ | 14,663 |
| | $ | 11,690 |
| | $ | 8,524 |
| | $ | 13,162 |
| $ | 14,501 |
| | $ | 15,692 |
| | $ | 14,669 |
| | $ | 11,690 |
| | $ | 8,524 |
|
| Income from continuing operations | 1,582 |
| | 1,707 |
| | 1,882 |
| | 716 |
| | 2,192 |
| 1,593 |
| | 1,613 |
| | 1,718 |
| | 1,448 |
| | 756 |
|
| Net income | 1,582 |
| | 2,946 |
| | 2,568 |
| | 1,463 |
| | 3,528 |
| 1,753 |
| | 1,582 |
| | 2,946 |
| | 2,568 |
| | 1,463 |
|
| Per Share Data | | | | | | | | | | | | | | | | | | |
| Basic: | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | $2.24 | | $2.40 | | $2.65 | | $1.01 | | $3.09 | $2.26 | | $2.28 | | $2.42 | | $2.04 | | $1.06 |
| Net income | $2.24 | | $4.15 | | $3.62 | | $2.06 | | $4.97 | $2.49 | | $2.24 | | $4.15 | | $3.62 | | $2.06 |
| Diluted: | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | $2.23 | | $2.39 | | $2.65 | | $1.01 | | $3.08 | $2.24 | | $2.27 | | $2.41 | | $2.03 | | $1.06 |
| Net income | $2.23 | | $4.13 | | $3.61 | | $2.06 | | $4.95 | $2.47 | | $2.23 | | $4.13 | | $3.61 | | $2.06 |
Statement of Cash Flows Data(b) | | | | | | | | | | | | | | | | | | |
| Additions to property, plant and equipment related to continuing operations | $ | 4,940 |
| | $ | 3,295 |
| | $ | 3,536 |
| | $ | 3,349 |
| | $ | 4,202 |
| $ | 4,766 |
| | $ | 4,593 |
| | $ | 2,986 |
| | $ | 3,269 |
| | $ | 3,056 |
|
| Dividends paid | 480 |
| | 567 |
| | 704 |
| | 679 |
| | 681 |
| 508 |
| | 480 |
| | 567 |
| | 704 |
| | 679 |
|
| Dividends per share | $0.68 | | $0.80 | | $0.99 | | $0.96 | | $0.96 | $0.72 | | $0.68 | | $0.80 | | $0.99 | | $0.96 |
| Balance Sheet Data as of December 31: | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 35,306 |
| | $ | 31,371 |
| | $ | 50,014 |
| | $ | 47,052 |
| | $ | 42,686 |
| $ | 35,620 |
| | $ | 35,306 |
| | $ | 31,371 |
| | $ | 50,014 |
| | $ | 47,052 |
|
| Total long-term debt, including capitalized leases | 6,512 |
| | 4,674 |
| | 7,601 |
| | 8,436 |
| | 7,087 |
| 6,394 |
| | 6,512 |
| | 4,674 |
| | 7,601 |
| | 8,436 |
|
| |
(a) | Includes impairments primarily related to E&P segment assets, of $96 million, $371 million, $310 million and $447 million in 2013, 2012, 2011 and 2010 respectively (see Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements). |
| |
(b) | OurWe entered into agreements to sell our Angola assets in 2013 (see Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements); our downstream business was spun-off on June 30, 2011. Previous periods have been recast to reflect the business in discontinued operations2011 (see Item 8. Financial Statements and Supplementary Data – Note 3 to the consolidated financial statements). |
| |
(c)
| Our businesses in; and our Ireland and previous Gabon businesses were sold in 2009. PreviousThe applicable periods have been recast to reflect these businesses in discontinued operations. |
| |
(d)
| Includes a $1,412 million impairment of goodwill related to the OSM reporting unit. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
We are an international energy company with operations inEach of our segments is organized and managed based upon both geographic location and the U.S., Canada, Africa,nature of the Middle Eastproducts and Europe. Our operations are organized into three reportable segments:services it offers:
North America E&P which– explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.in North America;
OSM whichInternational E&P – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
Oil Sands Mining – 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.
IG which produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
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 this Annual Report on Form 10-K.
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under Item 1. Business, Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data found in this Annual Report on Form 10-K.
Spin-off Downstream Business
On June 30, 2011, the spin-off of Marathon’s downstream business was completed, creating two independent energy companies: Marathon Oil and MPC. Marathon stockholders at the close of business on the record date of June 27, 2011 received one share of MPC common stock for every two shares of Marathon common stock held. A private letter tax ruling received in June 2011 from the IRS affirmed the tax-free nature of the spin-off. Activities related to the downstream business have been treated as discontinued operations in 2011 and 2010for all periods prior to the spin-off (see Item 8. Financial Statements and Supplementary Data – Note 3 to the consolidated financial statements for additional information).
Overview – Market Conditions
Exploration and Production
Prevailing prices for the various gradesqualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows. The following table lists benchmark crude oil and natural gas price annual averages relative to our North America E&P and International E&P segments for the past three years.
| | | Benchmark | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
WTI crude oil (Dollars per bbl) | $94.15 | | $95.11 | | $79.61 | $98.05 | | $94.15 | | $95.11 |
Brent (Europe) crude oil (Dollars per bbl) | $111.65 | | $111.26 | | $79.51 | $108.64 | | $111.65 | | $111.26 |
Henry Hub natural gas (Dollars per mmbtu)(a) | $2.79 | | $4.04 | | $4.39 | $3.65 | | $2.79 | | $4.04 |
| |
(a) | Settlement date average. |
North America E&P
Liquid hydrocarbonhydrocarbons – Prices of crude oil have been volatile in recent years, but less so when comparing annual averages for 2012 and 2011. In 2011, crude prices increased over 2010 levels, with increases in Brent averages outstripping those in WTI.
The quality, location and composition of our liquid hydrocarbon production mix willcan cause our U.S. liquid hydrocarbonNorth America E&P price realizations to differ from the WTI benchmark.
Quality – Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and has historically produced higher value products; therefore, light sweet crude is considered of higher quality and has historically sold at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude oil and condensate production that is light sweet crude has been increasing as onshore production from the Eagle Ford and Bakken increases and production from the Gulf of Mexico declines. In 2012, 2011 and 2010,2013, the percentage of our U.S. crude oil and condensate production that was soursweet averaged 3776 percent 58compared to 63 percent and 68 percent. Sour crude contains more sulfur42 percent in 2012 and tends to be heavier than light sweet crude oil so that refining it is more costly and produces lower value products; therefore, sour crude is considered of lower quality and typically sells at a discount to WTI. The percentage of our U.S. crude and condensate production that is sour has been decreasing as onshore production from the Eagle Ford and Bakken shale plays increases and production from the Gulf of Mexico declines.2011.
Location – In recent years, crude oil sold along the U.S. Gulf Coast, such as that from the Eagle Ford, has been priced based on the Louisiana Light Sweet ("LLS") benchmark which has historically priced at a premium to WTI because the Louisiana Light Sweet benchmarkand has been trackinghistorically tracked closely to Brent, while production from inland areas farther from large refineries has been at a discount to WTI. NGLs were 10 percent, 7 percent and 6 percent of our U.S. liquid hydrocarbon sales in 2012, 2011 and 2010. In 2012, our sales of NGLs increased due to our development of U.S. unconventional liquids-rich plays.priced lower. The average annual WTI
Our internationaldiscount to Brent was narrower in 2013 than in 2012 and 2011. As a result of the significant increase in U.S. production of light sweet crude oil, production is relatively sweet and is generally sold in relation to the Brent crude benchmark. The differentialhistorical relationship between WTI, Brent and Brent average prices widened significantlyLLS pricing may not be indicative of future periods.
Composition – The proportion of our liquid hydrocarbon sales volumes that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 15 percent of our North America E&P liquid hydrocarbon sales volumes in 20112013 compared to 10 percent in 2012 and remained7 percent in 2012 in comparison to almost no differential in 2010.2011.
Natural gas –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 in 201231 percent higher for 2013 than in recent years. A decline in average settlement date Henry Hub natural gas prices began in September 2011 and continued into 2012. Although prices stabilized in late for 2012 they have not increased appreciably..
International E&P
Liquid hydrocarbons – Our otherInternational E&P crude oil production is relatively sweet and has historically sold in relation to the Brent crude benchmark, which on average was 3 percent lower for 2013 than 2012.
Natural gas –Our major International E&P natural gas-producing regions are Europe and E.G. and Europe.Natural gas prices in Europe have been considerably higher than the U.S. in recent years. In the case of E.G,.E.G., our natural gas sales are subject to term contracts, making realizationsrealized prices in these areas less volatile. BecauseThe natural gas sales from E.G. are at fixed prices,prices; therefore, our worldwide reported average International E&P natural gas realizationsrealized prices may not fully track market price movements. Natural gas prices in Europe have been significantly higher than in the U.S.
Oil Sands Mining
The OSMOil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix will trackhas historically tracked movements in WTI and one-third will trackhas historically tracked movements in the Canadian heavy sour crude oil marker, primarily WCS. In 2012, theThe WCS discount fromto WTI had increased, putting downward pressurehas been increasing on average in each year presented below. Despite a wider WCS discount in 2013, our average realizations.Oil Sands Mining price realizations increased due to a greater proportion of higher value synthetic crude oil sales volumes compared to 2012.
The operating cost structure of the OSMOil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO")AECO natural gas sales index and crude oil prices, respectively.
The table below shows average benchmark prices that impact both our revenues and variable costs.costs:
| | | Benchmark | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
WTI crude oil (Dollars per bbl) | $94.15 | | $95.11 | | $79.61 | $98.05 | | $94.15 | | $95.11 |
WCS (Dollars per bbl)(a) | $73.18 | | $77.97 | | $65.31 | $72.77 | | $73.18 | | $77.97 |
AECO natural gas sales index (Dollars per mmbtu)(b) | $2.39 | | $3.68 | | $3.89 | $3.08 | | $2.39 | | $3.68 |
| |
(a) | Monthly pricing based upon average WTI adjusted for differentials unique to western Canada. |
| |
(b) | Monthly average day ahead index. |
Integrated Gas
Our IG operations include production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.
World LNG trade in 2012 has been estimated to be 240 mmt. Long-term, LNG continues to be in demand as markets seek the benefits of clean burning natural gas. Market prices for LNG are not reported or posted. In general, LNG delivered to the U.S. is tied to Henry Hub prices and will track with changes in U.S. natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices. We have a 60 percent ownership in an LNG production facility in E.G., which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices. Gross sales from the plant were 3.8 mmt, 4.1 mmt and 3.7 mmt in 2012, 2011 and 2010.
We own a 45 percent interest in a methanol plant located in E.G. through our investment in AMPCO. Gross sales of methanol from the plant totaled 1.1 mmt, 1.0 mmt and 0.9 mmt in 2012, 2011 and 2010. Methanol demand has a direct impact on AMPCO’s earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. World demand for methanol in 2012 has been estimated to be 49 mmt. Our plant capacity of 1.1 mmt is about 2 percent of world demand.
Key Operating and Financial Activities
Significant operating and financial2013 activities during related to our strategic imperatives:
•2012 include:Production growth
Net proved reserve additions for the E&P•Total company net sales volume growth of 11 percent (excluding Alaska and OSM segments combined of 389 mmboe, for a 226 percent reserve replacement ratioLibya)
Increased proved liquid hydrocarbon and synthetic crude oil reserves by 316 mmbbls, for a reserve replacement of 268 percent for these commodities
Recorded more than 95 percent average operational availability for operated E&P assets
IncreasedNorth America E&P net sales volumes excluding Libya, by 8 percent
Eagle Ford shale average net sales volumes of 65 mboed for December 2012, a fourfold increase over December 2011
Bakken shale average net sales volumes of 29averaged 201 mboed, a 7121 percent increase over last year
Resumed sales from Libya and reached pre-conflict production levels
International liquid hydrocarbonEagle Ford averaged net sales volumes of 81 mboed, a 136 percent increase
Bakken averaged net sales volumes of 39 mboed, a 34 percent increase
Oklahoma resource basins averaged net sales volumes of 14 mboed, a 68 percent increase
Proved reserve replacement of 194 percent, excluding dispositions
Total net proved reserves increased 8 percent to approximately 2.2 billion boe
Quality resource capture through focused exploration
Mirawa-1 discovery on operated Harir block in the Kurdistan Region of Iraq
Diaman-1B discovery on non-operated Diaba License in Gabon
Atrush block received approval from the KRG for which average realizations have exceeded WTI, were 62 percentthe first phase of oil development in the Kurdistan Region of Iraq
Shenandoah and Gunflint (both non-operated) prospects had successful appraisal wells in the Gulf of Mexico
Rigorous portfolio management
Exceeded three-year $1.5 billion to $3 billion divestiture target
Agreements to sell working interests in Angola Blocks 31 and 32 with an aggregate transaction value of $2.1 billion, before closing adjustments
Sold our interests in Alaska, the DJ Basin and the Neptune gas plant
Acquired 4,800 additional net E&P liquid hydrocarbon sales
Closed $1 billion of acquisitionsacres in the core of the Eagle Ford shale
Assumed operatorshipGrew SCOOP acreage position over 20 percent
Commenced efforts to market our U.K. and Norway assets
Competitive shareholder value
Increased dividend by 12 percent to 19 cents per share
Repurchased 14 million common shares for $500 million
Announced $500 million share repurchase to begin upon closing of the Vilje field located offshore NorwayAngola Block 31 sale
Signed agreements for new exploration positionsAuthorized $1.2 billion increase in E.G., Gabon, Kenya and Ethiopiashare repurchase program to $2.5 billion remaining
Issued $1 billion of 3-year senior notes at 0.9 percent interest and $1 billion of 10-year senior notes at 2.8 percent interest
Some significant 2013 activitiesSignificant 2014 activity through February 22, 2013 include:
Closed sale of our Alaska assets in January 201328, 2014 includes:
Closed sale of our interest in the Neptune gas plant in February 2013Angola Block 31
Consolidated Results of Operations: 20122013 compared to 20112012
Consolidated income before income taxes was 38 percent higher in 2012 than consolidated income from continuing operations before income taxes were in 2011, largely2013 was 20 percent lower than 2012 primarily due to higherlower liquid hydrocarbon net sales volumes in ourthe International E&P segment partially offset by lower earnings from our OSM and IG segments. The 7 percent decrease in income from continuing operations included lower earnings in the U.K.higher DD&A and E.G.,exploration expenses, partially offset by higher earningsliquid hydrocarbon net sales volumes in Libya. Also, in 2011 we were not in an excess foreign tax credit position for the entire year as we were in 2012.North America E&P segment. The effective income tax rate for continuing operations was 7468 percent in 20122013 compared to 6174 percent in 2011.2012, with the decrease primarily related to lower income from continuing operations in Libya and Norway, which are higher tax jurisdictions.
RevenuesSales and other operating revenues, including related partyare summarized by segment in the following table:
|
| | | | | | |
| (In millions) | 2013 | 2012 |
| Sales and other operating revenues, including related party | | |
| North America E&P | $ | 5,068 |
| $ | 3,944 |
|
| International E&P | 5,827 |
| 7,445 |
|
| Oil Sands Mining | 1,576 |
| 1,521 |
|
| Segment sales and other operating revenues, including related party | 12,471 |
| 12,910 |
|
| Unrealized gain (loss) on crude oil derivative instruments | (52 | ) | 53 |
|
| Sales and other operating revenues, including related party | $ | 12,419 |
| $ | 12,963 |
|
|
| | | | | | | |
| (In millions) | 2012 | | 2011 |
| E&P | $ | 14,084 |
| | $ | 13,029 |
|
| OSM | 1,552 |
| | 1,588 |
|
| IG | — |
| | 93 |
|
| Segment revenues | 15,636 |
| | 14,710 |
|
| Elimination of intersegment revenues | — |
| | (47 | ) |
| Unrealized gain on crude oil derivative instruments | 52 |
| | — |
|
| Total revenues | $ | 15,688 |
| | $ | 14,663 |
|
North America E&P segmentsales and other operating revenues increased $1,055$1,124 million from 20112012 to 2012,2013 primarily due to higher average liquid hydrocarbon net sales volumes. E&P segment revenues included avolumes resulting from ongoing development programs in the Eagle Ford, Bakken and Oklahoma resource basins, partially offset by lower natural gas net realized gain on crude oil derivative instrumentssales volumes, primarily the result of $15 million in 2012 while the impact of derivatives was not significant in 2011. See Item 8. Financial Statements and Supplementary Data – Note 16 to the consolidated financial statement for more information about our crude oil derivative instruments.
Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product
types and delivery points. Volumes associated with supply optimization have been decreasing in 2012 due to market dynamics and related commodity prices were also slightly lower in 2012.
Revenues from the sale of our U.S. production are higherAlaska assets in 2012 than in 2011 as a result of increased liquid hydrocarbon sales volumes from our U.S. shale plays. Lower liquid hydrocarbon and natural gas realizations partially offset the volume impact. early 2013.
The following table gives details of net sales volumes and average price realizations of our U.S. operations.North America E&P segment:
|
| | | | | |
| | 2012 | | 2011 |
| U.S. Operating Statistics | | | |
Net liquid hydrocarbon sales (mbbld) | 107 |
| | 75 |
|
Liquid hydrocarbon average realizations (per bbl)(a)(b) | $85.80 | | $92.55 |
Net crude oil and condensate sales (mbbld) | 96 |
| | 70 |
|
Crude oil and condensate (per bbl) | $91.29 | | $94.80 |
Net natural gas liquids sales (mbbld) | 11 |
| | 5 |
|
Natural gas liquids (per bbl) | $39.57 | | $58.53 |
Net natural gas sales (mmcfd) | 358 |
| | 326 |
|
Natural gas average realizations (per mcf)(a) | $3.91 | | $4.95 |
|
| | | | |
| | 2013 | 2012 |
| North America E&P Operating Statistics | | |
Net liquid hydrocarbon sales volumes (mbbld) | 149 |
| 107 |
|
Liquid hydrocarbon average price realizations (per bbl) (a) (b) | $85.20 | $85.80 |
Net crude oil and condensate sales volumes (mbbld) | 126 |
| 96 |
|
Crude oil and condensate average price realizations (per bbl) (a) | $94.19 | $91.30 |
Net natural gas liquids sales volumes (mbbld) | 23 |
| 11 |
|
Natural gas liquids average price realizations (per bbl) (a) | $35.12 | $39.57 |
Net natural gas sales volumes (mmcfd) | 312 |
| 358 |
|
Natural gas average price realizations (per mcf) (a) | $3.84 | $3.92 |
| |
(a) | Excludes gains orand losses on derivative instruments. |
| |
(b) | Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon price realizations $0.39 per bbl by $(0.27)for 2012.2013 and $0.40 for 2012. |
Revenues International E&P sales and other operating revenues decreased $1,618 million in 2013 from our international operations are higher in 2012 than in 2011the prior year. This decrease was primarily as a result of the previously discussed resumption ofdue to lower liquid hydrocarbon net sales from Libya. Higher averagevolumes in Libya and Norway and lower liquid hydrocarbon realizations during 2012, again primarily related to Libyan crude oil, also contributed to the revenue increase. average price realizations.
The following table gives details of net sales volumes and average price realizations of our international operations.International E&P segment:
|
| | | | | |
| | 2012 | | 2011 |
| International Operating Statistics | | | |
Net liquid hydrocarbon sales (mbbld)(a) | | | |
| Europe | 97 |
| | 101 |
|
| Africa | 78 |
| | 43 |
|
| Total International | 175 |
| | 144 |
|
Liquid hydrocarbon average realizations (per bbl)(b) | | | |
| Europe | $115.16 | | $115.55 |
| Africa | $98.52 | | $73.21 |
| Total International | $107.78 | | $102.96 |
Net natural gas sales (mmcfd) | | | |
Europe(c) | 101 |
| | 97 |
|
| Africa | 443 |
| | 443 |
|
| Total International | 544 |
| | 540 |
|
Natural gas average realizations (per mcf)(b) | | | |
| Europe | $10.47 | | $9.84 |
Africa(d) | $0.43 | | $0.24 |
| Total International | $2.29 | | $1.97 |
|
| | | | |
| | 2013 | 2012 |
| International E&P Operating Statistics | | |
Net liquid hydrocarbon sales volumes (mbbld)(a) | | |
| Europe | 86 |
| 97 |
|
| Africa | 58 |
| 78 |
|
| Total International E&P | 144 |
| 175 |
|
Liquid hydrocarbon average price realizations (per bbl) | | |
| Europe | $112.60 | $115.16 |
| Africa | $86.29 | $98.52 |
| Total International E&P | $102.10 | $107.78 |
Net natural gas sales volumes (mmcfd) | | |
Europe(b) | 83 |
| 101 |
|
| Africa | 464 |
| 443 |
|
| Total International E&P | 547 |
| 544 |
|
Natural gas average price realizations (per mcf) | | |
| Europe | $12.08 | $10.47 |
Africa(c) | $0.49 | $0.43 |
| Total International E&P | $2.25 | $2.29 |
| |
(a) | The amounts correspondCorresponds with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons. |
| |
(b) | Excludes gains or losses on derivative instruments. |
| |
(c)
| Includes natural gas acquired for injection and subsequent resale of 157 mmcfd and 1615 mmcfd infor 20122013 and 20112012. |
(d) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC’s income in our E&P segment and we include our share of AMPCO’s and EGHoldings’ income in our IG segment.
OSM segment revenues decreased $36 million from 2011 to 2012. The decrease was primarily the result of lower average realizations which were partially offset by the increase in sales volumes.
|
| | | | | |
| | 2012 | | 2011 |
| OSM Operating Statistics | | | |
Net synthetic crude oil sales (mbbld)(a) | 47 |
| | 43 |
|
Synthetic crude oil average realizations (per bbl) | $81.72 | | $91.65 |
| |
(a)(c)
| Includes bloodstocks.Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO, and EGHoldings, equity method investees. We include our share of Alba Plant LLC's, AMPCO's and EGHoldings' income in our International E&P segment. |
IG segmentOil Sands Mining sales and other operating revenues increased $55 million in 2013 from 2012. This increase was primarily due to a higher proportion of net sales volumes related to a premium grade synthetic crude oil and the associated average price realizations when compared to 2012. The increase was partially offset by lower feedstock sales in 2013.
The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment:
|
| | | | |
| | 2013 | 2012 |
| Oil Sands Mining Operating Statistics | | |
Net synthetic crude oil sales volumes (mbbld) (a) | 48 |
| 47 |
|
Synthetic crude oil average price realizations (per bbl) | $87.51 | $81.72 |
Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. These crude oil derivative instruments, all of which had terms that ended in December 2013, resulted in a $52 million net unrealized loss in 2013 compared to a net unrealized gain of $53 million in 2012. See Item 8. Financial Statements and Supplementary Data - Note 16 to the consolidated financial statements for information about our derivative positions.
Marketing revenues decreased $647 million in 2013 from 2012. North America E&P segment marketing activities, which serve to zeroaggregate volumes in 2012 from $93 millionorder to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points, decreased in 2011. Sales2013 as a result of LNG from our Alaska operations ceased in the third quarter of 2011 when we sold our interest in this production facility.market dynamics.
Income from equity method investments decreased $92increased $53 million in 2013 from 2011 to 2012the prior year primarily due to lowerhigher LNG average price realizations.
Net gain (loss) on disposal of assetsin 2013 primarily included a $114 million pretax loss on the sale of our interests in the DJ Basin, a $43 million pretax loss on the conveyance of our interests in the Marcellus natural gas pricesshale play to the operator, a $98 million pretax gain on the sale of our interest in the Neptune gas plant, and turnarounds earlya $55 million pretax gain on the sale of our remaining assets in 2012 at our facilities in E.G. Also, in January 2012, we sold our equity investments in several Gulf of Mexico crude oil pipelines.
NetAlaska. The net gain on disposal of assets in 2012 in 2012 consistsconsisted primarily of thea $166 million pretax gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems reduced by theand a $36 million pretax loss on the assignment of our Bone Bay and Kumawa exploration licenses in Indonesia and the $18 million loss on the sale of non-core Eagle Ford acreage. In 2011, net gain on disposal of assets is primarily related to sales of non-core assets, such as the Burns Point gas plant and the Alaska LNG facility, and the assignment of interests in our DJ Basin acreage position.exit from Indonesia. See Item 8. Financial Statements and Supplementary Data –- Note 6 to the consolidated financial statements for information about these dispositions.
Cost of revenuesProduction expensesincreased $129 million decreased $1,006 millionin 2013 from 2011 to 2012 primarily related to our supply optimization activities. Comparatively, costs relatedincreased North America E&P net sales volumes in the Eagle Ford and Bakken and International E&P well workovers in Norway. The production expense rate (expense
per boe) decreased in North America E&P in 2013 compared to supply optimization were lower by $1,152 million for 2012 primarily due to lower volumes improved operating efficiencies in 2012 due to market dynamics.the Eagle Ford. The related commodity prices were also slightly lower in 2012. Excluding the impact of supply optimization activities,International E&P segment operating expenses haveproduction expense rate increased in proportion2013 compared to our increased production from U.S. shale plays. Additionally, IG segment costs are lower in 2012 primarily due to the salewell workovers in Norway.
The following table provides production expense rates for each segment:
|
| | | | | | |
| ($ per boe) | 2013 | 2012 |
| North America E&P |
| $10.86 |
|
| $11.59 |
|
| International E&P |
| $6.24 |
|
| $5.13 |
|
Oil Sands Mining (a) |
| $46.30 |
| $45.95 |
| |
(a) | Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs. |
Marketing expenses decreased $672 million in 2013 from the prior year, consistent with the decrease in marketing revenues discussed above.
Exploration expenseswere $282 million higher in 2013 than in 2012, primarily due to larger non-cash unproved property impairments in our North America E&P segment related to Eagle Ford leases that either expired or that we did not expect to drill, partially offset by reduced geological and geophysical costs.
The following table summarizes the components of our interest in the Alaska LNG facility in the third quarter of 2011.exploration expenses:
|
| | | | | | |
| (In millions) | 2013 | 2012 |
| Unproved property impairments | $ | 580 |
| $ | 227 |
|
| Dry well costs | 218 |
| 230 |
|
| Geological and geophysical | 84 |
| 135 |
|
| Other | 106 |
| 114 |
|
| Total exploration expenses | $ | 988 |
| $ | 706 |
|
Depreciation, depletion and amortizationincreased $313 million in 2013 increased $212 million from 2011 to 2012. Since both our E&P and OSMthe prior year. Our segments apply the units-of-production method to the majority of their assets, the previously discussed increases in sales volumes generally result in similar changes in DD&A.including capitalized asset retirement costs. Increased DD&A in 20122013 primarily reflects the impact of higher North America E&P sales volumes. There was no depletionvolumes as well as increased amortization of capitalized asset retirement costs due to revisions of estimates for abandonment obligations in the Gulf of Mexico and the U.K. However, the disposition of our Alaska assets for much of 2012 because they were held for sale, whichin January 2013 and lower International E&P DD&A primarily due to 2013 reserve additions in Norway partially offset the DD&A increase. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about the Alaska disposition.
The DD&A rate (expense per barrel of oil equivalent)boe), which is impacted by changes in proved reserves and capitalized costs, can also cause changes into our DD&A. OurA higher 2013 DD&A rate in North America E&P segment'sversus 2012 is due to the ongoing development programs in the U.S. resource plays. A lower International E&P DD&A rates have decreased slightly since 2011rate in 2013 compared to 2012 was primarily due to proved reserve additions. increases for Norway.
The following table provides DD&A rates for our E&P and OSM segments.each segment:
|
| | | | | | | |
| ($ per boe) | 2012 | | 2011 |
| DD&A rate | | | |
| E&P Segment | | | |
| United States | $ | 24 |
| | $ | 25 |
|
| International | 8 |
| | 10 |
|
| OSM Segment | $ | 13 |
| | $ | 13 |
|
|
| | | | | | |
| ($ per boe) | 2013 | 2012 |
| North America E&P |
| $26.23 |
|
| $23.45 |
|
| International E&P |
| $7.26 |
|
| $8.08 |
|
| Oil Sands Mining |
| $12.39 |
|
| $12.57 |
|
Impairmentsin 2013 primarily related to capitalized costs associated with engineering and feasibility studies for a second LNG production train in 2012 related primarily to ourE.G., the Ozona development in the Gulf of Mexico, and to our Powder River Basin asset in Wyoming. Impairments in 20112012 were also related primarily to our Droshkythe Ozona development in the Gulf of Mexico and an intangible asset for an LNG delivery contract at Elba Island.Powder River Basin. See Item 8. Financial Statements and Supplementary Data –- Note 15 to the consolidated financial statements for further information about thethese impairments.
OtherTaxes other than incomeinclude production, severance and ad valorem taxes in the United States, which tend to increase or decrease in relation to net sales volumes and revenues, and increased $104 million increased $59 millionin 2013 from 2011 to 2012.2012. With the increase in North America E&P revenues related to higherand net sales volumes, production and severance taxes increased. In addition, ad valorem taxes arewere higher because the value of our U.S.North America E&P assets has increased with the recentcontinued acquisitions in the Eagle Ford shale.Ford.
Exploration expenses were higher in 2012 than 2011 primarily due to larger unproved property impairments. Unproved property impairments in 2012 related to the Marcellus shale, the Eagle Ford shale and Indonesia. The following table summarizes the components of exploration expenses.
|
| | | | | | | |
| (In millions) | 2012 | | 2011 |
| Unproved property impairments | $ | 227 |
| | $ | 79 |
|
| Dry well costs | 230 |
| | 278 |
|
| Geological, geophysical, seismic | 128 |
| | 120 |
|
| Other | 144 |
| | 167 |
|
| Total exploration expenses | $ | 729 |
| | $ | 644 |
|
Net interest and otherincreased $55 million increased $112 millionin 2013 from 20112012 primarily due to 2012 primarily as a result of lesshigher interest expense capitalized.related to our $2 billion issuance of senior notes in late 2012. See Item 8. Financial Statements and Supplementary Data –- Note 9 to the consolidated financial statements for more information on net interest and other.detailed information.
Loss on early extinguishment of debt in 2011 relates to debt retirements in February and March of 2011. See Item 8. Financial Statements and Supplementary Data – Note 17 to the consolidated financial statements for additional discussion of these transactions.40
Provision for income taxesdecreased $1,180 million increased $1,811 millionin 2013 from 2011 to 2012 primarily due to the increasedecrease in pretax income including the impact of the previously discussed resumption of salesfrom continuing operations, primarily in Libya in the first quarter of 2012.and Norway, which are higher tax jurisdictions. The following is an analysis of the effective income tax rates for 20122013 and 2011:2012.
| | | | 2012 | | 2011 | 2013 | | 2012 |
| Statutory rate applied to income from continuing operations before income taxes | 35 | % | | 35 | % | 35 | % | | 35 | % |
| Effects of foreign operations, including foreign tax credits | 18 |
| | 6 |
| 14 |
| | 18 |
|
| Change in permanent reinvestment assertion | — |
| | 5 |
| |
| Adjustments to valuation allowances | 21 |
| | 14 |
| 18 |
| | 21 |
|
| Tax law changes | — |
| | 1 |
| |
| Other | | 1 |
| | — |
|
| Effective income tax rate on continuing operations | 74 | % | | 61 | % | 68 | % | | 74 | % |
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income, and foreign currency remeasurement effects.income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments appears in the "Corporate and other unallocated items" shown in the reconciliation of segment income to net income below.
Effects of foreign operations – The effects of foreign operations on our effective tax rate decreased in 2013 as compared to 2012, primarily due to decreased sales in Libya during 2013 as a result of third-party labor strikes at the Es Sider oil terminal.
Adjustments to valuation allowances – In 2013 and 2012, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in those years.
See Item 8. Financial Statements and Supplementary Data - Note 10 to the consolidated financial statements for further information about income taxes.
Discontinued operations is presented net of tax. In 2013, we entered into agreements to sell our Angola assets; therefore, the Angola operations are reflected as discontinued operations in all periods presented. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements.
Segment Results: 2013 compared to 2012
Segment income for 2013 and 2012 is summarized and reconciled to net income in the following table.
|
| | | | | | | |
| (In millions) | 2013 | | 2012 |
| North America E&P | $ | 529 |
| | $ | 382 |
|
| International E&P | 1,423 |
| | 1,660 |
|
| Oil Sands Mining | 206 |
| | 171 |
|
| Segment income | 2,158 |
| | 2,213 |
|
| Items not allocated to segments, net of income taxes: | | | |
| Corporate and other unallocated items | (473 | ) | | (475 | ) |
| Unrealized gain (loss) on crude oil derivative instruments | (33 | ) | | 34 |
|
| Net gain (loss) on dispositions | (20 | ) | | 72 |
|
| Impairments | (39 | ) | | (231 | ) |
| Income from continuing operations | 1,593 |
| | 1,613 |
|
| Discontinued operations | 160 |
| | (31 | ) |
| Net income | $ | 1,753 |
| | $ | 1,582 |
|
North America E&P segment incomeincreased $147 million in 2013 compared to 2012. The increase was largely due to increased liquid hydrocarbon net sales volumes primarily in the Eagle Ford, Bakken and Oklahoma resource basins, partially offset by higher DD&A associated with the higher sales volumes. Segment income was also negatively impacted by higher exploration expenses related to non-cash unproved property impairments and the sale of our Alaska assets.
International E&P segment incomedecreased $237 million in 2013 compared to 2012. The decrease was primarily related to the lower liquid hydrocarbon net sales volumes in Libya and Norway and lower average liquid hydrocarbon price realizations, as well as higher exploration expenses, partially offset by lower DD&A associated with the lower sales volumes.
Oil Sands Mining segment incomeincreased $35 million in 2013 compared to 2012. This increase was primarily due to a higher proportion of net sale volumes in 2013 related to a premium grade of synthetic crude oil with a higher corresponding price realization.
Consolidated Results of Operations: 2012 compared to 2011
Consolidated income from continuing operations before income taxes in 2012 was 38 percent higher than in 2011 primarily related to increases in North America E&P and International E&P liquid hydrocarbon net sales volumes and higher average price realizations in International E&P. The effective tax rate for continuing operations was 74 percent in 2012 compared to 61 percent in 2011, with the increase primarily related to resumption in 2012 of sales in Libya, which is a higher tax jurisdiction. Also, in 2011 we were not in an excess foreign tax credit position for the entire year as we were in 2012.
Sales and other operating revenues, including related partyare summarized by segment in the following table:
|
| | | | | | |
| (In millions) | 2012 | 2011 |
| Sales and other operating revenues, including related party | | |
| North America E&P | $ | 3,944 |
| $ | 3,364 |
|
| International E&P | 7,445 |
| 5,851 |
|
| Oil Sands Mining | 1,521 |
| 1,535 |
|
| Segment sales and other operating revenues, including related party | 12,910 |
| 10,750 |
|
| Unrealized gain (loss) on crude oil derivative instruments | 53 |
| — |
|
| Sales and other operating revenues, including related party | $ | 12,963 |
| $ | 10,750 |
|
North America E&P sales and other operating revenues increased $580 million in 2012 from 2011 primarily due to higher liquid hydrocarbon net sales volumes resulting from ongoing development programs in the Eagle Ford and Bakken, partially offset by lower average liquid hydrocarbon and natural gas price realizations, when compared to 2011. Realized gains on our North America E&P crude oil derivative instruments were $15 million in 2012, while there were no open crude oil derivative instruments in 2011.
The following table gives details of net sales volumes and average price realizations of our North America E&P segment:
|
| | | | |
| | 2012 | 2011 |
| North America E&P Operating Statistics | | |
Net liquid hydrocarbon sales volumes (mbbld) | 107 |
| 75 |
|
Liquid hydrocarbon average price realizations (per bbl) (a)(b) | $85.80 | $92.55 |
Net crude oil and condensate sales volumes (mbbld) | 96 |
| 70 |
|
Crude oil and condensate average price realizations (per bbl) (a) | $91.30 | $94.80 |
Net natural gas liquids sales volumes (mbbld) | 11 |
| 5 |
|
Natural gas liquids average price realizations (per bbl) (a) | $39.57 | $58.53 |
Net natural gas sales volumes (mmcfd) | 358 |
| 326 |
|
Natural gas average price realizations (per mcf) (a) | $3.92 | $4.95 |
| |
(a) | Excludes gains and losses on derivative instruments. |
| |
(b) | Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations by $0.40 per bbl for 2012. There were no crude oil derivative instruments in 2011. |
International E&P sales and other operating revenues increased $1,594 million in 2012 from 2011 primarily as a result of the previously discussed resumption of liquid hydrocarbon sales in Libya. Higher average liquid hydrocarbon price realizations during 2012, again primarily related to Libyan crude oil, also contributed to the revenue increase.
The following table gives details of net sales volumes and average price realizations of our International E&P segment:
|
| | | | |
| | 2012 | 2011 |
| International E&P Operating Statistics | | |
Net liquid hydrocarbon sales volumes (mbbld)(a) | | |
| Europe | 97 |
| 101 |
|
| Africa | 78 |
| 43 |
|
| Total International E&P | 175 |
| 144 |
|
Liquid hydrocarbon average price realizations (per bbl) | | |
| Europe | $115.16 | $115.55 |
| Africa | $98.52 | $73.21 |
| Total International E&P | $107.78 | $102.96 |
Net natural gas sales volumes (mmcfd) | | |
Europe(b) | 101 |
| 97 |
|
| Africa | 443 |
| 443 |
|
| Total International E&P | 544 |
| 540 |
|
Natural gas average price realizations (per mcf) | | |
| Europe | $10.47 | $9.84 |
Africa(c) | $0.43 | $0.24 |
| Total International E&P | $2.29 | $1.97 |
| |
(a) | Corresponds with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons. |
| |
(b) | Includes natural gas acquired for injection and subsequent resale of 15 mmcfd and 16 mmcfd for 2012 and 2011. |
| |
(c) | Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO, and EGHoldings, equity method investees. We include our share of Alba Plant LLC's, AMPCO's and EGHoldings' income in our International E&P segment. |
Oil Sands Mining sales and other operating revenues decreased $14 million in 2012 from 2011. This decrease was primarily the result of lower average price realizations which were partially offset by higher net sales volumes.
The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment:
|
| | | | |
| | 2012 | 2011 |
| Oil Sands Mining Operating Statistics | | |
Net synthetic crude oil sales volumes (mbbld) (a) | 47 |
| 43 |
|
Synthetic crude oil average price realizations (per bbl) | $81.72 | $91.65 |
Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. These crude oil derivative instruments resulted in a net unrealized gain of $53 million in 2012, however, there were no open crude oil derivative instruments in 2011. See Item 8. Financial Statements and Supplementary Data - Note 16 to the consolidated financial statements for additional information about our derivative positions.
Marketing revenues decreased $1,190 million in 2012 from 2011. North America E&P segment marketing activities, which serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points, decreased in 2012 as a result of market dynamics and slightly lower commodity prices.
Income from equity method investmentsdecreased $92 million in 2012 from the prior year primarily due to lower natural gas prices and turnarounds early in 2012 at our facilities in E.G. Also, in January 2012, we sold our equity investments in several Gulf of Mexico crude oil pipelines.
Net gain (loss) on disposal of assetsin 2012 consisted primarily of the $166 million pretax gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems and a $36 million pretax loss related to our exit from Indonesia. In 2011, the net gain on disposal of assets was primarily related to the $37 million pretax gain related to the assignment of interests in our DJ Basin acreage position, the $34 million pretax gain on the sale of our interest in the Burns Point gas plant and the $8 million pretax gain on the sale of our interest in the Alaska LNG facility. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.
Production expensesincreased $251 million in 2012 from 2011. The increase is primarily related to increased liquid hydrocarbon net sales volumes in the Eagle Ford, Bakken and Libya as well as the 2012 planned turnaround in the U.K.
The following table provides production expense rates (expense per boe) for each segment:
|
| | | | | | |
| ($ per boe) | 2012 | 2011 |
| North America E&P |
| $11.59 |
|
| $11.51 |
|
| International E&P |
| $5.13 |
|
| $4.80 |
|
Oil Sands Mining (a) |
| $45.95 |
|
| $46.27 |
|
| |
(a) | Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs. |
Marketing expenses decreased $1,154 million in 2012 from the prior year, consistent with the decreases in marketing revenues discussed above.
Exploration expenseswere $65 million higher in 2012 than in 2011, primarily due to larger non-cash unproved property impairments. Unproved property impairments in 2012 related to Marcellus, Eagle Ford and Indonesia. The following table summarizes the components of exploration expenses.
|
| | | | | | |
| (In millions) | 2012 | 2011 |
| Unproved property impairments | $ | 227 |
| $ | 79 |
|
| Dry well costs | 230 |
| 278 |
|
| Geological and geophysical | 135 |
| 124 |
|
| Other | 114 |
| 160 |
|
| Total exploration expenses | $ | 706 |
| $ | 641 |
|
Depreciation, depletion and amortizationincreased $214 million in 2012 from the prior year. Our segments apply the units-of-production method to the majority of their assets; therefore, the previously discussed increases in North America E&P and International E&P sales volumes generally result in similar changes in DD&A. There was no depletion of our Alaska assets for much of 2012 because they were held for sale, which partially offset the DD&A increase.
The DD&A rate (expense per boe), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. The decreases in both the North America E&P and International E&P DD&A rates in 2012 compared to 2011 were primarily due to proved reserve additions.
The following table provides DD&A rates for each segment:
|
| | | | | | |
| ($ per boe) | 2012 | 2011 |
| North America E&P |
| $23.45 |
|
| $25.15 |
|
| International E&P |
| $8.08 |
|
| $9.70 |
|
| Oil Sands Mining |
| $12.57 |
|
| $12.43 |
|
Impairmentsin 2012 primarily related to the Ozona development in the Gulf of Mexico and to our Powder River Basin asset in Wyoming. Impairments in 2011 primarily related to the Droshky development in the Gulf of Mexico and an intangible asset for an LNG delivery contract at Elba Island. See Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements for information about these impairments.
Taxes other than incomeinclude production, severance and ad valorem taxes in the United States, which tend to increase or decrease in relation to sales volumes and revenues, and increased $55 million in 2012 from 2011. With the increase in revenues related to higher sales volumes, production and severance taxes increased. In addition, ad valorem taxes are higher because the value of our U.S. assets increased with the acquisitions in the Eagle Ford shale.
Net interest and otherincreased $112 million in 2012 from 2011 primarily due to lower capitalized interest in 2012. See Item 8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements for more detailed information.
Loss on early extinguishment of debt relates to debt retirements in February and March of 2011.
Provision for income taxesincreased $1,791 million in 2012 from 2011 primarily due to the increase in pretax income from continuing operations, including the impact of the resumption of sales in Libya in the first quarter of 2012. The following is an analysis of the effective income tax rates for 2012 and 2011:
|
| | | | | |
| | 2012 | | 2011 |
| Statutory rate applied to income from continuing operations before income taxes | 35 | % | | 35 | % |
| Effects of foreign operations, including foreign tax credits | 18 |
| | 6 |
|
| Change in permanent reinvestment assertion | — |
| | 5 |
|
| Adjustments to valuation allowances | 21 |
| | 14 |
|
| Tax law changes | — |
| | 1 |
|
| Effective income tax rate on continuing operations | 74 | % | | 61 | % |
The effective income tax rate is influenced by a variety of factors including the geographic sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments is reportedappears in the "Corporate and other unallocated items" shown in the reconciliation of segment income to net income below.
Effects of foreign operations – The effects of foreign operations on our effective tax rate increased in 2012 as compared to 2011,, primarily due to the resumption of sales of Libyan production in Libya in the first quarter of 2012, where the statutory tax rate is in excess of 90 percent.
Change in permanent reinvestment assertion – In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U.S. tax on previously undistributed earnings.
Adjustments to valuation allowances – In 2012 and 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in those years.
See Item 8. Financial Statements and Supplementary Data –- Note 10 to the consolidated financial statements for further information about income taxes.
Discontinued operations in 2011 reflect theis presented net of tax, andreflects our downstream business that was spun off June 30, 2011 spin-off ofand our downstreamAngola business and its historical operating results, net of tax.which we agreed to sell in 2013. See Item 8. Financial Statements and Supplementary Data – NoteNotes 3 and 6 to the consolidated financial statements.statements for additional information.
Segment Results: 2012 compared to 2011
Segment income for 2012 and 2011 is summarized and reconciled to net income in the following table.
| | | (In millions) | 2012 | | 2011 | 2012 | | 2011 |
| E&P | | | | |
| United States | $ | 393 |
| | $ | 366 |
| |
| International | 1,488 |
| | 1,791 |
| |
| E&P segment | 1,881 |
| | 2,157 |
| |
| OSM | 176 |
| | 256 |
| |
| IG | 91 |
| | 178 |
| |
| North America E&P | | $ | 382 |
| | $ | 392 |
|
| International E&P | | 1,660 |
| | 1,991 |
|
| Oil Sands Mining | | 171 |
| | 261 |
|
| Segment income | 2,148 |
| | 2,591 |
| 2,213 |
| | 2,644 |
|
| Items not allocated to segments, net of income taxes: | | | | | | |
| Corporate and other unallocated items | (441 | ) | | (317 | ) | (475 | ) | | (359 | ) |
| Unrealized gain on crude oil derivative instruments | | 34 |
| | — |
|
| Net gain on dispositions | | 72 |
| | 45 |
|
| Impairments | (231 | ) | | (195 | ) | (231 | ) | | (195 | ) |
| Gain on dispositions | 72 |
| | 45 |
| |
Unrealized gain on crude oil derivative instruments
| 34 |
| | — |
| |
| Loss on early extinguishment of debt | — |
| | (176 | ) | — |
| | (176 | ) |
| Tax effect of subsidiary restructuring | — |
| | (122 | ) | — |
| | (122 | ) |
| Deferred income tax items | — |
| | (61 | ) | — |
| | (61 | ) |
| Water abatement - Oil Sands | — |
| | (48 | ) | — |
| | (48 | ) |
| Eagle Ford transaction costs | — |
| | (10 | ) | — |
| | (10 | ) |
| Income from continuing operations | 1,582 |
| | 1,707 |
| 1,613 |
| | 1,718 |
|
| Discontinued operations | — |
| | 1,239 |
| (31 | ) | | 1,228 |
|
| Net income | $ | 1,582 |
| | $ | 2,946 |
| $ | 1,582 |
| | $ | 2,946 |
|
U.S. North America E&P segment incomedecreased $10 million in 2012 compared to 2011. The decrease is largely due to lower liquid hydrocarbon price realizations and increased $27 million from 2011exploration expenses due to 2012. The income increase was primarily the result ofnon-cash unproved property impairments, partially offset by higher liquid hydrocarbon net sales volumes as previously discussed, partially offset by lower liquid hydrocarbonprimarily in the Eagle Ford and natural gas realizations and the impact of increased production operations on DD&A and operating expenses. In addition, exploration expenses were higher primarily due to dry wells and unproved property impairments. Bakken.
International E&P segment incomedecreased $331 million in 2012 decreased $303 million from 2011compared to 2012.2011. The decrease included lower earnings in the U.K. and E.G., partially offset by higher earnings in Libya. Also, in 2011 we were not in an excess foreign tax credit position for the entire year as we were in 2012.
OSM Oil Sands Mining segment incomedecreased $90 million in 2012 income decreased $80 million from 2011compared to 2012. As previously discussed,2011. The decrease is primarily due to lower synthetic crude oil price realizations were the primary reason for the decrease in income partially offset by higher sales volumes.
IG segment income decreased $87 million from 2011 to 2012 primarily due to lower natural gas prices and turnarounds early in 2012 at our facilities in E.G. In addition, LNG sales volumes are lower in 2012 because we sold our interest in the Alaska LNG facility in the third quarter of 2011.
Consolidated Results of Operations: 2011 compared to 2010
Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company. Consolidated income from continuing operations before income taxes was 9 percent higher in 2011 than in 2010, largely due to higher liquid hydrocarbon prices. This improvement was more than offset by increased income taxes primarily the result of excess foreign tax credits generated during 2011 that we do not expect to utilize in the future. The effective income tax rate for continuing operations was 61 percent in 2011 compared to 54 percent in 2010.
Revenues are summarized in the following table:
|
| | | | | | | |
| (In millions) | 2011 | | 2010 |
| E&P | $ | 13,029 |
| | $ | 10,782 |
|
| OSM | 1,588 |
| | 833 |
|
| IG | 93 |
| | 150 |
|
| Segment revenues | 14,710 |
| | 11,765 |
|
| Elimination of intersegment revenues | (47 | ) | | (75 | ) |
| Total revenues | $ | 14,663 |
| | $ | 11,690 |
|
E&P segment revenues increased $2,247 million from 2010 to 2011, primarily due to higher average liquid hydrocarbon realizations, which were $99.37 per bbl in 2011, a 31 percent increase over 2010. Revenues in 2010 included net pre-tax gains of $95 million on derivative instruments intended to mitigate price risk on future sales of liquid hydrocarbons and natural gas.
Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Higher average crude oil prices in 2011 compared to 2010 increased revenues related to supply optimization.
Revenues from the sale of our U.S. production were higher in 2011 primarily as a result of higher liquid hydrocarbon and natural gas price realizations, but sales volumes declined.
The following table gives details of net sales and average realizations of our U.S. operations.
|
| | | | | | | |
| | 2011 | | 2010 |
| U.S. Operating Statistics | | | |
Net liquid hydrocarbon sales (mbbld) | 75 |
| | 70 |
|
Liquid hydrocarbon average realizations (per bbl)(a) | $ | 92.55 |
| | $ | 72.30 |
|
Net crude oil and condensate sales (mbbld) | 70 |
| | 66 |
|
Crude oil and condensate (per bbl) | $ | 94.80 |
| | $ | 73.66 |
|
Net natural gas liquids sales (mbbld) | 5 |
| | 4 |
|
Natural gas liquids (per bbl) | $ | 58.53 |
| | $ | 50.71 |
|
Net natural gas sales (mmcfd) | 326 |
| | 364 |
|
Natural gas average realizations (per mcf)(a) | $ | 4.95 |
| | $ | 4.71 |
|
| |
(a)
| Excludes gains or losses on derivative instruments. |
Increased liquid hydrocarbon sales volumes in 2011 were a result of new wells in the Bakken shale, new production from acreage acquired in the Eagle Ford shale and increased production from the Droshky development in the Gulf of Mexico, which commenced operations in July 2010. Natural gas sales volumes were lower in 2011 as compared to 2010 due to the sale of a portion of our Powder River Basin asset in 2010, decreased demand in Alaska and natural field declines, partly offset by increased natural gas production from the Droshky development.
The following table gives details of net sales and average realizations of our international operations.
|
| | | | | |
| | 2011 | | 2010 |
| International Operating Statistics | | | |
Net liquid hydrocarbon sales (mbbld)(a) | | | |
| Europe | 101 |
| | 92 |
|
| Africa | 43 |
| | 83 |
|
| Total International | 144 |
| | 175 |
|
Liquid hydrocarbon average realizations (per bbl)(b) | | | |
| Europe | $115.55 | | $81.95 |
| Africa | $73.21 | | $71.71 |
| Total International | $102.96 | | $77.11 |
Net natural gas sales (mmcfd) | | | |
Europe(c) | 97 |
| | 105 |
|
| Africa | 443 |
| | 409 |
|
| Total International | 540 |
| | 514 |
|
Natural gas average realizations (per mcf)(b) | | | |
| Europe | $9.84 | | $7.10 |
Africa(d) | $0.24 | | $0.25 |
| Total International | $1.97 | | $1.65 |
| |
(a)
| The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons. |
| |
(b)
| Excludes gains or losses on derivative instruments. |
| |
(c)
| Includes natural gas acquired for injection and subsequent resale of 16 mmcfd and 18 mmcfd in 2011 and 2010. |
| |
(d)
| Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC’s income in our E&P segment and we include our share of AMPCO’s and EGHoldings’ income in our IG segment. |
Compared to 2010, international liquid hydrocarbon sales volumes are lower due to the temporary cessation of production from Libya in February 2011. In the fourth quarter of 2011, limited production resumed from the Waha concessions, but we made no deliveries of hydrocarbons. Sales resumed in February 2012. Partially offsetting the impact of Libya, were higher liquid hydrocarbon sales from Norway due to increasing capacity of the Alvheim FPSO and from two new West Brae wells in the U.K. Natural gas sales volumes from E.G. were higher in 2011 due to a turnaround in 2010, while natural gas sales volumes from Europe were down primarily related to 2011 planned turnarounds and normal production declines in the U.K.
OSM segment revenues increased $755 million from 2010 to 2011. Revenues were impacted by net pre-tax gains of $25 million on derivative instruments in 2010. The increase in revenue is due to higher synthetic crude oil sales volumes and realizations as shown on the table below.
|
| | | | | |
| | 2011 | | 2010 |
| OSM Operating Statistics | | | |
Net synthetic crude oil sales (mbbld)(a) | 43 |
| | 29 |
|
Synthetic crude oil average realizations (per bbl) | $91.65 | | $71.06 |
The 2011 sales volumes improved as a result of the Jackpine mine, which commenced operations in late 2010, and the upgrader expansion which was completed and commenced operations in the second quarter of 2011. Sales volumes in 2010 were impacted by a turnaround that commenced in late March 2010 that caused production to be completely shut down in April, with a staged resumption in May 2010.
IG segment revenues decreased $57 million in 2011 from 2010 because sales of LNG from our Alaska operations declined throughout 2011 as we planned to shut down the LNG facility. In the third quarter of 2011, sales from the LNG facility ceased completely because we sold our equity interest in the facility.
Income from equity method investments increased $118 million in 2011 from 2010 primarily due to the impact of higher liquid hydrocarbon prices on the earnings of certain of our equity method investees in 2011.
Net gain on disposal of assets in 2011 is primarily related to sales of non-core assets, such as the Burns Point gas plant and the Alaska LNG facility, and the assignment of interests in our DJ Basin acreage position. The 2010 gain is primarily related to the pretax gain of $811 million on the sale of a 20 percent non-operated interest in our Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements for discussion of significant dispositions.
Cost of revenues increased $1,439 million from 2010 to 2011 primarily due to the impact of higher crude oil prices on our supply optimization activities. Costs related to supply optimization were $3,599 million in 2011 compared to $2,530 million in 2010.
Additionally, total OSM segment costs increased for 2011 primarily because the Jackpine mine commenced production in late 2010 and the upgrader expansion came online in 2011. Although gross costs were up due to the increased volumes from the expansion, per barrel costs were declining in comparison with 2010. OSM segment costs also increased in 2011 when compared to 2010 due to the expansion’s operation start-up costs. These increases were partially offset by no turnaround costs in 2011. We incurred $99 million in 2010 associated with the turnaround. Additionally, estimated net costs of $64 million were recorded in 2011 to address water flow in a previously mined and contained area of the Muskeg River mine.
Purchases from related parties increased $78 million from 2010 as a result of purchases from the Alba LPG plant in E.G., in which we own an equity interest. Higher liquid hydrocarbon prices in 2011 increased the value of those purchases.
Depreciation, depletion and amortization increased $210 million in 2011 from 2010. Since both our E&P and OSM segments apply the units-of-production method to the majority of their assets, the previously discussed increases or decreases in sales volumes generally result in similar changes in DD&A. Increased DD&A expense in 2011 reflects the impact of higher OSM segment sales volumes, partially offset by decreases in E&P segment sales volumes. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in proved reserves and capitalized costs, can also cause changes in our DD&A. The DD&A rate for the OSM segment increased in 2011 when depreciation began on the upgrader expansion. The following table provides DD&A rates for our E&P and OSM segments.
|
| | | | | | | |
| ($ per boe) | 2011 | | 2010 |
| DD&A rate | | | |
| E&P Segment | | | |
| United States | $ | 25 |
| | $ | 22 |
|
| International | 10 |
| | 9 |
|
| OSM Segment | $ | 13 |
| | $ | 10 |
|
Impairments in 2011 related primarily to our Droshky development in the Gulf of Mexico for $273 million and an intangible asset for an LNG delivery contract at Elba Island. Impairments in 2010 include $423 million related to our Powder River Basin field in the first quarter, as well as smaller impairments to other E&P segment fields due to reductions in estimated reserves, reduced drilling expectations and declining natural gas prices. See Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for further information about the impairments.
General and administrative expenses increased $53 million in 2011 compared to 2010 primarily due to additional compensation expense related to performance units and stock based compensation expense.
Other taxes increased $31 million in 2011 compared to 2010. With the increase in revenues, particularly related to higher prices, production and ad valorem taxes increased.
Exploration expenses were higher in 2011 than 2010 primarily due to higher dry well costs. Dry wells primarily related to Indonesia, the Gulf of Mexico, Norway and various U.S. onshore properties in both 2011 and 2010. In addition, costs related to some suspended exploratory wells in E.G. were expensed in 2010. Geologic and seismic costs have increased in 2011 over 2010 primarily related to the U.S. shale plays, Poland and the Kurdistan Region of Iraq.
The following table summarizes components of exploration expenses:
|
| | | | | | | |
| (In millions) | 2011 | | 2010 |
| Unproved property impairments | $ | 79 |
| | $ | 46 |
|
| Dry well costs | 278 |
| | 179 |
|
| Geological, geophysical, seismic | 120 |
| | 116 |
|
| Other | 167 |
| | 159 |
|
| Total exploration expenses | $ | 644 |
| | $ | 500 |
|
Loss on early extinguishment of debt relates to debt retirements in February and March of 2011 and in April of 2010. See Item 8. Financial Statements and Supplementary Data – Note 17 to the consolidated financial statements for additional discussion of the 2011 transactions.
Provision for income taxes increased $545 million from 2010 to 2011 in part due to the increase in pretax income. In 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2011. A higher price and production outlook over the next several years for Norway due to better than expected performance contributed to generating these excess foreign tax credits. The following is an analysis of the effective income tax rates for 2011 and 2010:
|
| | | | | |
| | 2011 | | 2010 |
| Statutory rate applied to income from continuing operations before income taxes | 35 | % | | 35 | % |
| Effects of foreign operations, including foreign tax credits | 6 |
| | 20 |
|
| Change in permanent reinvestment assertion | 5 |
| | — |
|
| Adjustments to valuation allowances | 14 |
| | (2 | ) |
| Tax law changes | 1 |
| | 1 |
|
| Effective income tax rate on continuing operations | 61 | % | | 54 | % |
The effective tax rate is influenced by a variety of factors including the geographical and functional sources of income, the relative magnitude of these sources of income, foreign currency remeasurement effects, and tax legislation changes. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in "Corporate and other unallocated items" shown in the reconciliation of segment income to net income shown below.
Effects of foreign operations – The effects of foreign operations on our effective tax rate decreased in 2011 as compared to 2010, primarily due to the suspension of all production operations in Libya in the first quarter of 2011, where the statutory tax rate is in excess of 90 percent.
Change in permanent reinvestment assertion – In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognized deferred U.S. tax on previously undistributed earnings.
Adjustments to valuation allowance – In 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2011.
See Item 8. Financial Statements and Supplementary Data – Note 10 to the consolidated financial statements for further information about income taxes.
Discontinued operations reflect the June 30, 2011 spin-off of our downstream business and the historical results of those operations, net of tax, for 2011 and 2010. See Item 8. Financial Statements and Supplementary Data – Note 3 to the consolidated financial statements.
Segment Results: 2011 compared to 2010
Segment income for 2011 and 2010 is summarized and reconciled to net income in the following table.
|
| | | | | | | |
| (In millions) | 2011 | | 2010 |
| E&P | | | |
| United States | $ | 366 |
| | $ | 251 |
|
| International | 1,791 |
| | 1,690 |
|
| E&P segment | 2,157 |
| | 1,941 |
|
| OSM | 256 |
| | (50 | ) |
| IG | 178 |
| | 142 |
|
| Segment income | 2,591 |
| | 2,033 |
|
| Items not allocated to segments, net of income taxes: | | | |
| Corporate and other unallocated items | (317 | ) | | (170 | ) |
| Impairments | (195 | ) | | (286 | ) |
| Gain on dispositions | 45 |
| | 407 |
|
| Loss on early extinguishment of debt | (176 | ) | | (57 | ) |
| Tax effect of subsidiary restructuring | (122 | ) | | — |
|
| Deferred income tax items | (61 | ) | | (45 | ) |
| Water abatement – Oil Sands | (48 | ) | | — |
|
| Eagle Ford transaction costs | (10 | ) | | — |
|
| Income from continuing operations | 1,707 |
| | 1,882 |
|
| Discontinued operations | 1,239 |
| | 686 |
|
| Net income | $ | 2,946 |
| | $ | 2,568 |
|
U.S. E&P income increased $115 million from 2010 to 2011. The majority of the income increase was due to higher liquid hydrocarbon realizations in 2011, along with higher liquid hydrocarbon sales volumes, partially offset by higher DD&A in the Gulf of Mexico and increased exploration and operating costs.
International E&P income increased $101 million from 2010 to 2011. This increase was primarily related to higher liquid hydrocarbon realizations, partially offset by lower liquid hydrocarbon sales volumes and higher income taxes.
OSM segment income increased $306 million from 2010 to 2011. The increase in segment income was primarily the result of higher synthetic crude oil sales volumes and higher price realizations.
IG segment income increased $36 million from 2010 to 2011. The increase in income was primarily the result of higher LNG and methanol sales volumes, somewhat offset by lower Henry Hub gas prices.
Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
Cash Flows
Net cash provided by continuing operations was $4,0175,091 million in 20122013 compared to $5,4344,036 million in 20112012 and $4,1945,441 million in 2010.2011. The $1,4171,055 million increase in 2013 primarily reflects the impact of increased North America E&P liquid hydrocarbon net sales volumes on operating income. The $1,405 million decrease in 2012 was primarily the result of working capital changes related to the 2012 ramp-up of operations in the Eagle Ford shale and Libya along with the timing of tax payments. The $1,240 million increase in 2011 primarily reflects increased average realized prices.
Net cash used in investing activities totaled $5,439 million in 2012 compared to net cash used in investing activities related to continuing operations oftotaled $7,1744,294 million in 20112013 compared to $5,092 million in 2012 and $2,1576,865 million in 2010.2011. Significant investing activities include acquisitions, additions to property, plant and equipment and asset disposals.
Acquisitions in 2013, 2012 and 2011 included proved and unproved assets in the Eagle Ford shale play in south Texas.Ford. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for further information about the transactions.
In recent years, acquisitions andthe focus of most of our capital spending in the U.S. has been increasing,in our North America E&P segment related to unconventional resource plays like the Eagle Ford, shaleBakken and to Gulf of Mexico exploration when drilling was once again permitted. Historically, long-term projects, which cross several years, have been the reasons for our additions to property, plant and equipment. In our E&P segment,
exploration and development projects in Angola impacted all three years. Development of fields tied back to the Alvheim FPSO occurred in 2010. In the OSM segment, the AOSP Expansion 1, which began in 2008, was substantially complete in 2010.Oklahoma resource basins.
DisposalDisposals of assets totaled $467450 million, $518467 million, and $1,368518 million in 2013, 2012, 2011 and 2010.2011. In 2012,2013, net proceeds resultedwere primarily related to the sales of our interests in Alaska, the Neptune gas plant, and the DJ Basin. In 2012, net proceeds were primarily from the sales of our interests in several Gulf of Mexico crude oil pipeline systems, a sell-down of our interestinterests in the Harir and Safen blocks in the Kurdistan Region of Iraq, and the final collection of proceeds on a 2009 asset sale. Several sales of non-core assets in 2011 and acreage sell-downs in 2011 resulted in net proceeds of $518 million. In 2010, we closed the sale of our 20 percent non-operated undivided interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola for $1.3 billion.$518 million. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements for more information about dispositions.
Financing activities related to continuing operations resulted in a use of cash of $1,162 million in 2013, provided cash of $1,600 million in 2012, but and used cash of $5,211 million in 2011. Debt repayments of 2011$182 million, $145 million, and $1,3432,877 million occurred in 2010.2013, 2012 and 2011. Purchases of common stock used $500 million in cash during 2013 and $300 million in 2011. Dividend payments were uses of cash in every year. Sources of cash in 2012 included the issuance of a net $200$200 million in commercial paper and $2 billion in senior notes. In connection with the spin-off, we distributed $1,622$1,622 million to MPC in the second quarter of 2011. Debt repayments of $145 million, $2,877 million, and $653 million occurred in 2012, 2011 and 2010. Purchases of common stock used $300 million in cash during 2011. Dividend payments were uses of cash in every year.
Liquidity and Capital Resources
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our committed revolving credit facility and sales of non-strategic assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements. We issued $13.9 billion$10,870 million and repaid $13.7 billion$10,935 million of commercial paper in 2012,2013, leaving a balance of $200$135 million outstanding at December 31, 20122013. Because of the alternatives available to us as discussed above and our access to capital markets through the shelf registration discussed below, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, share repurchase program and other amounts that may ultimately be paid in connection with contingencies.
Capital Resources
Credit Arrangements and Borrowings
At December 31, 20122013, we had $6,696$6,462 million in long-term debt outstanding, $184$68 million of which is due within one year. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
At December 31, 20122013, we had no borrowings against our revolving credit facility and had $200$135 million in commercial paper outstanding under our commercial paper program, which is backed by the revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 17 to the consolidated financial statements for a description of the revolving credit facility.
2014 Asset Disposals
The sale of our interest in Angola Block 31 closed in February 2014 for proceeds of $1.5 billion before closing adjustments. These proceeds will be used to repurchase $500 million of common stock with the remainder to be used for general corporate purposes. The sale of our interest in Angola Block 32 for proceeds of $590 million before closing adjustments is expected to close in the first quarter of 2014.
Shelf Registration
We haveare a "well-known seasoned issuer" for purposes of SEC rules, thereby allowing us to use a universal shelf registration statement filed with the SEC, under whichshould we as a "well-known seasoned issuer" for purpose of SEC rules, have the abilitychoose to issue and sell an indeterminate amount of various types of equity and debt securities. Beginning in the first quarter of 2013, we changed our reportable segments and equity securities from timesubsequently have recast all periods presented in this Annual Report on Form 10-K to time.reflect these new segments in our consolidated financial statements. We expect to update and file our universal shelf registration statement shortly after the filing of this Annual Report on Form 10-K with the SEC.
Cash-Adjusted Debt-To-Capital Ratio
Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 25 percent and 20 percentat December 31, 20122013 and 2011.2012.
| | | (Dollars in millions) | 2012 | | 2011 | 2013 | | 2012 |
| Commercial paper | $ | 200 |
| | $ | — |
| $ | 135 |
| | $ | 200 |
|
| Long-term debt due within one year | 184 |
| | 141 |
| 68 |
| | 184 |
|
| Long-term debt | 6,512 |
| | 4,674 |
| 6,394 |
| | 6,512 |
|
| Total debt | $ | 6,896 |
| | $ | 4,815 |
| $ | 6,597 |
| | $ | 6,896 |
|
| Cash | $ | 684 |
| | $ | 493 |
| $ | 264 |
| | $ | 684 |
|
| Equity | $ | 18,283 |
| | $ | 17,159 |
| $ | 19,344 |
| | $ | 18,283 |
|
| Calculation: | | | | | | |
| Total debt | $ | 6,896 |
| | $ | 4,815 |
| $ | 6,597 |
| | $ | 6,896 |
|
| Minus cash | 684 |
| | 493 |
| 264 |
| | 684 |
|
| Total debt minus cash | 6,212 |
| | 4,322 |
| 6,333 |
| | 6,212 |
|
| Total debt | 6,896 |
| | 4,815 |
| 6,597 |
| | 6,896 |
|
| Plus equity | 18,283 |
| | 17,159 |
| 19,344 |
| | 18,283 |
|
| Minus cash | 684 |
| | 493 |
| 264 |
| | 684 |
|
| Total debt plus equity minus cash | $ | 24,495 |
| | $ | 21,481 |
| $ | 25,677 |
| | $ | 24,495 |
|
| Cash-adjusted debt-to-capital ratio | 25 | % | | 20 | % | 25 | % | | 25 | % |
Capital Requirements
Capital Spending
Our approved capital, investment and exploration spending budget for 20132014 is $5,183$5,882 million. Additional details related to the 2013this 2014 budget are discussed in Outlook.
Other Expected Cash Outflows
We plan to make contributions of up to $64 million to our funded pension plans during 2013. As of December 31, 2012, $200 million of commercial paper and $184 million of our long-term debt is due in the next twelve months.
Dividends of $0.68 per common share or $480 million were paid during 2012 reflecting quarterly dividends of $0.17 per share. On January 25, 2013, we announced that our Board of Directors had declared a dividend of $0.17 cents per share on Marathon Oil common stock, payable March 11, 2013, to stockholders of record at the close of business on February 20, 2013.
Share Repurchase Program
Since January 2006,In 2013, our Board of Directors hasincreased the authorization for repurchases of our common stock by $1.2 billion, bringing the total authorized a common share repurchase program totaling $5 billion.to $6.2 billion of which $2.5 billion is remaining. As of December 31, 20122013, we had repurchased 7892 million common shares at a cost of $3,222$3,722 million, with 6614 million shares purchased for $2,922acquired at a cost of $500 million prior toduring the spin-offthird quarter of our downstream business and2013, 12 million shares acquired at a cost of $300 million in the third quarter of 2011.2011 and 66 million shares purchased for $2,922 million prior to the spin-off of our downstream business. As previously discussed, a portion of the proceeds from the sale of our interest in Angola Block 31 will be used to repurchase $500 million of common stock. Purchases under the repurchase program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.
Other Expected Cash Outflows
We plan to make contributions of up to $77 million to our funded pension plans during 2014, and $11 million of that amount was paid in January 2014. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $74 million and $19 million in 2014. As of December 31, 2013, $135 million of commercial paper and $68 million of our long-term debt is due in the next twelve months.
Dividends of $508 million were paid during 2013 reflecting quarterly dividends of $0.17 per share in the first two quarters of the year and $0.19 per share in the last two quarters for a per share increase of 12 percent. On January 29, 2014, we announced that our Board of Directors had declared a dividend of $0.19 cents per share on Marathon Oil common stock, payable March 10, 2014, to stockholders of record at the close of business on February 19, 2014.
Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The discussion of liquidity above also
contains forward-looking statements regarding expected capital, investmentthe use of proceeds from the sale of our interest in Angola Block 31, the timing and amount of repurchasing additional common stock and the timing of closing the sale of our interest in Angola Block 32. The expectations with respect to the use of proceeds from the sale of our interest in Angola Block 31 and the timing and amount of repurchasing additional common stock could be affected by changes in the prices and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our exploration spendingor production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and other operating and economic considerations. The sale of our interest in Angola Block 32 is subject to customary closing conditions. The discussion of liquidity above also contains forward-looking statements regarding planned funding of our pension plans. The forward-looking statements about our capital, investment and exploration budgetplans, which are based on current expectations, estimates and projections and are not guarantees of futureactual performance. The forward-looking statements about our common share repurchase program are based on current expectations, estimates and projections and are not guarantees of future
performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and bitumen upgrading operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2012.2013.
| | | (In millions) | Total | | 2013 | | 2014- 2015 | | 2016- 2017 | | Later Years | Total | | 2014 | | 2015- 2016 | | 2017- 2018 | | Later Years |
Short and long-term debt (excludes interest)(a) | $ | 6,853 |
| | $ | 384 |
| | $ | 1,141 |
| | $ | 688 |
| | $ | 4,640 |
| $ | 6,572 |
| | $ | 203 |
| | $ | 1,068 |
| | $ | 1,536 |
| | $ | 3,765 |
|
| Lease obligations | 237 |
| | 43 |
| | 71 |
| | 52 |
| | 71 |
| 235 |
| | 46 |
| | 78 |
| | 44 |
| | 67 |
|
| Purchase obligations: | | | | | | | | | | | | | | | | | | |
Oil and gas activities(b) | 993 |
| | 539 |
| | 342 |
| | 47 |
| | 65 |
| 1,294 |
| | 742 |
| | 391 |
| | 74 |
| | 87 |
|
Service and materials contracts(c) | 1,139 |
| | 218 |
| | 229 |
| | 174 |
| | 518 |
| 925 |
| | 192 |
| | 231 |
| | 100 |
| | 402 |
|
| Transportation and related contracts | 1,427 |
| | 210 |
| | 318 |
| | 231 |
| | 668 |
| 1,345 |
| | 211 |
| | 330 |
| | 201 |
| | 603 |
|
Drilling rigs and fracturing crews | 1,417 |
| | 709 |
| | 488 |
| | 220 |
| | — |
| 1,037 |
| | 554 |
| | 461 |
| | 22 |
| | — |
|
| Other | 216 |
| | 66 |
| | 80 |
| | 26 |
| | 44 |
| 237 |
| | 42 |
| | 57 |
| | 32 |
| | 106 |
|
| Total purchase obligations | 5,192 |
| | 1,742 |
| | 1,457 |
| | 698 |
| | 1,295 |
| 4,838 |
| | 1,741 |
| | 1,470 |
| | 429 |
| | 1,198 |
|
Other long-term liabilities reported in the consolidated balance sheet(d)(e) | 1,131 |
| | 122 |
| | 241 |
| | 162 |
| | 606 |
| 1,258 |
| | 181 |
| | 276 |
| | 244 |
| | 557 |
|
Total contractual cash obligations(e)(f) | $ | 13,413 |
| | $ | 2,291 |
| | $ | 2,910 |
| | $ | 1,600 |
| | $ | 6,612 |
| $ | 12,903 |
| | $ | 2,171 |
| | $ | 2,892 |
| | $ | 2,253 |
| | $ | 5,587 |
|
| |
(a) | We anticipate cash payments for interest of $310$299 million for 2013, $6022014, $596 million for 2014-2015, $5862015-2016, $520 million for 2016-20172017-2018 and $2,835$2,619 million for the remaining years for a total of $4,333$4,034 million. |
| |
(b) | Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately. |
| |
(c) | Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services. |
| |
(d) | Some contracts may be canceled at an amount less than the contract amount. Were we to elect that option where possible at December 31, 2013 our minimum commitment would be $905 million. |
| |
(e) | Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2022.2023. Also includes amounts for uncertain tax positions. |
| |
(e)(f)
| This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1,783$2,096 million. See Item 8. Financial Statements and Supplementary Data – Note 18 to the consolidated financial statements. |
Transactions with Related Parties
We own a 63 percent working interest in the Alba field offshore E.G. Onshore E.G., we own a 52 percent interest in an LPG processing plant, a 60 percent interest in an LNG production facility and a 45 percent interest in a methanol production plant, each through equity method investees. We sell our natural gas from the Alba field to these equity method investees as the feedstock for their production processes. The methanol that is produced is then sold through another equity method investee.
Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under accounting principles generally accepted in the U.S. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.
We will issue stand alone letters of credit when required by a business partner. Such letters of credit outstanding at December 31, 2013, 2012, 2011 and 20102011 aggregated $119 million, $139 million, $231 million, and $439$231 million. Most of the letters of credit are in support of obligations recorded in the consolidated balance sheet. For example, they are issued to counterparties to insure our payments for outstanding company debt and future abandonment liabilities and prior to June 30, 2011, crude purchases by our downstream business which we spun-off on that date. The decline in the level of our outstanding letters of credit in 2011 is primarily related to the spin-off of our downstream business.liabilities.
Outlook
Budget
Our Board of Directors approved a capital, investment and exploration spending budget of $5,183$5,882 million for 2013,2014, including budgeted capital expenditures of $5,003 million.$5,777 million. Our capital, investment and exploration spending budget is broken down by reportable segment in the table below.
|
| | | | | |
| (In millions) | 2014 Budget | Percent of Total |
| North America E&P | $ | 4,241 |
| 72 | % |
| International E&P | 1,242 |
| 21 | % |
| Oil Sands Mining | 294 |
| 5 | % |
| Segment total | 5,777 |
| 98 | % |
| Corporate and other | 105 |
| 2 | % |
| Total capital, investment and exploration spending budget | $ | 5,882 |
| 100 | % |
We continue to focus on growing profitable reserves and production worldwide. In 2014, we are accelerating drilling activity in 2013 continues to be our three key U.S. liquids-rich growth assets, with about one-thirdunconventional resource plays: the Eagle Ford, Bakken and Oklahoma resource basins, which account for approximately 60 percent of our overallbudget. The majority of spending in our unconventional resource plays is intended for drilling. With an increased number of rigs in each of these areas, we plan to drill more net wells in these areas than in any previous year. We also have dedicated a portion of our capital budget in these areas to facility construction and recompletions. In our conventional assets, we will follow a disciplined spending plan that is intended to provide stable production,with approximately 23 percent of our budget allocated to the Eagle Ford shale playdevelopment of these assets worldwide. We also plan to either drill or participate in south Texas. Further detail8 to 10 exploration wells throughout our portfolio, with 10 percent of our budget by segment and asset lifecycle is presented below.allocated to exploration projects. For additional information about expected exploration and development activities on specific assets see Item 1. Business.
Exploration and Production
Our worldwide E&P budget for 2013 is $4,740 million. Our E&P strategy is based on three key elements: a solid portfolio of base assets that generates significant cash flow, a defined set of growth assets that provides low risk profitable growth and a balanced exploration program targeting significant value creation.
Almost three-fourths, or $3,418 million of the budget is allocated to our growth assets. Of that, $1,940 million is allocated to the Eagle Ford shale play, including planned drilling of 275 - 320 gross (215 - 250 net) operated wells and $190 million for central batteries and pipeline construction. Additionally, we plan to spend nearly $800 million in the Bakken shale in North Dakota and $150 million in the Oklahoma Resource Basins. We plan to drill 190 - 220 gross (65 - 70 net) wells in the Bakken shale and 42 - 50 gross (15 - 19 net) wells in the Oklahoma Resource Basins. Approximately $540 million of our 2013 budget is allocated to other development activities, such as Angola Blocks 31 and 32, the Kurdistan Region of Iraq and Canadian in-situ development.
We plan to spend $872 million on our base E&P assets to provide stable production, income and cash flow. These assets include production operations in Norway, the Gulf of Mexico, U.S. conventional oil and gas plays, E.G., the U.K. and Libya. We will continue to stress a disciplined investment plan and maintain a competitive cost structure, with a continued emphasis on high operational availability, for our base assets.
Our 2013 budget includes $450 million for selective investment in a balanced exploration program. Planned activity will include conducting seismic surveys in Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq, Norway and the deepwater Gulf of Mexico. We plan to drill 10 - 13 gross (3 - 5 net) wells on these prospects and expect to operate three to four of the gross wells.
The above discussion includes forward-looking statements with respect to anticipatedprojected spending and investment in exploration and development activities under the 2014 capital, investment and exploration spending budget, accelerated rig and drilling activity in the Eagle Ford, Bakken, and Oklahoma resource basins, and future exploratory and development drilling activity, investments in new and existing resource plays, central batteries and pipeline construction projects, and potential development projects.activity. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products,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, availability of materials and labor, other risks associated with construction projects, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. The foregoingThese forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals or permits. The development projects could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Oil Sands MiningSales Volumes
The OSM segment budget for We expect to increase our U.S. resource plays' net sales volumes by more than 30 percent in 2014 compared to 2013, is $262 million. The excluding dispositions. In addition, we expect total production growth to be approximately 4 percent in 2014 versus 2013, budget includes funds for debottlenecking projects, Quest CCS excluding dispositions and other capital expenditures.Libya.
CorporateAcquisitions and Other
The remaining $180 million of our 2013 budget is approximately two-thirds capitalized interest on ongoing projects and one-third other corporate activities. Additionally, $1 million is budgeted for our IG segment.
TransactionsDispositions
Excluded from our budget are the impacts of our acquisitions and dispositions.dispositions not previously announced. We continually evaluate ways to optimize our portfolio for profitable growth through acquisitions and dispositions, with adivestitures and exceeded our previously stated goal of divesting between $1.5 billion and $3$3.0 billion of assets over the period of 2011 through 2013. For the two-yearthree-year period ended December 31, 20122013, we closed or entered into agreements for approximately $1.3$3.5 billion in divestitures, of which $785 million were completed.$2.1 billion is from the sales of our Angola assets. The remaining $545 millionsale of asset sales were completed by our interest in Angola Block 31 closed in February 22,2014 and the sale of our interest in Angola Block 32 is expected to close in the first quarter of 2014.
In December 2013,. Additionally, we have engagedannounced the commencement of efforts to market our assets in discussionsthe North Sea, both in the U.K. and Norway, which would simplify and concentrate our portfolio to higher margin growth opportunities and increase our production growth rate.
The above discussion includes forward-looking statements with respect to a potentialour percentage growth rate of production, production available for sale, the sale of a portionour interest in Angola Block 32 and the possible sale of our 20 percent interest in the AOSP. Given the uncertainty of such a transaction, potential proceeds have not been included in our previously stated divestiture goal.U.K. and Norway assets. Some factors
The forward-looking statements aboutwhich could potentially affect our capital, investmentpercentage growth rate of production and exploration budget and the goal of divesting between $1.5 and $3 billion of assets over the period of 2011 through 2013 are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materiallyproduction available for sale include prices ofpricing, supply and demand for crude oilliquid hydrocarbons and natural gas, actionsthe amount of competitors, disruptionscapital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, the inability to obtain or interruptions of our productiondelay in obtaining necessary government or bitumen miningthird-party approvals and upgrading operations due to the shortage of skilled labor andpermits, 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 above discussion also 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 timing of closing the sale of our interest in Block 32 is subject to customary closing conditions. The possible sale of our U.K. and Norway assets is subject to the identification of one or more buyers, successful negotiations, board approval and execution of definitive agreements. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies
We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, and production processes.
Legislation and regulations pertaining to climate change and greenhouse gas emissions have the potential to materially adversely impact our business, financial condition, results of operations and cash flows, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our customers. For additional information see Item 1A. Risk Factors.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required. For additional information see Item 8. Financial Statements and Supplementary Data – Note 2425 to the consolidated financial statements.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We comply with all legal requirements regarding the environment, but since not all costs are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
For more information on environmental regulations that impact us, or could impact us, see Item 1. Business – Environmental, Health and Safety Matters, Item 1A. Risk Factors and Item 3. Legal Proceedings and Item 1A. Risk Factors.Proceedings.
Critical Accounting Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.
Estimated Quantities of Net Reserves
The estimation of quantities of net reserves is a highly technical process performed by our engineers for liquid hydrocarbons and natural gas and by outside consultants for synthetic crude oil, which is based upon several underlying assumptions that are subject to change. Estimates of reserves may change, either positively or negatively, as additional information becomes available and as contractual, operational, economic and political conditions change. We evaluate our reserves using drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Reserve estimates are based upon an unweighted average of commodity prices in the prior 12-month period, using the closing prices on the first day of each month. These prices are not indicative of future market conditions. For a discussion of our reserve estimation process, including the use of third-party audits, see Item 1. Business.
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved liquid hydrocarbon, natural gas and synthetic crude oil reserves.
The existence and the estimated amount of reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. Additionally, both the expected future cash flows to be generated by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income available to realize deferred tax assets also rely, in part, on estimates of quantities of net reserves.
Depreciation and depletion of liquid hydrocarbon, natural gas and synthetic crude oil producing properties is determined by the units-of-production method and could change with revisions to estimated proved reserves. Over the past three years, the impact on our depreciation and depletion rate due to revisions of previous reserve estimates has not been significant to eitherany of our E&P or our OSM segments. For our E&P segment,The following table illustrates, on average, a five percent increase in the amountsensitivity of proved liquid hydrocarbon and natural gas reserves would lower the depreciation and depletion rate by approximately $0.67 per boe, which would increase pretax income by approximately $106 million annually, based on 2012 production. Conversely, on average, a five percent decrease in the amount of proved liquid hydrocarbon and natural gas reserves would increase the depreciation and depletion rate by approximately $0.74each segment's units-of-production DD&A per boe and would result in a decrease in pretax income of approximately $117 million annually,to a hypothetical five percent change in 2013 proved reserves based on 20122013 production. For our OSM segment,
|
| | | | | | | | | | | | | | | |
| | Impact of a Five Percent Increase in Proved Reserves | | Impact of a Five Percent Decrease in Proved Reserves |
| (In millions, except per boe) | DD&A per boe | | Pretax Income | | DD&A per boe | | Pretax Income |
| North America E&P | $ | (1.25 | ) | | $ | 92 |
| | $ | 1.38 |
| | $ | (101 | ) |
| International E&P | (0.35 | ) | | 30 |
| | 0.38 |
| | (33 | ) |
| Oil Sands Mining | $ | (0.46 | ) | | $ | 7 |
| | $ | 0.73 |
| | $ | (11 | ) |
Asset Retirement Obligations
We have material legal, regulatory and contractual obligations to remove and dismantle long-lived assets and to restore land or seabed at the end of oil and gas production operations, including bitumen mining operations. A liability equal to the fair value of such obligations and a corresponding capitalized asset retirement cost are recognized on average,the balance sheet in the period in which the legal obligation is incurred and a five percent increasereasonable estimate of fair value can be made. The capitalized asset retirement cost is depreciated using the units-of-production method and the discounted liability is accreted over the period until the obligation is satisfied, the impacts of which are recognized as DD&A in estimated proved synthetic crude oil reserves would lower the depreciationconsolidated statements of income. In many cases, the satisfaction and depletion rate by approximately $0.86 per barrelsubsequent discharge of these liabilities is projected to occur many years, or even decades, into the future. Furthermore, the legal, regulatory and would result in an increase in pretax incomecontractual requirements often do not provide specific guidance regarding removal practices and the criteria that must be fulfilled when the removal and/or restoration event actually occurs.
Estimates of approximately $13 million annually,retirement costs are developed for each property based on 2012 production. On average,numerous factors, such as the scope of the dismantlement, timing of settlement, interpretation of legal, regulatory and contractual requirements, type of production and processing structures, depth of water (if applicable), reservoir characteristics, depth of the reservoir, market demand for equipment, currently available dismantlement and restoration procedures and consultations with construction and engineering professionals. Inflation rates and credit-adjusted-risk-free interest rates are then applied to estimate the fair values of the obligations. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a five percent decreasecorresponding adjustment made to the related asset balance. See Item 8. Financial Statements and Supplementary Data – Note 18 to the consolidated financial statements for disclosures regarding our asset retirement obligation estimates.
An estimate of the sensitivity to net income if other assumptions had been used in estimated proved synthetic crude oil reserves would increaserecording these liabilities is not practical because of the depreciationnumber of obligations that must be assessed, the number of underlying assumptions and depletion rate by approximately $0.38 per barrel and would result in a decrease in pretax incomethe wide range of approximately $6 million annually, based on 2012 production.possible assumptions.
Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value, amountor range of present values, using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and doesdo not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use a market or income approach for recurring fair value measurements and endeavor to use the best information available. See Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
impairment assessments of long-lived assets;
impairment assessments of goodwill;
allocation of the purchase price paid to acquire businesses to the assets acquired and liabilities assumed; and
recorded value of derivative instruments.
Impairment Assessments of Long-Lived Assets and Goodwill
The need to test long-lived assets and goodwill for impairment can be based on several indicators, including a significant reduction in prices of liquid hydrocarbons, natural gas or synthetic crude oil, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which the property is located.
Long-lived assets used in operationsuse are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field for our North America E&P and International E&P assets and at the project level for OSM assets. If the sum of the undiscounted estimated pretax cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value.
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level.
Fair value calculated for the purpose of testing our long-lived assets and goodwill for impairment is estimated using the expected present value of expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:
Future liquid hydrocarbon, natural gas and synthetic crude oil prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates, and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies, and vehicle stocks. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in liquid hydrocarbon, natural gas and synthetic crude oil prices and estimates of such future prices are inherently imprecise.
Estimated quantities of liquid hydrocarbons, natural gas and synthetic crude oil. Such quantities are based on a combination of proved and probable reservesreserve categories such that the combined volumes represent the most likely expectation of recovery. By definition, probable reserve estimates are less precise than proved reserve estimates.
Expected timing of production. Production forecasts are the outcome of engineer studies which estimate proved and probable reserves.reserves, as well as expected capital development programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews.
Discount rate commensurate with the risks involvedinvolved. . We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.
Future capital requirements. Our estimates of future capital requirements are based onupon a combination of authorized spending and internal forecasts.
We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.
An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the numerous assumptions (e.g. reserves, pricing and discount rates) that can materially affect our estimates. That is, unfavorable adjustments to some of the above listed assumptions may be offset by favorable adjustments in other assumptions.
Acquisitions
In accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. The excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired is recorded as goodwill. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment and identifiable intangible assets. The most significant assumptions relate to the estimated fair values allocated to proved and unproved liquid hydrocarbon, natural gas and synthetic crude oil properties. Estimated fair values assigned to assets acquired can have a significant effect on our results of operations in the future. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance. During 20112013, 2012 and 2012,2011, we completed several business combinations in the Eagle Ford, shale thatthe purchase prices of which were allocated to the assets acquired and liabilities assumed based on their estimated fair values (see Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements).
The fair values used to allocate the purchase price of an acquisition are often estimated using the expected present value of future cash flows method, which requires us to estimate reserves as described above under Estimated Quantities of Net Reserves, project related future cash inflows and outflows and apply an appropriate discount rate. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value.
Derivatives
We record all derivative instruments at fair value. Fair value estimatesmeasurements for all our derivative instruments are based on observable market-based inputs that are corroborated by market data and are discussed in Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures aboutAbout Market Risk.
Income Taxes
We are subject to income taxes in numerous taxing jurisdictions worldwide. Estimates of income taxes to be recorded involve interpretation of complex tax laws and assessment of the effects of foreign taxes on our U.S. federal income taxes.
We have recorded deferred tax assets and liabilities for temporary differences between book basis and tax basis, tax credit carryforwards and operating loss carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider the preponderance of evidence concerning the realization of the deferred tax asset. We must consider any prudent and feasible tax planning strategies that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets, if we can implement the strategies and we expect to implement them in the event the forecasted conditions actually occur. Assumptions related to the permanent reinvestment of the earnings of our foreign subsidiaries are reconsidered quarterly to give effect to changes in our portfolio of producing properties and in our tax profile.
Our net deferred tax assets, after valuation allowances, are expected to be realized through our future taxable income and the reversal of temporary differences. Numerous judgments and assumptions are inherent in the estimation of future taxable income, including factors such as future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices) and the assessment of the effects of foreign taxes on our U.S. federal income taxes. The estimates and assumptions used in determining future taxable income are consistent with those used in our planning and capital investment reviews. We consider proved and, in some cases, probable and possible reservesa combination of reserve categories related to our existing producing properties, as well as estimated quantities of liquid hydrocarbon, natural gas and synthetic crude oil related to undeveloped discoveries if, in our judgment, it is likely that development plans will be approved in the foreseeable future. Assumptions regarding our ability to realize the U.S. federal benefit of foreign tax credits are based on certain estimates concerning future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and our tax profile in the year that such credits may be claimed.
Pension and Other Postretirement Benefit Obligations
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:
the discount rate for measuring the present value of future plan obligations;
the expected long-term return on plan assets;
the rate of future increases in compensation levels; and
health care cost projections.
We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our funded U.S. pension plans and our unfundedother U.S. retiree health carepostretirement benefit plans due to the different projected benefit payment patterns. In determining the assumed discount rates, our methods include a review of market yields on high-quality corporate debt and use of our third-party actuary's discount rate model. This model calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield curve derived from AA bond yields. The yield curve represents a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used are rated AA or higher by a recognized rating agency, only non-callable bonds are included and outlier bonds (bonds that have a yield to maturity that significantly deviates from the average yield within each maturity grouping) are removed. Each issue is required to have at least $250 million par value outstanding. The constructed yield curve is based on those bonds representing the 50 percent highest yielding issuanceissuances within each defined maturity group.
Of the assumptions used to measure the yearend obligations and estimated annual net periodic benefit cost as of December 31, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. DecreasingThe hypothetical impacts of a 0.25 percent change in the discount rates of 3.444.28 percent for our U.S. pension plans and 4.064.85 percent for our other U.S. postretirement benefit plans by 0.25 would increase pension obligations and other postretirement benefit plan obligations by $52 million and $9 million and would increase annual defined benefit pension expense by $5 million and would not have a significant impact on other postretirement benefit plan expense.is summarized in the table below:
|
| | | | | | | | | | | | | | | |
| | Impact of a 0.25 Percent Increase in Discount Rate | | Impact of a 0.25 Percent Decrease in Discount Rate |
| (In millions) | Obligation | | Expense | | Obligation | | Expense |
| U.S. pension plans | $ | (38 | ) | | $ | (4 | ) | | $ | 40 |
| | $ | 4 |
|
| Other U.S. postretirement benefit plans | $ | (7 | ) | | $ | — |
| | $ | 8 |
| | $ | — |
|
The asset rate of return assumption for the funded U.S. plan considers the plan's asset mix of the plans (currently targeted at approximately 6555 percent equity and high yieldhigh-yield bonds and 3545 percent other fixed income securities for the U.S. funded pension plans and 70 percent equity securities and 30 percent fixed income securities for the international funded pension plans)securities), past performance and other factors. Certain
components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Our long-term asset rate of return assumption is compared to those of other companies and to our historical returns for reasonableness. Decreasing the 7.256.75 percent asset rate of return assumption by 0.25 would not have a significant impact on our defined benefit pension expense. Effective January 1, 2014, the expected long-term rate of return was changed from 7.25 percent to 6.75 percent and this change also did not have a significant impact.
Compensation change assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans. Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.
Item 8. Financial Statements and Supplementary Data – Note 20 to the consolidated financial statements includes detailed information about the assumptions used to calculate the components of our annual defined benefit pension and other postretirement plan expense, as well as the obligations and accumulated other comprehensive income reported on the consolidated balance sheets.
Contingent Liabilities
We accrue contingent liabilities for environmental remediation, tax deficiencies related to operating taxes, and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation;interpretation, additional information on the extent and nature of site contamination;contamination, and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances, outside legal counsel is utilized.
We generally record losses related to these types of contingencies as cost of revenuesother operating expense or general and administrative expensesexpense in the consolidated statements of income, except for tax contingencies unrelated to income taxes, which are recorded as taxes other taxes.than income. For additional information on contingent liabilities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.
Accounting Standards Not Yet Adopted
In FebruaryJune 2013, the FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof ) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. These disclosures are effective for us beginning in the first quarter of 2013.2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. Adoption of this amendmentaccounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.
In December 2011February 2013, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosuresto provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are intendedseparately addressed within U.S. GAAP. An entity is required to enable financial statement usersmeasure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to evaluatepay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. These disclosures arereceivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 20132014 and mustshould be madeapplied retrospectively for comparable periods.those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. Adoption of this amendmentaccounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.
Item 7A. Quantitative and Qualitative Disclosures aboutAbout Market Risk
We are exposed to market risks related to the volatility of liquid hydrocarbon, natural gas and synthetic crude oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. We employ various strategies, including the use of financial derivative instruments, to manage the risks related to these fluctuations.
We are at risk for changes in the fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction.
We believe that our use of derivative instruments, along with our risk assessment procedures and internal controls, does not expose us to material adverse consequences. While the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods, we believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.
See Item 8. Financial Statements and Supplementary Data – NoteNotes 15 and 16 to the consolidated financial statementstatements for more information about the fair value measurement of our derivatives, as well as the amounts recorded in our consolidated balance sheets and statements of income for those which qualify as hedges and those not designated as hedges.the related notional amounts.
Commodity Price Risk
Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. However, management will occasionallyperiodically protect prices on forecasted sales, as deemed appropriate. We use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our different businesses. In AugustOur consolidated results for 2013 and 2012 we entered intowere impacted by crude oil derivatives related to a portion of our forecast U.S.North America E&P crude oil sales, throughall of which had terms that ended in December 31, 2013 as shown in the table below.
|
| | | |
| Remaining Term | Bbls per Day | Weighted Average Price per Bbl | Benchmark |
| Swaps | | | |
| January 2013 - December 2013 | 20,000 | $96.29 | West Texas Intermediate |
| January 2013 - December 2013 | 25,000 | $109.19 | Brent |
| Option collars | | | |
| January 2013 - December 2013 | 15,000 | $90.00 floor / $101.17 ceiling | West Texas Intermediate |
| January 2013 - December 2013 | 15,000 | $100.00 floor / $116.30 ceiling | Brent |
We regularly use commodity derivative instruments in the North America E&P segment to manage natural gas price risk duringrisk. Examples would include the time that the natural gas is held inhedging of storage before it is sold or related to our supply optimization activities. We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditionstransportation assets, and in risk profiles.
Sensitivity analysis of the incremental effects on income from operations ("IFO") of hypothetical 10 percent and 25 percent increases and decreases in commodity prices on our open commodity derivative instruments, by contract type as of December 31, 2012 is provided in the following table.when appropriate, managing equity price exposure.
|
| | | | | | | | | | | | | | | |
| | Incremental Change in IFO from a Hypothetical Price Increase of
| | Incremental Change in IFO from a Hypothetical Price Decrease of
|
| | 10% | | 25% | | 10% | | 25% |
| Crude oil | | | | | | | |
| Swaps | $ | (165 | ) | | $ | (412 | ) | | $ | 165 |
| | $ | 412 |
|
| Option collars | (77 | ) | | (212 | ) | | 77 |
| | 246 |
|
| Total crude oil | (242 | ) | | (624 | ) | | 242 |
| | 658 |
|
| Natural gas | | | | | | | |
| Futures | (1 | ) | | (2 | ) | | 1 |
| | 2 |
|
| Total natural gas | (1 | ) | | (2 | ) | | 1 |
| | 2 |
|
| Total | $ | (243 | ) | | $ | (626 | ) | | $ | 243 |
| | $ | 660 |
|
Interest Rate Risk
We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the mix of fixed and floating interest rate debt in our portfolio. As of December 31, 2012,2013, we had multiple interest rate swap agreements with a total notional amount of $600$900 million at a weighted-average, LIBOR-based, floating rate of 4.70 percent with a maturity date of October 1, 2017. These interest rate swaps are designated as fair value hedges, which effectively results in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates.
At December 31, 2013, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.
Sensitivity analysis of the incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of December 31, 2012,2013, is provided in the following table.
| | | | | | Incremental | | | Incremental |
| | | | Change in | | | Change in |
| (In millions) | Fair Value | | Fair Value | Fair Value | | Fair Value |
Financial assets (liabilities): (a) | | | | | | |
| Interest rate swap agreements | $ | 21 |
| (b) | $ | 1 |
| $ | 8 |
| (b) | $ | 4 |
|
| Long-term debt, including amounts due within one year | $ | (7,610 | ) | (b) | $ | (232 | ) | $ | (6,922 | ) | (b)(c) | $ | (234 | ) |
| |
(a) | Fair values of cash and cash equivalents, receivables, commercial paper, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table. |
| |
(b) | Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities. |
At December 31, 2012, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value. | |
(c) | Excludes capital leases. |
Foreign Currency Exchange Rate Risk
We may manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in foreign currency exchange rates by locking in such rates. As of December 31, 2012,2013, our foreign currency forwards had an aggregatea notional amount of 3,0432,387 million Norwegian Kroner, atwhich served as a weighted average forward ratehedge of 5.780. These forwards hedge our current Norwegian tax liability and have settlement dates through June 2013.liability. The incremental change in the fair value onof foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at December 31, 20122013 would be $54$39 million.
Counterparty Risk
We are also exposed to financial risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed and master netting agreements are used when appropriate.
Safe Harbor
These quantitative and qualitative disclosures about market risk include forward-looking statements with respect to management’s opinion about risks associated with the use of derivative instruments. These statements are based on certain assumptions with respect to market prices and industry supply of and demand for liquid hydrocarbons, natural gas and synthetic crude oil. If these assumptions prove to be inaccurate, future outcomes with respect to our use of derivative instruments may differ materially from those discussed in the forward-looking statements.
Item 8. Financial Statements and Supplementary Data
Index
Management’s Responsibilities for Financial Statements
To the Stockholders of Marathon Oil Corporation:
The accompanying consolidated financial statements of Marathon Oil Corporation and its consolidated subsidiaries ("Marathon Oil") are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.
Marathon Oil seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organization arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.
The Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit and Finance Committee. This Committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.
|
| | | | |
/s/ Clarence P. Cazalot, Jr.Lee M. Tillman | | /s/ Janet F. ClarkJohn R. Sult | | /s/ Michael K. Stewart |
Chairman, President and
Chief Executive Officer | | Executive Vice President and Chief Financial Officer | | Vice President, Finance and
Accounting, Controller and Treasurer
|
Management’s Report on Internal Control over Financial Reporting
To the Stockholders of Marathon Oil Corporation:
Marathon Oil’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13(a) – 15(f) under the Securities Exchange Act of 1934). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the original 1992 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on the results of this evaluation, Marathon Oil’s management concluded that its internal control over financial reporting was effective as of December 31, 2012.2013.
The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 20122013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
|
| | | |
/s/ Clarence P. Cazalot, Jr.Lee M. Tillman | | /s/ Janet F. ClarkJohn R. Sult | |
Chairman, President and
Chief Executive Officer | | Executive Vice President and Chief Financial Officer | |
Report of Independent Registered Public Accounting Firm
To the Stockholders of Marathon Oil Corporation:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Marathon Oil Corporation and its subsidiaries (the "Company") at December 31, 2012,2013, and 2011,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012,2013, in conformity with accounting principles generally accepted in the United States. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012,2013, based on criteria established in the original 1992 framework in Internal Control –- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
February 22, 201328, 2014
MARATHON OIL CORPORATION
Consolidated Statements of Income
| | | (In millions, except per share data) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Revenues and other income: | | | | | | | | | | |
| Sales and other operating revenues | $ | 15,630 |
| | $ | 14,603 |
| | $ | 11,634 |
| |
| Sales to related parties | 58 |
| | 60 |
| | 56 |
| |
| Sales and other operating revenues, including related party | | $ | 12,419 |
| | $ | 12,963 |
| | $ | 10,750 |
|
| Marketing revenues | | 2,082 |
| | 2,729 |
| | 3,919 |
|
| Income from equity method investments | 370 |
| | 462 |
| | 344 |
| 423 |
| | 370 |
| | 462 |
|
| Net gain on disposal of assets | 127 |
| | 103 |
| | 766 |
| |
| Net gain (loss) on disposal of assets | | (29 | ) | | 127 |
| | 103 |
|
| Other income | 36 |
| | 54 |
| | 73 |
| 64 |
| | 32 |
| | 48 |
|
| Total revenues and other income | 16,221 |
| | 15,282 |
| | 12,873 |
| 14,959 |
| | 16,221 |
| | 15,282 |
|
| Costs and expenses: | | | | | | | | | | |
| Cost of revenues (excludes items below) | 5,219 |
| | 6,225 |
| | 4,786 |
| |
| Purchases from related parties | 248 |
| | 250 |
| | 172 |
| |
| Production | | 2,331 |
| | 2,202 |
| | 1,951 |
|
| Marketing, including purchases from related parties | | 2,072 |
| | 2,744 |
| | 3,898 |
|
| Other operating | | 439 |
| | 425 |
| | 533 |
|
| Exploration | | 988 |
| | 706 |
| | 641 |
|
| Depreciation, depletion and amortization | 2,478 |
| | 2,266 |
| | 2,056 |
| 2,790 |
| | 2,477 |
| | 2,263 |
|
| Impairments | 371 |
| | 310 |
| | 447 |
| 96 |
| | 371 |
| | 310 |
|
| General and administrative expenses | 555 |
| | 544 |
| | 491 |
| |
| Other taxes | 289 |
| | 230 |
| | 199 |
| |
| Exploration expenses | 729 |
| | 644 |
| | 498 |
| |
| Taxes other than income | | 352 |
| | 248 |
| | 193 |
|
| General and administrative | | 687 |
| | 699 |
| | 663 |
|
| Total costs and expenses | 9,889 |
| | 10,469 |
| | 8,649 |
| 9,755 |
| | 9,872 |
| | 10,452 |
|
| Income from operations | 6,332 |
| | 4,813 |
| | 4,224 |
| 5,204 |
| | 6,349 |
| | 4,830 |
|
| Net interest and other | (219 | ) | | (107 | ) | | (75 | ) | (274 | ) | | (219 | ) | | (107 | ) |
| Loss on early extinguishment of debt | — |
| | (279 | ) | | (92 | ) | — |
| | — |
| | (279 | ) |
| Income from continuing operations before income taxes | 6,113 |
| | 4,427 |
| | 4,057 |
| 4,930 |
| | 6,130 |
| | 4,444 |
|
| Provision for income taxes | 4,531 |
| | 2,720 |
| | 2,175 |
| 3,337 |
| | 4,517 |
| | 2,726 |
|
| Income from continuing operations | 1,582 |
| | 1,707 |
| | 1,882 |
| 1,593 |
| | 1,613 |
| | 1,718 |
|
| Discontinued operations | — |
| | 1,239 |
| | 686 |
| 160 |
| | (31 | ) | | 1,228 |
|
| Net income | $ | 1,582 |
| | $ | 2,946 |
| | $ | 2,568 |
| $ | 1,753 |
| | $ | 1,582 |
| | $ | 2,946 |
|
| Per Share Data | | | | | | | | | | |
| Basic: | | | | | | | | | | |
| Income from continuing operations | $ | 2.24 |
| | $ | 2.40 |
| | $ | 2.65 |
| $ | 2.26 |
| | $ | 2.28 |
| | $ | 2.42 |
|
| Discontinued operations | $ | — |
| | $ | 1.75 |
| | $ | 0.97 |
| $ | 0.23 |
| | $ | (0.04 | ) | | $ | 1.73 |
|
| Net income | $ | 2.24 |
| | $ | 4.15 |
| | $ | 3.62 |
| $ | 2.49 |
| | $ | 2.24 |
| | $ | 4.15 |
|
| Diluted: | | | | | | | | | | |
| Income from continuing operations | $ | 2.23 |
| | $ | 2.39 |
| | $ | 2.65 |
| $ | 2.24 |
| | $ | 2.27 |
| | $ | 2.41 |
|
| Discontinued operations | $ | — |
| | $ | 1.74 |
| | $ | 0.96 |
| $ | 0.23 |
| | $ | (0.04 | ) | | $ | 1.72 |
|
| Net income | $ | 2.23 |
| | $ | 4.13 |
| | $ | 3.61 |
| $ | 2.47 |
| | $ | 2.23 |
| | $ | 4.13 |
|
| Dividends | $ | 0.68 |
| | $ | 0.80 |
| | $ | 0.99 |
| $ | 0.72 |
| | $ | 0.68 |
| | $ | 0.80 |
|
| Weighted average shares: | | | | | | | | | | |
| Basic | 706 |
| | 710 |
| | 710 |
| 705 |
| | 706 |
| | 710 |
|
| Diluted | 710 |
| | 714 |
| | 712 |
| 709 |
| | 710 |
| | 714 |
|
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income
|
| | | | | | | | | | | |
| (In millions) | 2012 | | 2011* | | 2010 |
| Net income | $ | 1,582 |
| | $ | 2,946 |
| | $ | 2,568 |
|
| Other comprehensive income (loss) | | | | | |
| Postretirement and postemployment plans | | | | | |
| Change in actuarial loss and other | (97 | ) | | 16 |
| | (76 | ) |
| Income tax benefit on postretirement and | |
| | |
| | |
| postemployment plans | 35 |
| | 20 |
| | 7 |
|
| Postretirement and postemployment plans, net of tax | (62 | ) | | 36 |
| | (69 | ) |
| Derivative hedges | | | | | |
| Net unrecognized gain | 1 |
| | 9 |
| | 5 |
|
| Income tax benefit (provision) on derivative hedges | — |
| | (4 | ) | | 1 |
|
| Derivative hedges, net of tax | 1 |
| | 5 |
| | 6 |
|
| Foreign currency translation and other | | | | | |
| Unrealized gain (loss) | 1 |
| | (1 | ) | | — |
|
| Income tax provision on foreign currency translation and other | (3 | ) | | — |
| | — |
|
| Foreign currency translation and other, net of tax | (2 | ) | | (1 | ) | | — |
|
| Other comprehensive income (loss) | (63 | ) | | 40 |
| | (63 | ) |
| Comprehensive income | $ | 1,519 |
| | $ | 2,986 |
| | $ | 2,505 |
|
*See Note 1 – Summary of Principal Accounting Policies – Revision for additional information.
|
| | | | | | | | | | | |
| (In millions) | 2013 | | 2012 | | 2011 |
| Net income | $ | 1,753 |
| | $ | 1,582 |
| | $ | 2,946 |
|
| Other comprehensive income (loss) | | | | | |
| Postretirement and postemployment plans | | | | | |
| Change in actuarial loss and other | 296 |
| | (97 | ) | | 16 |
|
| Income tax benefit (provision) | (112 | ) | | 35 |
| | 20 |
|
| Postretirement and postemployment plans, net of tax | 184 |
| | (62 | ) | | 36 |
|
| Derivative hedges | | | | | |
| Net unrecognized gain | 1 |
| | 1 |
| | 9 |
|
| Income tax provision | — |
| | — |
| | (4 | ) |
| Derivative hedges, net of tax | 1 |
| | 1 |
| | 5 |
|
| Foreign currency translation and other | | | | | |
| Unrealized gain (loss) | (3 | ) | | 1 |
| | (1 | ) |
| Income tax benefit (provision) | 1 |
| | (3 | ) | | — |
|
| Foreign currency translation and other, net of tax | (2 | ) | | (2 | ) | | (1 | ) |
| Other comprehensive income (loss) | 183 |
| | (63 | ) | | 40 |
|
| Comprehensive income | $ | 1,936 |
| | $ | 1,519 |
| | $ | 2,986 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Balance Sheets | | | | December 31, | December 31, |
| (In millions, except per share data) | 2012 | | 2011 | 2013 | | 2012 |
| Assets | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | $ | 684 |
| | $ | 493 |
| $ | 264 |
| | $ | 684 |
|
| Receivables | 2,389 |
| | 1,917 |
| 2,134 |
| | 2,418 |
|
| Receivables from related parties | 27 |
| | 35 |
| |
| Inventories | 361 |
| | 361 |
| 364 |
| | 361 |
|
| Other current assets | 301 |
| | 418 |
| 213 |
| | 299 |
|
| Total current assets | 3,762 |
| | 3,224 |
| 2,975 |
| | 3,762 |
|
| Equity method investments | 1,279 |
| | 1,383 |
| 1,201 |
| | 1,279 |
|
| Property, plant and equipment, less accumulated depreciation, | |
| | |
| |
| | |
|
| depletion and amortization of $19,266 and $17,248 | 28,272 |
| | 25,324 |
| |
| depletion and amortization of $21,895 and $19,266 | | 28,145 |
| | 28,272 |
|
| Goodwill | 525 |
| | 536 |
| 499 |
| | 525 |
|
| Other noncurrent assets | 1,468 |
| | 904 |
| 2,800 |
| | 1,468 |
|
| Total assets | $ | 35,306 |
| | $ | 31,371 |
| $ | 35,620 |
| | $ | 35,306 |
|
| Liabilities | | | | | | |
| Current liabilities: | | | | | | |
| Commercial paper | $ | 200 |
| | $ | — |
| $ | 135 |
| | $ | 200 |
|
| Accounts payable | 2,285 |
| | 1,864 |
| 2,206 |
| | 2,324 |
|
| Payables to related parties | 20 |
| | 18 |
| |
| Payroll and benefits payable | 217 |
| | 193 |
| 240 |
| | 217 |
|
| Accrued taxes | 1,987 |
| | 2,015 |
| 1,445 |
| | 1,983 |
|
| Other current liabilities | 188 |
| | 163 |
| 239 |
| | 173 |
|
| Long-term debt due within one year | 184 |
| | 141 |
| 68 |
| | 184 |
|
| Total current liabilities | 5,081 |
| | 4,394 |
| 4,333 |
| | 5,081 |
|
| Long-term debt | 6,512 |
| | 4,674 |
| 6,394 |
| | 6,512 |
|
| Deferred tax liabilities | 2,432 |
| | 2,544 |
| 2,492 |
| | 2,432 |
|
| Defined benefit postretirement plan obligations | 856 |
| | 789 |
| 604 |
| | 856 |
|
| Asset retirement obligations | 1,749 |
| | 1,510 |
| 2,009 |
| | 1,749 |
|
| Deferred credits and other liabilities | 393 |
| | 301 |
| 444 |
| | 393 |
|
| Total liabilities | 17,023 |
| | 14,212 |
| 16,276 |
| | 17,023 |
|
| Commitments and contingencies |
| |
|
|
| |
|
|
| Stockholders’ Equity | | | | | | |
| Preferred stock - no shares issued or outstanding (no par value, | | | | | | |
| 26 million shares authorized) | — |
| | — |
| — |
| | — |
|
| Common stock: | | | | | | |
| Issued – 770 million and 770 million shares (par value $1 per share, | | | | | | |
| 1.1 billion shares authorized) | 770 |
| | 770 |
| 770 |
| | 770 |
|
| Securities exchangeable into common stock – no shares issued | |
| | |
| |
| | |
|
| or outstanding (no par value, 29 million shares authorized) | — |
| | — |
| — |
| | — |
|
| Held in treasury, at cost – 63 million and 66 million shares | (2,560 | ) | | (2,716 | ) | |
| Held in treasury, at cost – 73 million and 63 million shares | | (2,903 | ) | | (2,560 | ) |
| Additional paid-in capital | 6,616 |
| | 6,680 |
| 6,592 |
| | 6,616 |
|
| Retained earnings | 13,890 |
| | 12,788 |
| 15,135 |
| | 13,890 |
|
| Accumulated other comprehensive loss | (433 | ) | | (370 | ) | (250 | ) | | (433 | ) |
| Total equity of Marathon Oil stockholders | 18,283 |
| | 17,152 |
| |
| Noncontrolling interest | — |
| | 7 |
| |
| Total equity | 18,283 |
| | 17,159 |
| |
| Total liabilities and equity | $ | 35,306 |
| | $ | 31,371 |
| |
| Total stockholders' equity | | 19,344 |
| | 18,283 |
|
| Total liabilities and stockholders' equity | | $ | 35,620 |
| | $ | 35,306 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows
|
| | | | | | | | | | | |
| (In millions) | 2013 | | 2012 | | 2011 |
| Increase (decrease) in cash and cash equivalents | | | | | |
| Operating activities: | | | | | |
| Net income | $ | 1,753 |
| | $ | 1,582 |
| | $ | 2,946 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Discontinued operations | (160 | ) | | 31 |
| | (1,228 | ) |
| Loss on early extinguishment of debt | — |
| | — |
| | 279 |
|
| Deferred income taxes | (60 | ) | | (224 | ) | | (193 | ) |
| Depreciation, depletion and amortization | 2,790 |
| | 2,477 |
| | 2,263 |
|
| Impairments | 96 |
| | 371 |
| | 310 |
|
| Pension and other postretirement benefits, net | 45 |
| | (31 | ) | | 64 |
|
| Exploratory dry well costs and unproved property impairments | 798 |
| | 457 |
| | 357 |
|
| Net (gain) loss on disposal of assets | 29 |
| | (127 | ) | | (103 | ) |
| Equity method investments, net | 12 |
| | 11 |
| | 47 |
|
| Changes in: | | | | | |
| Current receivables | 277 |
| | (502 | ) | | 9 |
|
| Inventories | (16 | ) | | (32 | ) | | 33 |
|
| Current accounts payable and accrued liabilities | (616 | ) | | 71 |
| | 489 |
|
| All other operating, net | 143 |
| | (48 | ) | | 168 |
|
| Net cash provided by continuing operations | 5,091 |
| | 4,036 |
| | 5,441 |
|
| Net cash provided by (used in) discontinued operations | 179 |
| | (19 | ) | | 1,083 |
|
| Net cash provided by operating activities | 5,270 |
| | 4,017 |
| | 6,524 |
|
| Investing activities: | | | | | |
| Acquisitions, net of cash acquired | (74 | ) | | (1,033 | ) | | (4,470 | ) |
| Additions to property, plant and equipment | (4,766 | ) | | (4,593 | ) | | (2,986 | ) |
| Disposal of assets | 450 |
| | 467 |
| | 518 |
|
| Investments - return of capital | 61 |
| | 57 |
| | 59 |
|
| Investing activities of discontinued operations | (227 | ) | | (347 | ) | | (802 | ) |
| All other investing, net | 35 |
| | 10 |
| | 14 |
|
| Net cash used in investing activities | (4,521 | ) | | (5,439 | ) | | (7,667 | ) |
| Financing activities: | | | | | |
| Commercial paper, net | (65 | ) | | 200 |
| | — |
|
| Borrowings | — |
| | 1,997 |
| | — |
|
| Debt issuance costs | — |
| | (21 | ) | | — |
|
| Debt repayments | (182 | ) | | (145 | ) | | (2,877 | ) |
| Purchases of common stock | (500 | ) | | — |
| | (300 | ) |
| Dividends paid | (508 | ) | | (480 | ) | | (567 | ) |
| Financing activities of discontinued operations | — |
| | — |
| | 2,916 |
|
| Distribution in spin-off | — |
| | — |
| | (1,622 | ) |
| All other financing, net | 93 |
| | 49 |
| | 155 |
|
| Net cash provided by (used in) financing activities | (1,162 | ) | | 1,600 |
| | (2,295 | ) |
| Effect of exchange rate changes on cash | (7 | ) | | 13 |
| | (20 | ) |
| Net increase (decrease) in cash and cash equivalents | (420 | ) | | 191 |
| | (3,458 | ) |
| Cash and cash equivalents at beginning of period | 684 |
| | 493 |
| | 3,951 |
|
| Cash and cash equivalents at end of period | $ | 264 |
| | $ | 684 |
| | $ | 493 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows
|
| | | | | | | | | | | |
| (In millions) | 2012 | | 2011 | | 2010 |
| Increase (decrease) in cash and cash equivalents | | | | | |
| Operating activities: | | | | | |
| Net income | $ | 1,582 |
| | $ | 2,946 |
| | $ | 2,568 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Discontinued operations | — |
| | (1,239 | ) | | (686 | ) |
| Loss on early extinguishment of debt | — |
| | 279 |
| | 92 |
|
| Deferred income taxes | (210 | ) | | (182 | ) | | (489 | ) |
| Depreciation, depletion and amortization | 2,478 |
| | 2,266 |
| | 2,056 |
|
| Impairments | 371 |
| | 310 |
| | 447 |
|
| Pension and other postretirement benefits, net | (31 | ) | | 64 |
| | 31 |
|
| Exploratory dry well costs and unproved property impairments | 457 |
| | 357 |
| | 225 |
|
| Net gain on disposal of assets | (127 | ) | | (103 | ) | | (766 | ) |
| Equity method investments, net | 11 |
| | 47 |
| | 56 |
|
| Changes in: | | | | | |
| Current receivables | (499 | ) | | 8 |
| | (409 | ) |
| Inventories | (34 | ) | | 33 |
| | (71 | ) |
| Current accounts payable and accrued liabilities | 96 |
| | 485 |
| | 1,018 |
|
| All other operating, net | (77 | ) | | 163 |
| | 122 |
|
| Net cash provided by continuing operations | 4,017 |
| | 5,434 |
| | 4,194 |
|
| Net cash provided by discontinued operations | — |
| | 1,090 |
| | 1,676 |
|
| Net cash provided by operating activities | 4,017 |
| | 6,524 |
| | 5,870 |
|
| Investing activities: | | | | | |
| Acquisitions, net of cash acquired | (1,033 | ) | | (4,470 | ) | | — |
|
| Additions to property, plant and equipment | (4,940 | ) | | (3,295 | ) | | (3,536 | ) |
| Disposal of assets | 467 |
| | 518 |
| | 1,368 |
|
| Investments - return of capital | 57 |
| | 59 |
| | 58 |
|
| Investing activities of discontinued operations | — |
| | (493 | ) | | (464 | ) |
| All other investing, net | 10 |
| | 14 |
| | (47 | ) |
| Net cash used in investing activities | (5,439 | ) | | (7,667 | ) | | (2,621 | ) |
| Financing activities: | | | | | |
| Commercial paper, net | 200 |
| | — |
| | — |
|
| Borrowings | 1,997 |
| | — |
| | — |
|
| Debt issuance costs | (21 | ) | | — |
| | — |
|
| Debt repayments | (145 | ) | | (2,877 | ) | | (653 | ) |
| Purchases of common stock | — |
| | (300 | ) | | — |
|
| Dividends paid | (480 | ) | | (567 | ) | | (704 | ) |
| Financing activities of discontinued operations | — |
| | 2,916 |
| | (12 | ) |
| Distribution in spin-off | — |
| | (1,622 | ) | | — |
|
| All other financing, net | 49 |
| | 155 |
| | 14 |
|
| Net cash provided by (used in) financing activities | 1,600 |
| | (2,295 | ) | | (1,355 | ) |
| Effect of exchange rate changes on cash | 13 |
| | (20 | ) | | — |
|
| Net increase (decrease) in cash and cash equivalents | 191 |
| | (3,458 | ) | | 1,894 |
|
| Cash and cash equivalents at beginning of period | 493 |
| | 3,951 |
| | 2,057 |
|
| Cash and cash equivalents at end of period | $ | 684 |
| | $ | 493 |
| | $ | 3,951 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Equity of Marathon Oil Stockholders | | | | |
| (In millions) | Preferred Stock | | Common Stock | | Securities Exchangeable into Common Stock | | Treasury Stock | | Additional Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Non- controlling Interest | | Total Equity |
| January 1, 2011 Balance | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,665 | ) | | $ | 6,756 |
| | $ | 19,907 |
| | $ | (997 | ) | | $ | — |
| | $ | 23,771 |
|
| Shares issued - stock-based | | | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | 257 |
| | (85 | ) | | — |
| | — |
| | — |
| | 172 |
|
| Shares repurchased | — |
| | — |
| | — |
| | (308 | ) | | — |
| | — |
| | — |
| | — |
| | (308 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | — |
| | 4 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 2,946 |
| | — |
| | — |
| | 2,946 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 40 |
| | — |
| | 40 |
|
| Dividends paid | — |
| | — |
| | — |
| | — |
| | — |
| | (567 | ) | | — |
| | — |
| | (567 | ) |
| Purchase of subsidiary | | | | | | | | | | | | | | | | | |
| shares from non- | | | | | | | | | | | | | | | | | |
| controlling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
| | 7 |
|
| Spin-off of downstream | — |
| | — |
| | — |
| | — |
| | 5 |
| | (9,498 | ) | | 587 |
| | — |
| | (8,906 | ) |
| December 31, 2011 Balance | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,716 | ) | | $ | 6,680 |
| | $ | 12,788 |
| | $ | (370 | ) | | $ | 7 |
| | $ | 17,159 |
|
| Shares issued - stock-based | | | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | 164 |
| | (75 | ) | | — |
| | — |
| | — |
| | 89 |
|
| Shares repurchased | — |
| | — |
| | — |
| | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (8 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | 22 |
| | — |
| | — |
| | — |
| | 22 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 1,582 |
| | — |
| | — |
| | 1,582 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (63 | ) | | — |
| | (63 | ) |
| Dividends paid | — |
| | — |
| | — |
| | — |
| | — |
| | (480 | ) | | — |
| | — |
| | (480 | ) |
| Purchase of subsidiary | | | | | | | | | | | | | | | | | |
| shares from non- | | | | | | | | | | | | | | | | | |
| controlling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7 | ) | | (7 | ) |
| Other | — |
| | — |
| | — |
| | — |
| | (11 | ) | | — |
| | — |
| | — |
| | (11 | ) |
| December 31, 2012 Balance | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,560 | ) | | $ | 6,616 |
| | $ | 13,890 |
| | $ | (433 | ) | | $ | — |
| | $ | 18,283 |
|
| Shares issued - stock-based | | | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | 170 |
| | (44 | ) | | — |
| | — |
| | — |
| | 126 |
|
| Shares repurchased | — |
| | — |
| | — |
| | (513 | ) | | — |
| | — |
| | — |
| | — |
| | (513 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 1,753 |
| | — |
| | — |
| | 1,753 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 183 |
| | — |
| | 183 |
|
| Dividends paid | — |
| | — |
| | — |
| | — |
| | — |
| | (508 | ) | | — |
| | — |
| | (508 | ) |
| December 31, 2013 Balance | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,903 | ) | | $ | 6,592 |
| | $ | 15,135 |
| | $ | (250 | ) | | $ | — |
| | $ | 19,344 |
|
| | | | | | | | | | | | | | | | | | |
| (Shares in millions) | Preferred Stock | | Common Stock | | Securities Exchangeable into Common Stock | | Treasury Stock | | | | | | | | | | |
| January 1, 2011 Balance | — |
| | 770 |
| | — |
| | 60 |
| | | | | | | | | | |
| Shares issued - stock-based | | | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | (6 | ) | | | | | | | | | | |
| Shares repurchased | — |
| | — |
| | — |
| | 12 |
| | | | | | | | | | |
| December 31, 2011 Balance | — |
| | 770 |
| | — |
| | 66 |
| | | | | | | | | | |
| Shares issued - stock-based | | | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | (3 | ) | | | | | | | | | | |
| December 31, 2012 Balance | — |
| | 770 |
| | — |
| | 63 |
| | | | | | | | | | |
| Shares issued - stock-based | | | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | (4 | ) | | | | | | | | | | |
| Shares repurchased | — |
| | — |
| | — |
| | 14 |
| | | | | | | | | | |
| December 31, 2013 Balance | — |
| | 770 |
| | — |
| | 73 |
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ Equity
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Total Equity of Marathon Oil Stockholders | | | | |
| (In millions) | | Preferred Stock | | Common Stock | | Securities Exchangeable into Common Stock | | Treasury Stock | | Additional Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Non- controlling Interest | | Total Equity |
| January 1, 2010 Balance | | $ | — |
| | $ | 769 |
| | $ | — |
| | $ | (2,706 | ) | | $ | 6,738 |
| | $ | 18,043 |
| | $ | (934 | ) | | $ | — |
| | $ | 21,910 |
|
| Shares issued - stock based | | | | | | | | | | | | | | | | | | |
| compensation | | — |
| | — |
| | — |
| | 46 |
| | (12 | ) | | — |
| | — |
| | — |
| | 34 |
|
| Shares exchanged | | — |
| | 1 |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
| Shares repurchased | | — |
| | — |
| | — |
| | (5 | ) | | — |
| | — |
| | — |
| | — |
| | (5 | ) |
| Stock-based compensation | | — |
| | — |
| | — |
| | — |
| | 31 |
| | — |
| | — |
| | — |
| | 31 |
|
| Net income | | — |
| | — |
| | — |
| | — |
| | — |
| | 2,568 |
| | — |
| | — |
| | 2,568 |
|
| Other comprehensive loss | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (63 | ) | | — |
| | (63 | ) |
| Dividends paid | | — |
| | — |
| | — |
| | — |
| | — |
| | (704 | ) | | — |
| | — |
| | (704 | ) |
| December 31, 2010 Balance | | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,665 | ) | | $ | 6,756 |
| | $ | 19,907 |
| | $ | (997 | ) | | $ | — |
| | $ | 23,771 |
|
| Shares issued - stock based | | | | | | | | | | | | | | | | | | |
| compensation | | — |
| | — |
| | — |
| | 257 |
| | (85 | ) | | — |
| | — |
| | — |
| | 172 |
|
| Shares repurchased | | — |
| | — |
| | — |
| | (308 | ) | | — |
| | — |
| | — |
| | — |
| | (308 | ) |
| Stock-based compensation | | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | — |
| | 4 |
|
| Net income | | — |
| | — |
| | — |
| | — |
| | — |
| | 2,946 |
| | — |
| | — |
| | 2,946 |
|
| Other comprehensive | | | | | | | | | | | | | | | | | | |
| income | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 40 |
| | — |
| | 40 |
|
| Dividends paid | | — |
| | — |
| | — |
| | — |
| | — |
| | (567 | ) | | — |
| | — |
| | (567 | ) |
| Purchase of subsidiary | | | | | | | | | | | | | | | | | | |
| shares from non- | | | | | | | | | | | | | | | | | | |
| controlling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
| | 7 |
|
| Spin-off of downstream | | | | | | | | | | | | | | | | | | |
| business | | — |
| | — |
| | — |
| | — |
| | 5 |
| | (9,498 | ) | | 587 |
| | — |
| | (8,906 | ) |
| December 31, 2011 Balance | | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,716 | ) | | $ | 6,680 |
| | $ | 12,788 |
| | $ | (370 | ) | | $ | 7 |
| | $ | 17,159 |
|
| Shares issued - stock based | | | | | | | | | | | | | | | | | | |
| compensation | | — |
| | — |
| | — |
| | 164 |
| | (75 | ) | | — |
| | — |
| | — |
| | 89 |
|
| Shares repurchased | | — |
| | — |
| | — |
| | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (8 | ) |
| Stock-based compensation | | — |
| | — |
| | — |
| | — |
| | 22 |
| | — |
| | — |
| | — |
| | 22 |
|
| Net income | | — |
| | — |
| | — |
| | — |
| | — |
| | 1,582 |
| | — |
| | — |
| | 1,582 |
|
| Other comprehensive | | | | | | | | | | | | | | | | | | |
| loss | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (63 | ) | | — |
| | (63 | ) |
| Dividends paid | | — |
| | — |
| | — |
| | — |
| | — |
| | (480 | ) | | — |
| | — |
| | (480 | ) |
| Purchase of subsidiary | | | | | | | | | | | | | | | | | | |
| shares from non- | | | | | | | | | | | | | | | | | | |
| controlling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7 | ) | | (7 | ) |
| Other | | — |
| | — |
| | — |
| | — |
| | (11 | ) | | — |
| | — |
| | — |
| | (11 | ) |
| December 31, 2012 Balance | | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,560 | ) | | $ | 6,616 |
| | $ | 13,890 |
| | $ | (433 | ) | | $ | — |
| | $ | 18,283 |
|
| | | | | | | | | | | | | | | | | | | |
| (Shares in millions) | | Preferred Stock | | Common Stock | | Securities Exchangeable into Common Stock | | Treasury Stock | | | | | | | | | | |
| January 1, 2010 Balance | | 1 |
| | 769 |
| | 1 |
| | (61 | ) | | | | | | | | | | |
| Shares issued - stock based | | | | | | | | | | | | | | | | | | |
| compensation | | — |
| | — |
| | — |
| | 1 |
| | | | | | | | | | |
| Shares exchanged | | (1 | ) | | 1 |
| | (1 | ) | | — |
| | | | | | | | | | |
| December 31, 2010 Balance | | — |
| | 770 |
| | — |
| | (60 | ) | | | | | | | | | | |
| Shares issued - stock based | | | | | | | | | | | | | | | | | | |
| compensation | | — |
| | — |
| | — |
| | 6 |
| | | | | | | | | | |
| Shares repurchased | | — |
| | — |
| | — |
| | (12 | ) | | | | | | | | | | |
| December 31, 2011 Balance | | — |
| | 770 |
| | — |
| | (66 | ) | | | | | | | | | | |
| Shares issued - stock based | | | | | | | | | | | | | | | | | | |
| compensation | | — |
| | — |
| | — |
| | 3 |
| | | | | | | | | | |
| Shares repurchased | | — |
| | — |
| | — |
| | — |
| | | | | | | | | | |
| December 31, 2012 Balance | | — |
| | 770 |
| | — |
| | (63 | ) | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
1. Summary of Principal Accounting Policies
We are engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; oil sands mining, bitumen transportation and upgrading, marketing of synthetic crude oil and vacuum gas oil in Canada; and production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.; and oil sands mining, bitumen transportation and upgrading, and marketing of synthetic crude oil and vacuum gas oil in Canada.
Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiariessubsidiaries. Investments in unincorporated joint ventures and variable interest entities for which weundivided interests in certain operating assets are the primary beneficiary.consolidated on a pro rata basis.
Equity method investments – Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees.
Equity method investments are carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.
Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.
As a result of the spin-off of our downstream business (see Note 3), the results ofDiscontinued operations and cash flows for the downstream business have been classified as discontinued operations for 2011 and 2010. The disclosures – Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. Due to the agreements entered in 2013 to sell our Angola assets (see Note 6), the corresponding results of operations and cash flows have been classified as discontinued operations for all presented periods. As a result of the spin-off of our downstream business in 2011 (see Note 3), the related results of operations and cash flows have been classified as discontinued operations for all periods prior to the spin-off.
Use of estimates– The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.
RevisionReclassifications – We have revised our 2011 consolidated statement of comprehensive income to excludeBeginning in 2013, we changed the effects of the spin-offpresentation of our former downstream business. Changes in accumulated other comprehensive loss of $587 million, net of tax, associated with postretirement and postemployment plans ($591 million, net of tax) and unrecognized derivative hedging losses ($4 million, net of tax) related to the downstream business were removed from this statement. The revision had no impact on our consolidated balance sheets or consolidated statements of income, cash flows or stockholders' equityprimarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for any periods presented.2012 and 2011 increased by $144 million and $119 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.
Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.
Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recordedWe follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in cost of revenues.the periods presented.
In the lower 48 states of the U.S., production volumes of liquid hydrocarbons and natural gas are generally sold immediately and transported to market. In Alaska and international locations, liquid hydrocarbon and natural gas production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic crude oil. Both bitumen and synthetic crude oil may be stored as inventory.
We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.
Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.
Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews,
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
these reviews, we may require a standby letter of credit or a financial guarantee. Uncollectible accounts receivable are reserved against the allowance for uncollectible accounts when it is determined the receivable will not be collected and the amount of any reserve may be reasonably estimated.
Inventories – Inventories are carried at the lower of cost or market value. The majority of our inventories are recorded at average cost. The last-in, first-out ("LIFO") method is used for our U.S. crude oil and natural gas inventories.
We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.
Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by brokerage firm,counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk and foreign currency exchange rate risk related to operating expenditures are classified in operating activities with the underlying transactions. Cash flows related to derivatives used to manage exchange rate risk related to capital expenditures denominated in foreign currencies are classified in investing activities with the underlying transactions. Our derivative instruments contain no significant contingent credit features.
Cash flow hedges – We may use foreign currency forwards and options to manage foreign currency risk associated with anticipated transactions primarily expenditures for capital projects denominated in certain foreign currencies, and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2013 and 2012. The effective portion of changes in fair value is recognized in other comprehensive income ("OCI") and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion is recognized in net interest and other as it occurs. For a discontinued cash flow hedge, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income.
We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 20122013 and 20112012.
Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio; commodity derivative instruments to manage the price risk on natural gas that we purchase to be marketed with our natural gas production; and foreign currency forwards to manage our exposure to changes in the value of foreign currency denominated tax liabilities. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.
Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price risk on the forecasted sale of crude oil, natural gas and synthetic crude oil that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.
Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. When significant transfers occur, they are disclosed in Note 15 to the consolidated financial statements.
Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities, which include bitumen mining and upgrading.
Property acquisition costs – Costs to acquire mineral interests in traditional oil and natural gas properties or in oil sands mines, to drill and equip exploratory wells in progress and those that find proved reserves, to drill and equip development wells and to construct or expand oil sands mines and upgrading facilities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties, which include our bitumen mining and upgrading facilities, are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities are depreciated on a straight-line basis over their estimated useful lives which range from 3 to 4340 years.
Property, plant and equipment unrelated to oil and gas producing activities is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 40 years.
Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells, development costs and our bitumen mining and upgrading facilities, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Impairment of proved properties is required when the carrying value exceeds the related undiscounted future net cash flows based on proved and probable reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors and may apply an undiscounted future net cash flow approach when appropriate. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. When unproved property investments are deemed to be impaired the expense is reported in exploration expenses.
Dispositions – When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.
Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operating expense.impairments.
Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred. These typesincurred and can include the costs of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs.
Environmental costs – Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed andor reliably determinable.
Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities, which include our bitumen mining facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.
Current inflationInflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Depreciation is generally determined on a units-of-production basis for oil and gas production facilities, which include our bitumen mining facilities, while accretion escalates over the lives of the assets.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Deferred income taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include our expectation to generate sufficient future taxable income including future foreign source income, tax credits, operating loss carryforwards and management’s intent regarding the permanent reinvestment of the income from certain foreign subsidiaries.
Stock basedStock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.
The fair value of our restricted stock awards and common stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted.
The fair value of our stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement.
Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Options with tandem SARs are classified as a liability and are remeasured at fair value each reporting period until settlement.
Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. When significant transfers occur, they are disclosed in the appropriate footnote to the financial statements.
2. Accounting Standards
Not Yet Adopted
In June 2013, the FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof ) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.
In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. These disclosures areThis accounting standards update was effective for us beginning the first quarter of 2013.2013
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
and we present the required disclosures in Note 22. Adoption of this amendment willstandard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. These disclosures areThe accounting standards update was effective for us beginning the first quarter of 2013 and must be made retrospectively for comparable periods.we include the required disclosures in Note 16. Adoption of this amendment willstandard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In September 2011, the FASB amended accounting standards to simplify how entities test goodwill for impairment. The amendment reduces complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test. The amendment was effective for our interim and annual periods beginning with the first quarter of 2012. Adoption of this amendment in 2012 did not have a significant impact on our consolidated results of operations, financial position or cash flows.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The FASB amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of OCI as part of the statement of changes in stockholders' equity. All non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of OCI, and total comprehensive income. The presentation of items that are reclassified from OCI to net income on the income statement is also required. The amendments did not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income. The amendments were effective for us beginning with the first quarter of 2012, except for the presentation of reclassifications, which was deferred and addressed in the February 2013 accounting standards update discussed above. Adoption of these amendmentsthis standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under U.S. GAAP and IFRS. The amendments change the wording used to describe certain of the U.S. GAAP requirements either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. The amendments were to be applied prospectively for our interim and annual periods beginning with the first quarter of 2012. The adoptionAdoption of the amendments in 2012 did not have a significant impact on our consolidated results of operations, financial position or cash flows. To the extent they were necessary, we made the expanded disclosures in Notes 15 and 20.16.
| |
| 3. | Spin-off of Downstream Business |
On June 30, 2011, the spin-off of Marathon's downstream business was completed, creating two independent energy companies: Marathon Oil and MPC. On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the "Record Date") received one common share of MPC stock for every two common shares of Marathon stock held as of the Record Date.
In order to effect the spin-off and govern our relationship with MPC after the spin-off, we entered into a Separation and Distribution Agreement, a Tax Sharing Agreement and an Employee Matters Agreement. The Separation and Distribution Agreement governed the separation of the downstream business, the distribution of MPC’s shares of common stock to our stockholders, transfer of assets and intellectual property, and other matters related to our relationship with MPC. The Separation and Distribution Agreement provides for cross-indemnities between Marathon Oil and MPC. In general, we have agreed to indemnify MPC for any liabilities relating to our historical E&P operations, OSM operationsexploration and IGproduction and oil sands mining operations, and MPC has agreed to indemnify us for any liabilities relating to the historical downstream operations.
The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Marathon Oil and MPC with respect to taxes and tax benefits, the filing of tax returns, the control of audits and other tax matters. In addition, the Tax Sharing Agreement reflects each company’s rights and obligations related to taxes that are attributable to periods prior to and including the separation date and taxes resulting from transactions effected in connection with the separation. In general, under the Tax Sharing Agreement, Marathon Oil is responsible for all U.S. federal, state, local and foreign income taxes attributable to Marathon Oil or any of its subsidiaries for any tax period that begins after the date of the spin-off, and MPC is responsible for all taxes attributable to it or its subsidiaries, whether accruing before, on or after the spin-off. The Tax Sharing Agreement contains covenants intended to protect the tax-free status of the spin-off. These covenants may restrict the ability of Marathon Oil and MPC to pursue strategic or other transactions that otherwise could maximize the values of their respective businesses and may discourage or delay a change of control of either company.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The Employee Matters Agreement contains provisions concerning benefit protection for employees who became MPC employees prior to December 31, 2011, treatment of holders of Marathon stock options, stock appreciation rights, restricted stock and restricted stock units, and cooperation between Marathon Oil and MPC in the sharing of employee information and maintenance of confidentiality. Unvested equity-based compensation awards were converted to awards of the entity where the employee holding them worked post-separation. For vested equity-based compensation awards, employees received both Marathon Oil and MPC awards.
The results of operations of our downstream business have been reported as discontinued operations for 2011 and 2010.2011. The table below shows selected financial information reported in discontinued operations related to the spin-off.
| | | (In millions) | | 2011 | | 2010 | | 2011 |
| Revenues applicable to discontinued operations | | $ | 38,602 |
| | $ | 62,488 |
| | $ | 38,602 |
|
| Pretax income from discontinued operations | | $ | 2,012 |
| | $ | 1,065 |
| | $ | 2,012 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
| |
| 4. | Variable Interest Entities |
The owners of the AOSP, in which we hold a 20 percent undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership ("Corridor Pipeline") to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3 million current liability recorded at December 31, 20122013, consistent with December 31, 2011.2012. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a variable interest entity ("VIE"). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore the Corridor Pipeline is not consolidated by Marathon Oil. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $694723 million as of December 31, 20122013. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.
5. Acquisitions
During 2013, 2012 and 2011, our significant business combinations related to properties acquired by our North America E&P segment in the Eagle Ford shale in south Texas. The pro forma impact of these transactions, individually and in the aggregate, is not material to our consolidated statements of income for any periods presented.
The fair values of assets acquired and liabilities assumed in each of these business combinations were measured primarily using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future operating and development costs. The discount rates used in the discounted cash flow analyses were approximately 10 percent for the 2013 and 2012 transactions and 11 percent for the 2011 transaction.
2013
In July 2013, we acquired 4,800 net undeveloped acres in the Eagle Ford in a transaction valued at $97 million, including carried interest of $23 million. The transaction was accounted for as a business combination, with the entire up-front cash consideration of $74 million allocated to property, plant and equipment at the acquisition date.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
2012 & 2011
We acquired approximately 25,000 net acres in the core of the Eagle Ford shale during 2012. The largest transactions were the acquisitions of Paloma Partners II, LLC, which closed August 1,in the second quarter of 2012 for cash consideration of $768 million, and an acquisition of proved and unproved properties that closed on November 1,in the third quarter of 2012 for cash consideration of $232 million. These transactions were accounted for as business combinations.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates:
|
| | | | | | | | |
| | | Acquisition Date |
| | | August 1, | | November 1, |
| (In millions) | | 2012 | | 2012 |
| Current assets: | | | | |
| Cash | | $ | 8 |
| | $ | — |
|
| Receivables | | 22 |
| | 8 |
|
| Inventories | | 1 |
| | — |
|
| Total current assets acquired | | 31 |
| | 8 |
|
| Property, plant and equipment | | 822 |
| | 248 |
|
| Total assets acquired | | $ | 853 |
| | $ | 256 |
|
| Current liabilities: | | | | |
| Accounts payable | | 78 |
| | 23 |
|
| Total current liabilities assumed | | 78 |
| | 23 |
|
| Asset retirement obligations | | 7 |
| | 1 |
|
| Total liabilities assumed | | 85 |
| | 24 |
|
| Net assets acquired | | $ | 768 |
| | $ | 232 |
|
2011
During the fourth quarter of 2011, we closed a series of transactions in the Eagle Ford shale that were accounted for as a business combination. The most significant of these transactions was the acquisition of Hilcorp Resources, LLC. The total cash consideration paid for all the transactions including approximately 167,000 net acres and a gathering system, was $4.5 billion which was funded from existing cash..
The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates:
| | | | | Closed in Quarter Ended |
| | | | | June 30, | | September 30, | | December 31, |
| (In millions) | | | 2012 | | 2012 | | 2011 |
| Current assets: | | | | | | | |
| Cash | | | $ | 8 |
| | $ | — |
| | $ | — |
|
| Receivables | $ | 40 |
| | 22 |
| | 8 |
| | 40 |
|
| Inventories | 4 |
| | 1 |
| | — |
| | 4 |
|
| Other current assets | 30 |
| | — |
| | — |
| | 30 |
|
| Total current assets acquired | 74 |
| | 31 |
| | 8 |
| | 74 |
|
| Property, plant and equipment | 4,501 |
| | 822 |
| | 248 |
| | 4,501 |
|
| Other noncurrent assets | 21 |
| | — |
| | — |
| | 21 |
|
| Total assets acquired | $ | 4,596 |
| | 853 |
| | 256 |
| | 4,596 |
|
| Current liabilities: | | | | | | | |
| Accounts payable | $ | 101 |
| | 78 |
| | 23 |
| | 101 |
|
| Other current liabilities | 20 |
| | — |
| | — |
| | 20 |
|
| Total current liabilities assumed | 121 |
| | 78 |
| | 23 |
| | 121 |
|
| Asset retirement obligations | 5 |
| | 7 |
| | 1 |
| | 5 |
|
| Total liabilities assumed | 126 |
| | 85 |
| | 24 |
| | 126 |
|
| Net assets acquired | $ | 4,470 |
| | $ | 768 |
| | $ | 232 |
| | $ | 4,470 |
|
In addition, during 2011,our North America E&P segment acquired approximately 108,000 net acres in the Eagle Ford shale for approximately $265 million. These transactions were funded from existing cash and were accounted for as asset acquisitions.
6. Dispositions
2013 - North America E&P
In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.
In February 2013, we entered an agreement to conveyconveyed our interestinterests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.
In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain was recorded in the first quarter of 2013.
In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million which was collected in July 2013. After closing adjustments were made in the second quarter of 2013, the pretax gain on this sale was $55 million.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
2012
Neptune gas plant – InAssets held for sale in the December 31, 2012 we entered into an agreementconsolidated balance sheet were related to sell our our E&P segment's interest in the Neptune gas plant located onshore Louisiana. The transaction, withand Alaska dispositions that were pending at that date and included:
|
| | | |
| (In millions) | December 31, 2012 |
| Other current assets | $ | 50 |
|
| Other noncurrent assets | 248 |
|
| Total assets | $ | 298 |
|
| Deferred credits and other liabilities | $ | 83 |
|
| Total liabilities | $ | 83 |
|
2013 - International E&P
In the fourth quarter of 2013, we transfered our 45 percent working interest and operatorship in the Safen block in the Kurdistan Region of Iraq at a valuepretax loss of $17017 million.
In June and December 2013, we entered into agreements, valued in total at $2.1 billion before closing adjustments, to sell our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32. The sale of our interest in Block 31 closed in February 2013.2014 and the sale of our interest in Block 32 is expected to close in the first quarter of 2014. Block 31 is presented as held for sale and Block 32 is reflected as unproved property in property, plant and equipment in the December 31, 2013 consolidated balance sheet (See Note 13 for discussion of the capitalized costs related to suspended wells). Our entire Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented.
Assets held for sale in the December 31, 2013 consolidated balance sheet were related to the Angola Block 31 disposition that was pending at that date and included:
|
| | | |
| (In millions) | December 31, 2013 |
| Other current assets | $ | 41 |
|
| Other noncurrent assets | 1,647 |
|
| Total assets | $ | 1,688 |
|
| Other current liabilities | $ | 25 |
|
| Deferred credits and other liabilities | 43 |
|
| Total liabilities | $ | 68 |
|
Related amounts reported in discontinued operations for 2013, 2012 and 2011 were as follows: |
| | | | | | | | | | | |
| (In millions) | 2013 | | 2012 | | 2011 |
| Revenues applicable to discontinued operations | $ | 361 |
| | $ | — |
| | $ | — |
|
| Pretax income (loss) from discontinued operations | $ | 247 |
| | $ | (17 | ) | | $ | (17 | ) |
2012 - North America E&P
Eagle Ford acreage – In the third quarter of 2012, we sold approximately 5,800 net undeveloped acres located outside the core ofin the Eagle Ford shale, held by our E&P segment, for proceeds of $9 million. A pretax loss of $18 million was recorded.
Indonesia – 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 reported a $36 million loss on disposal of assets. Government ratification of the agreements released us from our obligations and further commitments related to these licenses.
Alaska – In April 2012, we entered into agreements to sell all of our E&P segment’s assets in Alaska. One transaction closed in 2012 with proceeds and a net gain of $7 million. The second transaction closed in January 2013, for proceeds of $195 million subject to a six-month escrow of $50 million for various indemnities.
Gulf of Mexico pipelines – In January 2012, we closed on the sale of our E&P segment’s interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This included 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.
Assets held for sale2012 - International E&P
In May 2012, we executed agreements to relinquish our operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia. As a result, we reported a December 31, 2012$36 million consolidated balance sheet werepretax loss on disposal of assets. Government ratification of the agreements released us from our obligations and further commitments related to the Neptune gas plant and Alaska dispositions that were pending at that date and included:these licenses.
|
| | | |
| (In millions) | |
| Other current assets | $ | 50 |
|
| Other noncurrent assets | 248 |
|
| Total assets | $ | 298 |
|
| Deferred credits and other liabilities | 83 |
|
| Total liabilities | $ | 83 |
|
2011 - North America E&P
Burns Point gas plant – In December 2011, we sold our E&P segment’s 50 percent interest in the Burns Point gas plant, a cryogenic processing plant located in St. Mary Parish, Louisiana, for total consideration of $36 million and a pretax gain of $34 million.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Alaska LNG facility – In September 2011, we sold our IG segment’s equity interest in an LNG processing facility in Alaska and a pretax gain on the transaction of $8 million was recorded.
DJ Basin – In April 2011, we assigned a 30 percent undivided working interest in the approximately 180,000 acres then held by our E&P segment in the Niobrara shale play located within the DJ Basin of southeast Wyoming and northern Colorado for total consideration of $270 million, recording a pretax gain of $37 million. We remain operator of this jointly owned leasehold.
2010
Angola – In February 2010, we closedSee the sale of a 20 percent non-operated interest in our E&P segment’s Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. We received net proceeds of $1.3 billion and recorded a pretax gain on the sale of $811 million. We retained a 10 percent non-operated interest in Block 32.
Gudrun – In March 2011, we closed the salediscussion of our non-operated interests in2013 disposal of the Gudrun field development and the Brynhild and Eirin exploration areas offshore Norway for net proceeds of $85 million, excluding working capital adjustments. A $64 million pretax loss on this disposition was recorded in the fourth quarter 2010.remaining interest above.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
7. Income per Common Share
Basic income per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| (In millions, except per share data) | Basic | | Diluted | | Basic | | Diluted | | Basic | | Diluted | Basic | | Diluted | | Basic | | Diluted | | Basic | | Diluted |
| Income from continuing operations | $ | 1,582 |
| | $ | 1,582 |
| | $ | 1,707 |
| | $ | 1,707 |
| | $ | 1,882 |
| | $ | 1,882 |
| $ | 1,593 |
| | $ | 1,593 |
| | $ | 1,613 |
| | $ | 1,613 |
| | $ | 1,718 |
| | $ | 1,718 |
|
| Discontinued operations | — |
| | — |
| | 1,239 |
| | 1,239 |
| | 686 |
| | 686 |
| 160 |
| | 160 |
| | (31 | ) | | (31 | ) | | 1,228 |
| | 1,228 |
|
| Net income | $ | 1,582 |
| | $ | 1,582 |
| �� | $ | 2,946 |
| | $ | 2,946 |
| | $ | 2,568 |
| | $ | 2,568 |
| $ | 1,753 |
| | $ | 1,753 |
| | $ | 1,582 |
| | $ | 1,582 |
| | $ | 2,946 |
| | $ | 2,946 |
|
| Weighted average common shares outstanding | 706 |
| | 706 |
| | 710 |
| | 710 |
| | 710 |
| | 710 |
| 705 |
| | 705 |
| | 706 |
| | 706 |
| | 710 |
| | 710 |
|
| Effect of dilutive securities | — |
| | 4 |
| | — |
| | 4 |
| | — |
| | 2 |
| — |
| | 4 |
| | — |
| | 4 |
| | — |
| | 4 |
|
| Weighted average common shares, including dilutive effect | 706 |
| | 710 |
| | 710 |
| | 714 |
| | 710 |
| | 712 |
| 705 |
| | 709 |
| | 706 |
| | 710 |
| | 710 |
| | 714 |
|
| Per share: | | | | | | | | | | | | | | | | | | | | | | |
| Income from continuing operations | $ | 2.24 |
| | $ | 2.23 |
| | $ | 2.40 |
| | $ | 2.39 |
| | $ | 2.65 |
| | $ | 2.65 |
| $ | 2.26 |
| | $ | 2.24 |
| | $ | 2.28 |
| | $ | 2.27 |
| | $ | 2.42 |
| | $ | 2.41 |
|
| Discontinued operations | $ | — |
| | $ | — |
| | $ | 1.75 |
| | $ | 1.74 |
| | $ | 0.97 |
| | $ | 0.96 |
| $ | 0.23 |
| | $ | 0.23 |
| | $ | (0.04 | ) | | $ | (0.04 | ) | | $ | 1.73 |
| | $ | 1.72 |
|
| Net income | $ | 2.24 |
| | $ | 2.23 |
| | $ | 4.15 |
| | $ | 4.13 |
| | $ | 3.62 |
| | $ | 3.61 |
| $ | 2.49 |
| | $ | 2.47 |
| | $ | 2.24 |
| | $ | 2.23 |
| | $ | 4.15 |
| | $ | 4.13 |
|
The per share calculations above exclude 105 million, 710 million and 137 million stock options and stock appreciation rights in 20122013, 20112012 and 20102011 that were antidilutive.
8. Segment Information
Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.
We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services they offer.it offers:
North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.in North America;
OSMInternational E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
Oil Sands Mining (“OSM”) – 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.
IG – produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker ("CODM"(“CODM”). Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities, net of associated income tax effects. Impairments, gains or losses on disposal of assets, unrealizedUnrealized gains or losses on crude oil derivative instruments, certain impairments, gains or losses on dispositions or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.
In 2013, we entered into agreements to sell our Angola assets; therefore, the Angola operations are reflected as discontinued operations and excluded from the International E&P segment in all periods presented.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
As discussed in Note 3, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations for 2011 and 2010.2011. Sales to MPC previously reported as Intersegmentintersegment revenues are reported as Customersales and other operating revenues because such sales arewere expected to continue subsequent to the spin-off. SuchThese sales were $1.4$1.4 billion in the first six months of 2011, and 2011.$1.8 billion in 2010. Differences between segment totals and our consolidated totals for income taxes and depreciation, depletion and amortization represent amounts related to corporate administrative activities and other unallocated items which are included in "Items not allocated to segments, net of taxes" in the reconciliation below. Capital expenditures include accruals but not corporate administrative activities. |
| | | | | | | | | | | | | | | | | | | |
| 2013 | | | Not Allocated | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
| Sales and other operating revenues | $ | 5,068 |
| | $ | 5,827 |
| | $ | 1,576 |
| | $ | (52 | ) | (c) | $ | 12,419 |
|
| Marketing revenues | 1,797 |
| | 267 |
| | 18 |
| | — |
| | 2,082 |
|
| Total revenues | 6,865 |
| | 6,094 |
| | 1,594 |
| | (52 | ) | | 14,501 |
|
| Income from equity method investments | — |
| | 427 |
| | — |
| | (4 | ) | (d) | 423 |
|
| Net gain (loss) on disposal of assets and other income | 12 |
| | 50 |
| | 5 |
| | (32 | ) | | 35 |
|
| Production expenses | 797 |
| | 534 |
| | 1,000 |
| | — |
| | 2,331 |
|
| Marketing costs | 1,796 |
| | 258 |
| | 18 |
| | — |
| | 2,072 |
|
| Exploration expenses | 725 |
| | 263 |
| | — |
| | — |
| | 988 |
|
| Depreciation, depletion and amortization | 1,927 |
| | 621 |
| | 218 |
| | 24 |
| | 2,790 |
|
| Impairments | 41 |
| | — |
| | — |
| | 55 |
| | 96 |
|
Other expenses (a) | 420 |
| | 239 |
| | 66 |
| | 401 |
| | 1,126 |
|
| Taxes other than income | 318 |
| | 7 |
| | 22 |
| | 5 |
| | 352 |
|
| Net interest and other | — |
| | — |
| | — |
| | 274 |
| | 274 |
|
| Provision (benefit) for income taxes | 324 |
| | 3,226 |
| | 69 |
| | (282 | ) | | 3,337 |
|
| Segment income/Income from continuing operations | $ | 529 |
| | $ | 1,423 |
| | $ | 206 |
| | $ | (565 | ) | | $ | 1,593 |
|
Capital expenditures (b) | $ | 3,649 |
| | $ | 764 |
| | $ | 286 |
| | $ | 285 |
| | $ | 4,984 |
|
| |
(a) | Includes other operating expenses and general and administrative expenses. |
| |
(c) | Unrealized gain (loss) on crude oil derivative instruments. |
| |
(d) | EGHoldings impairment (see Note 15). |
|
| | | | | | | | | | | | | | | | | | | |
| 2012 | | | Not Allocated | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
| Sales and other operating revenues | $ | 3,944 |
| | $ | 7,445 |
| | $ | 1,521 |
| | $ | 53 |
| (c) | $ | 12,963 |
|
| Marketing revenues | 2,451 |
| | 248 |
| | 30 |
| | — |
| | 2,729 |
|
| Total revenues | 6,395 |
| | 7,693 |
| | 1,551 |
| | 53 |
| | 15,692 |
|
| Income from equity method investments | 2 |
| | 368 |
| | — |
| | — |
| | 370 |
|
| Net gain (loss) on disposal of assets and other income | 11 |
| | 30 |
| | 4 |
| | 114 |
| | 159 |
|
| Production expenses | 706 |
| | 500 |
| | 996 |
| | — |
| | 2,202 |
|
| Marketing costs | 2,444 |
| | 269 |
| | 31 |
| | — |
| | 2,744 |
|
| Exploration expenses | 588 |
| | 118 |
| | — |
| | — |
| | 706 |
|
| Depreciation, depletion and amortization | 1,428 |
| | 787 |
| | 217 |
| | 45 |
| | 2,477 |
|
| Impairments | 11 |
| | — |
| | — |
| | 360 |
| | 371 |
|
Other expenses (a) | 400 |
| | 200 |
| | 60 |
| | 464 |
| | 1,124 |
|
| Taxes other than income | 226 |
| | 5 |
| | 22 |
| | (5 | ) | | 248 |
|
| Net interest and other | — |
| | — |
| | — |
| | 219 |
| | 219 |
|
| Provision (benefit) for income taxes | 223 |
| | 4,552 |
| | 58 |
| | (316 | ) | | 4,517 |
|
| Segment income/Income from continuing operations | $ | 382 |
| | $ | 1,660 |
| | $ | 171 |
| | $ | (600 | ) | | $ | 1,613 |
|
Capital expenditures (b) | $ | 3,988 |
| | $ | 489 |
| | $ | 188 |
| | $ | 466 |
| | $ | 5,131 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | | | | |
| (In millions) | E&P | | OSM | | IG | | Total |
| 2012 | | | | | | | |
| Revenues: | | | | | | | |
| Customer | $ | 14,026 |
| | $ | 1,552 |
| | $ | — |
| | $ | 15,578 |
|
| Related parties | 58 |
| | — |
| | — |
| | 58 |
|
| Segment revenues | $ | 14,084 |
| | $ | 1,552 |
| | $ | — |
| | 15,636 |
|
| Unrealized gain on crude oil derivative instruments | | | | | | | 52 |
|
| Total revenues | | | | | | | $ | 15,688 |
|
| Segment income | $ | 1,881 |
| | $ | 176 |
| | $ | 91 |
| | $ | 2,148 |
|
| Income from equity method investments | 238 |
| | — |
| | 132 |
| | 370 |
|
| Depreciation, depletion and amortization | 2,226 |
| | 217 |
| | — |
| | 2,443 |
|
| Income tax provision | 4,741 |
| | 59 |
| | 27 |
| | 4,827 |
|
| Capital expenditures | 4,835 |
| | 188 |
| | 2 |
| | 5,025 |
|
|
| | | | | | | | | | | | | | | |
| (In millions) | E&P | | OSM | | IG | | Total |
| 2011 | | | | | | | |
| Revenues: | | | | | | | |
| Customer | $ | 12,922 |
| | $ | 1,588 |
| | $ | 93 |
| | $ | 14,603 |
|
| Intersegment | 47 |
| | — |
| | — |
| | 47 |
|
| Related parties | 60 |
| | — |
| | — |
| | 60 |
|
| Segment revenues | $ | 13,029 |
| | $ | 1,588 |
| | $ | 93 |
| | 14,710 |
|
| Elimination of intersegment revenues | | | | | | | (47 | ) |
| Total revenues | | | �� | | | | $ | 14,663 |
|
| Segment income | $ | 2,157 |
| | $ | 256 |
| | $ | 178 |
| | $ | 2,591 |
|
| Income from equity method investments | 249 |
| | — |
| | 213 |
| | 462 |
|
| Depreciation, depletion and amortization | 2,028 |
| | 196 |
| | 3 |
| | 2,227 |
|
| Income tax provision | 2,808 |
| | 82 |
| | 74 |
| | 2,964 |
|
| Capital expenditures | 3,038 |
| | 308 |
| | 2 |
| | 3,348 |
|
|
| | | | | | | | | | | | | | | |
| (In millions) | E&P | | OSM | | IG | | Total |
| 2010 | | | | | | | |
| Revenues: | | | | | | | |
| Customer | $ | 10,651 |
| | $ | 833 |
| | $ | 150 |
| | $ | 11,634 |
|
| Intersegment | 75 |
| | — |
| | — |
| | 75 |
|
| Related parties | 56 |
| | — |
| | — |
| | 56 |
|
| Segment revenues | $ | 10,782 |
| | $ | 833 |
| | $ | 150 |
| | 11,765 |
|
| Elimination of intersegment revenues | | | | | | | (75 | ) |
| Total revenues |
|
| |
|
| |
|
| | $ | 11,690 |
|
| Segment income (loss) | $ | 1,941 |
| | $ | (50 | ) | | $ | 142 |
| | $ | 2,033 |
|
| Income from equity method investments | 188 |
| | — |
| | 181 |
| | 369 |
|
| Depreciation, depletion and amortization | 1,911 |
| | 105 |
| | 2 |
| | 2,018 |
|
| Income tax provision (benefit) | 2,266 |
| | (12 | ) | | 73 |
| | 2,327 |
|
| Capital expenditures | 2,474 |
| | 874 |
| | 2 |
| | 3,350 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements |
| | | | | | | | | | | | | | | | | | | |
| 2011 | | | Not Allocated | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
| Sales and other operating revenues | $ | 3,364 |
| | $ | 5,851 |
| | $ | 1,535 |
| | $ | — |
| | $ | 10,750 |
|
| Marketing revenues | 3,614 |
| | 252 |
| | 53 |
| | — |
| | 3,919 |
|
| Total revenues | 6,978 |
| | 6,103 |
| | 1,588 |
| | — |
| | 14,669 |
|
| Income from equity method investments | 20 |
| | 442 |
| | — |
| | — |
| | 462 |
|
| Net gain (loss) on disposal of assets and other income | 21 |
| | 73 |
| | (17 | ) | | 74 |
| | 151 |
|
| Production expenses | 545 |
| | 409 |
| | 915 |
| | 82 |
| | 1,951 |
|
| Marketing costs | 3,598 |
| | 247 |
| | 53 |
| | — |
| | 3,898 |
|
| Exploration expenses | 388 |
| | 253 |
| | — |
| | — |
| | 641 |
|
| Depreciation, depletion and amortization | 1,191 |
| | 828 |
| | 196 |
| | 48 |
| | 2,263 |
|
| Impairments | 12 |
| | — |
| | — |
| | 298 |
| | 310 |
|
Other expenses (a) | 494 |
| | 191 |
| | 46 |
| | 465 |
| | 1,196 |
|
| Taxes other than income | 182 |
| | 6 |
| | 17 |
| | (12 | ) | | 193 |
|
| Net interest and loss on early extinguishment of debt | — |
| | — |
| | — |
| | 386 |
|
| 386 |
|
| Provision (benefit) for income taxes | 217 |
| | 2,693 |
| | 83 |
| | (267 | ) | | 2,726 |
|
| Segment income/Income from continuing operations | $ | 392 |
| | $ | 1,991 |
| | $ | 261 |
| | $ | (926 | ) | | $ | 1,718 |
|
Capital expenditures (b) | $ | 2,163 |
| | $ | 544 |
| | $ | 308 |
| | $ | 384 |
| | $ | 3,399 |
|
The following reconciles total revenues to sales and other operating revenues in the consolidated statements of income.
|
| | | | | | | | | | | |
| (In millions) | 2012 | | 2011 | | 2010 |
| Total revenues | $ | 15,688 |
| | $ | 14,663 |
| | $ | 11,690 |
|
| Less: Sales to related parties | 58 |
| | 60 |
| | 56 |
|
| Sales and other operating revenues | $ | 15,630 |
| | $ | 14,603 |
| | $ | 11,634 |
|
The following reconciles segment income to net income as reported in the consolidated statements of income.
|
| | | | | | | | | | | |
| (In millions) | 2012 | | 2011 | | 2010 |
| Segment income | $ | 2,148 |
| | $ | 2,591 |
| | $ | 2,033 |
|
| Items not allocated to segments, net of income taxes: | | | | | |
| Corporate and other unallocated items | (441 | ) | | (317 | ) | | (170 | ) |
| Impairments | (231 | ) | | (195 | ) | | (286 | ) |
| Gain on dispositions | 72 |
| | 45 |
| | 407 |
|
| Unrealized gain on crude oil derivative instruments | 34 |
| | — |
| | — |
|
| Loss on early extinguishment of debt | — |
| | (176 | ) | | (57 | ) |
| Tax effect of subsidiary restructuring | — |
| | (122 | ) | | — |
|
| Deferred income tax items | — |
| | (61 | ) | | (45 | ) |
| Water abatement - Oil Sands | — |
| | (48 | ) | | — |
|
| Eagle Ford transaction costs | — |
| | (10 | ) | | — |
|
| Income from continuing operations | 1,582 |
| | 1,707 |
| | 1,882 |
|
| Discontinued operations | — |
| | 1,239 |
| | 686 |
|
| Net income | $ | 1,582 |
| | $ | 2,946 |
| | $ | 2,568 |
|
Revenues from external customers are attributed to geographic areas based upon selling location. The following summarizes revenues from external customers by geographic area.
| | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| United States | $ | 6,442 |
| | $ | 6,971 |
| | $ | 5,363 |
| $ | 6,813 |
| | $ | 6,448 |
| | $ | 6,978 |
|
| United Kingdom | 1,245 |
| | 1,546 |
| | 1,063 |
| |
Libya(a) | 1,989 |
| | 216 |
| | 1,473 |
| |
| Norway | 3,582 |
| | 3,386 |
| | 2,243 |
| 3,183 |
| | 3,714 |
| | 3,563 |
|
| Canada | 1,552 |
| | 1,588 |
| | 833 |
| 1,594 |
| | 1,551 |
| | 1,588 |
|
Libya(a) | | 1,106 |
| | 1,989 |
| | 216 |
|
| Other international | 878 |
| | 956 |
| | 715 |
| 1,805 |
| | 1,990 |
| | 2,324 |
|
| Total revenues | $ | 15,688 |
| | $ | 14,663 |
| | $ | 11,690 |
| $ | 14,501 |
| | $ | 15,692 |
| | $ | 14,669 |
|
| |
(a) | See Note 13 for discussion of Libya operations. |
In 2013, sales to British Petroleum and its affiliates accounted for approximately 11 percent of our total revenues. In 2012, Statoil, the purchaser of the majority of our Libyan crude oil, accounted for approximately 15 percent of our total revenues, while sales to Shell Oil and its affiliates accounted for approximately 12 percent of total revenues. In 2011, and 2010, our sales to MPC accounted for approximately 18 percent and 16 percent of total revenues. In 2010, sales to the Libyan National Oil Company accounted for approximately 13 percentof total revenues.
Revenues by product line were:
|
| | | | | | | | | | | |
| (In millions) | 2013 | | 2012 | | 2011 |
| Liquid hydrocarbons | $ | 11,932 |
| | $ | 12,983 |
| | $ | 11,778 |
|
| Natural gas | 937 |
| | 1,052 |
| | 1,203 |
|
| Synthetic crude oil | 1,542 |
| | 1,409 |
| | 1,442 |
|
| Other | 90 |
| | 248 |
| | 246 |
|
| Total revenues | $ | 14,501 |
| | $ | 15,692 |
| | $ | 14,669 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Revenues by product line were:
|
| | | | | | | | | | | |
| (In millions) | 2012 | | 2011 | | 2010 |
| Liquid hydrocarbons | $ | 12,945 |
| | $ | 11,717 |
| | $ | 9,480 |
|
| Natural gas | 1,103 |
| | 1,291 |
| | 1,295 |
|
| Synthetic crude oil | 1,545 |
| | 1,581 |
| | 832 |
|
| Transportation & other | 95 |
| | 74 |
| | 83 |
|
| Total revenues | $ | 15,688 |
| | $ | 14,663 |
| | $ | 11,690 |
|
The following summarizes certain long-lived assets by geographic area, including property, plant and equipment and equity method investments.
| | | | | | | December 31, |
| (In millions) | 2012 | | 2011 | 2013 | | 2012 |
| United States | $ | 13,677 |
| | $ | 10,928 |
| $ | 14,635 |
| | $ | 13,677 |
|
| Canada | 9,693 |
| | 9,711 |
| 9,794 |
| | 9,693 |
|
| Norway | | 977 |
| | 987 |
|
| Equatorial Guinea | 2,081 |
| | 2,214 |
| 1,977 |
| | 2,081 |
|
| Norway | 987 |
| | 1,133 |
| |
| Other international | 3,113 |
| | 2,721 |
| 1,963 |
| | 3,113 |
|
| Total long-lived assets | $ | 29,551 |
| | $ | 26,707 |
| $ | 29,346 |
| | $ | 29,551 |
|
9. Other Items
| | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Interest: | | | | | | | | | | |
| Interest income | $ | 13 |
| | $ | 12 |
| | $ | 11 |
| $ | 6 |
| | $ | 13 |
| | $ | 12 |
|
Interest expense(a) | (300 | ) | | (281 | ) | | (375 | ) | (307 | ) | | (244 | ) | | (228 | ) |
| Income on interest rate swaps | 7 |
| | 10 |
| | 26 |
| 9 |
| | 7 |
| | 10 |
|
| Interest capitalized | 68 |
| | 151 |
| | 297 |
| 21 |
| | 12 |
| | 103 |
|
| Total interest | (212 | ) | | (108 | ) | | (41 | ) | (271 | ) | | (212 | ) | | (103 | ) |
| Other: | | | | | | | | | | |
| Net foreign currency gains (losses) | 4 |
| | 24 |
| | (21 | ) | |
| Net foreign currency gains | | 16 |
| | 4 |
| | 24 |
|
| Write off of contingent proceeds | — |
| | (7 | ) | | (15 | ) | (4 | ) | | — |
| | (7 | ) |
| Other | (11 | ) | | (16 | ) | | 2 |
| (15 | ) | | (11 | ) | | (21 | ) |
| Total other | (7 | ) | | 1 |
| | (34 | ) | (3 | ) | | (7 | ) | | (4 | ) |
| Net interest and other | $ | (219 | ) | | $ | (107 | ) | | $ | (75 | ) | $ | (274 | ) | | $ | (219 | ) | | $ | (107 | ) |
| |
(a) | Excludes $1 million, and $10 million and $16 million paid by United States Steel in2012, 2011 and 20102011 on assumed debt. |
Foreign currency transactions – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows: | | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Net interest and other | $ | 4 |
| | $ | 24 |
| | $ | (21 | ) | $ | 16 |
| | $ | 4 |
| | $ | 24 |
|
| Provision for income taxes | 80 |
| | (57 | ) | | (1 | ) | 105 |
| | (80 | ) | | 57 |
|
| Aggregate foreign currency gains (losses) | $ | 84 |
| | $ | (33 | ) | | $ | (22 | ) | $ | 121 |
| | $ | (76 | ) | | $ | 81 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
10. Income Taxes
Income tax provisions (benefits) for continuing operations were: | | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| (In millions) | Current | | Deferred | | Total | | Current | | Deferred | | Total | | Current | | Deferred | | Total | Current | | Deferred | | Total | | Current | | Deferred | | Total | | Current | | Deferred | | Total |
| Federal | $ | (80 | ) | | $ | 233 |
| | $ | 153 |
| | $ | (210 | ) | | $ | (206 | ) | | $ | (416 | ) | | $ | (279 | ) | | $ | (267 | ) | | $ | (546 | ) | $ | 63 |
| | $ | (46 | ) | | $ | 17 |
| | $ | (80 | ) | | $ | (30 | ) | | $ | (110 | ) | | $ | (193 | ) | | $ | (217 | ) | | $ | (410 | ) |
| State and local | (23 | ) | | 47 |
| | 24 |
| | 24 |
| �� | 82 |
| | 106 |
| | 2 |
| | (10 | ) | | (8 | ) | 44 |
| | 1 |
| | 45 |
| | (23 | ) | | 47 |
| | 24 |
| | 24 |
| | 82 |
| | 106 |
|
| Foreign | 4,844 |
| | (490 | ) | | 4,354 |
| | 3,088 |
| | (58 | ) | | 3,030 |
| | 2,941 |
| | (212 | ) | | 2,729 |
| 3,290 |
| | (15 | ) | | 3,275 |
| | 4,844 |
| | (241 | ) | | 4,603 |
| | 3,088 |
| | (58 | ) | | 3,030 |
|
| Total | $ | 4,741 |
| | $ | (210 | ) | | $ | 4,531 |
| | $ | 2,902 |
| | $ | (182 | ) | | $ | 2,720 |
| | $ | 2,664 |
| | $ | (489 | ) | | $ | 2,175 |
| $ | 3,397 |
| | $ | (60 | ) | | $ | 3,337 |
| | $ | 4,741 |
| | $ | (224 | ) | | $ | 4,517 |
| | $ | 2,919 |
| | $ | (193 | ) | | $ | 2,726 |
|
A reconciliation of the federal statutory income tax rate applied to income from continuing operations before income taxes to the provision for income taxes follows: | | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Statutory rate applied to income from continuing operations before income taxes | 35 | % | | 35 | % | | 35 | % | 35 | % | | 35 | % | | 35 | % |
| Effects of foreign operations, including foreign tax credits | 18 |
| | 6 |
| | 20 |
| 14 |
| | 18 |
| | 6 |
|
| Change in permanent reinvestment assertion | — |
| | 5 |
| | — |
| — |
| | — |
| | 5 |
|
| Adjustments to valuation allowances | 21 |
| | 14 |
| | (2 | ) | 18 |
| | 21 |
| | 14 |
|
| Tax law changes | — |
| | 1 |
| | 1 |
| — |
| | — |
| | 1 |
|
| Other | | 1 |
| | — |
| | — |
|
| Effective income tax rate on continuing operations | 74 | % | | 61 | % | | 54 | % | 68 | % | | 74 | % | | 61 | % |
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments andappears in the "Not Allocated to individual items not allocated to segments is reported in "Corporate and other unallocated items" shownSegments" column of the tables in Note 8.
Effects of foreign operations – The effects of foreign operations on our effective tax rate increaseddecreased in 20122013 as compared to 20112012, primarily due to decreased sales in Libya in 2013 as a result of third-party labor strikes at the Es Sider oil terminal. The effects of foreign operations on our effective tax rate increased in 2012 from 2011, primarily due to the resumption of sales of Libyan production in 2012, where the statutory tax rate is in excess of 90 percent.2012.
Change in permanent reinvestment assertion – In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U.S. tax on previously undistributed earnings.
Adjustments to valuation allowances – In 2013, 2012 and 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in those years.
Tax law changes – On July 17, 2012, theThe U.K. enacted Finance Bill 2013 in July 2013 and Finance Bill 2012 in July 2012, which restricted relief on decommissioning charges and reduced the main corporate tax rate. There were no changes todid not change the rate of corporation tax or the supplementary corporation tax for U.K. ring-fenced activities in the oil and gas sector. This As such, this legislation did not have a material impact on our consolidated financial statements.income tax provision. In July 2011, the U.K. enacted Finance Bill 2011 which increased the rate of the supplementary charge levied on profits from U.K. oil and gas production from 20 percent to 32 percent. As a result of this legislation, we recorded deferred tax expense of $10 million in 2011.
On May 25, 2011, Michigan enacted legislation that replaced the Michigan Business Tax ("MBT") with a corporate income tax ("CIT"), effective January 1, 2012. The CIT legislation eliminated the "book-tax difference deduction" that was provided under the MBT to mitigate the net increase in a taxpayer’s deferred tax liability resulting when Michigan moved from the Single Business Tax, a non-income tax, to the MBT, an income tax, on July 12, 2007. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relates to discontinued operations. As a result of the new CIT legislation, we recorded deferred tax expense of $32 million in the second quarter of 2011.
The Patient Protection and Affordable Care Act ("PPACA") and the Health Care and Education Reconciliation Act of 2010 ("HCERA"), (together, the "Acts") were signed in to law in March 2010. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the "MPDIMA"). Under the MPDIMA, the federal subsidy did not reduce our income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Beginning in 2013, under the Acts, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relates to discontinued operations. As a result, we recorded deferred tax expense of $45 million in the first quarter of 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.
Deferred tax assets and liabilities resulted from the following: | | | | December 31, | December 31, |
| (In millions) | 2012 | | 2011(a) | 2013 | | 2012 |
| Deferred tax assets: | | | | | | |
| Employee benefits | $ | 510 |
| | $ | 455 |
| $ | 387 |
| | $ | 510 |
|
| Operating loss carryforwards | 368 |
| | 354 |
| 284 |
| | 368 |
|
| Foreign tax credits | 4,351 |
| | 3,005 |
| 5,730 |
| | 4,351 |
|
| Other | 121 |
| | 95 |
| 98 |
| | 121 |
|
| Valuation allowances: | | | | | | |
| Federal | (2,067 | ) | | (790 | ) | (2,997 | ) | | (2,067 | ) |
| State, net of federal benefit | (60 | ) | | (40 | ) | (67 | ) | | (60 | ) |
| Foreign | (210 | ) | | (194 | ) | (149 | ) | | (210 | ) |
| Total deferred tax assets | 3,013 |
| | 2,885 |
| 3,286 |
| | 3,013 |
|
| Deferred tax liabilities: | | | | | | |
| Property, plant and equipment | 3,691 |
| | 3,404 |
| 4,018 |
| | 3,691 |
|
| Investments in subsidiaries and affiliates | 840 |
| | 1,216 |
| 794 |
| | 840 |
|
| Other | 12 |
| | 41 |
| 67 |
| | 12 |
|
| Total deferred tax liabilities | 4,543 |
| | 4,661 |
| 4,879 |
| | 4,543 |
|
| Net deferred tax liabilities | $ | 1,530 |
| | $ | 1,776 |
| $ | 1,593 |
| | $ | 1,530 |
|
(a) Certain 2011 amounts were reclassified to conform to the current period's presentation.
Operating lossTax carryforwards – At December 31, 20122013, our operating loss carryforwards includeincluded $811744 million of Canadian operating loss carryforwards thatfrom Canada which expire from 2013in 2026 through 20322030 and $216128 million from the Kurdistan Region of Indonesian operating loss carryforwardsIraq that do not have expiration dates.expire in 2016 through 2018. State operating loss carryforwards of $1,3631,503 million expire in 20132014 through 2031.2033. Foreign tax credit carryforwards of $3,560 million expire in 2022 through 2023.
Valuation allowances – The ability to realizeestimated realizability of the benefit of foreign tax credits is based on certain estimates concerning future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and our tax profile in the years that such credits may be claimed. Federal valuation allowances increased $930 million, $1,277 million in 2012, increasedand $585 million in 2013, 2012 and 2011 and, because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in those years.
Foreign valuation allowances decreased $7461 million in 20102013, primarily due to changes in the expected realizabilitydisposal of foreign tax credits.
our Indonesian assets. Foreign valuation allowances increased $16 million and $52 millionin 2012 and 2011, primarily due to deferred tax assets generated in the Kurdistan Region of Iraq, Angola and Angola. Foreign valuation allowances increased $52 million and $40 million in 2011 and 2010, primarily due to net operating loss carryforwards generated in Indonesia.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Net deferred tax liabilities were classified in the consolidated balance sheets as follows: | | | | December 31, | December 31, |
| (In millions) | 2012 | | 2011 | 2013 | | 2012 |
| Assets: | | | | | | |
| Other current assets | $ | 57 |
| | $ | 99 |
| $ | 53 |
| | $ | 57 |
|
| Other noncurrent assets | 849 |
| | 674 |
| 847 |
| | 849 |
|
| Liabilities: | | | | | | |
| Other current liabilities | 4 |
| | 5 |
| 1 |
| | 4 |
|
| Noncurrent deferred tax liabilities | 2,432 |
| | 2,544 |
| 2,492 |
| | 2,432 |
|
| Net deferred tax liabilities | $ | 1,530 |
| | $ | 1,776 |
| $ | 1,593 |
| | $ | 1,530 |
|
We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. Such audits have been completed through the 2009 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
As of December 31, 20122013, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated: |
| |
United States(a) | 2005-20112004-2012 |
| Canada | 2008-20112008-2012 |
| Equatorial Guinea | 2007-20112007-2012 |
| Libya | 2006-20112006-2012 |
| Norway | 2008-20112008-2012 |
| United Kingdom | 2008-20112008-2012 |
| |
(a) | Includes federal and state jurisdictions. |
The following table summarizes the activity in unrecognized tax benefits:
| | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Beginning balance | $ | 157 |
| | $ | 103 |
| | $ | 75 |
| $ | 98 |
| | $ | 157 |
| | $ | 103 |
|
| Additions for tax positions related to the current year | — |
| | 4 |
| | 28 |
| 14 |
| | — |
| | 4 |
|
| Reductions for tax positions related to the current year | — |
| | — |
| | (1 | ) | |
| Additions for tax positions of prior years | 81 |
| | 87 |
| | 25 |
| 66 |
| | 81 |
| | 87 |
|
| Reductions for tax positions of prior years | (67 | ) | | (29 | ) | | (12 | ) | (25 | ) | | (67 | ) | | (29 | ) |
| Settlements | (72 | ) | | (8 | ) | | (12 | ) | (5 | ) | | (72 | ) | | (8 | ) |
| Statute of limitations | (1 | ) | | — |
| | — |
| (2 | ) | | (1 | ) | | — |
|
| Ending balance | $ | 98 |
| | $ | 157 |
| | $ | 103 |
| $ | 146 |
| | $ | 98 |
| | $ | 157 |
|
If the unrecognized tax benefits as of December 31, 20122013 were recognized, $9298 million would affect our effective income tax rate. There were $1611 million of uncertain tax positions as of December 31, 20122013 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during the next twelve months.
Interest and penalties are recorded as part of the tax provision and were $413 million, $134 million and $513 million related to unrecognized tax benefits in 20122013, 20112012 and 20102011. As of December 31, 20122013 and 2011,2012, $2415 million and $2724 million of interest and penalties were accrued related to income taxes.
Pretax income from continuing operations included amounts attributable to foreign sources of $6,3654,874 million, $4,8696,382 million and $4,5634,886 million in 20122013, 20112012 and 20102011.
Undistributed income of certain consolidated foreign subsidiaries at December 31, 20122013 amounted to $5711,438 million for which no U.S. deferred income tax provision has been recorded because we intend to permanently reinvest such income in our foreign operations. If such income was not permanently reinvested, income tax expense of approximately $200503 million would be recorded, not including potential utilization of foreign tax credits.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
11. Inventories
Inventories are carried at the lower of cost or market value. The LIFO method accounted for 4 percent and 6 percent and 23 percent of total inventory value at December 31, 20122013 and 2011.2012. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 20122013 and 20112012 by $29$32 million and $74 million.$29 million.
| | | | December 31, | December 31, |
| (In millions) | 2012 | | 2011 | 2013 | | 2012 |
| Liquid hydrocarbons, natural gas and bitumen | $ | 73 |
| | $ | 147 |
| $ | 55 |
| | $ | 73 |
|
| Supplies and sundry items | 288 |
| | 214 |
| |
| Supplies and other items | | 309 |
| | 288 |
|
| Inventories at cost | $ | 361 |
| | $ | 361 |
| $ | 364 |
| | $ | 361 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
12. Equity Method Investments and Related Party Transactions
During 20122013, 20112012 and 20102011 only our equity method investees were considered related parties and they included:
•Alba Plant LLC, in which we have a 52 percent noncontrolling interest. Alba Plant LLC processes LPG.
AMPCO, in which we have a 45 percent interest. AMPCO is engaged in methanol production activity.
EGHoldings, in which we have a 60 percent noncontrolling interest. EGHoldings is engaged in LNG production activities.activity.
Our equity method investments are summarized in the following table:
|
| | | | | | | | | |
| | Ownership as of December 31, 2012 | | December 31, |
| (In millions) | 2012 | | 2011 |
| EGHoldings | 60% | | $ | 817 |
| | $ | 875 |
|
| Alba Plant LLC | 52% | | 264 |
| | 272 |
|
| AMPCO | 45% | | 187 |
| | 191 |
|
| Other investments | | | 11 |
| | 45 |
|
| Total | | | $ | 1,279 |
| | $ | 1,383 |
|
As of December 31, 2012, the carrying value of our equity method investments was $133 million higher than the underlying net assets of investees. This basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets. |
| | | | | | | | | |
| | Ownership as of | | December 31, |
| (In millions) | December 31, 2013 | 2013 | | 2012 |
| EGHoldings | 60% | | $ | 748 |
| | $ | 817 |
|
| Alba Plant LLC | 52% | | 263 |
| | 264 |
|
| AMPCO | 45% | | 189 |
| | 187 |
|
| Other investments | | | 1 |
| | 11 |
|
| Total | | | $ | 1,201 |
| | $ | 1,279 |
|
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $435 million in 2013, $381 million in 2012, and $509 million in 2011 and $400 million in 2010.
Summarized financial information for equity method investees is as follows:
| | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Income data – year: | | | | | | | | | | |
| Revenues and other income | $ | 1,330 |
| | $ | 1,544 |
| | $ | 1,305 |
| $ | 1,444 |
| | $ | 1,330 |
| | $ | 1,544 |
|
| Income from operations | 755 |
| | 942 |
| | 762 |
| 849 |
| | 755 |
| | 942 |
|
| Net income | 635 |
| | 820 |
| | 671 |
| 727 |
| | 635 |
| | 820 |
|
| Balance sheet data – December 31: | | | | | | | | | | |
| Current assets | $ | 607 |
| | $ | 688 |
| | | $ | 644 |
| | $ | 607 |
| | |
| Noncurrent assets | 1,743 |
| | 2,079 |
| | | 1,590 |
| | 1,743 |
| | |
| Current liabilities | 395 |
| | 504 |
| | | 384 |
| | 395 |
| | |
| Noncurrent liabilities | 29 |
| | 115 |
| | | 33 |
| | 29 |
| | |
Almost all of our purchasesRevenues from related parties are liquid hydrocarbons acquiredwere $55 million, $58 million and $60 million in 2013, 2012 and 2011, with the majority related to EGHoldings in all years. Purchases from related parties were $242 million, $248 million and $250 million in 2013, 2012 and 2011 with the majority related to Alba Plant LLC. Approximately 75 percent of our salesLLC in all years.
Current receivables from related parties at December 31, 2013 and 2012, approximately split evenly between EGHoldings and AMPCO, were $30 million and $27 million. Payables to related parties were $20 million at December 31, 2013 and 2012, with the majority related to Alba Plant LLC.
13. Property, Plant and Equipment
|
| | | | | | | |
| | December 31, |
| (In millions) | 2013 | | 2012 |
| North America E&P | $ | 26,755 |
| | $ | 23,748 |
|
| International E&P | 12,428 |
| | 13,214 |
|
| Oil Sands Mining | 10,436 |
| | 10,127 |
|
| Corporate | 421 |
| | 449 |
|
| Total property, plant and equipment | 50,040 |
| | 47,538 |
|
| Less accumulated depreciation, depletion and amortization | (21,895 | ) | | (19,266 | ) |
| Net property, plant and equipment | $ | 28,145 |
| | $ | 28,272 |
|
During the third quarter of 2013, our Libya production operations were impacted by third-party labor strikes at the Es Sider oil terminal. We have had no oil liftings in all periods are associated withLibya since July 2013. Uncertainty around production and sales levels from Libya have existed since the first quarter of natural gas to EGHoldings.2011 when production operations were suspended until the fourth quarter of that year. We
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
13. Property, Plant and Equipment
|
| | | | | | | |
| | December 31, |
| (In millions) | 2012 | | 2011 |
| E&P | | | |
| United States | $ | 23,400 |
| | $ | 19,679 |
|
| International | 13,523 |
| | 12,579 |
|
| Total E&P | 36,923 |
| | 32,258 |
|
| OSM | 10,128 |
| | 9,936 |
|
| IG | 38 |
| | 37 |
|
| Corporate | 449 |
| | 341 |
|
| Total property, plant and equipment | $ | 47,538 |
| | $ | 42,572 |
|
| Less accumulated depreciation, depletion and amortization | (19,266 | ) | | (17,248 | ) |
| Net property, plant and equipment | $ | 28,272 |
| | $ | 25,324 |
|
In the first quarter of 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed. Since that time, average net liquid hydrocarbon sales volumes have increased to pre-conflict levels. 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. As of December 31, 2012,2013, our net property, plant and equipment investment in Libya is approximately $745$761 million and total proved reserves (unaudited) in Libya are 244249 mmboe.
Deferred exploratory well costs were as follows: | | | | December 31, | December 31, |
| (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Amounts capitalized less than one year after completion of drilling | $ | 388 |
| | $ | 482 |
| | $ | 334 |
| $ | 512 |
| | $ | 388 |
| | $ | 482 |
|
| Amounts capitalized greater than one year after completion of drilling | 229 |
| | 222 |
| | 323 |
| 281 |
| | 229 |
| | 222 |
|
| Total deferred exploratory well costs | $ | 617 |
| | $ | 704 |
| | $ | 657 |
| $ | 793 |
| | $ | 617 |
| | $ | 704 |
|
| Number of projects with costs capitalized greater than one year after | | | | | | | | | | |
| completion of drilling | 6 |
| | 5 |
| | 7 |
| 7 |
| | 6 |
| | 5 |
|
| | | | | | | December 31, |
| (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Beginning balance | $ | 704 |
| | $ | 657 |
| | $ | 829 |
| $ | 617 |
| | $ | 704 |
| | $ | 657 |
|
| Additions | 731 |
| | 670 |
| | 329 |
| 746 |
| | 699 |
| | 625 |
|
| Dry well expense | (143 | ) | | (268 | ) | | (83 | ) | (147 | ) | | (111 | ) | | (223 | ) |
| Transfers to development | (629 | ) | | (279 | ) | | (54 | ) | (414 | ) | | (629 | ) | | (279 | ) |
| Dispositions | (46 | ) | | (76 | ) | | (364 | ) | (9 | ) | | (46 | ) | | (76 | ) |
| Ending balance | $ | 617 |
| | $ | 704 |
| | $ | 657 |
| $ | 793 |
| | $ | 617 |
| | $ | 704 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 20122013 are summarized by geographical area below:
| | | (In millions) | | |
| Angola | $ | 128 |
| $ | 153 |
|
| Norway | 70 |
| 70 |
|
| E.G. | 22 |
| 22 |
|
| U.S. | 9 |
| |
| Canada | | 36 |
|
| Total | $ | 229 |
| $ | 281 |
|
Well costs that have been suspended for longer than one year are associated with 6seven projects. Management believes these projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development.
Angola – Exploration on Angola Block 31 began in 2004, with costs accumulating through 2009. Development alternatives are being evaluatedExploration on Angola Block 32 began in 2011, with costs accumulating through 2013. In June and optimization efforts continue for this block.December 2013, we entered into agreements to sell our non-operated working interests in Angola Blocks 31 and 32 (see Note 6).
Norway – Three offshore Norway development projects had costs incurred from 2009 through 2011. The development plan for Boyla was approved by the Norwegian government in October 2012. This will tie-back to the Alvheim FPSO and development drilling is planned in 2014, with first production expected to begin in late 2013.early 2015. Development options are being evaluated for the Caterpillar and drilling on Viper is planned for 2015.projects.
E.G. – The Corona well on Block D offshore E.G. was drilled in 2004, and we acquired an additional interest in the well in 2012. We plan to develop Block D through a unitization with the Alba field, which is expected in late 2013 or early 2014.currently being negotiated.
U.S.Canada – Exploration began on our Canadian in-situ assets at Birchwood in 2010 with costs accumulating through 2011. In 2012, we submitted a regulatory application for a proposed 12 mbbld SAGD demonstration project. We incurred drilling costs in the Marcellus natural gas shale play from 2009 through 2010, and were carried in drilling that occurred during 2011. Atexpect to receive regulatory approval for this project by the end of 2012,2014. Upon receiving this approval, we will further evaluate our plans were to hold and develop our leasehold position in 2013 by drilling and completing one new well and completing one previously drilled well. In February 2013, we entered an agreement to convey our interest in this asset to the operator.development plans.
14. Goodwill
Goodwill is tested for impairment on an annual basis, or when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below theits carrying value. We performed our annual impairment tests during 20122013, 20112012 and 20102011 and no impairment was required. The fair value of each of our reporting units with goodwill exceeded the book value appreciably; however, should market conditions deteriorate or commodity prices decline significantly, an impairment may be necessary.appreciably.
The changes in the carrying amount of goodwill for the years ended December 31, 2012 and 2011 were as follows:
|
| | | | | | | | | | | | | | | |
| (In millions) | E&P | | OSM | | Downstream business | | Total |
| 2011 | | | | | | | |
| Beginning balance, gross | $ | 537 |
| | $ | 1,412 |
| | $ | 843 |
| | $ | 2,792 |
|
| Less: accumulated impairment | — |
| | (1,412 | ) | | — |
| | (1,412 | ) |
| Beginning balance, net | 537 |
| | — |
| | 843 |
| | 1,380 |
|
| Contingent consideration adjustment | — |
| | — |
| | (3 | ) | | (3 | ) |
| Purchase price adjustment | — |
| | — |
| | 9 |
| | 9 |
|
| Dispositions | (1 | ) | | — |
| | (2 | ) | | (3 | ) |
| Spin-off downstream business | — |
| | — |
| | (847 | ) | | (847 | ) |
| Ending balance, net | 536 |
| | — |
| | — |
| | 536 |
|
| 2012 | | | | | | | |
| Beginning balance, gross | 536 |
| | 1,412 |
| | — |
| | 1,948 |
|
| Less: accumulated impairments | — |
| | (1,412 | ) | | — |
| | (1,412 | ) |
| Beginning balance, net | 536 |
| | — |
| | — |
| | 536 |
|
| Dispositions | (11 | ) | | — |
| | — |
| | (11 | ) |
| Ending balance, net | $ | 525 |
| | $ | — |
| | $ | — |
| | $ | 525 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The changes in the carrying amount of goodwill for 2012 were as follows for the Exploration and Production ("E&P") and OSM segments in place for that year:
|
| | | | | | | | | | | |
| (In millions) | E&P | | OSM | | Total |
| 2012 | | | | | |
| Beginning balance, gross | $ | 536 |
| | $ | 1,412 |
| | $ | 1,948 |
|
| Less: accumulated impairments | — |
| | (1,412 | ) | | (1,412 | ) |
| Beginning balance, net | 536 |
| | — |
| | 536 |
|
| Dispositions | (11 | ) | | — |
| | (11 | ) |
| Ending balance, net | $ | 525 |
| | $ | — |
| | $ | 525 |
|
As discussed in Note 8, beginning in 2013, we changed our reportable segments. Goodwill related to the previously reported E&P segment was allocated between the North America E&P and International E&P segments as of January 1, 2013 based on the relative fair values of those reporting units. The fair values of the reporting units were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rates, all of which are Level 3 inputs. Inputs to the fair value measurements included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses. The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount of goodwill for 2013:
|
| | | | | | | | | | | | | | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | Total |
| 2013 | | | | | | | |
| Beginning balance, gross | $ | 343 |
| | $ | 182 |
| | $ | 1,412 |
| | $ | 1,937 |
|
| Less: accumulated impairments | — |
| | — |
| | (1,412 | ) | | (1,412 | ) |
| Beginning balance, net | 343 |
| | 182 |
| | — |
| | 525 |
|
| Dispositions | 4 |
| (a) | (30 | ) | | — |
| | (26 | ) |
| Ending balance, net | $ | 347 |
| | $ | 152 |
| | $ | — |
| | $ | 499 |
|
| |
(a) | Goodwill related to our Alaska disposition was less than the estimate classified as held for sale in 2012. |
15. Fair Value Measurements
Fair values – Recurring
The following table presentstables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2013 and 2012 by fair value hierarchy level.
| | | | | December 31, 2013 |
| (In millions) | | Level 1 | | Level 2 | | Level 3 | | Collateral | | Total |
| Derivative instruments, assets | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Foreign currency | | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Derivative instruments, assets | | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
| Derivative instruments, liabilities | | | | | | | | | | |
| Foreign currency | | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Derivative instruments, liabilities | | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| | | | | | | | | | | | | | | | | | | | |
| | December 31, 2012 | December 31, 2012 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Collateral | | Total | Level 1 | | Level 2 | | Level 3 | | Collateral | | Total |
| Derivative instruments, assets | | | | | | | | | |
| |
| |
| |
| |
|
| Commodity | $ | — |
| | $ | 52 |
| | $ | — |
| | $ | 1 |
| | $ | 53 |
| $ | — |
| | $ | 52 |
| | $ | — |
| | $ | 1 |
| | $ | 53 |
|
| Interest rate | — |
| | 21 |
| | — |
| | — |
| | 21 |
| — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Foreign currency | — |
| | 18 |
| | — |
| | — |
| | 18 |
| — |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Derivative instruments, assets | $ | — |
| | $ | 91 |
| | $ | — |
| | $ | 1 |
| | $ | 92 |
| $ | — |
| | $ | 91 |
| | $ | — |
| | $ | 1 |
| | $ | 92 |
|
As of December 31, 2011, balances related to interestInterest rate swaps accounted for at fair value on a recurring basis were noncurrent assets of $5 millionare measured at fair value with a market approach using actionable broker quotes which are Level 2 inputs. There were no other significant recurringForeign currency forwards are measured at fair value measurementswith a market approach using third-party pricing services, such as of December 31, 2011.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Bloomberg L.P., which have been corroborated with data from active markets for similar assets or liabilities, and are Level 2 inputs.
Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities. Commodity options in Level 2 are valued using the Black-Scholes Model. Inputs to this model include prices as noted above, discount factors, and implied market volatility. The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments. Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes which are Level 2 inputs. Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as Bloomberg L.P., which have been corroborated with data from active markets for similar assets or liabilities, and are Level 2 inputs.
Fair values – Nonrecurring
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| (In millions) | Fair Value | | Impairment | | Fair Value | | Impairment | | Fair Value | | Impairment | Fair Value | | Impairment | | Fair Value | | Impairment | | Fair Value | | Impairment |
| Long-lived assets held for use | $ | 16 |
| | $ | 371 |
| | $ | 226 |
| | $ | 285 |
| | $ | 147 |
| | $ | 447 |
| $ | 5 |
| | $ | 96 |
| | $ | 16 |
| | $ | 371 |
| | $ | 226 |
| | $ | 285 |
|
| Long-lived assets held for sale | — |
| | — |
| | — |
| | — |
| | 85 |
| | 64 |
| |
| Intangible assets | — |
| | — |
| | — |
| | 25 |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 25 |
|
| Equity method investments | — |
| | — |
| | — |
| | — |
| | — |
| | 25 |
| |
International E&P
Long-lived assets held for use – All long-livedIn light of E.G.’s recent natural gas policy developments related to the country’s natural gas resources, we elected to cease our efforts to develop a second LNG production train on Bioko Island and recorded a $40 million impairment of all capitalized costs associated with engineering and feasibility studies in the fourth quarter of 2013. In addition, our share of income from EGHoldings included a $4 million impairment related to the same project which is reflected in income from equity method investments in the 2013 consolidated statement of income.
North America E&P
Long-lived assets held for use that were impaired in 2012, 2011 and 2010 were held by our E&P segment.– The fair values of each discussed below were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs. Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.
In the fourth quarter of 2012, declining natural gas prices related to our Powder River Basin asset prompted lower production expectations and reductions in estimated reserves which resulted in an impairment of $73 million. Subsequently, in the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an additional impairment of $15 million was recorded to write down the asset's remaining fair value.
During early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly and have remained below initial expectations.significantly. Accordingly, our reserve engineers performed evaluations of our future production as well as our reserves and an impairment was recorded in the first quarter of 2012. As the development produced toward abandonment pressures, further downward revisions of reserves were taken resulting in a fair value measurement of $6 million by year end for an aggregate impairment of $289 million in 2012.
InOzona production ceased in the fourthfirst quarter of 2012, declining natural gas prices prompted lower production expectations and reductions in estimated reserves related to our Powder River Basin asset. This resulted in an impairment of $73 million to reach the $6 million fair value of this asset. Additionally, in March 2010, we completed a reservoir study which resulted in a portion of our Powder River Basin
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
asset being removed from plans for future development. At that time, the asset's fair value was measured at $144 million2013 and an additional $21 million impairment of $423 million was recorded.
In May 2011, significant water production and reservoir pressure declines occurred at our Droshky development in the Gulf of Mexico. Plans for a waterflood were canceled and the field will be produceddue to abandonment pressures, which are expecteda decrease in the first half of 2013. Consequently, proved reserves, were reduced by 3.4 million boe and a $273 million impairment of this asset to its $226 million fair value was recorded in 2011.
Other impairments of long-lived assets held for use by our E&P segment in 2013, 2012, 2011 and 20102011 were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.
Intangible assets– In the second quarter of 2011, our outlook for U.S. natural gas prices made it unlikely that sufficient U.S. demand for LNG would materialize by 2021, which is when the rights lapse under our arrangements at the Elba Island, Georgia regasification facility. Using an income approach based upon internal estimates of gas prices and future deliveries, which are Level 3 inputs, we determined that the contract had no remaining fair value and recorded a full impairment of this intangible asset held in our IG segment.asset.
Long-lived assets held for sale – In the fourth quarter of 2010, due84
MARATHON OIL CORPORATION
Notes to the pending sale of our E&P segment’s non-operated interest in the Gudrun field development, located offshore Norway, we recorded a loss for this asset held for sale. The fair value was based upon the transaction, which is a Level 3 market input.Consolidated Financial Statements
Equity method investments – In the third quarter of 2010, we fully impaired our IG segment’s equity method investment in an entity engaged in gas-to-fuels related technology. This investment was determined to have sustained an other than temporary loss in value. The fair value was measured with an income approach using internally developed estimates of future cash flows. These cash flows are Level 3 inputs.
Fair values – Financial instruments
Our current assets and liabilities include financial instruments, the most significant of which are accounts receivables, commercial paper and payables. We believe the carrying values of accounts receivable,our receivables, commercial paper and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding trade accounts receivable,receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at December 31, 20122013 and 2011.2012.
| | | | December 31, | December 31, |
| | 2012 | | 2011 | 2013 | | 2012 |
| (In millions) | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount |
| Financial assets | | | | | | | | | | | | | | |
| Other current assets | $ | 2 |
| | $ | 2 |
| | $ | 146 |
| | $ | 148 |
| |
| Other noncurrent assets | 189 |
| | 186 |
| | 68 |
| | 68 |
| $ | 154 |
| | $ | 147 |
| | $ | 189 |
| | $ | 186 |
|
| Total financial assets | 191 |
| | 188 |
| | 214 |
| | 216 |
| $ | 154 |
| | $ | 147 |
| | $ | 189 |
| | $ | 186 |
|
| Financial liabilities | | | | | | | | | | | | | | |
| Other current liabilities | 13 |
| | 13 |
| | — |
| | — |
| $ | 13 |
| | $ | 13 |
| | $ | 13 |
| | $ | 13 |
|
Long-term debt, including current portion(a) | 7,610 |
| | 6,642 |
| | 5,479 |
| | 4,753 |
| 6,922 |
| | 6,427 |
| | 7,610 |
| | 6,642 |
|
| Deferred credits and other liabilities | 94 |
| | 94 |
| | 36 |
| | 38 |
| 149 |
| | 147 |
| | 94 |
| | 94 |
|
| Total financial liabilities | $ | 7,717 |
| | $ | 6,749 |
| | $ | 5,515 |
| | $ | 4,791 |
| $ | 7,084 |
| | $ | 6,587 |
| | $ | 7,717 |
| | $ | 6,749 |
|
| |
(a) | Excludes capital leases. |
Fair values of our remaining financial assets included in other current assets and other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. Because these quotes cannot be independently verified to an active
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
16. Derivatives
For further information regarding the fair value measurement of derivative instruments see Note 15. See Note 1 for discussion of the types of derivatives we use and the reasons for them. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of December 31, 2013 and 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following table presentstables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheetsheets as of December 31, 2012.2013 and 2012.
| | | | December 31, 2012 | | December 31, 2013 | |
| (In millions) | Asset | | Liability | | Net Asset | | Balance Sheet Location | Asset | | Liability | | Net Asset | | Balance Sheet Location |
| Fair Value Hedges | | | | | | | | | | | | |
| Interest rate | | $ | 8 |
| | $ | — |
| | $ | 8 |
| | Other noncurrent assets |
| Foreign currency | $ | 18 |
| | $ | — |
| | $ | 18 |
| | Other current assets | 2 |
| | — |
| | 2 |
| | Other current assets |
| Interest rate | 21 |
| | — |
| | 21 |
| | Other noncurrent assets | |
| Total Designated Hedges | 39 |
| | — |
| | 39 |
| | $ | 10 |
| | $ | — |
| | $ | 10 |
| |
| | | | | | | | |
| Not Designated as Hedges | | | | | | | |
| Commodity | 52 |
| | — |
| | 52 |
| | Other current assets | |
| Total Not Designated as Hedges | 52 |
| | — |
| | 52 |
| | |
| Total | $ | 91 |
| | $ | — |
| | $ | 91 |
| | |
|
| | | | | | | | | | | | | |
| | December 31, 2013 | | |
| (In millions) | Asset | | Liability | | Net Liability | | Balance Sheet Location |
| Fair Value Hedges | | | | | | | |
| Foreign currency | $ | — |
| | $ | 4 |
| | $ | 4 |
| | Other current liabilities |
| Total Designated Hedges | $ | — |
| | $ | 4 |
| | $ | 4 |
| | |
MARATHON OIL CORPORATION
As of December 31, 2011, our only derivatives outstanding were interest rate swaps that are fair value hedges, which had an asset value of $5 million and were located on the consolidated balance sheet in other noncurrent assets.Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | | |
| | December 31, 2012 | | |
| (In millions) | Asset | | Liability | | Net Asset | | Balance Sheet Location |
| Fair Value Hedges | | | | | | | |
| Interest rate | $ | 21 |
| | $ | — |
| | $ | 21 |
| | Other noncurrent assets |
| Foreign currency | 18 |
| | — |
| | 18 |
| | Other current assets |
| Total Designated Hedges | 39 |
| | — |
| | 39 |
| | |
| Not Designated as Hedges | | | | | | | |
| Commodity | 52 |
| | — |
| | 52 |
| | Other current assets |
| Total Not Designated as Hedges | 52 |
| | — |
| | 52 |
| | |
| Total | $ | 91 |
| | $ | — |
| | $ | 91 |
| | |
Derivatives Designated as Fair Value Hedges
The following table presents by maturity date, information about our interest rate swap agreements as of December 31, 2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
|
| | | | | |
| Maturity Dates | Aggregate Notional Amount (in millions) | Weighted Average, LIBOR-Based, Floating Rate |
| October 1, 2017 | $ | 600 |
| 4.65 | % |
| March 15, 2018 | $ | 300 |
| 4.50 | % |
As of December 31, 2012 and 2011, we had multiple interest rate swap agreements with a total notional amount of $600 million with, a maturity date of October 1, 2017 at a weighted-average,weighted average, LIBOR-based, floating rate of 4.70 percent and 4.76 percent, respectively.a maturity date of October 1, 2017.
In connection with the debt retiredretirements in February and March 2011, discussed in Note 17, we settled interest rate swaps with a notional amount of $1,450 million. We recorded a $29 million gain, which reduced the loss on early extinguishment of debt.
As of December 31, 2013 and 2012,, our foreign currency forwards had an aggregate notional amount of 2,387 million and 3,043 million Norwegian Kroner at a weighted average forward raterates of 5.7806.060. and 5.780. These forwards hedge our current Norwegian tax liability and those outstanding at December 31, 2013 have settlement dates through June 20132014.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table summarizes the pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income.income are summarized in the table below. There is no ineffectiveness related to the fair value hedges.
| | | | | Gain (Loss) | | Gain (Loss) |
| (In millions) | Income Statement Location | 2012 | | 2011 | | 2010 | Income Statement Location | 2013 | | 2012 | | 2011 |
| Derivative | | | | | | | | | | | | |
| Commodity | Sales and other operating revenues | $ | — |
| | $ | — |
| | $ | (1 | ) | |
| Interest rate | Net interest and other | 16 |
| | 28 |
| | 26 |
| Net interest and other | $ | (13 | ) | | $ | 16 |
| | $ | 28 |
|
| Interest rate | Loss on early extinguishment of debt | — |
| | 29 |
| | — |
| Loss on early extinguishment of debt | — |
| | — |
| | 29 |
|
| Foreign currency | Provision for income taxes | (1 | ) | | — |
| | — |
| Provision for income taxes | (44 | ) | | (1 | ) | | — |
|
| Hedged Item | | |
| | |
| | | | |
| | |
| | |
| Commodity | Sales and other operating revenues | $ | — |
| | $ | — |
| | $ | 1 |
| |
| Long-term debt | Net interest and other | (16 | ) | | (28 | ) | | (26 | ) | Net interest and other | $ | 13 |
| | $ | (16 | ) | | $ | (28 | ) |
| Long-term debt | Loss on early extinguishment of debt | — |
| | (29 | ) | | — |
| Loss on early extinguishment of debt | — |
| | — |
| | (29 | ) |
| Accrued taxes | Provision for income taxes | 1 |
| | — |
| | — |
| Provision for income taxes | 44 |
| | 1 |
| | — |
|
Derivatives Not Designated as Hedges
In August 2012, we entered into crude oil derivativesderivative instruments related to a portion of our forecasted U.S.North America E&P crude oil sales through December 31, 2013.sales. These commodity derivatives were not designated as hedges and are shownhad terms that ended in the table below.
|
| | | |
| Remaining Term | Bbls per Day | Weighted Average Price per Bbl | Benchmark |
| Swaps | | | |
| January 2013 - December 2013 | 20,000 | $96.29 | West Texas Intermediate |
| January 2013 - December 2013 | 25,000 | $109.19 | Brent |
| Option Collars | | | |
| January 2013 - December 2013 | 15,000 | $90.00 floor / $101.17 ceiling | West Texas Intermediate |
| January 2013 - December 2013 | 15,000 | $100.00 floor / $116.30 ceiling | Brent |
The net gains related toimpact of all commodity derivative instruments not designated as hedges appearappears in the sales and other operating revenues line ofin our consolidated statements of income and were a net loss of $67 million in 2013 and net gains of $70 million, and $5 million in 2012 and $121 million in 2012, 2011 and 2010.2011.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
17. Debt
Short-term debt
As of December 31, 2012,2013, we had no borrowings against our revolving credit facility, as described below, and we had $200135 million in commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
In April 2012, we terminated our $3.0 billion five-year revolving credit facility and replaced it with a newOur $2.5 billion unsecured five-year revolving credit facility (the "Credit Facility"). was entered in April 2012. The Credit Facility matures in April 2017, but allows us to request two one-year extensions. It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender range from 10 basis points to 25 basis points depending on our credit ratings. Borrowings under the Credit Facility bear interest, at our option, at either (a) an adjusted LIBOR rate plus a margin ranging from 87.5 basis points to 162.5 basis points per year depending on our credit ratings or (b) the Base Rate plus a margin ranging from 0.0 basis points to 62.5 basis points depending on our credit ratings. Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent and (c) LIBOR for a one-month interest period plus one percent.
The agreement contains a covenant that requires our ratio of total debt to total capitalization not to exceed 65 percent as of the last day of each fiscal quarter. If an event of default occurs, the lenders may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Long-term debt
The following table details our long-term debt:
| | | | December 31, | December 31, |
| (In millions) | 2012 | | 2011 | 2013 | | 2012 |
| Senior unsecured notes: | | | | | | |
| 9.375% notes due 2012 | $ | — |
| | $ | 53 |
| |
| 9.125% notes due 2013 | 114 |
| | 114 |
| $ | — |
| | $ | 114 |
|
0.900% notes due 2015(a) | 1,000 |
| | — |
| 1,000 |
| | 1,000 |
|
6.000% notes due 2017(a) | 682 |
| | 682 |
| 682 |
| | 682 |
|
5.900% notes due 2018(a) | 854 |
| | 854 |
| 854 |
| | 854 |
|
7.500% notes due 2019(a) | 228 |
| | 228 |
| 228 |
| | 228 |
|
2.800% notes due 2022(a) | 1,000 |
| | — |
| 1,000 |
| | 1,000 |
|
| 9.375% notes due 2022 | 32 |
| | 32 |
| 32 |
| | 32 |
|
| Series A notes due 2022 | 3 |
| | 3 |
| 3 |
| | 3 |
|
| 8.500% notes due 2023 | 70 |
| | 70 |
| 70 |
| | 70 |
|
| 8.125% notes due 2023 | 131 |
| | 131 |
| 131 |
| | 131 |
|
6.800% notes due 2032(a) | 550 |
| | 550 |
| 550 |
| | 550 |
|
| 6.600% notes due 2037 | 750 |
| | 750 |
| 750 |
| | 750 |
|
| Capital leases: | | | | | | |
| Capital lease obligation due 2012 | — |
| | 9 |
| |
| Sale-leaseback obligation due 2012 | — |
| | 11 |
| |
| Capital lease obligation of consolidated subsidiary due 2013 – 2049 | 11 |
| | 11 |
| |
| Capital lease obligation of consolidated subsidiary due 2014 – 2049 | | 10 |
| | 11 |
|
| Other obligations: | | | | | | |
| 4.550% promissory note, semi-annual payments due 2013 – 2015 | 204 |
| | 272 |
| |
| 5.375% obligation relating to revenue bonds due 2013 | — |
| | 23 |
| |
| 4.550% promissory note, semi-annual payments due 2014 – 2015 | | 136 |
| | 204 |
|
| 5.125% obligation relating to revenue bonds due 2037 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
|
| Other | 35 |
| | — |
| — |
| | 35 |
|
Total(b) | 6,664 |
| | 4,793 |
| 6,446 |
| | 6,664 |
|
| Unamortized discount | (11 | ) | | (10 | ) | (9 | ) | | (11 | ) |
Fair value adjustments(c) | 43 |
| | 32 |
| 25 |
| | 43 |
|
| Amounts due within one year | (184 | ) | | (141 | ) | (68 | ) | | (184 | ) |
| Total long-term debt due after one year | $ | 6,512 |
| | $ | 4,674 |
| $ | 6,394 |
| | $ | 6,512 |
|
| |
(a) | These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price. |
| |
(b) | In the event of a change in control, as defined in the related agreements, debt obligations totaling $385236 million at December 31, 2012,2013, may be declared immediately due and payable. |
| |
(c) | See NoteNotes 15 and 16 for information on interest rate swaps. |
On October 29, 2012, we issued $1 billion aggregate principal amount of senior notes bearing interest at 0.9 percent with a maturity date of November 1, 2015 and $1 billion aggregate principal amount of senior notes bearing interest at 2.8 percent with a maturity date of November 1, 2022. Interest on the senior notes is payable semi-annually beginning May 1, 2013. The proceeds were used to pay off commercial paper and for general corporate purposes.
In the second quarter of 2012, we retired the remaining $23 million principal amount of our 5.375 percent revenue bonds due December 2013. No gain or loss was recorded on this early extinguishment of debt.
In February and March 2011, we retired $2,498 million aggregate face amount of debt at a weighted average price equal to 112 percent of face value. A $279 million loss on early extinguishment of debt was recognized in the first quarter of 2011. The loss includes related deferred financing and premium costs partially offset by the gain on settled interest rate swaps.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table shows five years of long-term debt payments: | | | (In millions) | | |
| 2013 | $ | 184 |
| |
| 2014 | 71 |
| $ | 68 |
|
| 2015 | 1,070 |
| 1,068 |
|
| 2016 | 3 |
| — |
|
| 2017 | 685 |
| 682 |
|
| 2018 | | 854 |
|
18. Asset Retirement Obligations
The following summarizes the changes in asset retirement obligations:
| | | (In millions) | 2012 | | 2011 | 2013 | | 2012 |
| Beginning balance | $ | 1,510 |
| | $ | 1,355 |
| $ | 1,783 |
| | $ | 1,510 |
|
| Incurred, including acquisitions | 150 |
| | 37 |
| 84 |
| | 150 |
|
| Settled, including dispositions | (35 | ) | | (39 | ) | (78 | ) | | (35 | ) |
| Accretion expense (included in depreciation, depletion and amortization) | 91 |
| | 81 |
| 106 |
| | 91 |
|
| Revisions to previous estimates | 150 |
| | 126 |
| 244 |
| | 150 |
|
| Held for sale | (83 | ) | | — |
| (43 | ) | | (83 | ) |
| Spin-off downstream business | — |
| | (50 | ) | |
Ending balance(a) | $ | 1,783 |
| | $ | 1,510 |
| $ | 2,096 |
| | $ | 1,783 |
|
| |
(a) | Includes asset retirement obligations of $87 million and $34 million classified as short-term at December 31,2013 and Includes asset retirement obligations of $34 million classified as a short-term at December 31, 2012. |
19. Supplemental Cash Flow Information
| | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Net cash provided by operating activities included: | | | | | | | | | | |
| Interest paid (net of amounts capitalized) | $ | 225 |
| | $ | 268 |
| | $ | 107 |
| $ | 307 |
| | $ | 225 |
| | $ | 268 |
|
| Income taxes paid to taxing authorities | 4,974 |
| | 2,893 |
| | 2,155 |
| 3,904 |
| | 4,974 |
| | 2,893 |
|
| Commercial paper: | | | | | | | | | | |
| Issuances | $ | 13,880 |
| | $ | 421 |
| | $ | — |
| $ | 10,870 |
| | $ | 13,880 |
| | $ | 421 |
|
| Repayments | (13,680 | ) | | (421 | ) | | — |
| (10,935 | ) | | (13,680 | ) | | (421 | ) |
| Net commercial paper | $ | 200 |
| | $ | — |
| | $ | — |
| $ | (65 | ) | | $ | 200 |
| | $ | — |
|
| Noncash investing and financing activities: | | | | | | |
| Additions to property, plant and equipment | | | | | | |
| Noncash investing and financing activities, related to continuing operations: | | | | | | |
| Additions to property, plant and equipment: | | | | | | |
| Asset retirement costs capitalized, excluding acquisitions | $ | 286 |
| | $ | 151 |
| | $ | 207 |
| $ | 319 |
| | $ | 257 |
| | $ | 148 |
|
| Change in capital expenditure accrual | 191 |
| | 104 |
| | (140 | ) | (9 | ) | | 187 |
| | 104 |
|
| Liabilities assumed in acquisitions | 109 |
| | 126 |
| | — |
| — |
| | 109 |
| | 126 |
|
| Asset retirement obligations assumed by buyer | | 92 |
| | 8 |
| | 5 |
|
| Debt payments made by United States Steel | 20 |
| | 214 |
| | 105 |
| — |
| | 20 |
| | 214 |
|
20. Defined Benefit Postretirement Plans and Defined Contribution Plan
We have noncontributory defined benefit pension plans covering substantially all domestic employees as well as international employees located in Norway and the U.K. Benefits under these plans are based on plan provisions specific to each plan.
We also have defined benefit plans for other postretirement benefits covering our U.S. employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Life insurance benefits are provided to certain retiree beneficiaries. Other postretirement benefits are not funded in advance.
Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $1,4421,359 million and $1,2311,442 million as of December 31, 20122013 and 2011.2012.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
As of December 31, 20122013, our U.S. plans had accumulated benefit obligations in excess of plan assets, and 2011,as of December 31, 2012, our U.S. plans and our international ("Int'l") plans all havehad accumulated benefit obligations in excess of plan assets. Summary information for ourthese defined benefit pension plans follows.
| | | | December 31, | December 31, |
| | 2012 | | 2011 | 2013 | | 2012 |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | U.S. | | U.S. | | Int’l |
| Projected benefit obligation | $ | (1,146 | ) | | $ | (565 | ) | | $ | (986 | ) | | $ | (465 | ) | $ | (933 | ) | | $ | (1,146 | ) | | $ | (565 | ) |
| Accumulated benefit obligation | (937 | ) | | (505 | ) | | (813 | ) | | (418 | ) | (791 | ) | | (937 | ) | | (505 | ) |
| Fair value of plan assets | 630 |
| | 500 |
| | 516 |
| | 412 |
| 625 |
| | 630 |
| | 500 |
|
The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.
| | | | Pension Benefits | | Other Benefits | Pension Benefits | | |
| | 2012 | | 2011 | | 2012 | | 2011 | 2013 | | 2012 | | Other Benefits |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | | | | U.S. | | Int’l | | U.S. | | Int’l | | 2013 | | 2012 |
| Change in benefit obligations: | | | | | | | | | | | | | | | | | | | | | | |
| Benefit obligations at January 1 | $ | 986 |
| | $ | 465 |
| | $ | 3,221 |
| | $ | 415 |
| | $ | 301 |
| | $ | 779 |
| |
| Spin-off downstream business | — |
| | — |
| | (2,308 | ) | | — |
| | — |
| | (483 | ) | |
| Beginning balance | | $ | 1,146 |
| | $ | 565 |
| | $ | 986 |
| | $ | 465 |
| | $ | 311 |
| | $ | 301 |
|
| Service cost | 31 |
| | 19 |
| | 28 |
| | 19 |
| | 4 |
| | 4 |
| 33 |
| | 22 |
| | 31 |
| | 19 |
| | 4 |
| | 4 |
|
| Interest cost | 42 |
| | 22 |
| | 44 |
| | 22 |
| | 14 |
| | 16 |
| 40 |
| | 24 |
| | 42 |
| | 22 |
| | 12 |
| | 14 |
|
| Plan amendment | — |
| | — |
| | — |
| | 11 |
| | — |
| | — |
| |
| Actuarial loss | 196 |
| | 49 |
| | 84 |
| | 13 |
| | 8 |
| | 1 |
| |
| Actuarial loss (gain) | | (140 | ) | | 40 |
| | 196 |
| | 49 |
| | (31 | ) | | 8 |
|
| Foreign currency exchange rate changes | — |
| | 25 |
| | — |
| | (2 | ) | | — |
| | — |
| — |
| | 11 |
| | — |
| | 25 |
| | — |
| | — |
|
| Benefits paid | (109 | ) | | (15 | ) | | (83 | ) | | (13 | ) | | (16 | ) | | (16 | ) | (146 | ) | | (13 | ) | | (109 | ) | | (15 | ) | | (17 | ) | | (16 | ) |
| Benefit obligations at December 31 | $ | 1,146 |
| | $ | 565 |
| | $ | 986 |
| | $ | 465 |
| | $ | 311 |
| | $ | 301 |
| |
| Change in plan assets: | | | | | | | | | | | | |
| Fair value of plan assets at January 1 | $ | 516 |
| | $ | 412 |
| | $ | 1,798 |
| | $ | 389 |
| | $ | — |
| | $ | — |
| |
| Spin-off downstream business | — |
| | — |
| | (1,268 | ) | | — |
| | — |
| | — |
| |
| Ending balance | | $ | 933 |
| | $ | 649 |
| | $ | 1,146 |
| | $ | 565 |
| | $ | 279 |
| | $ | 311 |
|
| Change in fair value of plan assets: | | | | | | | | | | | | |
| Beginning balance | | $ | 630 |
| | $ | 500 |
| | $ | 516 |
| | $ | 412 |
| | $ | — |
| | $ | — |
|
| Actual return on plan assets | 66 |
| | 57 |
| | 30 |
| | 15 |
| | — |
| | — |
| 65 |
| | 74 |
| | 66 |
| | 57 |
| | — |
| | — |
|
| Employer contributions | 157 |
| | 24 |
| | 39 |
| | 23 |
| | — |
| | — |
| 76 |
| | 23 |
| | 157 |
| | 24 |
| | — |
| | — |
|
| Foreign currency exchange rate changes | — |
| | 22 |
| | — |
| | (2 | ) | | — |
| | — |
| — |
| | 13 |
| | — |
| | 22 |
| | — |
| | — |
|
| Benefits paid | (109 | ) | | (15 | ) | | (83 | ) | | (13 | ) | | — |
| | — |
| (146 | ) | | (13 | ) | | (109 | ) | | (15 | ) | | — |
| | — |
|
| Fair value of plan assets at December 31 | $ | 630 |
| | $ | 500 |
| | $ | 516 |
| | $ | 412 |
| | $ | — |
| | $ | — |
| |
| Ending balance | | $ | 625 |
| | $ | 597 |
| | $ | 630 |
| | $ | 500 |
| | $ | — |
| | $ | — |
|
| Funded status of plans at December 31 | $ | (516 | ) | | $ | (65 | ) | | $ | (470 | ) | | $ | (53 | ) | | $ | (311 | ) | | $ | (301 | ) | $ | (308 | ) | | $ | (52 | ) | | $ | (516 | ) | | $ | (65 | ) | | $ | (279 | ) | | $ | (311 | ) |
| Amounts recognized in the consolidated balance sheet: | | | | | | | | | | | | |
| Amounts recognized in the consolidated balance sheets: | | | | | | | | | | | | |
| Current liabilities | (17 | ) | | — |
| | (17 | ) | | — |
| | (19 | ) | | (18 | ) | (16 | ) | | — |
| | (17 | ) | | — |
| | (19 | ) | | (19 | ) |
| Noncurrent liabilities | (499 | ) | | (65 | ) | | (453 | ) | | (53 | ) | | (292 | ) | | (283 | ) | (292 | ) | | (52 | ) | | (499 | ) | | (65 | ) | | (260 | ) | | (292 | ) |
| Accrued benefit cost | $ | (516 | ) | | $ | (65 | ) | | $ | (470 | ) | | $ | (53 | ) | | $ | (311 | ) | | $ | (301 | ) | $ | (308 | ) | | $ | (52 | ) | | $ | (516 | ) | | $ | (65 | ) | | $ | (279 | ) | | $ | (311 | ) |
Pretax amounts in accumulated other comprehensive loss: | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | $ | 511 |
| | $ | 74 |
| | $ | 432 |
| | $ | 63 |
| | $ | 23 |
| | $ | 16 |
| |
| Net loss (gain) | | $ | 262 |
| | $ | 59 |
| | $ | 511 |
| | $ | 74 |
| | $ | (8 | ) | | $ | 23 |
|
| Prior service cost (credit) | 21 |
| | 10 |
| | 27 |
| | 11 |
| | (11 | ) | | (18 | ) | 15 |
| | 9 |
| | 21 |
| | 10 |
| | (5 | ) | | (11 | ) |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Components of net periodic benefit cost and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.
| | | | Pension Benefits | | | | | | | Pension Benefits | | | | | | |
| | 2012 | | 2011 | | 2010 | | Other Benefits | 2013 | | 2012 | | 2011 | | Other Benefits |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | 2012 | | 2011 | | 2010 | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | 2013 | | 2012 | | 2011 |
| Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost | $ | 31 |
| | $ | 19 |
| | $ | 28 |
| | $ | 19 |
| | $ | 30 |
| | $ | 19 |
| | $ | 4 |
| | $ | 4 |
| | $ | 3 |
| $ | 33 |
| | $ | 22 |
| | $ | 31 |
| | $ | 19 |
| | $ | 28 |
| | $ | 19 |
| | $ | 4 |
| | $ | 4 |
| | $ | 4 |
|
| Interest cost | 42 |
| | 22 |
| | 44 |
| | 22 |
| | 47 |
| | 22 |
| | 14 |
| | 16 |
| | 16 |
| 40 |
| | 24 |
| | 42 |
| | 22 |
| | 44 |
| | 22 |
| | 12 |
| | 14 |
| | 16 |
|
| Expected return on plan assets | (43 | ) | | (22 | ) | | (43 | ) | | (23 | ) | | (44 | ) | | (22 | ) | | — |
| | — |
| | — |
| (43 | ) | | (24 | ) | | (43 | ) | | (22 | ) | | (43 | ) | | (23 | ) | | — |
| | — |
| | — |
|
| Amortization: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| - prior service cost (credit) | 7 |
| | 1 |
| | 6 |
| | — |
| | 6 |
| | — |
| | (7 | ) | | (7 | ) | | (7 | ) | 6 |
| | 1 |
| | 7 |
| | 1 |
| | 6 |
| | — |
| | (6 | ) | | (7 | ) | | (7 | ) |
| - actuarial loss | 48 |
| | 4 |
| | 47 |
| | 2 |
| | 48 |
| | 5 |
| | — |
| | — |
| | — |
| 43 |
| | 4 |
| | 48 |
| | 4 |
| | 47 |
| | 2 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| |
Net settlement loss(a) | 45 |
| | — |
| | 30 |
| | — |
| | 56 |
| | — |
| | — |
| | — |
| | — |
| 45 |
| | — |
| | 45 |
| | — |
| | 30 |
| | — |
| | — |
| | — |
| | — |
|
Net periodic benefit cost(b) | $ | 130 |
| | $ | 24 |
| | $ | 112 |
| | $ | 20 |
| | $ | 143 |
| | $ | 26 |
| | $ | 11 |
| | $ | 13 |
| | $ | 12 |
| $ | 124 |
| | $ | 27 |
| | $ | 130 |
| | $ | 24 |
| | $ | 112 |
| | $ | 20 |
| | $ | 10 |
| | $ | 11 |
| | $ | 13 |
|
| Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax): | | | | | | | | | | | | | | | | | | | | | | | | | �� | | | | | | | | | |
| Actuarial loss (gain) | $ | 172 |
| | $ | 15 |
| | $ | 97 |
| | $ | 24 |
| | $ | 211 |
| | $ | (25 | ) | | $ | 7 |
| | $ | 1 |
| | $ | 69 |
| $ | (161 | ) | | $ | (11 | ) | | $ | 172 |
| | $ | 15 |
| | $ | 97 |
| | $ | 24 |
| | $ | (31 | ) | | $ | 7 |
| | $ | 1 |
|
| Amortization of actuarial (loss) gain | (93 | ) | | (4 | ) | | (77 | ) | | (2 | ) | | (167 | ) | | (5 | ) | | — |
| | — |
| | 2 |
| (88 | ) | | (4 | ) | | (93 | ) | | (4 | ) | | (77 | ) | | (2 | ) | | — |
| | — |
| | — |
|
| Prior service cost | — |
| | 1 |
| | — |
| | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| |
| Prior service cost (credit) | | — |
| | — |
| | — |
| | 1 |
| | — |
| | (11 | ) | | — |
| | — |
| | — |
|
| Amortization of prior service credit (cost) | (7 | ) | | (1 | ) | | (6 | ) | | — |
| | (13 | ) | | — |
| | 7 |
| | 7 |
| | 6 |
| (6 | ) | | (1 | ) | | (7 | ) | | (1 | ) | | (6 | ) | | — |
| | 6 |
| | 7 |
| | 7 |
|
Spin-off downstream business (c) | — |
| | — |
| | (24 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | (24 | ) | | — |
| | — |
| | — |
| | — |
|
| Total recognized in other comprehensive (income) loss | $ | 72 |
| | $ | 11 |
| | $ | (10 | ) | | $ | 11 |
| | $ | 31 |
| | $ | (30 | ) | | $ | 14 |
| | $ | 8 |
| | $ | 77 |
| $ | (255 | ) | | $ | (16 | ) | | $ | 72 |
| | $ | 11 |
| | $ | (10 | ) | | $ | 11 |
| | $ | (25 | ) | | $ | 14 |
| | $ | 8 |
|
| Total recognized in net periodic benefit cost and other comprehensive (income) loss | $ | 202 |
| | $ | 35 |
| | $ | 102 |
| | $ | 31 |
| | $ | 174 |
| | $ | (4 | ) | | $ | 25 |
| | $ | 21 |
| | $ | 89 |
| $ | (131 | ) | | $ | 11 |
| | $ | 202 |
| | $ | 35 |
| | $ | 102 |
| | $ | 31 |
| | $ | (15 | ) | | $ | 25 |
| | $ | 21 |
|
| |
(a) | Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period. Such settlements occurred in one or more of our U.S. plans in 2013, 2012, 2011 and 2010. 2011. |
| |
(b) | Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years. |
| |
(c) | Includes net inter-company transfers of (gains)/losses due to the spin-off of the downstream business. |
The estimated net loss and prior service cost for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 20132014 are $5224 million and $76 million. The estimated net loss and prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2013 are2014 is $1 million and $75 million.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2013, 2012, 2011 and 2010.2011.
| | | | Pension Benefits | | | | | | | Pension Benefits | | | | | | |
| | 2012 | | 2011 | | 2010 | | Other Benefits | 2013 | | 2012 | | 2011 | | Other Benefits |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | 2012 | | 2011 | | 2010 | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | 2013 | | 2012 | | 2011 |
| Weighted average assumptions used to determine benefit obligation: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount rate | 3.44 | % | | 4.40 | % | | 4.45 | % | | 4.70 | % | | 5.05 | % | | 5.40 | % | | 4.06 | % | | 4.90 | % | | 5.55 | % | 4.28 | % | | 4.60 | % | | 3.44 | % | | 4.40 | % | | 4.45 | % | | 4.70 | % | | 4.85 | % | | 4.06 | % | | 4.90 | % |
| Rate of compensation increase | 5.00 | % | | 4.50 | % | | 5.00 | % | | 4.30 | % | | 5.00 | % | | 5.10 | % | | 5.00 | % | | 5.00 | % | | 5.00 | % | 5.00 | % | | 4.90 | % | | 5.00 | % | | 4.50 | % | | 5.00 | % | | 4.30 | % | | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Weighted average assumptions used to determine net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount rate | 4.21 | % | | 4.70 | % | | 5.05 | % | | 5.40 | % | | 5.23 | % | | 5.70 | % | | 4.90 | % | | 5.55 | % | | 6.85 | % | 3.79 | % | | 4.40 | % | | 4.21 | % | | 4.70 | % | | 5.05 | % | | 5.40 | % | | 4.06 | % | | 4.90 | % | | 5.55 | % |
| Expected long-term return on plan assets | 7.75 | % | (a) | 5.20 | % | | 8.50 | % | | 5.86 | % | | 8.50 | % | | 6.40 | % | | — |
| | — |
| | — |
| 7.25 | % | (a) | 4.90 | % | | 7.75 | % | | 5.20 | % | | 8.50 | % | | 5.86 | % | | — |
| | — |
| | — |
|
| Rate of compensation increase | 5.00 | % | | 4.30 | % | | 5.00 | % | | 5.10 | % | | 4.50 | % | | 5.55 | % | | 5.00 | % | | 5.00 | % | | 4.50 | % | 5.00 | % | | 4.50 | % | | 5.00 | % | | 4.30 | % | | 5.00 | % | | 5.10 | % | | 5.00 | % | | 5.00 | % | | 5.00 | % |
| |
(a) | Effective January 1, 2013,2014, the expected long-term rate of return on U.S. plan assets was changed from 7.757.25 percent to 7.256.75 percent. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Expected long-term return on plan assets
U.S. plan – The overall expected long-term return on plan assets assumption for our U.S. funded plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plan’s asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.
International plans – To determine the overall expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on the actual asset allocation in our international pension plans to develop the overall expected long-term return on plan assets assumption.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Assumed health care cost trend rates
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Health care cost trend rate assumed for the following year: | | | | | | | | | | |
| Medical | | | | | | | | | | |
| Pre-65 | 8.00 | % | | 7.50 | % | | 7.50 | % | 7.50 | % | | 8.00 | % | | 7.50 | % |
| Post-65 | 7.00 | % | | 7.00 | % | | 7.00 | % | 6.50 | % | | 7.00 | % | | 7.00 | % |
| Prescription drugs | 7.00 | % | | 7.50 | % | | 7.50 | % | 7.00 | % | | 7.00 | % | | 7.50 | % |
EGWP subsidy(a) | 7.50 | % | | n/a |
| | n/a |
| 8.70 | % | | 7.50 | % | | n/a |
|
| Rate to which the cost trend rate is assumed to decline (the ultimate trend rate): | | | | | | | | | | |
| Medical | | | | | | | | | | |
| Pre-65 | 5.00 | % | | 5.00 | % | | 5.00 | % | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Post-65 | 5.00 | % | | 5.00 | % | | 5.00 | % | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Prescription drugs | 5.00 | % | | 5.00 | % | | 5.00 | % | 5.00 | % | | 5.00 | % | | 5.00 | % |
EGWP subsidy(a) | 5.00 | % | | n/a |
| | n/a |
| 5.00 | % | | 5.00 | % | | n/a |
|
| Year that the rate reaches the ultimate trend rate: | | | | | | | | | | |
| Medical | | | | | | | | | | |
| Pre-65 | 2020 |
| | 2018 |
| | 2018 |
| 2020 |
| | 2020 |
| | 2018 |
|
| Post-65 | 2018 |
| | 2017 |
| | 2017 |
| 2020 |
| | 2018 |
| | 2017 |
|
| Prescription drugs | 2018 |
| | 2018 |
| | 2018 |
| 2020 |
| | 2018 |
| | 2018 |
|
EGWP subsidy(a) | 2020 |
| | n/a |
| | n/a |
| 2020 |
| | 2020 |
| | n/a |
|
| |
(a) | An employee group waiver plan ("EGWP") is a group Medicare Part D prescription drug plan. Effective January 1, 2013, we implemented the EGWP as a result of the Patient Protection and Affordable Care Act, which ended tax-free status of retiree drug subsidy programs but increased federal funding to Part D prescription drug plans. |
Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
| | | (In millions) | 1-Percentage- Point Increase | | 1-Percentage- Point Decrease | 1-Percentage- Point Increase | | 1-Percentage- Point Decrease |
| Effect on total of service and interest cost components | $ | 2 |
| | $ | (2 | ) | $ | 2 |
| | $ | (2 | ) |
| Effect on other postretirement benefit obligations | $ | 35 |
| | $ | (29 | ) | $ | 30 |
| | $ | (25 | ) |
Plan investment policies and strategies
– The investment policies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.
U.S. plan – Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. However, to reduce volatility in returns and to better match the plan’s liabilities over time,
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
as the plan’s funded ratio (as defined by the investment policy) improves, the allocation to equity securities will decrease while the amount allocated to fixed income securities will increase. As such, the plan’s current targeted asset allocation is comprised of 6555 percent equity securities and high-yield bonds and 3545 percent other fixed income securities but may be adjusted to better match the plan's liabilities over time as the funded ratio (as defined by the investment policy) changes.securities.
The plan's assets are managed by a third-party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.
International plans – Our international plans’ target asset allocation is comprised of 70 percent equity securities and 30 percent fixed income securities. The plan assets are invested in eleven separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers. Investments are diversified by industry and type, limited by grade and maturity. The use of derivatives by the investment managers is permitted, subject to strict guidelines. The investment managers' performance is measured independently by a third-party asset servicing consulting firm. Overall, investment performance and risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews and periodic asset and liability studies.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Fair value measurements
– Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 20122013 and 2011.2012.
Cash and cash equivalents – Cash and cash equivalents include cash on deposit and an investment in a money market mutual fund that invests mainly in short-term instruments and cash, both of which are valued using a market approach and are considered Level 1. The money market mutual fund is valued at the net asset value ("NAV") of shares held. Cash and cash equivalents also include a cash reserve account (a collective short-term investment fund) that is valued using an income approach and is considered Level 2. The underlying assets are usually short-term bonds, discount notes, and commercial paper.
Equity securities – Investments in common stock, an S&P 500 exchange-traded fund,preferred stock, and real estate investment trusts ("REIT") are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. The non-public investment trust is valued using a market approach based on the underlying investments in the trust, which are publicly-traded securities, and is considered Level 2. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership, determined using a combination of market, income and cost approaches, plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. These private equity investments are considered Level 3.
Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs.
Pooled funds – Investments in pooled funds are valued using a market approach at the NAV of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.
Fixed income securities – Fixed income securities are valued using a market approach. U.S. treasury notes and exchange traded funds are valued at the closing price reported in an active market, and are considered Level 1. Treasury inflation-protected securities ("TIPS") are valued at the daily closing price reported in an active market. TIPS prices exclude adjustment factors for inflation and are considered Level 1. Corporate bonds, non-U.S. government bonds, private placements, and yankee bonds are valued using calculated yield curves created by models that incorporate factors such as interest rate, benchmark quote,quotes, trade data, dealer quotes, primary and secondary market spread activity, and other market information and are considered Level 2. Taxable municipal bonds are valued using calculated yield curves considering market factors such as benchmark issues, trades, trading spreads between similar issuers or creditors, historical trading spreads over widely accepted market benchmarks, and verified bid information. These assets are considered Level 2. Municipal bonds are valued by an evaluation of terms and conditions of the security and considering market factors such as benchmark curves, trades, bid price or spreads, two-sided markets, and quotes. These assets are considered Level 2. The investment in the commingled fund is valued using a market approach at the NAV of units held, and is considered Level 2. The commingled fund consists mostly of high yieldhigh-yield U.S. and non-U.S. corporate bonds. Investment opportunities in this fund are limited to qualified retirement plans and their plan participants. The investment objective of the portfolio is to provide long-term total return in excess of the Barclays U.S. High Yield Bond Index.
Real estate – Real estate investments are valued using a combination of the income and market approaches that is based on discounted cash flows, comparable sales, outside appraisals, price per square foot or some combination thereof and therefore are considered Level 3.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Other – Other investments are composed of an investment in an unallocated annuity contract, an investment contract with an international insurance carrier, and investments in two limited liability companies (“LLCs") with no public market. The LLCs were formed to acquire timberland in the northwest and other properties. The investment in an unallocated annuity contract is valued using a market approach based on the experience of the assets held in an insurer’s general account. The majority of the general account is invested in a well-diversified portfolio of high-quality fixed income securities, primarily consisting of investment-grade bonds. Investment income is allocated among pension plans participating in the general account based on the investment year method. Under this method, a record of the book value of assets held is maintained in subdivisions according to the calendar year in which the funds are invested. The earnings rate for each of these calendar year subdivisions varies from year to year, reflecting the actual earnings on the assets attributed to that year. Due to the lack of transparency in the use of investment year subdivisions, this asset is considered Level 3. The insurance carrier contract is funded by premiums paid annually by the participating plans and the funds are invested by the insurance carrier in portfolios with different risk profiles (low, medium, high) that can be elected by clients. The majority of the underlying investments consists of a well-diversified mix of non-U.S. publicly traded equity securities valued at the closing price reported in an active market and fixed income securities.securities valued using calculated yield curves. This asset is considered Level 2. The values of the LLCs are determined using a cost approach based on historical cost less depletion for timber previously harvested. These assets are considered Level 3.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table presentstables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 20122013 and 2011.2012.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2012 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l |
| Cash and cash equivalents | $ | 16 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | 1 |
|
| Equity securities: | | | | | | | | | | | | | | | |
Common stock(a) | 312 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 312 |
| | — |
|
| Private equity | — |
| | — |
| | — |
| | — |
| | 25 |
| | — |
| | 25 |
| | — |
|
| REIT | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
|
| Investment trust | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
|
Mutual funds(b) | — |
| | 171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 171 |
Pooled funds(c) | — |
| | — |
| | — |
| | 152 |
| | — |
| | — |
| | — |
| | 152 |
|
| Fixed income securities: | | | | | | | | | | | | | | | |
| U.S. treasury notes | 67 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 67 |
| | — |
|
| Exchange traded fund | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
| | — |
|
Corporate bonds(d) | — |
| | — |
| | 96 |
| | — |
| | — |
| | — |
| | 96 |
| | — |
|
| Non-U.S. government bonds | — |
| | — |
| | 5 |
| | — |
| | — |
| | — |
| | 5 |
| | — |
|
| Private placements | — |
| | — |
| | 18 |
| | — |
| | — |
| | — |
| | 18 |
| | — |
|
| Taxable municipal bonds | — |
| | — |
| | 14 |
| | — |
| | — |
| | — |
| | 14 |
| | — |
|
| Yankee bonds | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
|
Commingled fund(e) | — |
| | — |
| | 28 |
| | — |
| | — |
| | — |
| | 28 |
| | — |
|
Pooled funds(f) | — |
| | — |
| | — |
| | 166 |
| | — |
| | — |
| | — |
| | 166 |
|
Real estate(g) | — |
| | — |
| | — |
| | — |
| | 23 |
| | — |
| | 23 |
| | — |
|
| Other | — |
| | — |
| | — |
| | 10 |
| | 12 |
| | — |
| | 12 |
| | 10 |
|
| Total investments, at fair value | $ | 405 |
| | $ | 172 |
| | $ | 165 |
| | $ | 328 |
| | $ | 60 |
| | $ | — |
| | $ | 630 |
| | $ | 500 |
|
| | | December 31, 2011 | December 31, 2013 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
| U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l |
| Cash and cash equivalents | $ | 12 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | 2 |
| $ | 19 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | 1 |
|
| Equity securities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Investment trust | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
| | — |
| |
| Exchange traded fund | 324 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 324 |
| | — |
| |
Common stock(a) | | 288 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 288 |
| | — |
|
| Preferred stock | | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
|
| Private equity | — |
| | — |
| | — |
| | — |
| | 23 |
| | — |
| | 23 |
| | — |
| — |
| | — |
| | — |
| | — |
| | 23 |
| | — |
| | 23 |
| | — |
|
| REIT | | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
|
Mutual funds(b) | — |
| | 159 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 159 |
| — |
| | 219 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 219 |
Pooled funds(c) | — |
| | — |
| | — |
| | 96 |
| | — |
| | — |
| | — |
| | 96 |
| — |
| | — |
| | — |
| | 186 |
| | — |
| | — |
| | — |
| | 186 |
|
| Fixed income securities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| U.S. treasury notes | | 63 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 63 |
| | — |
|
| Exchange traded funds | | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
|
Corporate bonds(d) | | — |
| | — |
| | 127 |
| | — |
| | — |
| | — |
| | 127 |
| | — |
|
| Municipal bonds | | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
|
| Non-U.S. government bonds | | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
| | — |
|
| Private placements | | — |
| | — |
| | 21 |
| | — |
| | — |
| | — |
| | 21 |
| | — |
|
| Taxable municipal bonds | | — |
| | — |
| | 13 |
| | — |
| | — |
| | — |
| | 13 |
| | — |
|
| Treasury inflation-protected securities | | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
|
| Yankee bonds | | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
|
Commingled fund(e) | | — |
| | — |
| | 17 |
| | — |
| | — |
| | — |
| | 17 |
| | — |
|
Pooled funds(f) | — |
| | — |
| | — |
| | 149 |
| | — |
| | — |
| | — |
| | 149 |
| — |
| | — |
| | — |
| | 178 |
| | — |
| | — |
| | — |
| | 178 |
|
| U.S. treasury notes | 92 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 92 |
| | — |
| |
Real estate(g) | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 21 |
| | — |
| — |
| | — |
| | — |
| | — |
| | 22 |
| | — |
| | 22 |
| | — |
|
Other(h) | — |
| | — |
| | 23 |
| | 6 |
| | 14 |
| | — |
| | 37 |
| | 6 |
| |
| Other | | — |
| | — |
| | — |
| | 13 |
| | 12 |
| | — |
| | 12 |
| | 13 |
|
| Total investments, at fair value | $ | 428 |
| | $ | 161 |
| | $ | 30 |
| | $ | 251 |
| | $ | 58 |
| | $ | — |
| | $ | 516 |
| | $ | 412 |
| $ | 378 |
| | $ | 220 |
| | $ | 190 |
| | $ | 377 |
| | $ | 57 |
| | $ | — |
| | $ | 625 |
| | $ | 597 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2012 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l |
| Cash and cash equivalents | $ | 16 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | 1 |
|
| Equity securities: |
| |
| |
| |
| |
| |
| |
| |
|
Common stock(a) | 312 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 312 |
| | — |
|
| Private equity | — |
| | — |
| | — |
| | — |
| | 25 |
| | — |
| | 25 |
| | — |
|
| REIT | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
|
| Investment trust | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
|
Mutual funds(b) | — |
| | 171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 171 |
|
Pooled funds(c) | — |
| | — |
| | — |
| | 152 |
| | — |
| | — |
| | — |
| | 152 |
|
| Fixed income securities: | | | | | | | | | | | | | | | |
| U.S. treasury notes | 67 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 67 |
| | — |
|
| Exchange traded funds | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
| | — |
|
Corporate bonds(d) | — |
| | — |
| | 96 |
| | — |
| | — |
| | — |
| | 96 |
| | — |
|
| Non-U.S. government bonds | — |
| | — |
| | 5 |
| | — |
| | — |
| | — |
| | 5 |
| | — |
|
| Private placements | — |
| | — |
| | 18 |
| | — |
| | — |
| | — |
| | 18 |
| | — |
|
| Taxable municipal bonds | — |
| | — |
| | 14 |
| | — |
| | — |
| | — |
| | 14 |
| | — |
|
| Yankee bonds | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
|
Commingled fund(e) | — |
| | — |
| | 28 |
| | — |
| | — |
| | — |
| | 28 |
| | — |
|
Pooled funds(f) | — |
| | — |
| | — |
| | 166 |
| | — |
| | — |
| | — |
| | 166 |
|
Real estate(g) | — |
| | — |
| | — |
| | — |
| | 23 |
| | — |
| | 23 |
| | — |
|
| Other | — |
| | — |
| | — |
| | 10 |
| | 12 |
| | — |
| | 12 |
| | 10 |
|
| Total investments, at fair value | $ | 405 |
| | $ | 172 |
| | $ | 165 |
| | $ | 328 |
| | $ | 60 |
| | $ | — |
| | $ | 630 |
| | $ | 500 |
|
| |
(a) | Includes approximately 60 percent of investments held in U.S. and non-U.S. common stocks in the banking, pharmaceuticals, banking, oil and gas, insurance, telecommunications, electric, aerospace/defense, retail, transportation, aerospace/defense, insurance, manufacturing, health care, computer,food processing, semiconductors, and financial serviceschemicals sectors. The remaining 40 percent of common stock is held in various other sectors. |
| |
(b) | Includes approximately 75 percent of investments held in U.S. and non-U.S. common stocks in the consumer staples, financial services, consumer staples, health care, energy, basic materials, leisure, and industrial goods and services and leisure sectors and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, FTSE ALL Share 5% Capped Index and MSCI World Index, as defined by the investment policy. |
| |
(c) | Includes approximately 9080 percent of investments held in non-U.S. publicly traded common stocks (specifically Asia Pacific, except Japan, and the U.K.) in the financial, energy, consumer staples, industrial,information technology, materials, energy, industrials, and materialstelecommunication services sectors and the remaining 1020 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, MSCI AC Asia Pacific ex Japan Index, FTSE Small Cap Index, and MSCI Emerging Markets Index, as defined by the investment policy. |
| |
(d) | Includes approximately 70 percent of U.S. and non-U.S. corporate bonds in the banking and finance, news/media,utilities, oil and gas, utilities,news/media, and health care sectors. The remaining 30 percent of corporate bonds are in various other sectors. |
| |
(e) | Includes approximately 7590 percent of investments held in U.S. and non-U.S. corporate bonds in the consumer discretionary, energy, financial, industrial, telecommunication services, andenergy, health care, information technology and materials sectors and 2510 percent of investments held among various other sectors. |
| |
(f) | Includes approximately 8075 percent of investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds which include gilts, treasuries, financial, corporates, and collateralized asset backed securities and 2025 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, as defined by the investment policy. |
| |
(g) | Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 70 percent of investments held, are office, hotel, residential, and retail with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India. |
| |
(h)
| U.S. Level 2 includes a receivable for the sale of an investment that closed as of December 31, 2011 but did not cash settle until the next business day. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy. | | | | 2012 | 2013 |
| (In millions) | Private Equity | | Real Estate | | Other | | Total | Private Equity | | Real Estate | | Other | | Total |
| Beginning balance | $ | 23 |
| | $ | 21 |
| | $ | 14 |
| | $ | 58 |
| $ | 25 |
| | $ | 23 |
| | $ | 12 |
| | $ | 60 |
|
| Actual return on plan assets: | | | | | | | | | | | | | | |
| Realized | 2 |
| | — |
| | — |
| | 2 |
| |
| Unrealized | 1 |
| | 1 |
| | (2 | ) | | — |
| |
| Realized gain | | 6 |
| | 1 |
| | — |
| | 7 |
|
| Unrealized gain (loss) | | (1 | ) | | 1 |
| | — |
| | — |
|
| Purchases | 4 |
| | 3 |
| | — |
| | 7 |
| 6 |
| | 1 |
| | — |
| | 7 |
|
| Sales | (5 | ) | | (2 | ) | | — |
| | (7 | ) | (13 | ) | | (4 | ) | | — |
| | (17 | ) |
| Ending balance | $ | 25 |
| | $ | 23 |
| | $ | 12 |
| | $ | 60 |
| $ | 23 |
| | $ | 22 |
| | $ | 12 |
| | $ | 57 |
|
| | | | 2011 | 2012 |
| (In millions) | Private
Equity | | Real
Estate | | Other | | Total | Private
Equity | | Real
Estate | | Other | | Total |
| Beginning balance | $ | 67 |
| | $ | 54 |
| | $ | 31 |
| | $ | 152 |
| $ | 23 |
| | $ | 21 |
| | $ | 14 |
| | $ | 58 |
|
| Less spin-off of downstream business | (46 | ) | | (37 | ) | | (17 | ) | | (100 | ) | |
| Actual return on plan assets: | | | | | | | | | | | | | | |
| Realized | 1 |
| | 1 |
| | — |
| | 2 |
| |
| Unrealized | 2 |
| | 1 |
| | — |
| | 3 |
| |
| Realized gain | | 2 |
| | — |
| | — |
| | 2 |
|
| Unrealized gain (loss) | | 1 |
| | 1 |
| | (2 | ) | | — |
|
| Purchases | 3 |
| | 4 |
| | — |
| | 7 |
| 4 |
| | 3 |
| | — |
| | 7 |
|
| Sales | (4 | ) | | (2 | ) | | — |
| | (6 | ) | (5 | ) | | (2 | ) | | — |
| | (7 | ) |
| Ending balance | $ | 23 |
| | $ | 21 |
| | $ | 14 |
| | $ | 58 |
| $ | 25 |
| | $ | 23 |
| | $ | 12 |
| | $ | 60 |
|
Cash flows
Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 2013 and reflect expected future services, as appropriate, are to be paid in the years indicated.
|
| | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| (In millions) | U.S. | | Int’l | |
2014(a) | $ | 96 |
| | $ | 14 |
| | $ | 19 |
|
| 2015 | 94 |
| | 14 |
| | 20 |
|
| 2016 | 95 |
| | 16 |
| | 20 |
|
| 2017 | 96 |
| | 18 |
| | 20 |
|
| 2018 | 92 |
| | 21 |
| | 20 |
|
| 2019 through 2023 | 368 |
| | 120 |
| | 98 |
|
| |
(a) | Primarily as a result of retirements effective January 1, 2014, actual 2014 U.S. gross benefit payments will exceed the actuarial estimate above, including approximately $163 million which will be paid during the first quarter of 2014. |
Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $6477 million in 2013.2014, and $11 million of that amount was paid in January 2014. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $1674 million and $1819 million in 2014.2013.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Estimated future benefit payments – The following gross benefit payments, which reflect expected future services, as appropriate, are expected to be paid in the years indicated.
|
| | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| (In millions) | U.S. | | Int’l | |
| 2013 | $ | 113 |
| | $ | 12 |
| | $ | 18 |
|
| 2014 | 114 |
| | 14 |
| | 19 |
|
| 2015 | 114 |
| | 16 |
| | 20 |
|
| 2016 | 112 |
| | 18 |
| | 20 |
|
| 2017 | 114 |
| | 20 |
| | 20 |
|
| 2018 through 2022 | 530 |
| | 109 |
| | 101 |
|
Contributions to defined contribution plan – We contribute to a defined contribution plan for eligible employees. Contributions to this plan totaled $2526 million, $2125 million and $2021 million in 2013, 2012, 2011 and 2010.2011.
21. Incentive Based Compensation
Description of stock basedstock-based compensation plans
– The Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan") was approved by our stockholders in April 2012 and authorizes the Compensation Committee of the Board of Directors to grant stock options, SARs, stock awards (including restricted stock and restricted stock unit awards) and performance awards to employees. The 2012 Plan also allows us to provide equity compensation to our non-employee directors. No more than 50 million shares of our common stock may be issued under the 2012 Plan. For stock options and SARs, the number of shares available for issuance under the 2012 Plan will be reduced by one share for each share of our common stock in respect of which
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
the award is granted. For awards other than stock options or SARs, the number of shares available for issuance under the 2012 Plan will be reduced by 2.41 shares for each share of our common stock in respect of which the award is granted.
Shares subject to awards under the 2012 Plan that are forfeited, are terminated or expire unexercised become available for future grants. If a SAR is settled upon exercise by delivery of shares of common stock, the full number of shares with respect to which the SAR was exercised will count against the number of shares of our common stock reserved for issuance under the 2012 Plan and will not again become available under the 2012 Plan. In addition, the number of shares of our common stock reserved for issuance under the 2012 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2012 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.
After approval of the 2012 Plan, no new grants were or will be made from the 2007 Incentive Compensation Plan, (the "2007 Plan"), the 2003 Incentive Compensation Plan (the "2003 Plan"), the 1990 Stock Plan, the Non-Officer Restricted Stock Plan, the Non-Employee Director Stock Plan and the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors (collectively, the Senior Executive Officer Annual Incentive Compensation Plan and the Annual Incentive Compensation Plan (the "Prior Plans"). Any awards previously granted under the 2007 Plan, the 2003 Plan or the Prior Plans shall continue to be exercisable in accordance with their original terms and conditions.
Stock basedStock-based awards under the plans
Stock options – We grant stock options under the 2012 Plan and previously granted stock options under certain of the 2007 Plan and the 2003 Plan.Prior Plans. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. Through 2004, certainIn general, our stock options were granted under the 2003 Plan with a tandem SAR, which allows the recipient to instead elect to receive cash or our common stock equal to the excess of the fair market value of shares of common stock, as determined in accordance with the 2003 Plan, over the option price of the shares. In general, stock options granted under the 2012 Plan, the 2007 Plan and the 2003 Plan vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.
Stock appreciation rights – Prior to 2005, we granted SARs under the 2003 Plan. No SARs have been granted under the 2012 Plan or the 2007 Plan. Similar to stock options,since then. SARs represent the right to receive a paymentshares of common stock equal in value to the excess of the fair market value of shares of common stock on the date the right is exercised over the grant price. Under the 2003 Plan, certain SARs were granted as stock-settled SARs and others were granted in tandem with stock options. In general, SARs granted under the 2003 Plan vested ratably over a three-year period and have a maximum term of ten years from the date they were granted.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Restricted stock – We grant restricted stock and restricted stock units ("restricted(collectively, "restricted stock awards") under the 2012 Plan and previously granted such awards under certain of the 2007 Plan and the 2003 Plan.Prior Plans. The restricted stock awards granted officers generally vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees and restricted stock units to certain international employees, based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest in one-third increments over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares are not transferable and are held by our transfer agent.
Stock-based performance units – Beginning in 2013, we grant stock-based performance units to officers under the 2012 Plan. At the grant date, each unit represents the value of one share of our common stock. These units provide a cash payout, based on the value of anywhere from zero to two times the number of units granted, upon the achievement of certain performance goals at the end of a 36-month performance period. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.
Common stock units – We maintain an equity compensation program for our non-employee directors under the 2012 Plan and previously maintained such a program under certain of the 2007 Plan and the 2003 Plan.Prior Plans. All non-employee directors receive annual grants of common stock units. Those units granted prior to 2012 must be held until completion of board service, at which time the non-employee director will receive common shares. Common shares will be issued for units granted on or after January 1, 2012 upon completion of board service or three years from the date of grant, whichever is earlier. When dividends are paid on our common stock, directors receive dividend equivalents in the form of additional common stock units.
Total stock basedstock-based compensation expense
– Total employee stock basedstock-based compensation expense was $7075 million, $6570 million and $5165 million in 20122013, 20112012 and 20102011, while the total related income tax benefits were $2527 million, $2325 million and $1923 million in the same years. In 20122013, 20112012 and 20102011, cash received upon exercise of stock option awards was $4158 million, $7741 million and $1277 million. Tax benefits realized for deductions for stock awards exercised during 20122013, 20112012 and 20102011 totaled $2436 million, $3224 million and $1132 million.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Stock option awards
– During 20122013, 20112012 and 20102011, we granted stock option awards to both officer and non-officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Weighted average exercise price per share | $33.52 | | $32.30 | | $30.00 | |
| Exercise price per share | | $33.54 | | $33.52 | | $32.30 |
| Expected annual dividend yield | 2.2 | % | | 2.1 | % | | 3.2 | % | 2.1 | % | | 2.2 | % | | 2.1 | % |
| Expected life in years | 5.6 |
| | 5.3 |
| | 5.1 |
| 6.1 |
| | 5.5 |
| | 5.3 |
|
| Expected volatility | 41 | % | | 40 | % | | 43 | % | 38 | % | | 41 | % | | 40 | % |
| Risk-free interest rate | 1.2 | % | | 1.7 | % | | 2.2 | % | 1.6 | % | | 1.2 | % | | 1.7 | % |
| Weighted average grant date fair value of stock option awards granted | $10.86 | | $10.44 | | $8.70 | $10.25 | | $10.86 | | $10.44 |
The following is a summary of stock option award activity in 2012.2013.
| | | | Number of Shares | | Weighted Average Exercise price | Number of Shares | | Weighted Average Exercise price |
| Outstanding at beginning of year | 21,370,715 | | $24.41 | 19,536,965 | | $26.19 |
| Granted | 1,858,872 | | $33.52 | 2,051,386 | | $33.54 |
| Exercised | (2,795,612) | | $16.46 | (2,718,639) | | $22.36 |
| Cancelled | (897,010) | | $29.29 | |
| Canceled | | (764,825) | | $34.02 |
| Outstanding at end of year | 19,536,965 | | $26.19 | 18,104,887 | | $27.27 |
The intrinsic value of stock option awards exercised during 2013, 2012, 2011 and 20102011, was$35 million, $40 million, and $59 million and $8 million.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table presents information related to stock option awards at December 31, 2012.2013.
|
| | | | | | | | | | |
| | | Outstanding | | Exercisable |
Range of Exercise Prices | | Number of Shares Under Option | | Weighted Average Remaining Contractual Life | | Weighted Average Exercise Price | | Number of Shares Under Option | | Weighted Average Exercise Price |
| $ 7.99-12.75 | | 429,685 | | 1 | | $10.06 | | 429,685 | | $10.06 |
| 12.76-16.81 | | 2,307,526 | | 4 | | $15.18 | | 2,307,526 | | $15.18 |
| 16.82-23.20 | | 5,409,048 | | 7 | | $18.60 | | 4,105,057 | | $18.55 |
| 23.21-29.24 | | 2,031,690 | | 5 | | $24.63 | | 1,599,222 | | $23.79 |
| 29.25-36.03 | | 6,809,564 | | 6 | | $32.93 | | 3,272,482 | | $32.50 |
| 36.04-46.41 | | 2,549,452 | | 6 | | $38.25 | | 2,549,452 | | $38.25 |
| Total | | 19,536,965 | | 6 | | $26.19 | | 14,263,424 | | $25.41 |
|
| | | | | | | | | | |
| | | Outstanding | | Exercisable |
Range of Exercise Prices | | Number of Shares Under Option | | Weighted Average Remaining Contractual Life | | Weighted Average Exercise Price | | Number of Shares Under Option | | Weighted Average Exercise Price |
| $7.99-12.75 | | 259,164 | | 0.3 years | | $10.53 | | 259,164 | | $10.53 |
| $12.76-16.81 | | 1,937,181 | | 3 years | | $15.13 | | 1,937,181 | | $15.13 |
| $16.82-23.20 | | 4,255,365 | | 5 years | | $18.57 | | 4,255,365 | | $18.57 |
| $23.21-29.24 | | 1,740,398 | | 4 years | | $24.59 | | 1,489,683 | | $24.05 |
| $29.25-36.03 | | 7,541,433 | | 7 years | | $33.06 | | 3,967,422 | | $32.70 |
| $36.04-46.41 | | 2,371,346 | | 3 years | | $38.19 | | 2,277,817 | | $38.26 |
| Total | | 18,104,887 | | 5 years | | $27.27 | | 14,186,632 | | $25.64 |
As of December 31, 2012,2013, the aggregate intrinsic value of stock option awards outstanding was $122152 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable were $105144 million and 54 years.
As of December 31, 2012,2013, the number of fully-vested stock option awards and stock option awards expected to vest was 19,466,85518,023,888. The weighted average exercise price and weighted average remaining contractual life of these stock option awards were $26.1827.24 and 65 years years and the aggregate intrinsic value was $122152 million. As of December 31, 2012,2013, unrecognized compensation cost related to stock option awards was $2216 million, which is expected to be recognized over a weighted average period of 12 years year..
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Restricted stock awards
– The following is a summary of restricted stock award activity in 2012.2013.
| | | | Awards | | Weighted Average Grant Date Fair Value | Awards | | Weighted Average Grant Date Fair Value |
| Unvested at beginning of year | 3,703,978 |
| | $25.88 | 4,177,884 |
| | $29.02 |
| Granted | 2,202,774 |
| | $31.59 | 2,120,839 |
| | $33.69 |
| Vested | (1,254,320 | ) | | $24.90 | (1,713,763 | ) | | $27.78 |
| Forfeited | (474,548 | ) | | $27.26 | (553,072 | ) | | $30.58 |
| Unvested at end of year | 4,177,884 |
| | $29.02 | 4,031,888 |
| | $31.80 |
The vesting date fair value of restricted stock awards which vested during 20122013, 20112012 and 20102011 was $36$59 million,, $30 $36 million and $21 million.$30 million. The weighted average grant date fair value of restricted stock awards was $29.0231.80, $25.8829.02, and $23.0325.88 for awards unvested at December 31, 2013, 2012, and 2011 and 2010.
As of December 31, 2012,2013, there was $9496 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 1.22 years.
PerformanceStock-based performance unit awards – During 2013, we granted 353,600 stock-based performance unit awards to officers and at December 31, 2013, there were 93,100 units outstanding. The key assumptions used in the Monte Carlo simulation to determine the December 31, 2013 fair value of stock-based performance units were:
|
| | |
| |
| Valuation date stock price | $35.30 |
| Expected annual dividend yield | 2.1 | % |
| Expected volatility | 26 | % |
| 2-Year risk-free interest rate | 0.4 | % |
| Fair value of stock-based performance units outstanding | $34.08 |
Performance unitsCash-based performance unit awards – Prior to 2013, cash-based performance unit awards were granted to officers that provide for executive officers to receive a cash payment upon the achievement of certain performance goals at the end of a defined measurement period. The performance goals are tied to our total shareholder return ("TSR")TSR as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. The target value of each performance unit is $1,$1, with a maximum payout of $2$2 per unit, but the actual payout could be anywhere between zero and the maximum. Because performance units are to be settled in cash at the end of the performance period, they are accounted for as liability awards.
During 2012, we granted 12.7 million performance units, all having a 36-month performance period. During the third quarter of 2011, we granted 15 million performance units, a portion of which had a 30-month performance period and a portion of which had an 18-month performance period to reflect the remaining periods of the original 2011 and 2010 performance unit grants outstanding prior to the spin-off. Compensation expense associated with cash-based performance units was $12$9 million, $12 million and $32$32 million in 2013, 2012 and 2011, but was not significant in 2010. ExpenseThe expense for 2011 included $14 million paid on three groups of performance unit grants outstanding at June 30, 2011, that were accelerated with the total payout determined based on performance through the effective date of the spin-off of our downstream business.
During 2012, we granted 12.7 million performance units. These units have a 36-month performance period. During the third quarter of 2011, we granted 15 million performance units. A portion of the units granted in 2011 had an 18-month performance
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
period and22. Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a portion had a 30-month performance periodsummary of amounts reclassified from accumulated other comprehensive loss to reflect the remaining periods of the original 2011 and 2010 performance unit grants outstanding prior to the spin-off. The performance period for the units with an 18-month performance period ended December 31, 2012.net income in their entirety:
|
| | | | | |
| (In millions) | 2013 | | Income Statement Line |
| Accumulated Other Comprehensive Loss Components | | |
| | Income (Expense) | | |
| Postretirement and postemployment plans | | | |
| Amortization of actuarial loss | $ | (47 | ) | | General and administrative |
| Net settlement loss | (45 | ) | | General and administrative |
| | 35 |
| | Provision for income taxes |
| | (57 | ) | | Net of tax |
| Other insignificant items, net of tax | (1 | ) | | |
| Total reclassifications for the period | $ | (58 | ) | | Net income |
22.23. Stockholders’ Equity
Share repurchase plan – TheIn the third quarter of 2013, we acquired 14 million common shares at a cost of $500 million under our share repurchase program, initially authorized in 2006, bringing our total repurchases to 92 million common shares at a cost of $3,722 million. In December 2013, our Board of Directors has authorizedincreased the authorization by an additional $1.2 billion, bringing the total remaining share repurchase of upauthorization to $5 billion of our common stock.$2.5 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables. As of December 31, 2012, we had acquired 78 million common shares at a cost of $3,222 million under this authorized share repurchase program, including 12 million common shares acquired in 2011 after the June 30, 2011 spin-off of our downstream business at a cost of $300 million.
23.24. Leases
We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for capital lease obligations and for operating lease obligations having initial or remaining noncancellable lease terms in excess of one year are as follows:
| | | (In millions) | Capital Lease Obligations | | Operating Lease Obligations | Capital Lease Obligations | | Operating Lease Obligations |
| 2013 | $ | 1 |
| | $ | 42 |
| |
| 2014 | 1 |
| | 36 |
| $ | 1 |
| | $ | 45 |
|
| 2015 | 1 |
| | 33 |
| 1 |
| | 42 |
|
| 2016 | 1 |
| | 29 |
| 1 |
| | 34 |
|
| 2017 | 1 |
| | 21 |
| 1 |
| | 22 |
|
| 2018 | | 1 |
| | 20 |
|
| Later years | 24 |
| | 49 |
| 23 |
| | 48 |
|
| Sublease rentals | — |
| | (2 | ) | — |
| | (4 | ) |
| Total minimum lease payments | $ | 29 |
| | $ | 208 |
| $ | 28 |
| | $ | 207 |
|
| Less imputed interest costs | (18 | ) | | | (18 | ) | | |
| Present value of net minimum lease payments | $ | 11 |
| | | $ | 10 |
| | |
Operating lease rental expense related to continuing operations was $74106 million,$103 million and $70 million in 2013, $74 million2012 and $77 million in 2012, 2011 and 2010, which excludes $16 million paid by United States Steel on assumed leases in 2010.
24.MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
25. Commitments and Contingencies
We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.
Litigation – In March 2011, Noble Drilling (U.S.) LLC ("Noble"(“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble is seekingalleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an unspecified amountoffshore daywork drilling contract. The parties settled this litigation in the fourth quarter of damages. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial2013, and the settlement did not have a material adverse effect on us, remains uncertain. We do not believe an estimateour consolidated results of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.operations, financial position or cash flows.
Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
At December 31, 20122013 and 20112012, accrued liabilities for remediation were not significant. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.
Guarantees – We have variousentered into a guarantee of a long-term transportation services agreement and a performance guaranteesguarantee related to specific agreementsasset retirement obligations with aggregate maximum potential undiscounted payments totaling $96 million as discussed below.of December 31, 2013. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements.
United States Steel was the sole general partner of Clairton 1314B Partnership, L.P., which owned certain facilities formerly owned by United States Steel. We have agreed, under certain circumstances, to indemnify the limited partners if the partnership’s product sales fail to qualify for the credit under Section 29 of the Internal Revenue Code. The Clairton 1314B Partnership was terminated on October 31, 2008, but we were not released from our obligations. United States Steel has estimated the maximum potential amount of this indemnity obligation, including interest and tax gross-up, was approximately $110 million as of December 31, 2012.
After our 2009 sale of the subsidiary holding our interest in the Corrib natural gas development offshore Ireland, one guarantee of that entity's performance related to asset retirement obligations remains issued to certain Irish government entities until the Irish government and the current Corrib partners agree to release our guarantee and accept the purchaser's guarantee to replace it. We have been indemnified by the purchaser of the subsidiary and have the benefit of a letter of credit. The maximum potential undiscounted payments related to asset retirement obligations under this guarantee as of December 31, 2012 are $40 million.
We have entered into other guarantees with maximum potential undiscounted payments totaling $94 million as of December 31, 2012, which consist primarily of a performance guarantee and a long-term transportation services agreement.
In October 2010, upon acquiring a position in four exploration blocks in the Kurdistan Region of Iraq, we indemnified the KRG against any negative tax effects related to certain payments we are obligated to make to the KRG. As of December 31, 2012, some of those payments had been made, no related taxes have been assessed, and neither is there any history of such payments being taxed. Given the lack of history of tax assessment against such payments, and because certain of our future payments to the KRG are not quantifiable, a maximum potential undiscounted payments cannot be calculated.
Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.
Contract commitments – At December 31, 20122013 and 20112012, contractual commitments to acquire property, plant and equipment totaled $949$1,270 million and $615 million.$949 million.
Other contingencies – During the second quarter of 2011, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section of the Muskeg River mine. Our share of the estimated costs in the amount of $64 million was recorded to cost of revenuesproduction expense in 2011. At December 31, 20122013, the remaining liability is $3929 million.
Select Quarterly Financial Data (Unaudited)
| | | | 2012 | | 2011(a) | 2013 | | 2012 |
| (In millions, except per share data) | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. | | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. | | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. |
| Revenues | $ | 3,791 |
| | $ | 3,731 |
| | $ | 4,034 |
| | $ | 4,132 |
| | $ | 3,671 |
| | $ | 3,694 |
| | $ | 3,649 |
| | $ | 3,649 |
| $ | 3,784 |
| | $ | 3,839 |
| | $ | 3,699 |
| | $ | 3,179 |
| | $ | 3,793 |
| | $ | 3,732 |
| | $ | 4,036 |
| | $ | 4,131 |
|
| Income from operations before income taxes | 1,394 |
| | 1,475 |
| | 1,782 |
| | 1,681 |
| | 1,289 |
| | 928 |
| | 1,333 |
| | 1,263 |
| |
| Income from continuing operations before income taxes | | 1,367 |
| | 1,467 |
| | 1,278 |
| | 818 |
| | 1,350 |
| | 1,421 |
| | 1,733 |
| | 1,626 |
|
| Income from continuing operations | 417 |
| | 393 |
| | 450 |
| | 322 |
| | 455 |
| | 298 |
| | 405 |
| | 549 |
| 380 |
| | 399 |
| | 518 |
| | 296 |
| | 423 |
| | 406 |
| | 469 |
| | 315 |
|
Discontinued operations | — |
| | — |
| | — |
| | — |
| | 541 |
| | 698 |
| | — |
| | — |
| 3 |
| | 27 |
| | 51 |
| | 79 |
| | (6 | ) | | (13 | ) | | (19 | ) | | 7 |
|
| Net income | $ | 417 |
| | $ | 393 |
| | $ | 450 |
| | $ | 322 |
| | $ | 996 |
| | $ | 996 |
| | $ | 405 |
| | $ | 549 |
| $ | 383 |
| | $ | 426 |
| | $ | 569 |
| | $ | 375 |
| | $ | 417 |
| | $ | 393 |
| | $ | 450 |
| | $ | 322 |
|
| Income per share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Continuing operations | $0.59 | | $0.56 | | $0.64 | | $0.46 | | $0.64 | | $0.42 | | $0.57 | | $0.78 | $0.54 | | $0.56 | | $0.73 | | $0.43 | | $0.60 | | $0.58 | | $0.67 | | $0.45 |
| Discontinued operations | — |
| | — |
| | — |
| | — |
| | $0.76 | | $0.98 | | — |
| | — |
| |
Discontinued operations (a) | | $0.00 | | $0.04 | | $0.07 | | $0.11 | | ($0.01) | | ($0.02) | | ($0.03) | | $0.01 |
| Net income | $0.59 | | $0.56 | | $0.64 | | $0.46 | | $1.40 | | $1.40 | | $0.57 | | $0.78 | $0.54 | | $0.60 | | $0.80 | | $0.54 | | $0.59 | | $0.56 | | $0.64 | | $0.46 |
| Diluted: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Continuing operations | $0.59 | | $0.56 | | $0.63 | | $0.45 | | $0.64 | | $0.42 | | $0.57 | | $0.78 | $0.54 | | $0.56 | | $0.73 | | $0.43 | | $0.60 | | $0.58 | | $0.66 | | $0.44 |
| Discontinued operations | — |
| | — |
| | — |
| | — |
| | $0.75 | | $0.97 | | — |
| | — |
| |
Discontinued operations (a) | | $0.00 | | $0.04 | | $0.07 | | $0.11 | | ($0.01) | | ($0.02) | | ($0.03) | | $0.01 |
| Net income | $0.59 | | $0.56 | | $0.63 | | $0.45 | | $1.39 | | $1.39 | | $0.57 | | $0.78 | $0.54 | | $0.60 | | $0.80 | | $0.54 | | $0.59 | | $0.56 | | $0.63 | | $0.45 |
| Dividends paid per share | $0.17 | | $0.17 | | $0.17 | | $0.17 | | $0.25 | | $0.25 | | $0.15 | | $0.15 | $0.17 | | $0.17 | | $0.19 | | $0.19 | | $0.17 | | $0.17 | | $0.17 | | $0.17 |
| |
(a) | The downstream business was spun-off on June 30, 2011. All quarters prior to the spin-off have been recast to reflect this business in discontinued operations. |
(a) In 2013, we entered into agreements to sell our Angola assets; therefore, our Angola operations are reflected as discontinued operations in all periods presented.
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
The supplementary information is disclosed by the following geographic areas: the U.S.; Europe, which primarily includes activities in Norway, Poland and the U.K.; E.G.Canada; E. G.; Other Africa, which primarily includes activities in Angola, Gabon, Kenya, Ethiopia and Libya; Canada;Europe, which primarily includes activities in Norway and the U.K.; and Other International ("Other Int’l"), which includes activities in Indonesia and the Kurdistan Region of Iraq. Our Angola operations are shown as discontinued operations ("Disc Ops") in all periods since we entered into agreements to sell these assets in 2013.
Estimated Quantities of Proved Oil and Gas Reserves
The estimation of net recoverable quantities of liquid hydrocarbons, natural gas and synthetic crude oil is a highly technical process, which is based upon several underlying assumptions that are subject to change. For a discussion of our reserve estimation process, including the use of third-party audits, see Item 1. Business – Reserves.
| | | (mmbbl) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Europe | | Total | U.S. | | Canada | | E.G.(a) | | Other Africa | | Europe | | Disc Ops | | Total |
| Liquid Hydrocarbons | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | | Proved developed and undeveloped reserves: | | | | | | | | | | | | |
| Beginning of year - 2010 | 170 |
| | — |
| | 122 |
| | 228 |
| | 102 |
| | 622 |
| |
| Revisions of previous estimates | (3 | ) | | — |
| | 10 |
| | — |
| | 23 |
| | 30 |
| |
| Purchases of reserves in place | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| |
| Extensions, discoveries and other additions | 30 |
| | — |
| | — |
| | 28 |
| | 8 |
| | 66 |
| |
| Production | (25 | ) | | — |
| | (13 | ) | | (17 | ) | | (34 | ) | | (89 | ) | |
| End of year - 2010 | 173 |
| | — |
| | 119 |
| | 239 |
| | 99 |
| | 630 |
| |
| Beginning of year - 2011 | | 173 |
| | — |
| | 119 |
| | 224 |
| | 99 |
| | 15 |
| | 630 |
|
| Revisions of previous estimates | 16 |
| | — |
| | 11 |
| | 2 |
| | 21 |
| | 50 |
| 16 |
| | — |
| | 11 |
| | — |
| | 21 |
| | 2 |
| | 50 |
|
| Improved recovery | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Purchases of reserves in place | 89 |
| | — |
| | — |
| | — |
| | — |
| | 89 |
| 89 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 89 |
|
| Extensions, discoveries and other additions | 27 |
| | — |
| | — |
| | 1 |
| | 14 |
| | 42 |
| |
| Extensions, discoveries and other | | | | | | | | | | | | | | |
| additions | | 27 |
| | — |
| | — |
| | — |
| | 14 |
| | 1 |
| | 42 |
|
| Production | (27 | ) | | — |
| | (13 | ) | | (2 | ) | | (37 | ) | | (79 | ) | (27 | ) | | — |
| | (13 | ) | | (2 | ) | | (37 | ) | | — |
| | (79 | ) |
| End of year - 2011 | 279 |
| | — |
| | 117 |
| | 240 |
| | 97 |
| | 733 |
| 279 |
| | — |
| | 117 |
| | 222 |
| | 97 |
| | 18 |
| | 733 |
|
| Revisions of previous estimates | 9 |
| | — |
| | 6 |
| | (5 | ) | | 28 |
| | 38 |
| 9 |
| | — |
| | 6 |
| | (5 | ) | | 28 |
| | — |
| | 38 |
|
| Improved recovery | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Purchases of reserves in place | 52 |
| | — |
| | — |
| | — |
| | — |
| | 52 |
| 52 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 52 |
|
| Extensions, discoveries and other additions | 172 |
| | — |
| | — |
| | 7 |
| | — |
| | 179 |
| |
| Extensions, discoveries and other | | | | | | | | | | | | | | |
| additions | | 172 |
| | — |
| | — |
| | 7 |
| | — |
| | — |
| | 179 |
|
| Production | (39 | ) | | — |
| | (13 | ) | | (15 | ) | | (36 | ) | | (103 | ) | (39 | ) | | — |
| | (13 | ) | | (15 | ) | | (36 | ) | | — |
| | (103 | ) |
| End of year - 2012 | 475 |
| | — |
| | 110 |
| | 227 |
| | 89 |
| | 901 |
| 475 |
| | — |
| | 110 |
| | 209 |
| | 89 |
| | 18 |
| | 901 |
|
| Revisions of previous estimates | | 46 |
| | — |
| | (1 | ) | | 12 |
| | 26 |
| | (1 | ) | | 82 |
|
| Improved recovery | | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
| | 11 |
|
| Purchases of reserves in place | | 14 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 14 |
|
| Extensions, discoveries and other | | | | | | | | | | | | | | |
| additions | | 137 |
| | — |
| | 1 |
| | 3 |
| | 5 |
| | 3 |
| | 149 |
|
| Production | | (55 | ) | | — |
| | (12 | ) | | (9 | ) | | (31 | ) | | (3 | ) | | (110 | ) |
| Sales of reserves in place | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) |
| End of year - 2013 | | 616 |
| | — |
| | 98 |
| | 215 |
| | 89 |
| | 28 |
| | 1,046 |
|
| Proved developed reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| Beginning of year - 2010 | 120 |
| | — |
| | 83 |
| | 186 |
| | 87 |
| | 476 |
| |
| End of year - 2010 | 124 |
| | — |
| | 86 |
| | 180 |
| | 89 |
| | 479 |
| |
| Beginning of year - 2011 | | 124 |
| | — |
| | 86 |
| | 180 |
| | 89 |
| | — |
| | 479 |
|
| End of year - 2011 | 141 |
| | — |
| | 78 |
| | 179 |
| | 84 |
| | 482 |
| 141 |
| | — |
| | 78 |
| | 179 |
| | 84 |
| | — |
| | 482 |
|
| End of year - 2012 | 198 |
| | — |
| | 68 |
| | 168 |
| | 84 |
| | 518 |
| 198 |
| | — |
| | 68 |
| | 168 |
| | 84 |
| | — |
| | 518 |
|
| End of year - 2013 | | 292 |
| | — |
| | 55 |
| | 176 |
| | 78 |
| | 19 |
| | 620 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| Beginning of year - 2010 | 50 |
| | — |
| | 39 |
| | 42 |
| | 15 |
| | 146 |
| |
| End of year - 2010 | 49 |
| | — |
| | 33 |
| | 59 |
| | 10 |
| | 151 |
| |
| Beginning of year - 2011 | | 49 |
| | — |
| | 33 |
| | 44 |
| | 10 |
| | 15 |
| | 151 |
|
| End of year - 2011 | 138 |
| | — |
| | 39 |
| | 61 |
| | 13 |
| | 251 |
| 138 |
| | — |
| | 39 |
| | 43 |
| | 13 |
| | 18 |
| | 251 |
|
| End of year - 2012 | 277 |
| | — |
| | 42 |
| | 59 |
| | 5 |
| | 383 |
| 277 |
| | — |
| | 42 |
| | 41 |
| | 5 |
| | 18 |
| | 383 |
|
| End of year - 2013 | | 324 |
| | — |
| | 43 |
| | 39 |
| | 11 |
| | 9 |
| | 426 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued) |
| | | | | | | | | | | | | | | | | | | | |
| (bcf) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Europe | | Disc Ops | | Total |
| Natural Gas | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | | |
| Beginning of year - 2011 | 745 |
| | — |
| | 1,651 |
| | 105 |
| | 116 |
| | — |
| | 2,617 |
|
| Revisions of previous estimates | 18 |
| | — |
| | 81 |
| | (1 | ) | | 22 |
| | — |
| | 120 |
|
| Purchases of reserves in place | 119 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 119 |
|
| Extensions, discoveries and other | | | | | | | | | | | | | |
| additions | 109 |
| | — |
| | — |
| | — |
| | 11 |
| | — |
| | 120 |
|
Production(b) | (119 | ) | | — |
| | (161 | ) | | — |
| | (30 | ) | | — |
| | (310 | ) |
| End of year - 2011 | 872 |
| | — |
| | 1,571 |
| | 104 |
| | 119 |
| | — |
| | 2,666 |
|
| Revisions of previous estimates | (29 | ) | | — |
| | 10 |
| | (1 | ) | | 15 |
| | — |
| | (5 | ) |
| Purchases of reserves in place | 105 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 105 |
|
| Extensions, discoveries and other | | | | | | | | | | | | | |
| additions | 224 |
| | — |
| | — |
| | 111 |
| | — |
| | — |
| | 335 |
|
Production(b) | (129 | ) | | — |
| | (157 | ) | | (5 | ) | | (31 | ) | | — |
| | (322 | ) |
| End of year - 2012 | 1,043 |
| | — |
| | 1,424 |
| | 209 |
| | 103 |
| | — |
| | 2,779 |
|
| Revisions of previous estimates | (4 | ) | | — |
| | 45 |
| | 4 |
| | 43 |
| | — |
| | 88 |
|
| Purchases of reserves in place | 13 |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | 16 |
|
| Extensions, discoveries and other | | | | | | | | | | | | | |
| additions | 163 |
| | — |
| | 9 |
| | — |
| | 3 |
| | — |
| | 175 |
|
Production(b) | (114 | ) | | — |
| | (161 | ) | | (8 | ) | | (28 | ) | | — |
| | (311 | ) |
| Sales of reserves in place | (76 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (76 | ) |
| End of year - 2013 | 1,025 |
| | — |
| | 1,320 |
| | 205 |
| | 121 |
| | — |
| | 2,671 |
|
| Proved developed reserves: | | | | | | | | | | | | |
|
| Beginning of year - 2011 | 591 |
| | — |
| | 1,186 |
| | 104 |
| | 43 |
| | — |
| | 1,924 |
|
| End of year - 2011 | 551 |
| | — |
| | 1,104 |
| | 104 |
| | 40 |
| | — |
| | 1,799 |
|
| End of year - 2012 | 546 |
| | — |
| | 980 |
| | 99 |
| | 28 |
| | — |
| | 1,653 |
|
| End of year - 2013 | 540 |
| | — |
| | 823 |
| | 95 |
| | 41 |
| | — |
| | 1,499 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | |
|
| Beginning of year - 2011 | 154 |
| | — |
| | 465 |
| | 1 |
| | 73 |
| | — |
| | 693 |
|
| End of year - 2011 | 321 |
| | — |
| | 467 |
| | — |
| | 79 |
| | — |
| | 867 |
|
| End of year - 2012 | 497 |
| | — |
| | 444 |
| | 110 |
| | 75 |
| | — |
| | 1,126 |
|
| End of year - 2013 | 485 |
| | — |
| | 497 |
| | 110 |
| | 80 |
| | — |
| | 1,172 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued) |
| | | | | | | | | | | | | | | | | | | | |
| (mmbbl) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Europe | | Disc Ops | | Total |
| Synthetic crude oil | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | | |
| Beginning of year - 2011 | — |
| | 572 |
| | — |
| | — |
| | — |
| | — |
| | 572 |
|
| Revisions of previous estimates | — |
| | 17 |
| | — |
| | — |
| | — |
| | — |
| | 17 |
|
| Extensions, discoveries and other | | | | | | | | | | | | | |
| additions | — |
| | 48 |
| | — |
| | — |
| | — |
| | — |
| | 48 |
|
| Production | — |
| | (14 | ) | | — |
| | — |
| | — |
| | — |
| | (14 | ) |
| End of year - 2011 | — |
| | 623 |
| | — |
| | — |
| | — |
| | — |
| | 623 |
|
| Revisions of previous estimates | — |
| | 45 |
| | — |
| | — |
| | — |
| | — |
| | 45 |
|
| Production | — |
| | (15 | ) | | — |
| | — |
| | — |
| | — |
| | (15 | ) |
| End of year - 2012 | — |
| | 653 |
| | — |
| | — |
| | — |
| | — |
| | 653 |
|
| Revisions of previous estimates | — |
| | 36 |
| | — |
| | — |
| | — |
| | — |
| | 36 |
|
| Extensions, discoveries and other | | | | | | | | | | | | | |
| additions | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
| Production | — |
| | (15 | ) | | — |
| | — |
| | — |
| | — |
| | (15 | ) |
| End of year - 2013 | — |
| | 680 |
| | — |
| | — |
| | — |
| | — |
| | 680 |
|
| Proved developed reserves: | | | | | | | | | | | | | |
| Beginning of year - 2011 | — |
| | 433 |
| | — |
| | — |
| | — |
| | — |
| | 433 |
|
| End of year - 2011 | — |
| | 623 |
| | — |
| | — |
| | — |
| | — |
| | 623 |
|
| End of year - 2012 | — |
| | 653 |
| | — |
| | — |
| | — |
| | — |
| | 653 |
|
| End of year - 2013 | — |
| | 674 |
| | — |
| | — |
| | — |
| | — |
| | 674 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | |
| Beginning of year - 2011 | — |
| | 139 |
| | — |
| | — |
| | — |
| | — |
| | 139 |
|
| End of year - 2011 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2012 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2013 | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued) |
| | | | | | | | | | | | | | | | | |
| | U.S. | | Canada | | E.G.(a) | | Other Africa | | Europe | | Total |
Natural Gas (bcf) | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | |
| Beginning of year - 2010 | 820 |
| | — |
| | 1,688 |
| | 107 |
| | 109 |
| | 2,724 |
|
| Revisions of previous estimates | 16 |
| | — |
| | 111 |
| | (1 | ) | | 35 |
| | 161 |
|
| Purchases of reserves in place | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Extensions, discoveries and other additions | 61 |
| | — |
| | — |
| | — |
| | 4 |
| | 65 |
|
Production(b) | (133 | ) | | — |
| | (148 | ) | | (1 | ) | | (32 | ) | | (314 | ) |
| Sales of reserves in place | (20 | ) | | — |
| | — |
| | — |
| | — |
| | (20 | ) |
| End of year - 2010 | 745 |
| | — |
| | 1,651 |
| | 105 |
| | 116 |
| | 2,617 |
|
| Revisions of previous estimates | 18 |
| | — |
| | 81 |
| | (1 | ) | | 22 |
| | 120 |
|
| Purchases of reserves in place | 119 |
| | — |
| | — |
| | — |
| | — |
| | 119 |
|
| Extensions, discoveries and other additions | 109 |
| | — |
| | — |
| | — |
| | 11 |
| | 120 |
|
Production(b) | (119 | ) | | — |
| | (161 | ) | | — |
| | (30 | ) | | (310 | ) |
| End of year - 2011 | 872 |
| | — |
| | 1,571 |
| | 104 |
| | 119 |
| | 2,666 |
|
| Revisions of previous estimates | (29 | ) | | — |
| | 10 |
| | (1 | ) | | 15 |
| | (5 | ) |
| Purchases of reserves in place | 105 |
| | — |
| | — |
| | — |
| | — |
| | 105 |
|
| Extensions, discoveries and other additions | 224 |
| | — |
| | — |
| | 111 |
| | — |
| | 335 |
|
Production(b) | (129 | ) | | — |
| | (157 | ) | | (5 | ) | | (31 | ) | | (322 | ) |
| End of year - 2012 | 1,043 |
| | — |
| | 1,424 |
| | 209 |
| | 103 |
| | 2,779 |
|
| Proved developed reserves: | | | | | | | | | | | |
| Beginning of year - 2010 | 652 |
| | — |
| | 1,102 |
| | 107 |
| | 50 |
| | 1,911 |
|
| End of year - 2010 | 591 |
| | — |
| | 1,186 |
| | 104 |
| | 43 |
| | 1,924 |
|
| End of year - 2011 | 551 |
| | — |
| | 1,104 |
| | 104 |
| | 40 |
| | 1,799 |
|
| End of year - 2012 | 546 |
| | — |
| | 980 |
| | 99 |
| | 28 |
| | 1,653 |
|
| Proved undeveloped reserves: | | | | | | | | | | | |
| Beginning of year - 2010 | 168 |
| | — |
| | 586 |
| | — |
| | 59 |
| | 813 |
|
| End of year - 2010 | 154 |
| | — |
| | 465 |
| | 1 |
| | 73 |
| | 693 |
|
| End of year - 2011 | 321 |
| | — |
| | 467 |
| | — |
| | 79 |
| | 867 |
|
| End of year - 2012 | 497 |
| | — |
| | 444 |
| | 110 |
| | 75 |
| | 1,126 |
|
Synthetic crude oil (mmbbl) | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | |
| Beginning of year - 2010 | — |
| | 603 |
| | — |
| | — |
| | — |
| | 603 |
|
| Revisions of previous estimates | — |
| | (22 | ) | | — |
| | — |
| | — |
| | (22 | ) |
| Production | — |
| | (9 | ) | | — |
| | — |
| | — |
| | (9 | ) |
| End of year - 2010 | — |
| | 572 |
| | — |
| | — |
| | — |
| | 572 |
|
| Revisions of previous estimates | — |
| | 17 |
| | — |
| | — |
| | — |
| | 17 |
|
| Production | — |
| | (14 | ) | | — |
| | — |
| | — |
| | (14 | ) |
| Extensions, discoveries and other additions | — |
| | 48 |
| | — |
| | — |
| | — |
| | 48 |
|
| End of year - 2011 | — |
| | 623 |
| | — |
| | — |
| | — |
| | 623 |
|
| Revisions of previous estimates | — |
| | 45 |
| | — |
| | — |
| | — |
| | 45 |
|
| Production | — |
| | (15 | ) | | — |
| | — |
| | — |
| | (15 | ) |
| End of year - 2012 | — |
| | 653 |
| | — |
| | — |
| | — |
| | 653 |
|
| Proved developed reserves: | | | | | | | | | | | |
| Beginning of year - 2010 | — |
| | 392 |
| | — |
| | — |
| | — |
| | 392 |
|
| End of year - 2010 | — |
| | 433 |
| | — |
| | — |
| | — |
| | 433 |
|
| End of year - 2011 | — |
| | 623 |
| | — |
| | — |
| | — |
| | 623 |
|
| End of year - 2012 | — |
| | 653 |
| | — |
| | — |
| | — |
| | 653 |
|
| Proved undeveloped reserves: | | | | | | | | | | | |
| Beginning of year - 2010 | — |
| | 211 |
| | — |
| | — |
| | — |
| | 211 |
|
| End of year - 2010 | — |
| | 139 |
| | — |
| | — |
| | — |
| | 139 |
|
| End of year - 2011 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2012 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued) | | | (mmboe) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Europe | | Total | U.S. | | Canada | | E.G.(a) | | Other Africa | | Europe | | Disc Ops | | Total |
| Total Proved Reserves | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | | | | | | | | | | | | Proved developed and undeveloped reserves: | | | | | | | | | | | | |
| Beginning of year - 2010 | 307 |
| | 603 |
| | 403 |
| | 246 |
| | 120 |
| | 1,679 |
| |
| Revisions of previous estimates | (1 | ) | | (22 | ) | | 29 |
| | — |
| | 28 |
| | 34 |
| |
| Purchases of reserves in place | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| |
| Extensions, discoveries and other additions | 40 |
| | — |
| | — |
| | 28 |
| | 9 |
| | 77 |
| |
Production(b) | (47 | ) | | (9 | ) | | (38 | ) | | (17 | ) | | (39 | ) | | (150 | ) | |
| Sales of reserves in place | (3 | ) | | — |
| | — |
| | — |
| | — |
| | (3 | ) | |
| End of year - 2010 | 297 |
| | 572 |
| | 394 |
| | 257 |
| | 118 |
| | 1,638 |
| |
| Beginning of year - 2011 | | 297 |
| | 572 |
| | 394 |
| | 242 |
| | 118 |
| | 15 |
| | 1,638 |
|
| Revisions of previous estimates | 19 |
| | 17 |
| | 25 |
| | 1 |
| | 25 |
| | 87 |
| 19 |
| | 17 |
| | 25 |
| | (1 | ) | | 25 |
| | 2 |
| | 87 |
|
| Improved recovery | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Purchases of reserves in place | 109 |
| | — |
| | — |
| | — |
| | — |
| | 109 |
| 109 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 109 |
|
| Extensions, discoveries and other additions | 45 |
| | 48 |
| | — |
| | 1 |
| | 16 |
| | 110 |
| |
| Extensions, discoveries and other | | | | | | | | | | | | | | |
| additions | | 45 |
| | 48 |
| | — |
| | — |
| | 16 |
| | 1 |
| | 110 |
|
Production(b) | (47 | ) | | (14 | ) | | (40 | ) | | (2 | ) | | (42 | ) | | (145 | ) | (47 | ) | | (14 | ) | | (40 | ) | | (2 | ) | | (42 | ) | | — |
| | (145 | ) |
| End of year - 2011 | 424 |
| | 623 |
| | 379 |
| | 257 |
| | 117 |
| | 1,800 |
| 424 |
| | 623 |
| | 379 |
| | 239 |
| | 117 |
| | 18 |
| | 1,800 |
|
| Revisions of previous estimates | 5 |
| | 45 |
| | 7 |
| | (5 | ) | | 30 |
| | 82 |
| 5 |
| | 45 |
| | 7 |
| | (5 | ) | | 30 |
| | — |
| | 82 |
|
| Improved recovery | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Purchases of reserves in place | 70 |
| | — |
| | — |
| | — |
| | — |
| | 70 |
| 70 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 70 |
|
| Extensions, discoveries and other additions | 209 |
| | — |
| | — |
| | 26 |
| | — |
| | 235 |
| |
| Extensions, discoveries and other | | | | | | | | | | | | | | |
| additions | | 209 |
| | — |
| | — |
| | 26 |
| | — |
| | — |
| | 235 |
|
Production(b) | (61 | ) | | (15 | ) | | (39 | ) | | (16 | ) | | (41 | ) | | (172 | ) | (61 | ) | | (15 | ) | | (39 | ) | | (16 | ) | | (41 | ) | | — |
| | (172 | ) |
| End of year - 2012 | 649 |
| | 653 |
| | 347 |
| | 262 |
| | 106 |
| | 2,017 |
| 649 |
| | 653 |
| | 347 |
| | 244 |
| | 106 |
| | 18 |
| | 2,017 |
|
| Revisions of previous estimates | | 45 |
| | 36 |
| | 7 |
| | 12 |
| | 33 |
| | (1 | ) | | 132 |
|
| Improved recovery | | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
| | 11 |
|
| Purchases of reserves in place | | 16 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | 17 |
|
| Extensions, discoveries and other | | | | | | | | | | | | | | |
| additions | | 164 |
| | 6 |
| | 2 |
| | 3 |
| | 6 |
| | 3 |
| | 184 |
|
Production(b) | | (74 | ) | | (15 | ) | | (39 | ) | | (10 | ) | | (36 | ) | | (3 | ) | | (177 | ) |
| Sales of reserves in place | | (13 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (13 | ) |
| End of year - 2013 | | 787 |
| | 680 |
|
| 318 |
|
| 249 |
|
| 109 |
|
| 28 |
|
| 2,171 |
|
| Proved developed reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| Beginning of year - 2010 | 229 |
| | 392 |
| | 267 |
| | 204 |
| | 95 |
| | 1,187 |
| |
| End of year - 2010 | 222 |
| | 433 |
| | 284 |
| | 198 |
| | 96 |
| | 1,233 |
| |
| Beginning of year - 2011 | | 222 |
| | 433 |
| | 284 |
| | 198 |
| | 96 |
| | — |
| | 1,233 |
|
| End of year - 2011 | 233 |
| | 623 |
| | 262 |
| | 196 |
| | 91 |
| | 1,405 |
| 233 |
| | 623 |
| | 262 |
| | 196 |
| | 91 |
|
| — |
| | 1,405 |
|
| End of year - 2012 | 289 |
| | 653 |
| | 231 |
| | 185 |
| | 88 |
| | 1,446 |
| 289 |
| | 653 |
| | 231 |
| | 185 |
| | 88 |
| | — |
| | 1,446 |
|
| End of year - 2013 | | 382 |
| | 674 |
| | 193 |
| | 192 |
| | 84 |
| | 19 |
| | 1,544 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | | | | | |
|
| Beginning of year - 2010 | 78 |
| | 211 |
| | 136 |
| | 42 |
| | 25 |
| | 492 |
| |
| End of year - 2010 | 75 |
| | 139 |
| | 110 |
| | 59 |
| | 22 |
| | 405 |
| |
| Beginning of year - 2011 | | 75 |
| | 139 |
| | 110 |
| | 44 |
| | 22 |
| | 15 |
| | 405 |
|
| End of year - 2011 | 191 |
| | — |
| | 117 |
| | 61 |
| | 26 |
| | 395 |
| 191 |
| | — |
| | 117 |
| | 43 |
| | 26 |
| | 18 |
| | 395 |
|
| End of year - 2012 | 360 |
| | — |
| | 116 |
| | 77 |
| | 18 |
| | 571 |
| 360 |
| | — |
| | 116 |
| | 59 |
| | 18 |
| | 18 |
| | 571 |
|
| End of year - 2013 | | 405 |
| | 6 |
| | 125 |
| | 57 |
| | 25 |
| | 9 |
| | 627 |
|
| |
(a) | Consists of estimated reserves from properties governed by production sharing contracts. |
| |
(b) | Excludes the resale of purchased natural gas used in reservoir management. |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization | | | | December 31, | December 31, |
| (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Europe | | Other Int’l | | Total | U.S. | | Canada | | E.G. | | Other Africa (a) | | Europe | | Other Int’l | | Total |
| 2013 Capitalized Costs: | | | | | | | | | | | | | | |
| Proved properties | | $ | 24,165 |
| | $ | 9,276 |
| | $ | 1,683 |
| | $ | 2,257 |
| | $ | 8,898 |
| | $ | — |
| | $ | 46,279 |
|
| Unproved properties | | 2,097 |
| | 1,508 |
| | 31 |
| | 693 |
| | 296 |
| | 214 |
| | 4,839 |
|
| Total | | 26,262 |
| | 10,784 |
| | 1,714 |
| | 2,950 |
| | 9,194 |
| | 214 |
| | 51,118 |
|
| Accumulated depreciation, | | | | | | | | | | | | | | |
| depletion and amortization: | | | | | | | | | | | | | | |
| Proved properties | | 11,568 |
| | 989 |
| | 918 |
| | 307 |
| | 7,607 |
| | — |
| | 21,389 |
|
| Unproved properties | | 180 |
| | 1 |
| | — |
| | 13 |
| | 7 |
| | 8 |
| | 209 |
|
| Total | | 11,748 |
| | 990 |
| | 918 |
| | 320 |
| | 7,614 |
| | 8 |
| | 21,598 |
|
| Net capitalized costs | | $ | 14,514 |
| | $ | 9,794 |
| | $ | 796 |
| | $ | 2,630 |
| | $ | 1,580 |
| | $ | 206 |
| | $ | 29,520 |
|
| 2012 Capitalized Costs: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved properties | $ | 21,309 |
| | $ | 9,003 |
| | $ | 1,586 |
| | $ | 2,139 |
| | $ | 8,778 |
| | $ | 67 |
| | $ | 42,882 |
| $ | 21,106 |
| | $ | 8,963 |
| | $ | 1,586 |
| | $ | 1,898 |
| | $ | 8,690 |
| | $ | — |
| | $ | 42,243 |
|
| Unproved properties | 3,019 |
| | 1,473 |
| | 29 |
| | 361 |
| | 72 |
| | 79 |
| | 5,033 |
| 3,222 |
| | 1,513 |
| | 29 |
| | 602 |
| | 160 |
| | 146 |
| | 5,672 |
|
| Total | 24,328 |
| | 10,476 |
| | 1,615 |
| | 2,500 |
| | 8,850 |
| | 146 |
| | 47,915 |
| 24,328 |
| | 10,476 |
| | 1,615 |
| | 2,500 |
| | 8,850 |
| | 146 |
| | 47,915 |
|
| Accumulated depreciation, depletion and | | | | | | | | | | | | | | |
| amortization: | | | | | | | | | | | | | | |
| Accumulated depreciation, | | | | | | | | | | | | | | |
| depletion and amortization: | | | | | | | | | | | | | | |
| Proved properties | 10,493 |
| | 782 |
| | 824 |
| | 178 |
| | 7,191 |
| | 1 |
| | 19,469 |
| 10,493 |
| | 781 |
| | 824 |
| | 174 |
| | 7,191 |
| | — |
| | 19,463 |
|
| Unproved properties | 293 |
| | — |
| | — |
| | 9 |
| | — |
| | 19 |
| | 321 |
| 293 |
| | 1 |
| | — |
| | 13 |
| | — |
| | 20 |
| | 327 |
|
| Total | 10,786 |
| | 782 |
| | 824 |
| | 187 |
| | 7,191 |
| | 20 |
| | 19,790 |
| 10,786 |
| | 782 |
| | 824 |
| | 187 |
| | 7,191 |
| | 20 |
| | 19,790 |
|
| Net capitalized costs | $ | 13,542 |
| | $ | 9,694 |
| | $ | 791 |
| | $ | 2,313 |
| | $ | 1,659 |
| | $ | 126 |
| | $ | 28,125 |
| $ | 13,542 |
| | $ | 9,694 |
| | $ | 791 |
| | $ | 2,313 |
| | $ | 1,659 |
| | $ | 126 |
| | $ | 28,125 |
|
| 2011 Capitalized Costs: | | | | | | | | | | | | | | |
| Proved properties | $ | 15,183 |
| | $ | 8,810 |
| | $ | 1,545 |
| | $ | 1,722 |
| | $ | 8,314 |
| | $ | 33 |
| | $ | 35,607 |
| |
| Unproved properties | 4,344 |
| | 1,473 |
| | 23 |
| | 303 |
| | 51 |
| | 179 |
| | 6,373 |
| |
| Total | 19,527 |
| | 10,283 |
| | 1,568 |
| | 2,025 |
| | 8,365 |
| | 212 |
| | 41,980 |
| |
| Accumulated depreciation, depletion and | | | | | | | | | | | | | | |
| amortization: | | | | | | | | | | | | | | |
| Proved properties | 8,499 |
| | 572 |
| | 729 |
| | 134 |
| | 6,593 |
| | 1 |
| | 16,528 |
| |
| Unproved properties | 359 |
| | — |
| | — |
| | 9 |
| | — |
| | 12 |
| | 380 |
| |
| Total | 8,858 |
| | 572 |
| | 729 |
| | 143 |
| | 6,593 |
| | 13 |
| | 16,908 |
| |
| Net capitalized costs | $ | 10,669 |
| | $ | 9,711 |
| | $ | 839 |
| | $ | 1,882 |
| | $ | 1,772 |
| | $ | 199 |
| | $ | 25,072 |
| |
| |
(a) | Includes Angola costs. |
Costs Incurred for Property Acquisition, Exploration and Development(a) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Europe | | Other Int’l | | Total |
| 2012 | Property acquisition: | | | | | | | | | | | | | |
| | Proved | $ | 756 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 759 |
|
| | Unproved | 432 |
| | — |
| | 18 |
| | 68 |
| | — |
| | (13 | ) | | 505 |
|
| | Exploration | 1,587 |
| | 31 |
| | 3 |
| | 45 |
| | 54 |
| | 136 |
| | 1,856 |
|
| | Development | 2,469 |
| | 195 |
| | 22 |
| | 368 |
| | 468 |
| | 5 |
| | 3,527 |
|
| | Total | $ | 5,244 |
| | $ | 226 |
| | $ | 43 |
| | $ | 481 |
| | $ | 525 |
| | $ | 128 |
| | $ | 6,647 |
|
| 2011 | Property acquisition: | | | | | | | | | | | | | |
| | Proved | $ | 1,782 |
| | $ | 5 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,788 |
|
| | Unproved | 3,271 |
| | — |
| | — |
| | 1 |
| | 7 |
| | 57 |
| | 3,336 |
|
| | Exploration | 782 |
| | 42 |
| | — |
| | 33 |
| | 109 |
| | 168 |
| | 1,134 |
|
| | Development | 889 |
| | 293 |
| | 18 |
| | 294 |
| | 388 |
| | — |
| | 1,882 |
|
| | Total | $ | 6,724 |
| | $ | 340 |
| | $ | 19 |
| | $ | 328 |
| | $ | 504 |
| | $ | 225 |
| | $ | 8,140 |
|
| 2010 | Property acquisition: | | | | | | | | | | | | | |
| | Proved | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| | Unproved | 400 |
| | — |
| | — |
| | 1 |
| | 2 |
| | 103 |
| | 506 |
|
| | Exploration | 520 |
| | 10 |
| | 1 |
| | 41 |
| | 43 |
| | 153 |
| | 768 |
|
| | Development | 855 |
| | 889 |
| | 13 |
| | 315 |
| | 465 |
| | — |
| | 2,537 |
|
| | Total | $ | 1,776 |
| | $ | 899 |
| | $ | 14 |
| | $ | 357 |
| | $ | 510 |
| | $ | 256 |
| | $ | 3,812 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Europe | | Other Int’l | | Disc Ops | | Total |
| 2013 Property acquisition: | | | | | | | | | | | | | | | |
| Proved | $ | 51 |
| | $ | 30 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 90 |
|
| Unproved | 157 |
| | — |
| | — |
| | 44 |
| | — |
| | 21 |
| | — |
| | 222 |
|
| Exploration | 885 |
| | 9 |
| | 4 |
| | 124 |
| | 102 |
| | 137 |
| | 10 |
| | 1,271 |
|
| Development | 2,876 |
| | 280 |
| | 84 |
| | 46 |
| | 354 |
| | 1 |
| | 227 |
| | 3,868 |
|
| Total | $ | 3,969 |
| | $ | 319 |
| | $ | 97 |
| | $ | 214 |
| | $ | 456 |
| | $ | 159 |
| | $ | 237 |
| | $ | 5,451 |
|
| 2012 Property acquisition: | | | | | | | | | | | | | | | |
| Proved | $ | 756 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 759 |
|
| Unproved | 432 |
| | — |
| | 18 |
| | 63 |
| | — |
| | (13 | ) | | 5 |
| | 505 |
|
| Exploration | 1,587 |
| | 31 |
| | 3 |
| | 25 |
| | 54 |
| | 136 |
| | 20 |
| | 1,856 |
|
| Development | 2,469 |
| | 195 |
| | 22 |
| | 15 |
| | 468 |
| | 5 |
| | 353 |
| | 3,527 |
|
| Total | $ | 5,244 |
| | $ | 226 |
| | $ | 43 |
| | $ | 103 |
| | $ | 525 |
| | $ | 128 |
| | $ | 378 |
| | $ | 6,647 |
|
| 2011 Property acquisition: | | | | | | | | | | | | | | | |
| Proved | $ | 1,782 |
| | $ | 5 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,788 |
|
| Unproved | 3,271 |
| | — |
| | — |
| | — |
| | 7 |
| | 57 |
| | 1 |
| | 3,336 |
|
| Exploration | 782 |
| | 42 |
| | — |
| | 10 |
| | 109 |
| | 168 |
| | 23 |
| | 1,134 |
|
| Development | 889 |
| | 293 |
| | 18 |
| | (5 | ) | | 388 |
| | — |
| | 299 |
| | 1,882 |
|
| Total | $ | 6,724 |
| | $ | 340 |
| | $ | 19 |
| | $ | 5 |
| | $ | 504 |
| | $ | 225 |
| | $ | 323 |
| | $ | 8,140 |
|
| |
(a) | Includes costs incurred whether capitalized or expensed. |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities | | | (In millions) | (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Europe | | Other Int’l | | Total | (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Europe | | Other Int’l | | Total |
| 2013 | | Revenues and other income: | | | | | | | | | | | | | |
| | | Sales | $ | 5,059 |
| | $ | 1,376 |
| | $ | 33 |
| | $ | 1,106 |
| | $ | 924 |
| | $ | — |
| | $ | 8,498 |
|
| | | Transfers | 3 |
| | — |
| | 715 |
| | — |
| | 2,941 |
| | — |
| | 3,659 |
|
| | | Other income(a) | (9 | ) | | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (17 | ) |
| | | Total revenues and other income | 5,053 |
| | 1,376 |
| | 748 |
| | 1,106 |
| | 3,865 |
| | (8 | ) | | 12,140 |
|
| | | Expenses: | | | | | | | | | | | | | |
| | | Production costs | (1,318 | ) | | (867 | ) | | (113 | ) | | (73 | ) | | (498 | ) | | — |
| | (2,869 | ) |
| | | Exploration expenses | (717 | ) | | (8 | ) | | (3 | ) | | (65 | ) | | (123 | ) | | (72 | ) | | (988 | ) |
| | | Depreciation, depletion and amortization(b) | (1,980 | ) | | (218 | ) | | (97 | ) | | (28 | ) | | (440 | ) | | — |
| | (2,763 | ) |
| | | Administrative expenses | (185 | ) | | (21 | ) | | (30 | ) | | (19 | ) | | (36 | ) | | (14 | ) | | (305 | ) |
| | | Total expenses | (4,200 | ) | | (1,114 | ) | | (243 | ) | | (185 | ) | | (1,097 | ) | | (86 | ) | | (6,925 | ) |
| | | Results before income taxes | 853 |
| | 262 |
| | 505 |
| | 921 |
| | 2,768 |
| | (94 | ) | | 5,215 |
|
| | | Income tax (provision) benefit | (323 | ) | | (66 | ) | | (182 | ) | | (920 | ) | | (2,004 | ) | | 26 |
| | (3,469 | ) |
| | | Results of continuing operations | $ | 530 |
| | $ | 196 |
| | $ | 323 |
| | $ | 1 |
| | $ | 764 |
| | $ | (68 | ) | | $ | 1,746 |
|
| | | Results of discontinued operations | $ | — |
| | $ | — |
| | $ | — |
| | $ | 160 |
| | $ | — |
| | $ | — |
| | $ | 160 |
|
| 2012 | Revenues and other income: | | | | | | | | | | | | | | Revenues and other income: | | | | | | | | | | | | | |
| | | Sales | $ | 3,879 |
| | $ | 1,261 |
| | $ | 29 |
| | $ | 2,000 |
| | $ | 835 |
| | $ | — |
| | $ | 8,004 |
|
| | Sales | $ | 3,873 |
| | $ | 1,261 |
| | $ | 30 |
| | $ | 2,003 |
| | $ | 840 |
| | $ | — |
| | $ | 8,007 |
| Transfers | 2 |
| | — |
| | 818 |
| | — |
| | 3,601 |
| | — |
| | 4,421 |
|
| | Transfers | 2 |
| | — |
| | 818 |
| | — |
| | 3,609 |
| | — |
| | 4,429 |
| Other income(a) | (8 | ) | | — |
| | — |
| | — |
| | — |
| | (32 | ) | | (40 | ) |
| | Other income(a) | (4 | ) | | — |
| | — |
| | — |
| | — |
| | (32 | ) | | (36 | ) | Total revenues and other income | 3,873 |
| | 1,261 |
| | 847 |
| | 2,000 |
| | 4,436 |
| | (32 | ) | | 12,385 |
|
| | Total revenues and other income | 3,871 |
| | 1,261 |
| | 848 |
| | 2,003 |
| | 4,449 |
| | (32 | ) | | 12,400 |
| Expenses: | | | | | | | | | | | | | |
| | Expenses: | | | | | | | | | | | | | | Production costs | (1,054 | ) | | (826 | ) | | (141 | ) | | (58 | ) | | (398 | ) | | — |
| | (2,477 | ) |
| | Production costs | (1,204 | ) | | (922 | ) | | (141 | ) | | (76 | ) | | (376 | ) | | — |
| | (2,719 | ) | Exploration expenses | (558 | ) | | (30 | ) | | (5 | ) | | (10 | ) | | (34 | ) | | (69 | ) | | (706 | ) |
| | Exploration expenses | (564 | ) | | (31 | ) | | (3 | ) | | (16 | ) | | (42 | ) | | (73 | ) | | (729 | ) | Depreciation, depletion and amortization(b) | (1,792 | ) | | (217 | ) | | (95 | ) | | (43 | ) | | (615 | ) | | — |
| | (2,762 | ) |
| | Depreciation, depletion and amortization(b) | (1,793 | ) | | (217 | ) | | (95 | ) | | (40 | ) | | (614 | ) | | — |
| | (2,759 | ) | Administrative expenses | (193 | ) | | (8 | ) | | (5 | ) | | (4 | ) | | (40 | ) | | (12 | ) | | (262 | ) |
| | Administrative expenses | (73 | ) | | (10 | ) | | (3 | ) | | (4 | ) | | (17 | ) | | (19 | ) | | (126 | ) | Total expenses | (3,597 | ) | | (1,081 | ) | | (246 | ) | | (115 | ) | | (1,087 | ) | | (81 | ) | | (6,207 | ) |
| | Total expenses | (3,634 | ) | | (1,180 | ) | | (242 | ) | | (136 | ) | | (1,049 | ) | | (92 | ) | | (6,333 | ) | Results before income taxes | 276 |
| | 180 |
| | 601 |
| | 1,885 |
| | 3,349 |
| | (113 | ) | | 6,178 |
|
| | Results before income taxes | 237 |
| | 81 |
| | 606 |
| | 1,867 |
| | 3,400 |
| | (124 | ) | | 6,067 |
| Income tax (provision) benefit | (100 | ) | | (45 | ) | | (210 | ) | | (1,795 | ) | | (2,486 | ) | | 51 |
| | (4,585 | ) |
| | Income tax (provision) benefit | (86 | ) | | (20 | ) | | (211 | ) | | (1,788 | ) | | (2,537 | ) | | 55 |
| | (4,587 | ) | Results of continuing operations | $ | 176 |
| | $ | 135 |
| | $ | 391 |
| | $ | 90 |
| | $ | 863 |
| | $ | (62 | ) | | $ | 1,593 |
|
| | Results of operations | $ | 151 |
| | $ | 61 |
| | $ | 395 |
| | $ | 79 |
| | $ | 863 |
| | $ | (69 | ) | | $ | 1,480 |
| Results of discontinued operations | $ | — |
| | $ | — |
| | $ | — |
| | $ | (31 | ) | | $ | — |
| | $ | — |
| | $ | (31 | ) |
| 2011 | Revenues and other income: | | | | | | | | | | | | | | Revenues and other income: | | | | | | | | | | | | | |
| | Sales | $ | 3,063 |
| | $ | 1,332 |
| | $ | 29 |
| | $ | 216 |
| | $ | 1,010 |
| | $ | — |
| | $ | 5,650 |
| Sales | $ | 3,058 |
| | $ | 1,332 |
| | $ | 29 |
| | $ | 216 |
| | $ | 1,000 |
| | $ | — |
| | $ | 5,635 |
|
| | Transfers | 63 |
| | — |
| | 905 |
| | — |
| | 3,560 |
| | — |
| | 4,528 |
| Transfers | 63 |
| | — |
| | 905 |
| | — |
| | 3,546 |
| | — |
| | 4,514 |
|
| | Other income(a) | 41 |
| | — |
| | — |
| | — |
| | 15 |
| | — |
| | 56 |
| Other income(a) | 41 |
| | — |
| | — |
| | — |
| | 15 |
| | — |
| | 56 |
|
| | Total revenues and other income | 3,167 |
| | 1,332 |
| | 934 |
| | 216 |
| | 4,585 |
| | — |
| | 10,234 |
| Total revenues and other income | 3,162 |
| | 1,332 |
| | 934 |
| | 216 |
| | 4,561 |
| | — |
| | 10,205 |
|
| | Expenses: | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | |
| | Production costs(c) | (954 | ) | | (814 | ) |
| (117 | ) | | (33 | ) | | (350 | ) | | — |
| | (2,268 | ) | Production costs(c) | (961 | ) | | (818 | ) | | (118 | ) | | (24 | ) | | (376 | ) | | — |
| | (2,297 | ) |
| | Exploration expenses | (378 | ) | | (10 | ) | | (1 | ) | | (10 | ) | | (81 | ) | | (164 | ) | | (644 | ) | Exploration expenses | (377 | ) | | (11 | ) | | (1 | ) | | 1 |
| | (86 | ) | | (167 | ) | | (641 | ) |
| | Depreciation, depletion and amortization(b) | (1,471 | ) | | (196 | ) | | (104 | ) | | (11 | ) | | (685 | ) | | — |
| | (2,467 | ) | Depreciation, depletion and amortization(b) | (1,472 | ) | | (196 | ) | | (104 | ) | | (9 | ) | | (684 | ) | | — |
| | (2,465 | ) |
| | Administrative expenses | (67 | ) | | (10 | ) | | (2 | ) | | (1 | ) | | (19 | ) | | (15 | ) | | (114 | ) | Administrative expenses | (182 | ) | | (10 | ) | | — |
| | (1 | ) | | (18 | ) | | (10 | ) | | (221 | ) |
| | Total expenses | (2,870 | ) | | (1,030 | ) | | (224 | ) | | (55 | ) | | (1,135 | ) | | (179 | ) | | (5,493 | ) | Total expenses | (2,992 | ) | | (1,035 | ) | | (223 | ) | | (33 | ) | | (1,164 | ) | | (177 | ) | | (5,624 | ) |
| | Results before income taxes | 297 |
| | 302 |
| | 710 |
| | 161 |
| | 3,450 |
| | (179 | ) | | 4,741 |
| Results before income taxes | 170 |
| | 297 |
| | 711 |
| | 183 |
| | 3,397 |
| | (177 | ) | | 4,581 |
|
| | Income tax (provision) benefit | (104 | ) | | (76 | ) | | (254 | ) | | (168 | ) | | (2,203 | ) | | 63 |
| | (2,742 | ) | Income tax (provision) benefit | (59 | ) | | (75 | ) | | (254 | ) | | (176 | ) | | (2,176 | ) | | 65 |
| | (2,675 | ) |
| | Results of operations | $ | 193 |
| | $ | 226 |
| | $ | 456 |
| | $ | (7 | ) | | $ | 1,247 |
| | $ | (116 | ) | | $ | 1,999 |
| Results of continuing operations | $ | 111 |
| | $ | 222 |
| | $ | 457 |
| | $ | 7 |
| | $ | 1,221 |
| | $ | (112 | ) | | $ | 1,906 |
|
| 2010 | Revenues and other income: | | | | | | | | | | | | | | |
| | Sales | $ | 2,429 |
| | $ | 604 |
| | $ | 11 |
| | $ | 1,473 |
| | $ | 697 |
| | $ | — |
| | $ | 5,214 |
| Results of discontinued operations | $ | — |
| | $ | — |
| | $ | — |
| | $ | (11 | ) | | $ | — |
| | $ | — |
| | $ | (11 | ) |
| | Transfers | 93 |
| | — |
| | 701 |
| | — |
| | 2,319 |
| | — |
| | 3,113 |
| |
| | Other income(a) | 17 |
| | — |
| | — |
| | 812 |
| | (64 | ) | | — |
| | 765 |
| |
| | Total revenues and other income | 2,539 |
| | 604 |
| | 712 |
| | 2,285 |
| | 2,952 |
| | — |
| | 9,092 |
| |
| | Expenses: | | | | | | | | | | | | | | |
| | Production costs | (815 | ) | | (596 | ) | | (108 | ) | | (70 | ) | | (297 | ) | | — |
| | (1,886 | ) | |
| | Exploration expenses | (275 | ) | | (5 | ) | | (21 | ) | | (47 | ) | | (32 | ) | | (118 | ) | | (498 | ) | |
| | Depreciation, depletion and amortization(b) | (1,463 | ) | | (108 | ) | | (110 | ) | | (36 | ) | | (687 | ) | | — |
| | (2,404 | ) | |
| | Administrative expenses | (52 | ) | | (9 | ) | | (1 | ) | | 2 |
| | (20 | ) | | (10 | ) | | (90 | ) | |
| | Total expenses | (2,605 | ) | | (718 | ) | | (240 | ) | | (151 | ) | | (1,036 | ) | | (128 | ) | | (4,878 | ) | |
| | Results before income taxes | (66 | ) | | (114 | ) | | 472 |
| | 2,134 |
| | 1,916 |
| | (128 | ) | | 4,214 |
| |
| | Income tax (provision) benefit | 26 |
| | 28 |
| | (187 | ) | | (1,647 | ) | | (658 | ) | | 46 |
| | (2,392 | ) | |
| | Results of operations | $ | (40 | ) | | $ | (86 | ) | | $ | 285 |
| | $ | 487 |
| | $ | 1,258 |
| | $ | (82 | ) | | $ | 1,822 |
| |
| |
(a) | Includes net gain(loss)gain (loss) on dispositions. |
| |
(b) | Includes long-lived asset impairments. |
| |
(c) | 2011 Canada production costs include $64 million accrued for Oil Sands water abatement. |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
The following reconciles results of operations for oil and gas producing activities to segment income:
|
| | | | | | | | | | | |
| (In millions) | 2012 | | 2011 | | 2010 |
| Results of operations | $ | 1,480 |
| | $ | 1,999 |
| | $ | 1,822 |
|
| Items not included in results of oil and gas operations, net of tax: | | | | | |
| Marketing income and technology costs | 94 |
| | (10 | ) | | 55 |
|
| Income from equity method investments | 206 |
| | 213 |
| | 167 |
|
Other third-party income(a) | 6 |
| | 10 |
| | (5 | ) |
| Other | 8 |
| | (2 | ) | | (2 | ) |
| Items not allocated to segment income, net of tax: | | | | | |
| Loss (gain) on asset disposition | 32 |
| | (23 | ) | | (449 | ) |
| Long-lived asset impairments | 231 |
| | 178 |
| | 303 |
|
| Water abatement-Oil Sands | — |
| | 48 |
| | — |
|
| Segment income not included in results of oil and gas operations: | | | | | |
| Integrated Gas | 91 |
| | 178 |
| | 142 |
|
| Segment income | $ | 2,148 |
| | $ | 2,591 |
| | $ | 2,033 |
|
|
| | | | | | | | | | | |
| (In millions) | 2013 | | 2012 | | 2011 |
| Results of continuing operations | $ | 1,746 |
| | $ | 1,593 |
| | $ | 1,906 |
|
| Items not included in results of oil and gas operations, net of tax: | | | | | |
| Marketing income and other non-oil and gas producing related activities | 42 |
| | 49 |
| | 182 |
|
| Income from equity method investments | 340 |
| | 309 |
| | 351 |
|
| Items not allocated to segment income, net of tax: | | | | | |
| Loss (gain) on asset dispositions | 20 |
| | 31 |
| | (24 | ) |
| Long-lived asset impairments | 10 |
| | 231 |
| | 181 |
|
| Water abatement-Oil Sands Mining | — |
| | — |
| | 48 |
|
| Segment income | $ | 2,158 |
| | $ | 2,213 |
| | $ | 2,644 |
|
| |
(a)
| Includes revenues, net of associated costs and income taxes, from activities that support our production operations, which may include processing or transportation of third-party production and the purchase and subsequent resale of natural gas utilized for reservoir management. |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | | | | December 31, | December 31, |
| (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Europe | | Total | U.S. | | Canada | | E.G. | | Other Africa | | Europe | | Total |
| 2013 | | | | | | | | | | | | |
| Future cash inflows | | $ | 54,099 |
| | $ | 59,585 |
| | $ | 5,911 |
| | $ | 28,195 |
| | $ | 11,395 |
| | $ | 159,185 |
|
| Future production and administrative costs | | (16,774 | ) | | (35,954 | ) | | (1,619 | ) | | (976 | ) | | (2,986 | ) | | (58,309 | ) |
| Future development costs | | (9,685 | ) | | (9,694 | ) | | (367 | ) | | (793 | ) | | (2,178 | ) | | (22,717 | ) |
| Future income tax expenses | | (7,592 | ) | | (3,098 | ) | | (1,032 | ) | | (24,982 | ) | | (4,581 | ) | | (41,285 | ) |
| Future net cash flows | | $ | 20,048 |
| | $ | 10,839 |
| | $ | 2,893 |
| | $ | 1,444 |
| | $ | 1,650 |
| | $ | 36,874 |
|
| 10 percent annual discount for estimated timing of cash flows | | (9,940 | ) | | (8,300 | ) | | (1,084 | ) | | (828 | ) | | (252 | ) | | (20,404 | ) |
| Standardized measure of discounted future net cash flows - | | | | | | | | | | | | |
| related to continuing operations | | $ | 10,108 |
| | $ | 2,539 |
| | $ | 1,809 |
| | $ | 616 |
| | $ | 1,398 |
| | $ | 16,470 |
|
| related to discontinued operations | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,302 |
| | $ | — |
| | $ | 1,302 |
|
| 2012 | | | | | | | | | | | | | | | | | | | | | | |
| Future cash inflows | $ | 42,710 |
| | $ | 55,171 |
| | $ | 6,627 |
| | $ | 29,993 |
| | $ | 11,271 |
| | $ | 145,772 |
| $ | 42,710 |
| | $ | 55,171 |
| | $ | 6,627 |
| | $ | 28,173 |
| | $ | 11,271 |
| | $ | 143,952 |
|
| Future production and administrative costs | (13,765 | ) | | (32,131 | ) | | (1,829 | ) | | (1,315 | ) | | (2,302 | ) | | (51,342 | ) | (13,765 | ) | | (32,131 | ) | | (1,829 | ) | | (1,015 | ) | | (2,302 | ) | | (51,042 | ) |
| Future development costs | (11,104 | ) | | (9,350 | ) | | (451 | ) | | (1,119 | ) | | (1,673 | ) | | (23,697 | ) | (11,104 | ) | | (9,350 | ) | | (451 | ) | | (787 | ) | | (1,673 | ) | | (23,365 | ) |
| Future income tax expenses | (4,489 | ) | | (2,948 | ) | | (1,191 | ) | | (25,370 | ) | | (5,275 | ) | | (39,273 | ) | (4,489 | ) | | (2,948 | ) | | (1,191 | ) | | (25,020 | ) | | (5,274 | ) | | (38,922 | ) |
| Future net cash flows | $ | 13,352 |
| | $ | 10,742 |
| | $ | 3,156 |
| | $ | 2,189 |
| | $ | 2,021 |
| | $ | 31,460 |
| $ | 13,352 |
| | $ | 10,742 |
| | $ | 3,156 |
| | $ | 1,351 |
| | $ | 2,022 |
| | $ | 30,623 |
|
| 10 percent annual discount for estimated timing of cash flows | (6,956 | ) | | (7,842 | ) | | (1,178 | ) | | (939 | ) | | (326 | ) | | (17,241 | ) | (6,956 | ) | | (7,842 | ) | | (1,178 | ) | | (743 | ) | | (327 | ) | | (17,046 | ) |
| Standardized measure of discounted future net cash flows | | | | | | | | | | | | |
| relating to proved oil and gas reserves | $ | 6,396 |
| | $ | 2,900 |
| | $ | 1,978 |
| | $ | 1,250 |
| | $ | 1,695 |
| | $ | 14,219 |
| |
| Standardized measure of discounted future net cash flows - | | | | | | | | | | | | |
| related to continuing operations | | $ | 6,396 |
| | $ | 2,900 |
| | $ | 1,978 |
| | $ | 608 |
| | $ | 1,695 |
| | $ | 13,577 |
|
| related to discontinued operations | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 642 |
| | $ | — |
| | $ | 642 |
|
| 2011 | | | | | | | | | | | | | | | | | | | | | | |
| Future cash inflows | $ | 28,108 |
| | $ | 59,365 |
| | $ | 7,318 |
| | $ | 30,007 |
| | $ | 12,120 |
| | $ | 136,918 |
| $ | 28,108 |
| | $ | 59,365 |
| | $ | 7,318 |
| | $ | 28,197 |
| | $ | 12,120 |
| | $ | 135,108 |
|
| Future production and administrative costs | (10,751 | ) | | (28,048 | ) | | (1,931 | ) | | (1,269 | ) | | (2,752 | ) | | (44,751 | ) | (10,751 | ) | | (28,048 | ) | | (1,931 | ) | | (1,099 | ) | | (2,752 | ) | | (44,581 | ) |
| Future development costs | (6,341 | ) | | (10,346 | ) | | (435 | ) | | (874 | ) | | (1,702 | ) | | (19,698 | ) | (6,341 | ) | | (10,346 | ) | | (435 | ) | | (559 | ) | | (1,702 | ) | | (19,383 | ) |
| Future income tax expenses | (2,740 | ) | | (4,490 | ) | | (1,368 | ) | | (25,821 | ) | | (5,375 | ) | | (39,794 | ) | (2,740 | ) | | (4,490 | ) | | (1,368 | ) | | (25,463 | ) | | (5,375 | ) | | (39,436 | ) |
| Future net cash flows | $ | 8,276 |
| | $ | 16,481 |
| | $ | 3,584 |
| | $ | 2,043 |
| | $ | 2,291 |
| | $ | 32,675 |
| $ | 8,276 |
| | $ | 16,481 |
| | $ | 3,584 |
| | $ | 1,076 |
| | $ | 2,291 |
| | $ | 31,708 |
|
| 10 percent annual discount for estimated timing of cash flows | (4,539 | ) | | (11,845 | ) | | (1,331 | ) | | (733 | ) | | (446 | ) | | (18,894 | ) | (4,539 | ) | | (11,845 | ) | | (1,331 | ) | | (509 | ) | | (446 | ) | | (18,670 | ) |
| Standardized measure of discounted future net cash flows | | | | | | | | | | | | |
| relating to proved oil and gas reserves | $ | 3,737 |
| | $ | 4,636 |
| | $ | 2,253 |
| | $ | 1,310 |
| | $ | 1,845 |
| | $ | 13,781 |
| |
| 2010 | | | | | | | | | | | | |
| Future cash inflows | $ | 15,349 |
| | $ | 41,901 |
| | $ | 5,366 |
| | $ | 20,815 |
| | $ | 8,800 |
| | $ | 92,231 |
| |
| Future production and administrative costs | (6,878 | ) | | (21,675 | ) | | (1,469 | ) | | (996 | ) | | (2,275 | ) | | (33,293 | ) | |
| Future development costs | (2,084 | ) | | (9,688 | ) | | (441 | ) | | (907 | ) | | (1,535 | ) | | (14,655 | ) | |
| Future income tax expenses | (1,726 | ) | | (1,821 | ) | | (1,208 | ) | | (17,201 | ) | | (3,108 | ) | | (25,064 | ) | |
| Future net cash flows | $ | 4,661 |
| | $ | 8,717 |
| | $ | 2,248 |
| | $ | 1,711 |
| | $ | 1,882 |
| | $ | 19,219 |
| |
| 10 percent annual discount for estimated timing of cash flows | (2,008 | ) | | (6,168 | ) | | (795 | ) | | (825 | ) | | (234 | ) | | (10,030 | ) | |
| Standardized measure of discounted future net cash flows | | | | | | | | | | | | |
| relating to proved oil and gas reserves | $ | 2,653 |
| | $ | 2,549 |
| | $ | 1,453 |
| | $ | 886 |
| | $ | 1,648 |
| | $ | 9,189 |
| |
| Standardized measure of discounted future net cash flows - | | | | | | | | | | | | |
| related to continuing operations | | $ | 3,737 |
| | $ | 4,636 |
| | $ | 2,253 |
| | $ | 567 |
| | $ | 1,845 |
| | $ | 13,038 |
|
| related to discontinued operations | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 743 |
| | $ | — |
| | $ | 743 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Changes in the Standardized Measure of Discounted Future Net Cash Flows | | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Sales and transfers of oil and gas produced, net of production and administrative costs | $ | (9,632 | ) | | $ | (7,824 | ) | | $ | (6,316 | ) | $ | (8,997 | ) | | $ | (9,696 | ) | | $ | (7,637 | ) |
| Net changes in prices and production and administrative costs related to future production | (1,527 | ) | | 12,269 |
| | 9,839 |
| (243 | ) | | (1,445 | ) | | 11,786 |
|
| Extensions, discoveries and improved recovery, less related costs | 2,758 |
| | 1,451 |
| | 1,268 |
| 3,457 |
| | 2,763 |
| | 1,369 |
|
| Development costs incurred during the period | 3,550 |
| | 1,899 |
| | 2,546 |
| 3,708 |
| | 3,197 |
| | 1,600 |
|
| Changes in estimated future development costs | (329 | ) | | (1,349 | ) | | (2,153 | ) | 622 |
| | 25 |
| | (1,069 | ) |
Revisions of previous quantity estimates(a) | 1,475 |
| | 2,604 |
| | 1,357 |
| 3,123 |
| | 1,652 |
| | 2,453 |
|
| Net changes in purchases and sales of minerals in place | 908 |
| | 233 |
| | (20 | ) | (229 | ) | | 909 |
| | 230 |
|
| Accretion of discount | 3,172 |
| | 2,040 |
| | 1,335 |
| 3,054 |
| | 3,073 |
| | 1,989 |
|
| Net change in income taxes | 63 |
| | (6,731 | ) | | (4,322 | ) | (1,602 | ) | | 61 |
| | (6,607 | ) |
| Net change for the year | 438 |
| | 4,592 |
| | 3,534 |
| 2,893 |
| | 539 |
| | 4,114 |
|
| Beginning of the year | 13,781 |
| | 9,189 |
| | 5,655 |
| |
| End of year | $ | 14,219 |
| | $ | 13,781 |
| | $ | 9,189 |
| |
| Beginning of the year related to continuing operations | | 13,577 |
| | 13,038 |
| | 8,924 |
|
| End of the year related to continuing operations | | $ | 16,470 |
| | $ | 13,577 |
| | $ | 13,038 |
|
| Net change for the year related to discontinued operations | | $ | 660 |
| | $ | (101 | ) | | $ | 478 |
|
(a) Includes amounts resulting from changes in the timing of production and other.
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
| | | (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Segment Income (Loss) | | | | | | |
| Exploration and Production | | | | | | |
| United States | $ | 393 |
| | $ | 366 |
| | $ | 251 |
| |
| International | 1,488 |
| | 1,791 |
| | 1,690 |
| |
| E&P segment | 1,881 |
| | 2,157 |
| | 1,941 |
| |
| Segment Income | | | | | | |
| North America E&P | | $ | 529 |
| | $ | 382 |
| | $ | 392 |
|
| International E&P | | 1,423 |
| | 1,660 |
| | 1,991 |
|
| Oil Sands Mining | 176 |
| | 256 |
| | (50 | ) | 206 |
| | 171 |
| | 261 |
|
| Integrated Gas | 91 |
| | 178 |
| | 142 |
| |
| Segment income | 2,148 |
| | 2,591 |
| | 2,033 |
| 2,158 |
| | 2,213 |
| | 2,644 |
|
| Items not allocated to segments, net of income taxes | (566 | ) | | (884 | ) | | (151 | ) | (565 | ) | | (600 | ) | | (926 | ) |
| Income from continuing operations | 1,582 |
| | 1,707 |
| | 1,882 |
| 1,593 |
| | 1,613 |
| | 1,718 |
|
Discontinued operations(a) | — |
| | 1,239 |
| | 686 |
| 160 |
| | (31 | ) | | 1,228 |
|
| Net income | $ | 1,582 |
| | $ | 2,946 |
| | $ | 2,568 |
| $ | 1,753 |
| | $ | 1,582 |
| | $ | 2,946 |
|
Capital Expenditures(b) | | | | | | | | | | |
| Exploration and Production | | | | | | |
| United States | $ | 3,995 |
| | $ | 2,145 |
| | $ | 1,528 |
| |
| International | 840 |
| | 893 |
| | 946 |
| |
| E&P segment | 4,835 |
| | 3,038 |
| | 2,474 |
| |
| North America E&P | | $ | 3,649 |
| | $ | 3,988 |
| | $ | 2,163 |
|
| International E&P | | 764 |
| | 489 |
| | 544 |
|
| Oil Sands Mining | 188 |
| | 308 |
| | 874 |
| 286 |
| | 188 |
| | 308 |
|
| Integrated Gas | 2 |
| | 2 |
| | 2 |
| |
| Corporate | 106 |
| | 51 |
| | 46 |
| 58 |
| | 115 |
| | 75 |
|
Discontinued operations(a) | | 227 |
| | 351 |
| | 309 |
|
| Total | $ | 5,131 |
| | $ | 3,399 |
| | $ | 3,396 |
| $ | 4,984 |
| | $ | 5,131 |
| | $ | 3,399 |
|
| Exploration Expenses | | | | | | | | | | |
| United States | $ | 564 |
| | $ | 379 |
| | $ | 275 |
| |
| International | 165 |
| | 265 |
| | 223 |
| |
| North America E&P | | $ | 725 |
| | $ | 588 |
| | $ | 388 |
|
| International E&P | | 263 |
| | 118 |
| | 253 |
|
| Total | $ | 729 |
| | $ | 644 |
| | $ | 498 |
| $ | 988 |
| | $ | 706 |
| | $ | 641 |
|
| |
(a) | In 2013, we entered into agreements to sell our Angola assets; therefore, our Angola operations are reflected as discontinued operations in all periods presented. The spin-off of the downstream business was completed on June 30, 2011 and has been reported as discontinued operations in 2011 and 2010.2011. |
| |
(b) | Capital expenditures include changes in accruals. |
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | | |
| Net Sales Volumes | 2013 | | 2012 | | 2011 |
| North America E&P | | | | | |
Crude Oil and Condensate (mbbld) | | | | | |
| Bakken | 35 |
| | 27 |
| | 16 |
|
| Eagle Ford | 51 |
| | 23 |
| | 2 |
|
| Oklahoma resource basins | 2 |
| | 1 |
| | — |
|
| Other North America | 38 |
| | 45 |
| | 52 |
|
| Total Crude Oil and Condensate | 126 |
| | 96 |
| | 70 |
|
Natural Gas Liquids (mbbld) | | | | | |
| Bakken | 2 |
| | 1 |
| | — |
|
| Eagle Ford | 14 |
| | 5 |
| | — |
|
| Oklahoma resource basins | 4 |
| | 2 |
| | 1 |
|
| Other North America | 3 |
| | 3 |
| | 4 |
|
| Total Natural Gas Liquids | 23 |
| | 11 |
| | 5 |
|
Total Liquid Hydrocarbons (mbbld) | | | | | |
| Bakken | 37 |
| | 28 |
| | 16 |
|
| Eagle Ford | 65 |
| | 28 |
| | 2 |
|
| Oklahoma resource basins | 6 |
| | 3 |
| | 1 |
|
| Other North America | 41 |
| | 48 |
| | 56 |
|
| Total Liquid Hydrocarbons | 149 |
| | 107 |
| | 75 |
|
Natural Gas (mmcfd) | | | | | |
| Bakken | 13 |
| | 8 |
| | 6 |
|
| Eagle Ford | 94 |
| | 37 |
| | 2 |
|
| Oklahoma resource basins | 48 |
| | 32 |
| | 7 |
|
| Alaska | 7 |
| | 92 |
| | 94 |
|
| Other North America | 150 |
| | 189 |
| | 217 |
|
| Total Natural Gas | 312 |
| | 358 |
| | 326 |
|
Total North America E&P (mboed) | 201 |
| | 166 |
| | 129 |
|
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | | |
| | 2012 | | 2011 | | 2010 |
| E&P Operating Statistics - Net Sales Volumes | | | | | |
Crude Oil and Condensate (mbbld) | | | | | |
| United States | 96 |
| | 70 |
|
| 66 |
|
| Europe | 96 |
| | 100 |
| | 90 |
|
| Africa | 67 |
| | 32 |
| | 72 |
|
| Total International | 163 |
| | 132 |
| | 162 |
|
| Worldwide | 259 |
| | 202 |
| | 228 |
|
Natural Gas Liquids (mbbld) | | | | | |
| United States | 11 |
| | 5 |
| | 4 |
|
| Europe | 1 |
| | 1 |
| | 2 |
|
| Africa | 11 |
| | 11 |
| | 11 |
|
| Total International | 12 |
| | 12 |
| | 13 |
|
| Worldwide | 23 |
| | 17 |
| | 17 |
|
Total Liquid Hydrocarbon (mbbld) | | | | | |
| United States | 107 |
| | 75 |
| | 70 |
|
| Europe | 97 |
| | 101 |
| | 92 |
|
| Africa | 78 |
| | 43 |
| | 83 |
|
| Total International | 175 |
| | 144 |
| | 175 |
|
| Worldwide | 282 |
| | 219 |
| | 245 |
|
Natural Gas (mmcfd) | | | | | |
| United States | 358 |
| | 326 |
| | 364 |
|
Europe(c) | 101 |
| | 97 |
| | 105 |
|
| Africa | 443 |
| | 443 |
| | 409 |
|
| Total International | 544 |
| | 540 |
| | 514 |
|
| Worldwide | 902 |
| | 866 |
| | 878 |
|
| | | | | | |
Total Worldwide (mboed) | 432 |
| | 363 |
| | 391 |
|
|
| | | | | | | | |
| Net Sales Volumes | 2013 | | 2012 | | 2011 |
| International E&P | | | | | |
Total Liquid Hydrocarbons (mbbld) | | | | | |
| Equatorial Guinea | 34 |
| | 36 |
| | 38 |
|
| Norway | 71 |
| | 81 |
| | 80 |
|
| United Kingdom | 15 |
| | 16 |
| | 21 |
|
| Libya | 24 |
| | 42 |
| | 5 |
|
| Total Liquid Hydrocarbons | 144 |
| | 175 |
| | 144 |
|
Natural Gas (mmcfd) | | | | | |
| Equatorial Guinea | 442 |
| | 428 |
| | 443 |
|
| Norway | 51 |
| | 53 |
| | 42 |
|
United Kingdom(c) | 32 |
| | 48 |
| | 55 |
|
| Libya | 22 |
| | 15 |
| | — |
|
| Total Natural Gas | 547 |
| | 544 |
| | 540 |
|
Total International E&P (mboed) | 234 |
| | 266 |
| | 234 |
|
| Oil Sands Mining | | | | | |
Synthetic Crude Oil (mbbld)(d) | 48 |
| | 47 |
| | 43 |
|
Total Continuing Operations (mboed) | 483 |
| | 479 |
| | 406 |
|
Discontinued Operations (mboed)(e) | 10 |
| | — |
| | — |
|
Total Company (mboed) | 493 |
| | 479 |
| | 406 |
|
| Net Sales Volumes of Equity Method Investees | | | | | |
LNG (mtd) | 6,548 |
| | 6,290 |
| | 6,681 |
|
Methanol (mtd) | 1,249 |
| | 1,298 |
| | 1,282 |
|
(c) Includes natural gas acquired for injection and subsequent resale of 157 mmcfd, 1615 mmcfd and 1816 mmcfd for the years 2013, 2012, and 2011.
2012, 2011(d) Includes blendstocks.
(e) In 2013, we entered into agreements to sell our Angola assets; therefore, our Angola operations are reflected as discontinued operations and excluded from segments in all periods presented.2010.
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | |
| | 2012 | | 2011 | | 2010 |
E&P Operating Statistics - Average Realizations (d) | | | | | |
Crude Oil and Condensate (per bbl) | | | | | |
| United States | $91.29 | | $94.80 | | $73.66 |
| Europe | $115.59 | | $115.88 | | $82.31 |
| Africa | $114.52 | | $98.80 | | $82.16 |
| Total International | $115.15 | | $111.78 | | $82.25 |
| Worldwide | $106.35 | | $105.84 | | $79.76 |
Natural Gas Liquids (per bbl) | | | | | |
| United States | $39.57 | | $58.53 | | $50.71 |
| Europe | $78.81 | | $78.76 | | $62.62 |
| Africa | $1.00 | | $1.00 | | $1.00 |
| Total International | $8.32 | | $6.77 | | $9.37 |
| Worldwide | $23.44 | | $21.21 | | $19.75 |
Total Liquid Hydrocarbon (per bbl) | | | | | |
United States(e) | $85.80 | | $92.55 | | $72.30 |
| Europe | $115.16 | | $115.55 | | $81.95 |
| Africa | $98.52 | | $73.21 | | $71.71 |
| Total International | $107.78 | | $102.96 | | $77.11 |
| Worldwide | $99.46 | | $99.37 | | $75.73 |
Natural Gas (per mcf) | | | | | |
| United States | $3.91 | | $4.95 | | $4.71 |
| Europe | $10.47 | | $9.84 | | $7.10 |
Africa(f) | $0.43 | | $0.24 | | $0.25 |
| Total International | $2.29 | | $1.97 | | $1.65 |
| Worldwide | $2.94 | | $3.09 | | $2.91 |
|
| | | | | | | | | | | |
Average Price Realizations (f) | 2013 | | 2012 | | 2011 |
| North America E&P | | | | | |
Crude Oil and Condensate (per bbl) | | | | | |
| Bakken |
| $90.25 |
| |
| $83.11 |
| |
| $90.60 |
|
| Eagle Ford | 99.69 |
| | 100.14 |
| | 101.46 |
|
| Oklahoma resource basins | 94.84 |
| | 89.26 |
| | — |
|
| Other North America | 90.42 |
| | 91.75 |
| | 95.91 |
|
| Total Crude Oil and Condensate | 94.19 |
| | 91.30 |
| | 94.80 |
|
Natural Gas Liquids (per bbl) | | | | | |
| Bakken |
| $41.60 |
| |
| $42.35 |
| | — |
|
| Eagle Ford | 30.16 |
| | 32.96 |
| | — |
|
| Oklahoma resource basins | 35.28 |
| | 31.82 |
| | $ | 36.95 |
|
| Other North America | 55.69 |
| | 52.51 |
| | 62.24 |
|
| Total Natural Gas Liquids | 35.12 |
| | 39.57 |
| | 58.53 |
|
Total Liquid Hydrocarbons (per bbl) (g) | | | | | |
| Bakken |
| $87.76 |
| |
| $81.36 |
| |
| $90.29 |
|
| Eagle Ford | 84.95 |
| | 88.09 |
| | 95.84 |
|
| Oklahoma resource basins | 50.77 |
| | 49.21 |
| | 36.95 |
|
| Other North America | 88.16 |
| | 89.03 |
| | 93.70 |
|
| Total Liquid Hydrocarbons | 85.20 |
| | 85.80 |
| | 92.55 |
|
Natural Gas (per mcf) | | | | | |
| Bakken |
| $3.90 |
| |
| $3.11 |
| |
| $6.92 |
|
| Eagle Ford | 3.67 |
| | 3.03 |
| | 4.12 |
|
| Oklahoma resource basins | 3.78 |
| | 3.05 |
| | 3.45 |
|
| Alaska | 7.79 |
| | 6.86 |
| | 6.53 |
|
| Other North America | 3.76 |
| | 2.84 |
| | 4.26 |
|
| Total Natural Gas | 3.84 |
| | 3.92 |
| | 4.95 |
|
(d)(f) Excludes gains or losses on derivative instruments.
(e)(g) Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon price realizations per barrel by $0.39 per bbl$(0.27) and $0.40 for the year 2012.2013 and 2012.
(f) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC’s income in our E&P segment and we include our share of AMPCO’s and EGHoldings’ income in our IG segment.
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | | |
| | 2012 | | 2011 | | 2010 |
| OSM Operating Statistics | | | | | |
Net Synthetic Crude Oil Sales (mbbld)(g) | 47 |
| | 43 |
| | 29 |
|
Synthetic Crude Oil Average Realizations (per bbl)(d) | $81.72 | | $91.65 | | $71.06 |
| IG Operating Statistics | | | | | |
Net Sales (mtd) | | | | | |
LNG(h) | 6,290 |
| | 7,086 |
| | 6,859 |
|
| Methanol | 1,298 |
| | 1,282 |
| | 1,049 |
|
Total Proved Reserves (at year end) | | | | | |
Liquid Hydrocarbon (mmbbl) | | | | | |
| United States | 475 |
| | 279 |
| | 173 |
|
| International | 426 |
| | 454 |
| | 457 |
|
| Worldwide | 901 |
| | 733 |
| | 630 |
|
Natural Gas (bcf) | | | | | |
| United States | 1,043 |
| | 872 |
| | 745 |
|
| International | 1,736 |
| | 1,794 |
| | 1,872 |
|
| Worldwide | 2,779 |
| | 2,666 |
| | 2,617 |
|
Synthetic Crude Oil (mmbbl) | | | | | |
| Canada | 653 |
| | 623 |
| | 572 |
|
Total Proved Reserves (mmboe) | 2,017 |
| | 1,800 |
| | 1,638 |
|
(g) Includes blendstocks. |
| | | | | | | | | | | |
| Average Price Realizations | 2013 | | 2012 | | 2011 |
| International E&P | | | | | |
Total Liquid Hydrocarbons (per bbl) | | | | | |
| Equatorial Guinea |
| $60.34 |
| |
| $64.33 |
| |
| $67.70 |
|
| Norway | 113.38 |
| | 116.70 |
| | 116.62 |
|
| United Kingdom | 108.92 |
| | 107.31 |
| | 111.55 |
|
| Libya | 122.92 |
| | 127.31 |
| | 112.56 |
|
| Total Liquid Hydrocarbons | 102.10 |
| | 107.78 |
| | 102.96 |
|
Natural Gas (per mcf) | | | | | |
Equatorial Guinea(h) |
| $0.24 |
| |
| $0.24 |
| |
| $0.24 |
|
| Norway | 13.01 |
| | 11.15 |
| | 10.60 |
|
| United Kingdom | 10.64 |
| | 9.72 |
| | 9.26 |
|
| Libya | 5.44 |
| | 5.76 |
| | 0.70 |
|
| Total Natural Gas | 2.25 |
| | 2.29 |
| | 1.97 |
|
| Oil Sands Mining | | | | | |
Synthetic Crude Oil (per bbl) |
| $87.51 |
| |
| $81.72 |
| |
| $91.65 |
|
Discontinued Operations (per bbl)(e) |
| $104.77 |
| | — |
| | — |
|
| Total Proved Reserves (at year end) | | | | | |
Liquid Hydrocarbons (mmbbl) | | | | | |
| North America E&P | 616 |
| | 475 |
| | 279 |
|
| International E&P | 402 |
| | 408 |
| | 436 |
|
| Total Continuing Operations | 1,018 |
| | 883 |
| | 715 |
|
Natural Gas (bcf) | | | | | |
| North America E&P | 1,025 |
| | 1,043 |
| | 872 |
|
| International E&P | 1,646 |
| | 1,736 |
| | 1,794 |
|
| Total Continuing Operations | 2,671 |
| | 2,779 |
| | 2,666 |
|
Synthetic Crude Oil (mmbbl) | | | | | |
| Oil Sands Mining | 680 |
| | 653 |
| | 623 |
|
Continuing Operations (mmboe) | 2,143 |
| | 1,999 |
| | 1,782 |
|
Discontinued Operations (mmboe)(e) | 28 |
| | 18 |
| | 18 |
|
Total Proved Reserves (mmboe) | 2,171 |
| | 2,017 |
| | 1,800 |
|
(h) Includes both consolidated sales volumesPrimarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, which are equity method investees. We include our share of the sales volumesincome from each of these equity method investees in 2011 and 2010. LNG sales from Alaska, conducted through a consolidated subsidiary, ceased when these operations were sold in the third quarter of 2011. LNG and methanol sales from E.G. are conducted through equity method investees.our International E&P segment.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13(a)-15(e)13a-15(e) and 15(d)-15(e)15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2012.2013.
Internal Control Over Financial Reporting
In 2012,the first quarter of 2013, we began a project tocompleted the update of our existing ERPEnterprise Resource Planning ("ERP") system. The project includes implementation ofThis update included a new general ledger, consolidations system and reporting tools. This project is currently in testing phases and we expect full implementation in the first half of 2013. We believe that controls over project development and implementation are adequate to assure there will be no material effect, or a reasonable likelihood of a material effect, on our internal control over financial reporting.
During the fourth quarter of 2012,2013, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting. See Item 8. Financial Statements and Supplementary Data — Management’s Report on Internal Control over Financial Reporting and – Report of Independent Registered Public Accounting Firm.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information concerning our directors required by this item is incorporated by reference to the material appearing under the heading "Election of Directors" in our Proxy Statement for the 20132014 Annual Meeting of Stockholders.
Our Board of Directors has established the Audit and Finance Committee and determined our "Audit Committee Financial Expert." The related information required by this item is incorporated by reference to the material appearing under the sub-heading "Audit and Finance Committee" located under the heading "The Board of Directors and Governance Matters" in our Proxy Statement for the 20132014 Annual Meeting of Stockholders.
We have adopted a Code of Ethics for Senior Financial Officers. It is available on our website at http://marathonoil.com/Code_Ethics_Sr_Finan_Off.www.marathonoil.com/Investor_Center/Corporate_Governance/Code_of_Ethics_for_Senior_Financial_Officers/.
Executive Officers of the Registrant
See Item 1. Business – Executive Officers of the Registrant for the names, ages and titles of our executive officers.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires that our directors and executive officers, and persons who own more than ten percent of a registered class of our equity securities, file reports of beneficial ownership on Form 3 and changes in beneficial ownership on Form 4 or Form 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us from the individuals required to file reports, we believe that each of our directors and executive officers has complied with the applicable reporting requirements for transactions in Marathon Oil securities during the fiscal year ended December 31, 2012.2013.
Item 11. Executive Compensation
Information required by this item is incorporated by reference to the material appearing under the heading "Executive Compensation Tables and Other Information," under the sub-headings "Compensation Committee" and "Compensation Committee Interlocks and Insider Participation," under the heading "The Board of Directors and Governance Matters" and under the heading "Compensation Committee Report" in our Proxy Statement for the 20132014 Annual Meeting of Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information concerning security ownership of certain beneficial owners and management required by this item is incorporated by reference to the material appearing under the headings "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Directors and Executive Officers" in our Proxy Statement for the 20132014 Annual Meeting of Stockholders.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 20122013 with respect to shares of Marathon Oil common stock that may be issued under our existing equity compensation plans:
Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan")
Marathon Oil Corporation 2007 Incentive Compensation Plan (the "2007 Plan") – No additional awards will be granted under this plan.
Marathon Oil Corporation 2003 Incentive Compensation Plan (the "2003 Plan") – No additional awards will be granted under this plan.
Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.
| | | Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted- average exercise price of outstanding options, warrants and rights(c) | | Number of securities remaining available for future issuance under equity compensation plans | | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted- average exercise price of outstanding options, warrants and rights(c) | | Number of securities remaining available for future issuance under equity compensation plans | |
| Equity compensation plans approved by stockholders | 20,452,668 |
| (a) | $26.19 | | 48,601,445 |
| (d) | 19,244,830 |
| (a) | $27.27 | | 45,950,524 |
| (d) |
| Equity compensation plans not approved by stockholders | 20,984 |
| (b) | N/A | | — |
| | 20,984 |
| (b) | N/A | | — |
| |
| Total | 20,473,652 |
| | N/A | | 48,601,445 |
| | 19,265,814 |
| | N/A | | 45,950,524 |
| |
| |
(a) | Includes the following: |
393,4232,273,594 stock options outstanding under the 2012 Plan;
15,827,24813,203,379 stock options outstanding under the 2007 Plan;
2,883,8332,465,332 stock options outstanding under the 2003 Plan and the net number of stock-settled SARs that could be issued from this Plan. The number of stock-settled SARs is based on the closing price of Marathon Oil common stock on December 31, 20122013 of $30.66$35.30 per share;
317,872324,672 common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the 2012 Plan, 2007 Plan and 2003 Plan; common stock units credited under the 2012 Plan, 2007 Plan and 2003 Plan were 44,19551,196, 222,416222,215 and 51,261, respectively;
1,030,292977,853 restricted stock units granted to non-officers under the 2012 Plan and 2007 Plan and outstanding as of December 31, 2012.2013.
In addition to the awards reported above 764,3482,014,310 and 2,388,1601,094,122 shares of restricted stock were issued and outstanding as of December 31, 2012,2013, but subject to forfeiture restrictions under the 2012 Plan and 2007 Plan, respectively.
| |
(b) | Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon Oil common stock in place of the common stock units. |
| |
(c) | Weighted-averageThe weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price. |
| |
(d) | Reflects the shares available for issuance under the 2012 Plan. No more than 19,739,08518,810,490 of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, canceled or expire unexercised shall again immediately become available for issuance. |
The Deferred Compensation Plan for Non-Employee Directors is our only equity compensation plan that has not been approved by our stockholders. Our authority to make equity grants under this plan was terminated effective April 30, 2003. Under the Deferred Compensation Plan for Non-Employee Directors, all non-employee directors were required to defer half of their annual retainers in the form of common stock units. On the date the retainer would have otherwise been payable to the non-employee director, we credited an unfunded bookkeeping account for each non-employee director with a number of common stock units equal to half of his or her annual retainer divided by the fair market value of our common stock on that date. The ongoing value of each common stock unit equals the market price of a share of our common stock. When the non-employee director leaves the Board, he or she is issued actual shares of our common stock equal to the number of common stock units in his or her account at that time.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item is incorporated by reference to the material appearing under the heading "Certain Relationships and Related Person Transactions," and under the sub-heading "Board and Committee Independence" under the heading "The Board of Directors and Governance Matters" in our Proxy Statement for the 20132014 Annual Meeting of Stockholders.
Item 14. Principal Accounting Fees and Services
Information required by this item is incorporated by reference to the material appearing under the heading "Information Regarding the Independent Registered Public Accounting Firm’s Fees, Services and Independence" in our Proxy Statement for the 20132014 Annual Meeting of Stockholders.
PART IV
Item 15. Exhibits, Financial Statement Schedules
A. Documents Filed as Part of the Report
1. Financial Statements (see Part II, Item 8. of this Report regarding financial statements)
2. Financial Statement Schedules
Financial statement schedules required under SEC rules but not included in this Report are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.
3. Exhibits:
References to Marathon Ashland Petroleum LLC or MAP are references to the entity now known as Marathon Petroleum Corporation.
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 2 | | Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession |
| 2.1++ | | Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation | 8-K | | 2.1 | | 5/26/2011 | | 001-05153 | | | | |
| 2.2++ | | Purchase and Sale Agreement between Hilcorp Resources Holding, LP and Marathon Oil Company dated as of May 31, 2011 | 10-Q/A | | 2.2 | | 10/18/2011 | | 001-05153 | | | | |
| 3 | | Articles of Incorporation and Bylaws |
| 3.1 | | Restated Certificate of Incorporation of Marathon Oil Corporation | 8-K | | 3.1 | | 4/25/2007 | | 001-05153 | | | | |
| 3.2 | | Amended By-Laws of Marathon Oil Corporation | 10-Q | | 3.1 | | 11/7/2012 | | 001-05153 | | | | |
| 3.3 | | Specimen of Common Stock Certificate | 8-K | | 3.3 | | 5/14/2007 | | 001-05153 | | | | |
| 4 | | Instruments Defining the Rights of Security Holders, Including Indentures |
| 4.1 | | Credit Agreement, dated as of April 5, 2012, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein. | 8-K | | 4.1 | | 4/10/2012 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 2 | | Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession |
| 2.1++ | | Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation | 8-K | | 2.1 | | 5/26/2011 | | 001-05153 | | | | |
| 3 | | Articles of Incorporation and Bylaws |
| 3.1 | | Restated Certificate of Incorporation of Marathon Oil Corporation | 10-Q | | 3.1 | | 8/8/2013 | | 001-05153 | | | | |
| 3.2 | | Amended By-Laws of Marathon Oil Corporation effective February 25, 2014 | | | | | | | | | X | | |
| 3.3 | | Specimen of Common Stock Certificate | | | | | | | | | X | | |
| 4 | | Instruments Defining the Rights of Security Holders, Including Indentures |
| 4.1 | | Credit Agreement, dated as of April 5, 2012, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein. | 8-K | | 4.1 | | 4/10/2012 | | 001-05153 | | | | |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 4.2 | | Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request. | S-3 | | 4.4 | | 7/26/2007 | | 333-144874 | | | | |
| 10 | | Material Contracts | | | | | | | | | | | |
| 10.1 | | Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC | 8-K | | 10.1 | | 5/26/2011 | | 001-05153 | | | | |
| 10.2 | | Employee Matters Agreement dated as of May 25, 2011 among Marathon Oil Corporation and Marathon Petroleum Corporation | 8-K | | 10.2 | | 5/26/2011 | | 001-05153 | | | | |
| 10.3 | | Amendment to Employee Matters Agreement dated as of June 30, 2011 between Marathon Oil Corporation and Marathon Petroleum Corporation | 10-Q | | 10.3 | | 8/8/2011 | | 001-05153 | | | | |
| 10.4 | | Marathon Oil Corporation 2012 Incentive Compensation Plan | DEF 14A | | App. III | | 3/8/2012 | | 001-05153 | | | | |
| 10.5 | | Form of Nonqualified Stock Option Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.6 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.7 | | Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting) | | | | | | | | | X | | |
| 10.8 | | Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting) | | | | | | | | | X | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 4.2 | | Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request. | | | | | | | | | X | | |
| 10 | | Material Contracts | | | | | | | | | | | |
| 10.1 | | Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC | 8-K | | 10.1 | | 5/26/2011 | | 001-05153 | | | | |
| 10.2 | | Employee Matters Agreement dated as of May 25, 2011 among Marathon Oil Corporation and Marathon Petroleum Corporation | 8-K | | 10.2 | | 5/26/2011 | | 001-05153 | | | | |
| 10.3 | | Amendment to Employee Matters Agreement dated as of June 30, 2011 between Marathon Oil Corporation and Marathon Petroleum Corporation | 10-Q | | 10.3 | | 8/8/2011 | | 001-05153 | | | | |
| 10.4 | | Marathon Oil Corporation 2012 Incentive Compensation Plan | DEF 14A | | App. III | | 3/8/2012 | | 001-05153 | | | | |
| 10.5 | | Form of Initial CEO Option Grant Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan. | 10-Q | | 10.1 | | 11/6/2013 | | 001-05153 | | | | |
| 10.6 | | Form of CEO Restricted Stock Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year prorata vesting). | 10-Q | | 10.2 | | 11/6/2013 | | 001-05153 | | | | |
| 10.7 | | Form of CEO Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year cliff vesting). | 10-Q | | 10.3 | | 11/6/2013 | | 001-05153 | | | | |
| 10.8 | | Marathon Oil Corporation Bonus Agreement Upon Commencement of Employment for Lee M. Tillman. | 10-Q | | 10.4 | | 11/6/2013 | | 001-05153 | | | | |
| 10.9 | | Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan | 10-Q | | 10.1 | | 5/10/2013 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.9 | | Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.10 | | Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.11 | | Form of Nonqualified Stock Option Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.12 | | Form of Nonqualified Stock Option Award Agreement for non-officers in Canada granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.13 | | Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.14 | | Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | | | | | | | | | X | | |
| 10.15 | | Marathon Oil Corporation 2007 Incentive Compensation Plan | 10-K | | 10.5 | | 2/29/2012 | | 001-05153 | | | | |
| 10.16 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan, effective May 30, 2007 | 10-K | | 10.6 | | 2/29/2012 | | 001-05153 | | | | |
| 10.17 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010 | 10-K | | 10.5 | | 2/28/2011 | | 001-05153 | | | | |
| 10.18 | | Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 | 10-K | | 10.8 | | 2/29/2012 | | 001-05153 | | | | |
| 10.19 | | Form of Officer Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010 | 10-K | | 10.7 | | 2/28/2011 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.10 | | Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan | 10-Q | | 10.2 | | 5/10/2013 | | 001-05153 | | | | |
| 10.11 | | Form of Nonqualified Stock Option Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.5 | | 2/22/2013 | | 001-05153 | | | | |
| 10.12 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.6 | | 2/22/2013 | | 001-05153 | | | | |
| 10.13 | | Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting) | 10-K | | 10.7 | | 2/22/2013 | | 001-05153 | | | | |
| 10.14 | | Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting) | 10-K | | 10.8 | | 2/22/2013 | | 001-05153 | | | | |
| 10.15 | | Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.9 | | 2/22/2013 | | 001-05153 | | | | |
| 10.16 | | Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.10 | | 2/22/2013 | | 001-05153 | | | | |
| 10.17 | | Form of Nonqualified Stock Option Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.11 | | 2/22/2013 | | 001-05153 | | | | |
| 10.18 | | Form of Nonqualified Stock Option Award Agreement for non-officers in Canada granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.12 | | 2/22/2013 | | 001-05153 | | | | |
| 10.19 | | Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.13 | | 2/22/2013 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.20 | | Form of Performance Unit Award Agreement (18 month Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.10 | | 2/29/2012 | | 001-05153 | | | | |
| 10.21 | | Form of Performance Unit Award Agreement (18 month Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.11 | | 2/29/2012 | | 001-05153 | | | | |
| 10.22 | | Form of Performance Unit Award Agreement (30 month Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.12 | | 2/29/2012 | | 001-05153 | | | | |
| 10.23 | | Form of Performance Unit Award Agreement (30 month Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.13 | | 2/29/2012 | | 001-05153 | | | | |
| 10.24 | | Form of Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan. | 10-K | | 10.27 | | 2/26/2010 | | 001-05153 | | | | |
| 10.25 | | Form of Performance Unit Award Agreement (2010-2012 Performance Cycle) granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan | 10-K | | 10.25 | | 2/26/2010 | | 001-05153 | | | | |
| 10.26 | | Form of Nonqualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan | 10-K | | 10.26 | | 2/26/2010 | | 001-05153 | | | | |
| 10.27 | | Marathon Oil Corporation 2003 Incentive Compensation Plan, Effective January 1, 2003 | 10-K | | 10.9 | | 2/26/2010 | | 001-05153 | | | | |
| 10.28 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.15 | | 2/26/2010 | | 001-05153 | | | | |
| 10.29 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.16 | | 2/26/2010 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.20 | | Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.14 | | 2/22/2013 | | 001-05153 | | | | |
| 10.21 | | Marathon Oil Corporation 2007 Incentive Compensation Plan | 10-K | | 10.5 | | 2/29/2012 | | 001-05153 | | | | |
| 10.22 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan, effective May 30, 2007 | 10-K | | 10.6 | | 2/29/2012 | | 001-05153 | | | | |
| 10.23 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010 | 10-K | | 10.5 | | 2/28/2011 | | 001-05153 | | | | |
| 10.24 | | Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 | 10-K | | 10.8 | | 2/29/2012 | | 001-05153 | | | | |
| 10.25 | | Form of Officer Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010 | 10-K | | 10.7 | | 2/28/2011 | | 001-05153 | | | | |
| 10.26 | | Form of Performance Unit Award Agreement (30 month Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.12 | | 2/29/2012 | | 001-05153 | | | | |
| 10.27 | | Form of Performance Unit Award Agreement (30 month Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.13 | | 2/29/2012 | | 001-05153 | | | | |
| 10.28 | | Form of Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan. | 10-K | | 10.27 | | 2/26/2010 | | 001-05153 | | | | |
| 10.29 | | Form of Nonqualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan | 10-K | | 10.26 | | 2/26/2010 | | 001-05153 | | | | |
| 10.30 | | Marathon Oil Corporation 2003 Incentive Compensation Plan, Effective January 1, 2003 | 10-K | | 10.9 | | 2/26/2010 | | 001-05153 | | | | |
| 10.31 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.15 | | 2/26/2010 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.30 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.17 | | 2/26/2010 | | 001-05153 | | | | |
| 10.31 | | Form of Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.19 | | 2/26/2010 | | 001-05153 | | | | |
| 10.32 | | Form of Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.20 | | 2/26/2010 | | 001-05153 | | | | |
| 10.33 | | Form of Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.21 | | 2/26/2010 | | 001-05153 | | | | |
| 10.34 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan | 10-K | | 10.22 | | 2/26/2010 | | 001-05153 | | | | |
| 10.35 | | Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan | 10-K | | 10.23 | | 2/26/2010 | | 001-05153 | | | | |
| 10.36 | | Form of Performance Unit Award Agreement (2005-2007 Performance Cycle) granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan | 10-K | | 10.24 | | 2/26/2010 | | 001-05153 | | | | |
| 10.37 | | Form of Nonqualified Stock Option Award Agreement for MAP officers granted under Marathon Oil Corporation's 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.18 | | 2/26/2010 | | 001-05153 | | | | |
| 10.38 | | Marathon Oil Corporation 1990 Stock Plan (as Amended and Restated), Effective January 1, 2002 | 10-Q | | 10.1 | | 11/7/2008 | | 001-05153 | | | | |
| 10.39 | | First Amendment to Marathon Oil Corporation 1990 Stock Plan (as Amended and Restated), Effective February 1, 2007 | 10-Q | | 10.2 | | 11/7/2008 | | 001-05153 | | | | |
| 10.40 | | Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2009) | 10-K | | 10.14 | | 2/27/2009 | | 001-05153 | | | | |
| 10.41 | | Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011 | 10-K | | 10.32 | | 2/29/2012 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.32 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.16 | | 2/26/2010 | | 001-05153 | | | | |
| 10.33 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.17 | | 2/26/2010 | | 001-05153 | | | | |
| 10.34 | | Form of Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.19 | | 2/26/2010 | | 001-05153 | | | | |
| 10.35 | | Form of Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.20 | | 2/26/2010 | | 001-05153 | | | | |
| 10.36 | | Form of Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.21 | | 2/26/2010 | | 001-05153 | | | | |
| 10.37 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan | 10-K | | 10.22 | | 2/26/2010 | | 001-05153 | | | | |
| 10.38 | | Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan | 10-K | | 10.23 | | 2/26/2010 | | 001-05153 | | | | |
| 10.39 | | Form of Nonqualified Stock Option Award Agreement for MAP officers granted under Marathon Oil Corporation's 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.18 | | 2/26/2010 | | 001-05153 | | | | |
| 10.40 | | Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2009) | 10-K | | 10.14 | | 2/27/2009 | | 001-05153 | | | | |
| 10.41 | | Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011 | 10-K | | 10.32 | | 2/29/2012 | | 001-05153 | | | | |
| 10.42 | | Marathon Oil Company Excess Benefit Plan Amended and Restated | 10-K | | 10.31 | | 2/29/2012 | | 001-05153 | | | | |
| 10.43 | | Marathon Oil Executive Change in Control Severance Benefits Plan, effective as of December 31, 2008 | 10-K | | 10.35 | | 2/27/2009 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.42 | | Marathon Oil Company Excess Benefit Plan Amended and Restated | 10-K | | 10.31 | | 2/29/2012 | | 001-05153 | | | | |
| 10.43 | | Marathon Oil Executive Change in Control Severance Benefits Plan, effective as of December 31, 2008 | 10-K | | 10.35 | | 2/27/2009 | | 001-05153 | | | | |
| 10.44 | | Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts | 10-K | | 10.10 | | 2/28/2011 | | 001-05153 | | | | |
| 10.45 | | Marathon Oil Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009 | 10-K | | 10.32 | | 2/27/2009 | | 001-05153 | | | | |
| 10.46 | | Severance Letter Agreement from Mr. David E. Roberts, Jr. dated December 14, 2012 | 8-K | | 99.1 | | 12/7/2012 | | 001-05153 | | | | |
| 12.1 | | Computation of Ratio of Earnings to Fixed Charges | | | | | | | | | X | | |
| 14.1 | | Code of Ethics for Senior Financial Officers | 10-K | | 14.1 | | 2/26/2010 | | 001-05153 | | | | |
| 21.1 | | List of Significant Subsidiaries | | | | | | | | | X | | |
| 23.1 | | Consent of Independent Registered Public Accounting Firm | | | | | | | | | X | | |
| 23.2 | | Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 23.3 | | Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 23.4 | | Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 31.1 | | Certification of Chairman, President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | | | | | X | | |
| 31.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | | | | | X | | |
| 32.1 | | Certification of Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350 | | | | | | | | | X | | |
| 32.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 | | | | | | | | | X | | |
| 99.1 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2012 | | | | | | | | | X | | |
| 99.2 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2011 | 10-K | | 99.1 | | 2/29/2012 | | 001-05153 | | | | |
| 99.3 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2010 | 10-K | | 99.1 | | 2/28/2011 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.44 | | First Amendment to the Marathon Oil Corporation Executive Change in Control Severance Benefits Plan, effective October 26, 2011. | 10-Q | | 10.3 | | 5/4/2012 | | 001-05153 | | | | |
| 10.45 | | Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011). | 10-Q | | 10.4 | | 5/4/2012 | | 001-05153 | | | | |
| 10.46 | | Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts | 10-K | | 10.10 | | 2/28/2011 | | 001-05153 | | | | |
| 10.47 | | Marathon Oil Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009 | 10-K | | 10.32 | | 2/27/2009 | | 001-05153 | | | | |
| 10.48 | | Form of Performance Unit Award Agreement (2012-2014 Performance Cycle) granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan. | 10-Q | | 10.2 | | 5/4/2012 | | 001-05153 | | | | |
| 12.1 | | Computation of Ratio of Earnings to Fixed Charges | | | | | | | | | X | | |
| 14.1 | | Code of Ethics for Senior Financial Officers | 10-K | | 14.1 | | 2/26/2010 | | 001-05153 | | | | |
| 21.1 | | List of Significant Subsidiaries | | | | | | | | | X | | |
| 23.1 | | Consent of Independent Registered Public Accounting Firm | | | | | | | | | X | | |
| 23.2 | | Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 23.3 | | Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 23.4 | | Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 31.1 | | Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | | | | | X | | |
| 31.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | | | | | X | | |
| 32.1 | | Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350 | | | | | | | | | X | | |
| 32.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 | | | | | | | | | X | | |
| 99.1 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2013 | | | | | | | | | X | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 99.4 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2012 | | | | | | | | | X | | |
| 99.5 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2011 | 10-K | | 99.4 | | 2/29/2012 | | 001-05153 | | | | |
| 99.6 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2012 | | | | | | | | | X | | |
| 99.7 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2011 | 10-K | | 99.5 | | 2/29/2012 | | 001-05153 | | | | |
| 101.INS | | XBRL Instance Document | | | | | | | | | X | | |
| 101.SCH | | XBRL Taxonomy Extension Schema | | | | | | | | | X | | |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase | | | | | | | | | X | | |
| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase | | | | | | | | | X | | |
| 101.LAB | | XBRL Taxonomy Extension Label Linkbase | | | | | | | | | X | | |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase | | | | | | | | | X | | |
| ++ | | Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request. |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 99.2 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2012 | 10-K | | 99.1 | | 2/22/2013 | | 001-05153 | | | | |
| 99.3 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2011 | 10-K | | 99.1 | | 2/29/2012 | | 001-05153 | | | | |
| 99.4 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2013 | | | | | | | | | X | | |
| 99.5 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2012 | 10-K | | 99.4 | | 2/22/2013 | | 001-05153 | | | | |
| 99.6 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2011 | 10-K | | 99.4 | | 2/29/2012 | | 001-05153 | | | | |
| 99.7 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2013 | | | | | | | | | X | | |
| 99.8 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2012 | 10-K | | 99.6 | | 2/22/2013 | | 001-05153 | | | | |
| 99.9 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2011 | 10-K | | 99.5 | | 2/29/2012 | | 001-05153 | | | | |
| 101.INS | | XBRL Instance Document | | | | | | | | | X | | |
| 101.SCH | | XBRL Taxonomy Extension Schema | �� | | | | | | | | X | | |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase | | | | | | | | | X | | |
| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase | | | | | | | | | X | | |
| 101.LAB | | XBRL Taxonomy Extension Label Linkbase | | | | | | | | | X | | |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase | | | | | | | | | X | | |
| ++ | | Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | |
February 22, 201328, 2014 | | MARATHON OIL CORPORATION |
| | | |
| | | By: /s/ MICHAEL K. STEWARTJohn R. Sult |
| | | Michael K. StewartExecutive Vice President and Chief Financial Officer |
| | | Vice President, Finance and Accounting, Controller and Treasurer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 22, 201328, 2014 on behalf of the registrant and in the capacities indicated.
|
| | |
| Signature | | Title |
| | | |
/S/ CLARENCE P. CAZALOT, JR.LEE M. TILLMAN | | Chairman, President and Chief Executive Officer and Director |
Clarence P. Cazalot, Jr.Lee M. Tillman | | |
| | | |
/S/ JANET F. CLARKJOHN R. SULT | | Executive Vice President and Chief Financial Officer |
Janet F. ClarkJohn R. Sult | | |
| | | |
/S/ MICHAEL K. STEWARTDENNIS H. REILLEY | | Vice President, Finance and Accounting, Controller and TreasurerChairman of the Board |
Michael K. StewartDennis H. Reilley | | |
| | | |
/S/ GREGORY H. BOYCE | | Director |
| Gregory H. Boyce | | |
| | | |
/S/ PIERRE BRONDEAU | | Director |
| Pierre Brondeau | | |
| | | |
/S/ LINDA Z. COOK | | Director |
| Linda Z. Cook | | |
| | | |
/S/ CHADWICK C. DEATON | | Director |
| Chadwick C. Deaton | | |
| | |
/S/ SHIRLEY ANN JACKSON | | Director |
| Shirley Ann Jackson | | |
| | | |
/S/ PHILIP LADER | | Director |
| Philip Lader | | |
| | | |
/S/ MICHAEL E. J. PHELPS | | Director |
| Michael E. J. Phelps | | |
| | | |
/S/ DENNIS H. REILLEY
| | Director |
Dennis H. Reilley | | |
| | |
Exhibit Index
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 2 | | Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession |
| 2.1++ | | Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation | 8-K | | 2.1 | | 5/26/2011 | | 001-05153 | | | | |
| 3 | | Articles of Incorporation and Bylaws |
| 3.1 | | Restated Certificate of Incorporation of Marathon Oil Corporation | 10-Q | | 3.1 | | 8/8/2013 | | 001-05153 | | | | |
| 3.2 | | Amended By-Laws of Marathon Oil Corporation effective February 25, 2014 | | | | | | | | | X | | |
| 3.3 | | Specimen of Common Stock Certificate | | | | | | | | | X | | |
| 4 | | Instruments Defining the Rights of Security Holders, Including Indentures |
| 4.1 | | Credit Agreement, dated as of April 5, 2012, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein. | 8-K | | 4.1 | | 4/10/2012 | | 001-05153 | | | | |
| 4.2 | | Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request. | | | | | | | | | X | | |
| 10 | | Material Contracts | | | | | | | | | | | |
| 10.1 | | Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC | 8-K | | 10.1 | | 5/26/2011 | | 001-05153 | | | | |
| 10.2 | | Employee Matters Agreement dated as of May 25, 2011 among Marathon Oil Corporation and Marathon Petroleum Corporation | 8-K | | 10.2 | | 5/26/2011 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.3 | | Amendment to Employee Matters Agreement dated as of June 30, 2011 between Marathon Oil Corporation and Marathon Petroleum Corporation | 10-Q | | 10.3 | | 8/8/2011 | | 001-05153 | | | | |
| 10.4 | | Marathon Oil Corporation 2012 Incentive Compensation Plan | DEF 14A | | App. III | | 3/8/2012 | | 001-05153 | | | | |
| 10.5 | | Form of Initial CEO Option Grant Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan. | 10-Q | | 10.1 | | 11/6/2013 | | 001-05153 | | | | |
| 10.6 | | Form of CEO Restricted Stock Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year prorata vesting). | 10-Q | | 10.2 | | 11/6/2013 | | 001-05153 | | | | |
| 10.7 | | Form of CEO Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year cliff vesting). | 10-Q | | 10.3 | | 11/6/2013 | | 001-05153 | | | | |
| 10.8 | | Marathon Oil Corporation Bonus Agreement Upon Commencement of Employment for Lee M. Tillman. | 10-Q | | 10.4 | | 11/6/2013 | | 001-05153 | | | | |
| 10.9 | | Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan | 10-Q | | 10.1 | | 5/10/2013 | | 001-05153 | | | | |
| 10.10 | | Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan | 10-Q | | 10.2 | | 5/10/2013 | | 001-05153 | | | | |
| 10.11 | | Form of Nonqualified Stock Option Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.5 | | 2/22/2013 | | 001-05153 | | | | |
| 10.12 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.6 | | 2/22/2013 | | 001-05153 | | | | |
| 10.13 | | Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting) | 10-K | | 10.7 | | 2/22/2013 | | 001-05153 | | | | |
| 10.14 | | Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting) | 10-K | | 10.8 | | 2/22/2013 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.15 | | Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.9 | | 2/22/2013 | | 001-05153 | | | | |
| 10.16 | | Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.10 | | 2/22/2013 | | 001-05153 | | | | |
| 10.17 | | Form of Nonqualified Stock Option Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.11 | | 2/22/2013 | | 001-05153 | | | | |
| 10.18 | | Form of Nonqualified Stock Option Award Agreement for non-officers in Canada granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.12 | | 2/22/2013 | | 001-05153 | | | | |
| 10.19 | | Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.13 | | 2/22/2013 | | 001-05153 | | | | |
| 10.20 | | Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting) | 10-K | | 10.14 | | 2/22/2013 | | 001-05153 | | | | |
| 10.21 | | Marathon Oil Corporation 2007 Incentive Compensation Plan | 10-K | | 10.5 | | 2/29/2012 | | 001-05153 | | | | |
| 10.22 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan, effective May 30, 2007 | 10-K | | 10.6 | | 2/29/2012 | | 001-05153 | | | | |
| 10.23 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010 | 10-K | | 10.5 | | 2/28/2011 | | 001-05153 | | | | |
| 10.24 | | Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 | 10-K | | 10.8 | | 2/29/2012 | | 001-05153 | | | | |
| 10.25 | | Form of Officer Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010 | 10-K | | 10.7 | | 2/28/2011 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.26 | | Form of Performance Unit Award Agreement (30 month Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.12 | | 2/29/2012 | | 001-05153 | | | | |
| 10.27 | | Form of Performance Unit Award Agreement (30 month Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011 | 10-K | | 10.13 | | 2/29/2012 | | 001-05153 | | | | |
| 10.28 | | Form of Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan. | 10-K | | 10.27 | | 2/26/2010 | | 001-05153 | | | | |
| 10.29 | | Form of Nonqualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan | 10-K | | 10.26 | | 2/26/2010 | | 001-05153 | | | | |
| 10.30 | | Marathon Oil Corporation 2003 Incentive Compensation Plan, Effective January 1, 2003 | 10-K | | 10.9 | | 2/26/2010 | | 001-05153 | | | | |
| 10.31 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.15 | | 2/26/2010 | | 001-05153 | | | | |
| 10.32 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.16 | | 2/26/2010 | | 001-05153 | | | | |
| 10.33 | | Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.17 | | 2/26/2010 | | 001-05153 | | | | |
| 10.34 | | Form of Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.19 | | 2/26/2010 | | 001-05153 | | | | |
| 10.35 | | Form of Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.20 | | 2/26/2010 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 10.36 | | Form of Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.21 | | 2/26/2010 | | 001-05153 | | | | |
| 10.37 | | Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan | 10-K | | 10.22 | | 2/26/2010 | | 001-05153 | | | | |
| 10.38 | | Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan | 10-K | | 10.23 | | 2/26/2010 | | 001-05153 | | | | |
| 10.39 | | Form of Nonqualified Stock Option Award Agreement for MAP officers granted under Marathon Oil Corporation's 2003 Incentive Compensation Plan, effective January 1, 2003 | 10-K | | 10.18 | | 2/26/2010 | | 001-05153 | | | | |
| 10.40 | | Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2009) | 10-K | | 10.14 | | 2/27/2009 | | 001-05153 | | | | |
| 10.41 | | Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011 | 10-K | | 10.32 | | 2/29/2012 | | 001-05153 | | | | |
| 10.42 | | Marathon Oil Company Excess Benefit Plan Amended and Restated | 10-K | | 10.31 | | 2/29/2012 | | 001-05153 | | | | |
| 10.43 | | Marathon Oil Executive Change in Control Severance Benefits Plan, effective as of December 31, 2008 | 10-K | | 10.35 | | 2/27/2009 | | 001-05153 | | | | |
| 10.44 | | First Amendment to the Marathon Oil Corporation Executive Change in Control Severance Benefits Plan, effective October 26, 2011. | 10-Q | | 10.3 | | 5/4/2012 | | 001-05153 | | | | |
| 10.45 | | Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011). | 10-Q | | 10.4 | | 5/4/2012 | | 001-05153 | | | | |
| 10.46 | | Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts | 10-K | | 10.10 | | 2/28/2011 | | 001-05153 | | | | |
| 10.47 | | Marathon Oil Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009 | 10-K | | 10.32 | | 2/27/2009 | | 001-05153 | | | | |
| 10.48 | | Form of Performance Unit Award Agreement (2012-2014 Performance Cycle) granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan. | 10-Q | | 10.2 | | 5/4/2012 | | 001-05153 | | | | |
| 12.1 | | Computation of Ratio of Earnings to Fixed Charges | | | | | | | | | X | | |
| 14.1 | | Code of Ethics for Senior Financial Officers | 10-K | | 14.1 | | 2/26/2010 | | 001-05153 | | | | |
| 21.1 | | List of Significant Subsidiaries | | | | | | | | | X | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 23.1 | | Consent of Independent Registered Public Accounting Firm | | | | | | | | | X | | |
| 23.2 | | Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 23.3 | | Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 23.4 | | Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists | | | | | | | | | X | | |
| 31.1 | | Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | | | | | X | | |
| 31.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | | | | | X | | |
| 32.1 | | Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350 | | | | | | | | | X | | |
| 32.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 | | | | | | | | | X | | |
| 99.1 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2013 | | | | | | | | | X | | |
| 99.2 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2012 | 10-K | | 99.1 | | 2/22/2013 | | 001-05153 | | | | |
| 99.3 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2011 | 10-K | | 99.1 | | 2/29/2012 | | 001-05153 | | | | |
| 99.4 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2013 | | | | | | | | | X | | |
| 99.5 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2012 | 10-K | | 99.4 | | 2/22/2013 | | 001-05153 | | | | |
| 99.6 | | Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2011 | 10-K | | 99.4 | | 2/29/2012 | | 001-05153 | | | | |
| 99.7 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2013 | | | | | | | | | X | | |
| 99.8 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2012 | 10-K | | 99.6 | | 2/22/2013 | | 001-05153 | | | | |
|
| | | | | | | | | | | | | |
Exhibit Number | | | Incorporated by Reference | | Filed Herewith | | Furnished Herewith |
| Exhibit Description | Form | | Exhibit | | Filing Date | | SEC File No. | |
| 99.9 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2011 | 10-K | | 99.5 | | 2/29/2012 | | 001-05153 | | | | |
| 101.INS | | XBRL Instance Document | | | | | | | | | X | | |
| 101.SCH | | XBRL Taxonomy Extension Schema | | | | | | | | | X | | |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase | | | | | | | | | X | | |
| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase | | | | | | | | | X | | |
| 101.LAB | | XBRL Taxonomy Extension Label Linkbase | | | | | | | | | X | | |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase | | | | | | | | | X | | |
| ++ | | Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request. |
