MRO-2013.12.31-10K


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, 2013
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 R No £
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  R
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 R 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 R 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.  R
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  R    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   R
The aggregate market value of Common Stock held by non-affiliates as of June 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 696,944,638 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 2014.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 2014 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") operations, spun-off on June 30, 2011 and now treated as discontinued operations.
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, a liquefied natural gas production company located in E.G. in which we own a 60 percent equity interest.
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.
FASB – Financial Accounting Standards Board.
FPSO – Floating production, storage and offloading vessel.
IFRS – International Financial Reporting Standards.
Internal 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 International 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.
LNG – Liquefied natural gas.
LPG – Liquefied petroleum gas.

1


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.
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 liquid hydrocarbon, natural gas and synthetic crude oil reserves are those quantities of 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 for 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.

2


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 liquid hydrocarbons, natural gas and synthetic 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 sometimes 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 About 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 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.

3


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 with operations in the U.S., Angola, Canada, E.G., Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq, Libya, Norway 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 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:
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 key unconventional liquids-rich plays in 2013: the Eagle Ford, Bakken and 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 main horizons. Our exploration program includes prospects in E.G., Ethiopia, Gabon, the Gulf of Mexico, Kenya and the Kurdistan Region of Iraq.
We ended 2013 with proved reserves of approximately 2.2 bboe, an 8 percent increase over 2012. Proved reserve replacement was 194 percent, excluding dispositions.
During 2013, our cash additions to property, plant and equipment were $5.0 billion, including those related to discontinued operations, and we made acquisitions of $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, for discussion of our $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 sale of our interest in Angola Block 32, the possible sale of our U.K. and Norway assets and projected spending and expected investment in exploration and development activities under the 2014 capital, investment and exploration budget. Some factors that could potentially affect the 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 conditions, operating results and economic and/or regulatory factors affecting our businesses. The timing of closing

4


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, successful negotiations, board approval and execution of definitive agreements. The projected spending under the 2014 capital, investment and 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.
In the discussion that follows regarding our North America E&P, 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. and Canada.
Unconventional Resource Plays
Eagle Ford - As of December 31, 2013, we had approximately 211,000 net acres in the Eagle Ford in south Texas and 655 gross (493 net) operated producing wells in the Eagle Ford, Austin 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 the 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 evaluated the potential of downspacing to 40-acre and 60-acre spacing with several pilot 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 exploration budget is dedicated to the Eagle Ford. Our accelerated drilling plans include drilling 250 - 260 net wells (385 - 405 gross, of which we will operate 340 - 355) in 2014, an increase of almost 20 percent over 2013.

5


Eagle Ford average net sales for 2013 were 81 mboed, composed of 51 mbbld of crude oil and condensate, 14 mbbld of NGLs and 94 mmcfd of natural gas, compared to 34 mboed in 2012, a 136 percent increase. Our 2013 exit rate was over 98 mboed, a 50 percent increase over December 2012. In 2013, we were able to transport approximately 70 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 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 evaluate 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 production growth across the Eagle Ford operating area.
Approximately 193 miles of gathering lines were installed in 2013 for a total of over 700 miles of operated gathering pipeline in the area. We now have 24 central gathering and treating facilities, with aggregate capacity of over 275 mboed. We also own and operate the Sugarloaf gathering system, a 37-mile natural gas pipeline through the heart of our acreage in Karnes, Atascosa, and Bee Counties of south Texas.
Bakken – We hold approximately 370,000 net acres in the Bakken shale oil play in North Dakota and eastern 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 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 have identified additional improvements to the 30-stage hydraulic fracturing designs put in place in 2012, which are expected to further increase both production rates and estimated ultimate recovery from our Bakken shale wells beyond the increases that were attained in 2012 and 2013. We reached TD on 76 gross operated wells and brought to sales 77 gross operated wells in 2013.  Our Bakken shale program includes plans to drill 80 - 90 net wells (200 - 220 gross, of which we will operate 75 - 85) in 2014. In addition, we plan to recomplete 22 - 26 gross wells to the stage design optimized in 2013.
Our net sales from the Bakken shale averaged 39 mboed in 2013, composed of 35 mbbld of crude oil and condensate, 2 mbbld of NGLs and 13 mmcfd of natural gas, a 34 percent increase over 29 mboed in 2012. Our production exit rate for 2013 was approximately 38 mboed. We sell our Bakken production primarily into local North Dakota markets via truck or pipeline in efforts to optimize price realizations and such production could be transported to other areas of the U.S. by the purchaser.
Oklahoma resource basins – We hold 209,000 net acres in unconventional Oklahoma resource basins, namely the Anadarko Woodford shale (including the SCOOP), the Southern Mississippi Trend, and the Granite Wash, of which approximately 147,000 net acres are held by production. We continued to add incremental acres to our SCOOP position in 2013. In the Anadarko Woodford shale, we reached TD on 10 gross operated wells and brought nine gross operated wells to sales in 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 operated wells 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 were 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. Our accelerated drilling plans for the Oklahoma resource 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 completed.
See below for discussion of our conventional, primarily natural gas, production operations in Oklahoma.
Other United States
Gulf of MexicoProduction – On December 31, 2013, we held significant interests in 11 producing fields, 4 of which are company-operated. Average net sales for 2013 from the Gulf of Mexico were 17 mbbld of liquid hydrocarbons and 14 mmcfd of natural gas. Operational availability for our operated properties was strong at 97 percent, with internal unplanned losses of three percent.
We 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 Blocks 873, 917 and 963. The facility also processes third-party production via subsea tie-backs.

6


We have a 100 percent operated working interest in the Droshky development located on Green Canyon Block 244 and a 68 percent operated working interest in Ozona which is located on Garden Banks Block 515. The Ozona development ceased production in the first quarter of 2013 and is scheduled for abandonment in 2014.
We have 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. A well side track project was successfully completed in 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 side track project is planned for 2014.
We have an 18 percent working interest in the non-operated Gunflint field development located on Mississippi Canyon Blocks 948, 949, 992(N/2) and 993(N/2). The discovery well was drilled in 2008 and encountered pay in the Middle Miocene reservoirs. Two subsequent appraisal wells were drilled and evaluated in 2012 and 2013. First oil from this subsea tie-back development project is expected in 2016.
Gulf of Mexico – Exploration – We have a portfolio of over 17 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.
We have a 60 percent operated working interest in the Key Largo prospect located on Walker Ridge Block 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 the third quarter of 2014.
Prior to commencing drilling in September 2013, we reduced our working interest in the 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 on the Madagascar prospect did not encounter commercial hydrocarbons and the well costs and related unproved property were charged to exploration expense in 2013.
A deepwater oil discovery on the Shenandoah prospect, located on Walker Ridge Block 52, was drilled in 2009. We own a 10 percent non-operated working interest in this prospect. The first appraisal well on 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 Colorado 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 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

7


and operate the 420-mile Red Butte Pipeline. This crude oil pipeline connects Silvertip Station on the Montana/Wyoming state line to 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 70 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 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 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 February 2013, we conveyed our interests 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 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 spending budget, planned use of carbon dioxide flood programs, the abandonment of the Powder River Basin in Wyoming, 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 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, 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 projected spending under the 2014 capital, investment and exploration spending budget is a 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 GuineaProduction – We own a 63 percent operated working interest under a PSC in the Alba field which is offshore E.G. During 2013, E.G. net liquid hydrocarbon sales averaged 34 mbbld and net natural gas sales averaged 442 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.

8


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 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 GuineaExploration – 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 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 GuineaGas Processing – We 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 2013, the gross quantity of natural gas supplied to the LPG production facility was 866 mmcfd, from which 6 mbbld of secondary condensate and 21 mbbld of LPG were produced by Alba Plant LLC.
We also own 60 percent of EGHoldings and 45 percent of AMPCO, both of which are accounted for as equity method investments. EGHoldings operates an LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These facilities allow us to monetize natural gas reserves from the Alba field.
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 less 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 internal unplanned losses were 10 percent. Production from the plant is used to supply customers in Europe and the 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. Beginning 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 when production operations were suspended until the fourth quarter of that year. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya.
Angola – During 2013, we entered into agreements to sell our Angola assets. See discussion of the transactions in the Acquisitions and Dispositions section below.
Gabon – We hold a 21.25 percent non-operated working interest in the Diaba License G4-223 and its related permit offshore Gabon, which covers 2.2 million gross (476,000 net) acres. The Diaman-1B well reached total depth in the third quarter of 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, consisting of 3.9 million gross (1.9 million net) acres in northwest 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 spud in February 2014 on the eastern side of Block 9, where previous wells drilled in the 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.

9


Ethiopia – We hold a 20 percent non-operated interest in the onshore South Omo Block in Ethiopia. The concession has an area of approximately 5.4 million gross (1.1 million net) acres. The Sabisa-1 exploration well encountered 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 the 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 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.
NorwayProduction – At the end of 2013, we operated 9 licenses and held interests in 6 non-operated licenses, which encompass approximately 286,000 net acres offshore on the Norwegian continental shelf. In 2013, net sales from Norway averaged 71 mbbld of liquid hydrocarbons and 51 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. At the end of 2013, the Alvheim development included 12 producing, 3 temporarily shut-in and 2 water disposal wells. One infill well is planned for 2014 along with several well workovers.
The Vilje field (PL 036D), in which we own a 47 percent operated working interest, began producing through the Alvheim complex in August 2008. Vilje has two subsea templates and two production wells, and is tied back through a 12-mile pipeline to the Alvheim FPSO. A third production well, Vilje Sor, will be developed as a subsea tieback to the Vilje field. Production start-up is expected in the first half of 2014.
The Volund field (PL 150 and PL 150B), located five miles south of the Alvheim complex consists of four production wells and one water injection well at December 31, 2013. We own a 65 percent operated working interest in Volund.
The Viper oil discovery, in the immediate vicinity of the Volund Field, was announced in November 2009. Along with our partners, we are evaluating a possible tie-back to the Alvheim 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, is located approximately 17 miles south of 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. Further development drilling is planned in the Boyla field in 2014, with first production expected in early 2015. Near Boyla, the Caterpillar discovery (PL 340BS) made in 2011 continues to be evaluated as a tie-back to the Alvheim complex through Boyla.
The Darwin (formerly Veslemoy) exploration well was drilled in the first quarter of 2013 on PL 531, in which we hold a 10 percent non-operated fully-carried working interest, 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 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. 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, in 2013 we withdrew from three licenses (PL505, PL505BS and PL570).
United Kingdom – Net sales from the U.K. averaged 15 mbbld of liquid hydrocarbons and 32 mmcfd of natural gas in 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 platforms, respectively. The East Brae platform also hosts the nearby Braemar field in which we have a 28 percent working interest. Two development wells are in the West Brae program, with the first to be spud in 2014. Operational availability was 92 percent and internal unplanned losses were eight percent.

10


The strategic location of the Brae platforms, along with pipeline and onshore infrastructure, has generated third-party processing and transportation business since 1986. Currently, the operators of 30 third-party fields are contracted to use the Brae system and 62 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 area 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.
We own working interests 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.
Poland – After an extensive evaluation of our exploration activities in Poland and unsuccessful attempts to find commercial levels of hydrocarbons, we have elected to conclude operations in the country. During 2013, we relinquished 7 of our 11 operated concessions to the government and are in the process of relinquishing the remainder.
Other International
Kurdistan Region of Iraq – In aggregate, we have access to approximately 145,000 net acres in the Kurdistan Region of Iraq. We have interests in two non-operated blocks located north-northwest of Erbil: Atrush with 15 percent working interest and Sarsang with 25 percent working interest. We also have a 45 percent operated working interest in the Harir block located 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 and constructing 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 field 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 existing wells, confirmed the extension of the oil bearing reservoirs and has been suspended as a potential future producer. Testing has commenced on the Atrush-4 development well, spud in October 2013, with anticipated 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. On 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 test 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 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 Jisik-1 prospect, located nine miles to the northwest of the Mirawa-1 discovery, will test a similar structure. Drilling on the Jisik-1 prospect commenced in December 2013 and is expected to reach total depth in the second quarter of 2014. The Mirawa-2 appraisal well is expected to spud in the third quarter of 2014, subject to government approval of the Mirawa appraisal plan.
Acquisitions and Dispositions
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 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 of 2013, we transfered our 45 percent working interest and operatorship in the Safen Block in the Kurdistan Region of Iraq at a pretax loss of $17 million.
In January 2013, government approval was received for our acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia.
The above discussions include forward-looking statements with respect to anticipated future exploratory and development drilling activity in the Kurdistan Region of Iraq, Ethiopia, Kenya, Norway, the U.K., and E.G., the anticipated start-up date of the

11


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 first production from the Boyla field, the timing of first production from the Atrush development, a potential Phase 2 development in the Atrush block, other potential development projects and the sale of our interest in Angola Block 32. Some factors which could possibly affect these forward-looking statements include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, 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 award 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 and execution of 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.

12


Productive and Drilling Wells
For our North America E&P 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 and 2011 and drilling wells as of December 31, 2013.
 
Productive Wells(a)
 
 
 
 
 
 
 
 
 
Oil
 
Natural Gas
 
Service Wells  
 
Drilling Wells
  
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

 
 
 
 
E.G.

 

 
14

 
9

 
4

 
3

 
 
 
 
Other Africa
1,050

 
171

 
6

 
1

 
101

 
16

 
 
 
 
Total Africa
1,050

 
171

 
20

 
10

 
105

 
19

 
 
 
 
Total Europe
77

 
34

 
40

 
16

 
28

 
11

 
 
 
 
Worldwide
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

 
 
 
 
E.G.

 

 
14

 
9

 
4

 
3

 
 
 
 
Other Africa(b)

 

 

 

 
1

 

 
 
 
 
Total Africa

 

 
14

 
9

 
5

 
3

 
 
 
 
Total Europe
73

 
31

 
40

 
16

 
28

 
10

 
 
 
 
Worldwide
5,882

 
2,089

 
3,175

 
1,901

 
2,346

 
747

 
 
 
 
(a) 
Of the gross productive wells, wells with multiple completions operated by us totaled 204, 188 and 168 as of December 31, 2013, 2012 and 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.


13


Drilling Activity
For our North America E&P 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
  
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

Total Africa
4

 

 

 
4

 
1

 

 

 
1

 
5

Total Europe
3

 

 

 
3

 

 

 

 

 
3

Worldwide
179

 
21

 
2

 
202

 
118

 
13

 
9

 
140

 
342

2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
46

 
17

 
3

 
66

 
37

 
4

 
1

 
42

 
108

Total Africa(a)
2

 

 

 
2

 

 

 

 

 
2

Total Europe
2

 

 

 
2

 

 

 

 

 
2

Total Other International

 

 

 

 

 

 
1

 
1

 
1

Worldwide
50

 
17

 
3

 
70

 
37

 
4

 
2

 
43

 
113

(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 acreage held in our North America E&P and International E&P segments and discontinued operations combined as of December 31, 2013.
 
Developed
 
Undeveloped
 
Developed and
Undeveloped
(In thousands)
Gross    
 
Net
 
Gross    
 
Net
 
Gross    
 
Net
U.S.
1,720

 
1,289

 
695

 
523

 
2,415

 
1,812

Canada

 

 
142

 
54

 
142

 
54

Total North America
1,720

 
1,289

 
837

 
577

 
2,557

 
1,866

E.G.
45

 
29

 
183

 
164

 
228

 
193

Other Africa
12,921

 
2,109

 
18,549

 
4,463

 
31,470

 
6,572

Total Africa
12,966

 
2,138

 
18,732

 
4,627

 
31,698

 
6,765

Total Europe
179

 
88

 
2,030

 
748

 
2,209

 
836

Other International

 

 
466

 
145

 
466

 
145

Worldwide
14,865

 
3,515

 
22,065

 
6,097

 
36,930

 
9,612


14


 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
(In thousands)
2014
 
2015
 
2016
 
U.S.
145

 
60

 
46

 
E.G. (a)
36

 

 

 
Other Africa
189

 
2,605

 
189

 
Total Africa
225

 
2,605

 
189

 
Total Europe
216

 
372

 
1

 
Other International

 
20

 

 
Worldwide
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.

15


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


16


 
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

17


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.

18


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.

19


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.


20


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 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 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 areas. We continue to evaluate midstream infrastructure investments in connection with our development plans.
Delivery Commitments
We have committed to deliver quantities of crude oil and synthetic crude oil to customers under a 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 paying a monetary shortfall penalty if production is inadequate. The Bakken contract carries no penalty for shortfalls.
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 "2013 Global Upstream Performance Review" published by IHS Herold Inc., we rank ninth among U.S.-based petroleum companies on the basis of 2012 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 for liquid hydrocarbons, synthetic crude oil and natural gas, 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,

21


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 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 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 issuing 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

22


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. 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, 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 issued a 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 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 open-pit 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 tailings 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 2013, 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 2011, 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.

23


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 3,359 active, full-time employees as of December 31, 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, 2014, are as follows:
Lee M. Tillman
 
52
 
President and Chief Executive Officer
John R. Sult
 
54
 
Executive Vice President and Chief Financial Officer
Sylvia J. Kerrigan
 
48
 
Executive Vice President, General Counsel and Secretary
Annell R. Bay
 
58
 
Vice President, Global Exploration
T. Mitch Little
 
50
 
Vice President, International and Offshore Production Operations
Lance W. Robertson
 
41
 
Vice President, North America Production Operations
Howard J. Thill
 
54
 
Vice President, Corporate, Government and Investor Relations
With the exception of Mr. Tillman, Mr. Sult and Mr. Robertson, 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. Tillman was appointed president and chief executive officer effective 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.
Mr. Sult was appointed executive vice president and chief financial officer effective September 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 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.
Mr. Little was appointed vice president, international and offshore production operations in September 2013 and served as 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 since 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. Thill was appointed vice president, corporate, government and investor relations effective January 2014, and vice president, investor relations and public affairs effective January 2008. Mr. Thill was previously director of investor relations from April 2003 to December 2007.
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://marathonoil.com/Investor_Center/Corporate_Governance/.

24


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 and 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.

25


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 cash 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 cash 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 and 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 cash 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;

26


title problems;
pressure or irregularities in formations;
equipment failures or accidents;
fires, explosions, blowouts or 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 timel