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, 2016
Commission file number 1-5153 |
| | |
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the Fiscal Year Ended | December 31, 2019 |
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from _____ to _____ |
| Commission file number | 1-1513 |
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, TXTexas 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 | | Trading Symbol | | Name of each exchange on which registered |
| Common Stock, par value $1.00 | | MRO | | 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 ☑þNo ☐o
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 ☐oNo ☑þ
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 ☑þ No ☐o
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 ☑þ 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. ☑o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See definitionthe definitions of "large“large accelerated filer," "accelerated filer"” “accelerated filer”, “smaller reporting company,” and "smaller reporting company"“emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☑ Accelerated filer ☐Non-accelerated filer ☐ |
| | | | | | | | | |
| Large accelerated filer | þ | Accelerated filer | o | Non-accelerated filer | o | |
| Smaller reporting company | ☐ | Emerging growth company | ☐ | | |
If an emerging growth company, ☐indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐No ☑þ
The aggregate market value of Common Stock held by non-affiliates as of June 30, 2016: $12,6962019: $11,398 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 847,201,196795,849,999 shares of Marathon Oil Corporation Common Stock outstanding as of February 15, 2017.14, 2020.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 20172020 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“Marathon Oil," "we," "our"” “we,” “our” or "us"“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).
Definitions
Throughout this report, the following company or industry specific terms and abbreviations are used.
AMPCO – Atlantic Methanol Production Company LLC, a company located in Equatorial Guinea in which we own a 45% equity interest.
AMT – Alternative minimum tax.
AOSP – Athabasca Oil Sands Project, an oil sands mining, transportation and upgrading joint venture located in Alberta, Canada, in which we holdheld a 20% non-operated working interest.
bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
bcf – Billion cubic feet.
boe – Barrels of oil equivalent.
btu – British thermal unit, an energy equivalence measure.
BLM – Bureau of Land Management.
Capital Program Budget – Includes capital expenditures, cash investments in equity method investees and other investments, exploration costs that are expensed as incurred rather than capitalized, such as geological and geophysical costs and certain staff costs, and other miscellaneous investment expenditures.
CWA – Clean Water Act.
Development Capital Budget – Includes expenditures, investments and costs associated with the Capital Budget excludingresource play exploration (“REx”).
DD&A – Depreciation, depletion and amortization.
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 operations, spun-off on June 30, 2011 and 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.completion as an oil or gas well.
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% equity interest.
EIA – United States Energy Information Agency.
EPA – United States Environmental Protection Agency.
E&P - Exploration and production.
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.
Henry Hub price - – a natural gas benchmark price quoted at settlement date average.
IRS – United States Internal Revenue Service.
Kurdistan – Kurdistan Region of Iraq.
LIBOR – London Interbank Offered Rate.
LNG – Liquefied natural gas.
LPG – Liquefied petroleum gas.
Liquid hydrocarbons or liquids – Collectively, crude oil, synthetic crude oil, condensate and natural gas liquids.
LLS – Louisiana Light Sweet crude oil, an oil index benchmark price as per Bloomberg Finance LLP: LLS St. James.
MEH – Magellan East Houston, an oil index benchmark price of WTI at Magellan East Houston.
Marathon Oil – Marathon Oil Corporation, including wholly owned and majority-owned subsidiaries, and 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 consolidated subsidiaries: theownership interest). The company as it exists following the June 30, 2011 spin-off of the downstream business.refining, marketing and transportation operations.
mbbld – Thousand barrels per day.
mboed – Thousand barrels of oil equivalent per day.
mcf – Thousand cubic feet.
mmbbl – Million barrels.
mmboe – Million barrels of oil equivalent. Natural gas is converted on the basis of six mcf of gas per one barrel of crude oil equivalent.
mmbtu – Million British thermal units.
mmcfd – Million stabilized cubic feet per day.
mmta – Million metric tonnes per annum.
MPC –Marathon Petroleum Corporationmt– the separate independent company, which owns and operates the downstream business.Metric tonnes.
mtmtd – metric tonnes
mtd – Thousand metricMetric tonnes per day.
NAAQS – National Ambient Air Quality Standard.
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, thatwhich can be collectively removed from produced natural gas, separated into these substances and sold.
NYMEX - – New York Mercantile Exchange.
OECD – Organization for Economic Cooperation and Development.
OPEC – Organization of Petroleum Exporting Countries.
Operational availability –A term used to measure the ability of an asset to produce to its maximum capacity over a specified period of time, after consideration of internal losses.
Productive well – A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
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 and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved reserves – Proved crude oil and condensate, NGLs, natural gas and our historical synthetic crude oil reserves are those quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
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 or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.recompletion. Undrilled locations can be classified as having proved undeveloped reserves if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibilityviability at greater distances.
PSC – Production sharing contract.
Quest CCS – Quest Carbon Capture and Storage project at the AOSP in Alberta, Canada.
Reserve replacement ratio – A ratio which measures the amount of proved reserves added to our reserve base during the year relative to the amount of liquid hydrocarbons and natural gas produced.
REx – Resource play exploration.
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).
STACK – Sooner Trend (oil field), Anadarko (basin), Canadian (and) Kingfisher (counties). in Oklahoma.
TD - Total depthor the bottom of a drilled hole.
Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.
Turnaround – A planned major maintenance program the costs for which are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.
U.K. – United Kingdom.
U.S. – United States of America.
U.S. GAAPresource plays – Accounting principles generally acceptedConsists of our unconventional properties in the U.S.Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico.
WCSU.S. GAAP – Western Canadian Select, an oil index benchmark price with monthly pricing based upon average adjusted for differentials unique to western Canada.U.S. Generally Accepted Accounting Principles.
Working interest – 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 interests or other interests.
WOTUS – Waters of the United States.
WTI – West Texas Intermediate crude oil, an oil index benchmark price as quoted by NYMEX.
Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including without limitation: our operational, financial and growth strategies, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling and completion improvements, cost reductions, non-core asset sales, and financial flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2017 capital program2020 Capital Budget and the planned allocation thereof; planned capital expenditures and the impact thereof; expectations regarding future economic and market conditions and their effects on us; our ability and strategies to manage through the lower commodity price cycle; our financial and operational outlook, and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources, and the benefits thereof; resource and asset potential; reserve estimates; growth expectations; and future production and sales expectations, and the drivers thereof. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, we can give no assurance that these expectations willmay not prove to be correct. A number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:
conditions in the oil and gas industry, including supply/supply and demand levels for crude oil and condensate, NGLs and natural gas and synthetic crude oil and the resulting impact on price;
changes in expected reserve or production levels;
changes in political or economic conditions in the jurisdictions in which we operate,E.G., including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
risks relatingrelated to our hedging activities;
liability resulting from litigation;
capital available for exploration and development;
the inability of any party to satisfy closing conditions or delays in execution with respect to our asset acquisitions and dispositions;
drilling and operating risks;
lack of, or disruption in, access to pipelines or other transportation methods;
well production timing;
availability of drilling rigs, materials and labor, including the costs associated therewith;
difficulty in obtaining necessary approvals and permits;
non-performance by third parties of their contractual obligations;
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
cyber-attacks;
changes in safety, health, environmental, tax and other regulations;regulations, or requirements or initiatives including those addressing the impact of global climate change, air emissions or water management;
other geological, operating and economic considerations; and
other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in this report.
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assumeundertake no dutyobligation to revise or update any forward-looking statements whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.
PART I
ItemItems 1. and 2. Business and Properties
General
Marathon Oil Corporation (NYSE: MRO) is an independent exploration and production company basedincorporated in Houston, Texas,2001, focused on U.S. unconventional resource plays withplays: the Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico. We also have international operations in North America, Europe and Africa.E.G. Our corporate headquarters is located at 5555 San Felipe Street, Houston, Texas 77056-2723 and our telephone number is (713) 629-6600. Each of our threetwo reportable operating segments isare organized by geographic location and managed based upon both geographic location andaccording to the nature of the products and services it offers.offered. The threetwo segments are:
North America E&PUnited States – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;the United States;
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America andthe United States as well as produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.;
Our strategy is to deliver competitive and
Oil Sands Mining – mines, extracts improving corporate level returns by focusing our capital investment in the lower cost, higher margin U.S. resource plays while maintaining a strong balance sheet, prioritizing sustainable cash flow generation over a wide range of commodity prices, and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumenreturning capital to produce and market synthetic crude oil and vacuum gas oil.
We were incorporated in 2001.
Our portfolio is concentrated in our 2017 Capital Program.
core operations in the U.S. resource plays and E.G. The map below shows the locations of our worldwide operations.U.S. operations:
Segment and Geographic Information
For reportable operating segment and geographic financial information, see Item 8. Financial Statements and Supplementary Data – Note 7 to the consolidated financial statements.
In the following discussion regarding our North America E&P,United States and 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&PUnited States Segment
North America E&P-- UnconventionalUnited States – U.S. Resource Plays
Oklahoma Resource BasinsEagle Ford – We hold approximately 365,000 net surface acres and includes 61,000 net acres added in the PayRock acquisition in the STACK Meramec play during 2016. In the SCOOP and STACK areas we hold net acres with rights to the Woodford, Springer, Meramec, Osage, Oswego, Granite Wash and other Pennsylvanian and Mississippian plays. Our primary 2017 focus will be in the Meramec play in the STACK and the Woodford and Springer plays in the SCOOP.
Eagle Ford - We hold approximately 145,000 net acres in south Texas where we have been operating in the South Texas Eagle Ford play since 2011. We2011, where our acreage is located in the high-return Karnes, Atascosa, Gonzales and Lavaca Counties. Our focus is capital efficient development with a goal of maximizing returns and cash flow generation while extending our core acreage. During 2019, we acquired 18,000 net acres adjacent to our existing acreage in the Eagle Ford, which included production of approximately 7,000 net boed and associated midstream infrastructure. Additionally, we operate more than 1,365 gross (962 net) producing wells, 32 central gathering and treating facilities and approximately 865 miles of gathering pipeline inacross the Eagle Ford. We alsoplay that support more than 1,600 producing wells as well as own and operate the Sugarloaf gathering system, a 42-mile natural gas pipeline through the heart of our acreage in Karnes and Atascosa and Bee Counties of south Texas.Counties.
Approximately 95% of the crude oil and condensate production is transported by pipeline with connections to multiple sales points. The ability to transport more barrels by pipeline enables us to improve/optimize price realizations, reduce costs, improve reliability and lessen our environmental footprint.
Bakken – We have been operating in the Williston Basin since 2006. The majority of our core acreage is within McKenzie, Mountrail, and Dunn Counties in North Dakota targeting the Middle Bakken and Three Forks reservoirs. We continue focusing our investment in our high-return Myrmidon and Hector areas, while also delineating and extending our core acreage across the rest of our position.
Oklahoma– With a history in Oklahoma that dates back more than 100 years, our primary focus has recently been early infill development in the STACK Meramec and SCOOP Woodford, while progressing delineation of other plays across our footprint. We primarily hold net acreage with rights to the Woodford, Springer, Meramec, Osage and other prospect intervals, with a majority of this in the SCOOP and STACK, with our recent activity in these plays being directed towards the more advantaged overpressured oil areas.
Northern Delaware – We have been operating in the Northern Delaware basin, which is located within the greater Permian area, since closing on two major acquisitions in 2017. Our focus has been to strategically advance our position and prepare for future development by further coring up our footprint, progressing early delineation of our acreage, improving our cost structure and securing midstream solutions. We have the majority of our acreage in Eddy and Lea counties primarily in the Wolfcamp and Bone Spring New Mexico plays.
United States – Resource Exploration
Our resource exploration properties in the United States include our acquired acreage in the emerging Louisiana Austin Chalk play, with an acreage position focused in the Western Fairway. Our first exploration well is on flowback and well clean-up and we have recently spud on our second exploration well. We also closed on approximately 270,00040,000 net acres in North Dakota and eastern Montana, where we have been operating since 2006. Our large scale water gathering system is handling nearly 70% of our produced water. We are currently transporting about 75% of ourthe Texas Delaware oil production on pipeline. In an effort to optimize price realizations, we sell our productionplay in local North Dakota markets and to select purchasers who may elect to transport outside of the state.
Other North America
Our remaining properties in North America primarily consist of a number of outside operated assets in the Gulf of Mexico, the largest of which is the Gunflint field located on Mississippi Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). The Gunflint field, in which we hold an 18% non-operated working interest, achieved first oil in the third quarter of 2016.
In 2016, we continued our progress on portfolio management, with approximately $1.3 billion of non-core assets sales, which mainly included Wyoming and West Texas properties. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.$106 million in 2019.
International E&P Segment
We are engaged in a range of activities, including oil and gas exploration, development and production across our international locationsactivities in E.G., Gabon, the Kurdistan Region of Iraq, Libya and the U.K. We include the results of our naturalinvestments in the LPG processing plant, gas liquefaction operations and methanol production operations in E.G. in our International E&P segment.
AfricaInternational
Equatorial Guinea – Production – We own a 63% operated working interest under a PSCproduction sharing contract in the Alba field and an 80% operated working interest in Block D, both of which isare offshore E.G. Operational availability from our company-operated facilities averaged approximately 97% in 2016.2019.
Equatorial Guinea – Gas Processing – We own a 52% interest in Alba Plant LLC, accounted for as an equity method investee,investment, which operates an onshore LPG processing plant located on Bioko Island. Alba field natural gas under a long-term contract at a fixed price per btu, is processed by the LPG plant.plant under a fixed-price long term contract. 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.
We also own 60% of EGHoldings and 45% of AMPCO, both of which are accounted for as equity method investments. EGHoldings operates a 3.7 mmta LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These facilities allow us to further monetize natural gas production from the Alba field. AMPCO had gross sales totaling 1,100 mt in 2016. Methanol production is sold to customers in Europe and the U.S.
The LNG production facility sells LNG under a 3.4 mmta or 460 mmcfd, sales and purchase agreement. Under the current agreement, which runs through 2023, the purchaser takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index. Gross sales of LNG from this production facility totaled 3.6approximately 3 mmta in 2016.2019. AMPCO had gross sales totaling approximately 878 mt in 2019. Methanol production is sold to customers in Europe and the U.S.
During 2019, we executed agreements for third-party gas through existing E.G. infrastructure, the initial step in creating an E.G. gas hub. Natural gas from the Alen field will be processed through the existing Alba Plant LLC LPG processing plant and the EGHoldings LNG production facility. First gas sales are expected in early 2021.
LibyaUnited Kingdom – We hold In the third quarter of 2019, we closed on the sale of our U.K. business, which represents a 16% non-operated working interest in the Waha concessions, which encompass almost 13 million gross acres located in the Sirte Basin of eastern Libya. Civil and political unrest has interrupted our production operations in recent years. During 2016, Force Majeure was lifted in September, production commenced shortly thereafter and liftings resumed in December.complete country exit. See Item 8. Financial Statements and Supplementary Data – Note 125 to the consolidated financial statements for additional information about our Libya operations.further detail.Other International
United KingdomKurdistan Region of Iraq – Our operated asset inIn the U.K. sectorsecond quarter of 2019, we closed on the North Sea is the Brae area complex where we are the operator and have a 42% working interest in the South, Central, North and West Brae fields, a 39% working interest in the East Brae field, and a 28% working interest in the nearby Braemar field.
The strategic locationsale of the Brae platforms, along with pipeline and onshore infrastructure, has generated third-party processing and transportation business since 1986. Currently, the operators of 31 third-party fields are contracted to use the Brae system and 72 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%our 15% non-operated interest in the SAGE pipeline system,Atrush block in Kurdistan which hasrepresents 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 0.3 bcf per day of third-party natural gas.
We own non-operated working interests in the Foinaven area complex, consisting of a 28% working interest in the main Foinaven field, a 47% working interest in East Foinaven and a 20% working interest in the T35 and T25 fields. The export of Foinaven liquid hydrocarbons is via shuttle tanker from an FPSO to market. All natural gas sales are to the non-operated Magnus platform for use as injection gas.
Kurdistan Region of Iraq – In 2016, we relinquished to the Kurdistan Regional Government our 45% operated working interest in the Harir block located northeast of Erbil. We have non-operated interests in two blocks located north-northwest of Erbil: Atrush with a 15% working interest and Sarsang with a 20% working interest.
International E&P Exploration
Equatorial Guinea – Exploration – We hold a 63% operated working interest in the Deep Luba discovery on the Alba Block and an 80% operated working interest in the Corona well on Block D. We plan to develop Block D through unitization with the Alba field. Negotiations have been substantially completed and we are awaiting approval from the host government.
Gabon – Exploration – We hold a 21.25% non-operated working interest in the Diaba License G4-223 and its related permit offshore Gabon, and a 100% participating interest and operatorship in the Tchicuate block where we have an exploration and production sharing agreement.
In 2015, we entered into agreements to sell our East Africa exploration acreage in Ethiopia and Kenya. This transaction closed during the first quarter of 2016.complete country exit. See Item 8. Financial Statements and Supplementary Data
- – Note 65 to the consolidated financial statements for information about these dispositions.Oil Sands Mining Segment
We hold a 20% non-operated interest in the AOSP, an oil sands mining and upgrading joint venture located in Alberta, Canada. Other JV partners include Shell Canada Limited with a 60% ownership interest and Chevron Canada Limited with a 20% ownership interest. Shell Canada Limited operates the joint venture, which produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and upgrades the bitumen into synthetic crude oils. 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) barrels of bitumen per day.
As of December 31, 2016, we own or have rights to participate in developed and undeveloped surface mineable leases totaling approximately 155,000 gross (31,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta.further detail.
Reserves
Proved reserves are required to be disclosed by continent and by country if the proved reserves related to any geographic area, on an oil equivalent barrel basis, represent 15% or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent or a continent. Other International ("Other Int’l"), includes the U.K.For additional detail on reserves, see Item 8. Financial Statements and the Kurdistan Region of Iraq. Approximately 79% of our proved reserves are located in OECD countries.Supplementary Data - Supplementary Information on Oil and Gas Producing Activities.
The following tables set forth estimated quantities of our total proved crude oil and condensate, NGLs and natural gas and synthetic crude oil reserves based upon an SEC pricing for period ended December 31, 2016.2019.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | | | |
| December 31, 2016 | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Other Int'l | | Total |
| Proved Developed Reserves | | | | | | | | | | | | | | | |
Crude oil and condensate (mmbbl) | 238 |
| | — |
| | 238 |
| | 45 |
| | 172 |
| | 217 |
| | 13 |
| | 468 |
|
Natural gas liquids (mmbbl) | 78 |
| | — |
| | 78 |
| | 24 |
| | — |
| | 24 |
| | — |
| | 102 |
|
Natural gas (bcf) | 648 |
| | — |
| | 648 |
| | 943 |
| | 95 |
| | 1,038 |
| | 5 |
| | 1,691 |
|
Synthetic crude oil (mmbbl) | — |
| | 692 |
| | 692 |
| | — |
| | — |
| | — |
| | — |
| | 692 |
|
Total proved developed reserves (mmboe) | 424 |
| | 692 |
| | 1,116 |
| | 226 |
| | 188 |
| | 414 |
| | 14 |
| | 1,544 |
|
| Proved Undeveloped Reserves | | | | | | | | | | | | | | | |
Crude oil and condensate (mmbbl) | 325 |
| | — |
| | 325 |
| | — |
| | — |
| | — |
| | 9 |
| | 334 |
|
Natural gas liquids (mmbbl) | 92 |
| | — |
| | 92 |
| | — |
| | — |
| | — |
| | — |
| | 92 |
|
Natural gas (bcf) | 640 |
| | — |
| | 640 |
| | — |
| | 110 |
| | 110 |
| | 5 |
| | 755 |
|
Synthetic crude oil (mmbbl) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total proved undeveloped reserves (mmboe) | 524 |
| | — |
| | 524 |
| | — |
| | 18 |
| | 18 |
| | 10 |
| | 552 |
|
| Total Proved Reserves | | | | | | | | | | | | | | | |
Crude oil and condensate (mmbbl) | 563 |
| | — |
| | 563 |
| | 45 |
| | 172 |
| | 217 |
| | 22 |
| | 802 |
|
Natural gas liquids (mmbbl) | 170 |
| | — |
| | 170 |
| | 24 |
| | — |
| | 24 |
| | — |
| | 194 |
|
Natural gas (bcf) | 1,288 |
| | — |
| | 1,288 |
| | 943 |
| | 205 |
| | 1,148 |
| | 10 |
| | 2,446 |
|
Synthetic crude oil (mmbbl) | — |
| | 692 |
| | 692 |
| | — |
| | — |
| | — |
| | — |
| | 692 |
|
Total proved reserves (mmboe) | 948 |
| | 692 |
| | 1,640 |
| | 226 |
| | 206 |
| | 432 |
| | 24 |
| | 2,096 |
|
|
| | | | | | | | | | | | | | |
| | Crude Oil and Condensate (mmbbl) | | Natural Gas Liquids (mmbbl) | | Natural Gas (bcf) | | Total (mmboe) | | Total (%) |
| Proved Developed Reserves | | | | | | | | | |
| U.S. | 304 |
| | 122 |
| | 825 |
| | 563 |
| | 47 | % |
| E.G. | 30 |
| | 19 |
| | 649 |
| | 158 |
| | 13 | % |
Total proved developed reserves (mmboe) | 334 |
| | 141 |
| | 1,474 |
| | 721 |
| | 60 | % |
| Proved Undeveloped Reserves | | | | | | | | | |
| U.S. | 315 |
| | 82 |
| | 453 |
| | 473 |
| | 39 | % |
| E.G. | 3 |
| | 2 |
| | 41 |
| | 11 |
| | 1 | % |
Total proved undeveloped reserves (mmboe) | 318 |
| | 84 |
| | 494 |
| | 484 |
| | 40 | % |
| Total Proved Reserves | | | | | | | | | |
| U.S. | 619 |
| | 204 |
| | 1,278 |
| | 1,036 |
| | 86 | % |
| E.G. | 33 |
| | 21 |
| | 690 |
| | 169 |
| | 14 | % |
Total proved reserves (mmboe) | 652 |
| | 225 |
| | 1,968 |
| | 1,205 |
| | 100 | % |
| Total proved reserves (%) | 54 | % | | 19 | % | | 27 | % | | 100 | % | | |
As of December 31, 2016, we had total estimated proved reserves of 802 mmbbl of crude oil and condensate, 194 mmbbl of NGLs, 2,446 bcf of natural gas, and 692 mmbbl of synthetic crude oil. Combined, total estimated proved reserves are 2,096 mmboe, of which liquids represents 81 percent. As of December 31, 2016, we had estimated proved developed reserves totaled 1,544 mmboe or 74% and estimated proved undeveloped reserves totaling 552 mmboe or 26% of our total proved reserves. For additional detail on reserves, 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. Crude oil and condensate, NGLs, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group ("CRG"), which includes our Director of Corporate Reserves and his staff of Reserve Coordinators. Crude oil and condensate, NGLs, natural gas and synthetic crude oil reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs"). QREs are petro-technical professionals located throughout our organization who meet the qualifications we have established for employees engaged in estimating reserves and resources. QREs have the education, experience, and training necessary to estimate reserves and resources in a manner consistent with all external reserve estimation regulations and internal resource estimation directives and practices. QREs generally hold 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 our QRE training course. All reserves changes (including proved) must be approved by the CRG. Additionally, any change to proved reserve estimates in excess of 5 mmboe on a total field basis, within a single month, must be approved by the Director of Corporate Reserves.
The 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 New Mexico. In his 30 years with Marathon Oil, he has held numerous engineering and management positions, including more recently managing reservoir engineering and geoscience for our Eagle Ford development in South Texas. He is a 25 year member of the Society of Petroleum Engineers ("SPE").
Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The
observed statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves.
Estimates of synthetic crude oil reserves were prepared by GLJ Petroleum Consultants of Calgary, Alberta, Canada, third-party consultants during 2015 and 2014. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The individual responsible, during 2015 and 2014, for the estimates of our synthetic crude oil reserves had 15 years of experience in petroleum engineering, has conducted surface mineable oil sands evaluations since 2009 and is a registered Practicing Professional Engineer in the Province of Alberta.
Audits of Estimates
We engage third-party consultants to provide, at a minimum, independent estimates for fields that comprise 80% of our total proved reserves over a rolling four-year period. We exceeded this percentage for the four-year period ended December 31, 2016, with 84% of our total proved reserves independently audited. An audit tolerance at a field level of +/- 10%, to our internal estimates, has been established. Should the third-party consultants’ initial analysis fall outside our tolerance band, both parties will re-examine the information provided, request additional data and refine their analysis, if appropriate. In the very limited instances where differences outside the 10% tolerance cannot be resolved by year end, a plan to resolve the difference is developed and executive management consent is obtained. The audit process did not result in any significant changes to our reserve estimates for 2016, 2015 or 2014.
During 2016, 2015 and 2014, Netherland, Sewell & Associates, Inc. prepared a reserves certification for the last three reporting periods 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 multiple years of industry experience, having worked for large, international oil and gas companies before joining NSAI. NSAI’s technical team members meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The senior technical advisor has over 12 years of practical experience in petroleum engineering and the estimation and evaluation of reserves and is a registered Professional Engineer in the State of Texas. The second team member has over 10 years of practical experience in petroleum geosciences and is a licensed Professional Geoscientist in the State of Texas.
Ryder Scott Company also performed audits of the prior years' reserves of several of our fields in 2016, 2015 and 2014. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 34 years of industry experience, having worked for a major financial advisory services group before joining Ryder Scott. He is a 25 year member of SPE and is a registered Professional Engineer in the State of Texas.
Productive and Drilling Wells
For our North America E&PUnited States and International E&P segments, the following table sets forth gross and net productive wells, service wells and drilling wells as of December 31 for the years presented.
| | | | Productive Wells(a) | | | | | | | | | Productive Wells | | | | | | | | |
| | Oil | | Natural Gas | | Service Wells | | Drilling Wells | Oil | | Natural Gas | | Service Wells | | Drilling Wells |
| Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| 2016 | | | | | | | | | | | | | | | | |
| 2019 | | | | | | | | | | | | | | | | |
U.S. (b) | 4,533 |
| | 1,650 |
| | 1,830 |
| | 708 |
| | 821 |
| | 85 |
| | 42 |
| | 10 |
| 4,984 |
| | 2,195 |
| | 1,550 |
| | 615 |
| | 204 |
| | 20 |
| | 30 |
| | 15 |
|
| E.G. | — |
| | — |
| | 17 |
| | 11 |
| | 2 |
| | 1 |
| | — |
| | — |
| — |
| | — |
| | 19 |
| | 12 |
| | — |
| | — |
| | — |
| | — |
|
| Other Africa | 1,071 |
| | 175 |
| | 7 |
| | 1 |
| | 94 |
| | 16 |
| | — |
| | — |
| |
Total (a) | | 4,984 |
| | 2,195 |
| | 1,569 |
| | 627 |
| | 204 |
| | 20 |
| | 30 |
| | 15 |
|
| 2018 | |
| | | | | | | | | | | | | | |
U.S. (b) | | 4,630 |
| | 2,056 |
| | 1,703 |
| | 655 |
| | 209 |
| | 21 |
| | | | |
| E.G. | | — |
| | — |
| | 19 |
| | 12 |
| | — |
| | — |
| | | | |
| Other International | | 62 |
| | 22 |
| | 11 |
| | 4 |
| | 24 |
| | 8 |
| | | | |
Total (c) | | 4,692 |
| | 2,078 |
| | 1,733 |
| | 671 |
| | 233 |
| | 29 |
| | | | |
| 2017 | | | | | | | | | | | | | | | | |
| U.S. | | 5,132 |
| | 1,905 |
| | 1,690 |
| | 676 |
| | 799 |
| | 70 |
| | | | |
| E.G. | | — |
| | — |
| | 19 |
| | 12 |
| | — |
| | — |
| | | | |
| Libya | | 1,071 |
| | 175 |
| | 7 |
| | 2 |
| | 94 |
| | 16 |
| | | | |
| Total Africa | 1,071 |
| | 175 |
| | 24 |
| | 12 |
| | 96 |
| | 17 |
| | — |
| | — |
| 1,071 |
| | 175 |
| | 26 |
| | 14 |
| | 94 |
| | 16 |
| | | | |
| Other International | 62 |
| | 23 |
| | 35 |
| | 14 |
| | 23 |
| | 8 |
| | — |
| | — |
| 61 |
| | 22 |
| | 19 |
| | 7 |
| | 23 |
| | 8 |
| | | | |
| Total | 5,666 |
| | 1,848 |
| | 1,889 |
| | 734 |
| | 940 |
| | 110 |
| | 42 |
| | 10 |
| 6,264 |
| | 2,102 |
| | 1,735 |
| | 697 |
| | 916 |
| | 94 |
| | | | |
| 2015 |
| | | | | | | | | | | | | | | |
| U.S. | 7,198 |
| | 2,878 |
| | 1,796 |
| | 750 |
| | 2,727 |
| | 747 |
| | | | | |
| E.G. | — |
| | — |
| | 17 |
| | 11 |
| | 2 |
| | 1 |
| | | | | |
| Other Africa | 1,071 |
| | 175 |
| | 7 |
| | 1 |
| | 94 |
| | 16 |
| | | | | |
| Total Africa | 1,071 |
| | 175 |
| | 24 |
| | 12 |
| | 96 |
| | 17 |
| | | | | |
| Other International | 59 |
| | 21 |
| | 39 |
| | 16 |
| | 24 |
| | 8 |
| | | | | |
| Total | 8,328 |
| | 3,074 |
| | 1,859 |
| | 778 |
| | 2,847 |
| | 772 |
| | | | | |
| 2014 | | | | | | | | | | | | | | | | |
| U.S. | 7,058 |
| | 2,919 |
| | 2,246 |
| | 1,023 |
| | 2,638 |
| | 760 |
| | | | | |
| E.G. | — |
| | — |
| | 16 |
| | 11 |
| | 2 |
| | 1 |
| | | | | |
| Other Africa | 1,071 |
| | 175 |
| | 7 |
| | 1 |
| | 94 |
| | 16 |
| | | | | |
| Total Africa | 1,071 |
| | 175 |
| | 23 |
| | 12 |
| | 96 |
| | 17 |
| | | | | |
| Other International | 55 |
| | 20 |
| | 39 |
| | 16 |
| | 24 |
| | 8 |
| | | | | |
| Total | 8,184 |
| | 3,114 |
| | 2,308 |
| | 1,051 |
| | 2,758 |
| | 785 |
| | | | | |
| |
(a) | Of the gross productive wells, wells with multiple completions operated by us totaled 8, 12 and 31 as of December 31, 2016, 2015 and 2014. Information on wells with multiple completions operated by others is unavailable to us. |
| |
(b)
| Reduction in December 31, 2016 gross and net productive wells and service wells is primarilyOther International was removed from 2019 due to the dispositionssale of our West TexasU.K. business and Wyoming assetsour 15% non-operated interest in 2016.the Atrush block in Kurdistan. See Item 8. Financial Statements and Supplementary Data - Note 65 to the consolidated financial statements for further information. |
| |
(b) | The 2018 decrease in gross productive oil wells and gross service wells is a result of the sale of non-core, non-operated conventional properties in the United States segment during the third quarter of 2018. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions. |
| |
(c) | Libya was removed from 2018 due to the sale of our subsidiary in Libya. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for further information. |
Drilling Activity
For our North America E&PUnited States and International E&P segments, the table below sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed as of December 31 for the years represented.
| | | | Development | | Exploratory | | | Development | | Exploratory | | |
| Oil | | Natural Gas | | Dry | | Total | | Oil | | Natural Gas | | Dry | | Total | | Total | Oil | | Natural Gas | | Dry | | Total | | Oil | | Natural Gas | | Dry | | Total | | Total |
| 2016 | | | | | | | | | | | | | |
| 2019 | | 2019 | | | | | | | | | | | | |
| U.S. | 64 |
| | 12 |
| | — |
| | 76 |
| | 70 |
| | 27 |
| | — |
| | 97 |
| | 173 |
| 197 |
| | 28 |
| | — |
| | 225 |
| | 57 |
| | 26 |
| | 2 |
| | 85 |
| | 310 |
|
| E.G. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other Africa | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Total (a) | | 197 |
| | 28 |
| | — |
| | 225 |
| | 57 |
| | 26 |
| | 2 |
| | 85 |
| | 310 |
|
| 2018 | | 2018 | | | | | | | | | | | | |
| U.S. | | 171 |
| | 25 |
| | — |
| | 196 |
| | 66 |
| | 36 |
| | 2 |
| | 104 |
| | 300 |
|
| E.G. | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
|
| Other International | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total (b) | | 171 |
| | 25 |
| | — |
| | 196 |
| | 66 |
| | 36 |
| | 3 |
| | 105 |
| | 301 |
|
| 2017 | | 2017 | | | | | | | | | | | | |
| U.S. | | 107 |
| | 27 |
| | — |
| | 134 |
| | 88 |
| | 16 |
| | — |
| | 104 |
| | 238 |
|
| E.G. | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Libya | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Africa | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other International | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
| | 2 |
|
| Total | 64 |
| | 12 |
| | — |
| | 76 |
| | 70 |
| | 27 |
| | — |
| | 97 |
| | 173 |
| 107 |
| | 27 |
| | — |
| | 134 |
| | 88 |
| | 16 |
| | 2 |
| | 106 |
| | 240 |
|
| 2015 | | | | | | | | | | | | | |
| U.S. | 135 |
| | 36 |
| | 11 |
| | 182 |
| | 49 |
| | 48 |
| | 1 |
| | 98 |
| | 280 |
| |
| E.G. | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | 2 |
| |
| Other Africa | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Total Africa | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | 2 |
| |
| Other International | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| |
| Total | 136 |
| | 37 |
| | 11 |
| | 184 |
| | 49 |
| | 48 |
| | 2 |
| | 99 |
| | 283 |
| |
| 2014 | | | | | | | | | | | | | |
| U.S. | 253 |
| | 43 |
| | 1 |
| | 297 |
| | 49 |
| | 19 |
| | 4 |
| | 72 |
| | 369 |
| |
| E.G. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | 1 |
| |
| Other Africa | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| |
| Total Africa | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
| | 2 |
| |
| Other International | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| |
| Total | 255 |
| | 43 |
| | 1 |
| | 299 |
| | 49 |
| | 19 |
| | 5 |
| | 73 |
| | 372 |
| |
| |
(a) | Other International was removed from 2019 due to the sale of our U.K. business and our 15% non-operated interest in the Atrush block in Kurdistan. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for further information. |
| |
(b) | Libya was removed from 2018 due to the sale of our subsidiary in Libya. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for further information. |
Acreage
We believe we have satisfactory title to our North America E&PUnited States 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 PSCsproduction sharing contracts 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 as of December 31, 2016.2019.
|
| | | | | | | | | | | | | | | | | |
| | Developed | | Undeveloped | | Developed and Undeveloped |
| (In thousands) | Gross | | Net | | Gross | | Net | | Gross | | Net |
| U.S. | 1,399 |
| | 1,053 |
| | 413 |
| | 386 |
| | 1,812 |
| | 1,439 |
|
| Canada | — |
| | — |
| | 142 |
| | 54 |
| | 142 |
| | 54 |
|
| Total North America | 1,399 |
| | 1,053 |
| | 555 |
| | 440 |
| | 1,954 |
| | 1,493 |
|
| E.G. | 45 |
| | 29 |
| | 92 |
| | 73 |
| | 137 |
| | 102 |
|
| Other Africa | 12,909 |
| | 2,108 |
| | 2,519 |
| | 753 |
| | 15,428 |
| | 2,861 |
|
| Total Africa | 12,954 |
| | 2,137 |
| | 2,611 |
| | 826 |
| | 15,565 |
| | 2,963 |
|
| Other International | 86 |
| | 31 |
| | 171 |
| | 32 |
| | 257 |
| | 63 |
|
| Total | 14,439 |
| | 3,221 |
| | 3,337 |
| | 1,298 |
| | 17,776 |
| | 4,519 |
|
|
| | | | | | | | | | | | | | | | | |
| | Developed | | Undeveloped | | Developed and Undeveloped |
| (In thousands) | Gross | | Net | | Gross | | Net | | Gross | | Net |
| U.S. | 1,388 |
| | 993 |
| | 391 |
| | 306 |
| | 1,779 |
| | 1,299 |
|
| E.G. | 82 |
| | 67 |
| | — |
| | — |
| | 82 |
| | 67 |
|
| Total | 1,470 |
| | 1,060 |
| | 391 |
| | 306 |
| | 1,861 |
| | 1,366 |
|
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, additional undeveloped acreage willlisted in the table below could expire in futureover the next three years. We plan to continue the terms of certain of these licenses and concession areas or retain leases through operational or administrative actions. There are no material quantities of net proved undeveloped reserves assigned to expiring undeveloped acreage in the next three years.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | |
| | | | |
| | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Other Int'l | | Disc Ops | |
Total |
| Year Ended December 31, | | | | | | | | | | | | | | | | | |
| 2016 | | | | | | | | | | | | | | | | |
Crude and condensate (mbbld)(a) | 131 |
| | — |
| | 131 |
| | 20 |
| | 3 |
| | 23 |
| | 12 |
| | — |
| | 166 |
|
Natural gas liquids (mbbld) | 40 |
| | — |
| | 40 |
| | 11 |
| | — |
| | 11 |
| | — |
| | — |
| | 51 |
|
Natural gas (mmcfd)(b) | 314 |
| | — |
| | 314 |
| | 425 |
| | — |
| | 425 |
| | 28 |
| | — |
| | 767 |
|
Synthetic crude oil (mbbld)(c) | — |
| | 48 |
| | 48 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 48 |
|
Total production (mboed) | 223 |
| | 48 |
| | 271 |
| | 102 |
| | 3 |
| | 105 |
| | 17 |
| | — |
| | 393 |
|
| 2015 | | | |
| | | | | |
| | | | | |
|
Crude and condensate (mbbld)(a) | 171 |
| | — |
| | 171 |
| | 19 |
| | — |
| | 19 |
| | 14 |
| | — |
| | 204 |
|
Natural gas liquids (mbbld) | 39 |
| | — |
| | 39 |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | 49 |
|
Natural gas (mmcfd)(b) | 351 |
| | — |
| | 351 |
| | 410 |
| | — |
| | 410 |
| | 21 |
| | — |
| | 782 |
|
Synthetic crude oil (mbbld)(c) | — |
| | 45 |
| | 45 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 45 |
|
Total production (mboed) | 269 |
| | 45 |
| | 314 |
| | 97 |
| | — |
| | 97 |
| | 18 |
| | — |
| | 429 |
|
| 2014 | | | |
| | | | | |
| | | | | |
|
Crude and condensate (mbbld)(a) | 157 |
| | — |
| | 157 |
| | 21 |
| | 7 |
| | 28 |
| | 11 |
| | 48 |
| | 244 |
|
Natural gas liquids (mbbld) | 29 |
| | — |
| | 29 |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | 39 |
|
Natural gas (mmcfd)(b) | 310 |
| | — |
| | 310 |
| | 439 |
| | 1 |
| | 440 |
| | 21 |
| | 37 |
| | 808 |
|
Synthetic crude oil (mbbld)(c) | — |
| | 41 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 41 |
|
Total production (mboed) | 238 |
| | 41 |
| | 279 |
| | 104 |
| | 7 |
| | 111 |
| | 15 |
| | 54 |
| | 459 |
|
|
| | | | | | | | |
| | Net Undeveloped Acres Expiring |
| | Year Ended December 31, |
| (In thousands) | 2020 | | 2021 | | 2022 |
| U.S. | 70 |
| | 108 |
| | 31 |
|
| E.G. | — |
| | — |
| | — |
|
| Total | 70 |
| | 108 |
| | 31 |
|
Net Sales Volumesare presented on a continuing operations basis. At December 31, 2019, 2018 and 2017, the Eagle Ford, Bakken and Oklahoma fields in the United States contained 15% or more of our total proved reserves. Production for these fields along with our production from fields containing less than 15% of our total proved reserves are presented in the table below. |
| | | | | | | | |
| | December 31, |
| | 2019 | | 2018 | | 2017 |
| Net Sales Volumes | | | | | |
Crude oil and condensate (mbbld) (a) | | | | | |
| United States | | | | | |
| Eagle Ford | 63 |
| | 63 |
| | 59 |
|
| Bakken | 86 |
| | 71 |
| | 46 |
|
| Oklahoma | 21 |
| | 18 |
| | 15 |
|
| Northern Delaware | 16 |
| | 12 |
| | 4 |
|
| Other U.S. | 4 |
| | 7 |
| | 9 |
|
| Africa | | | | | |
| E.G. | 15 |
| | 17 |
| | 21 |
|
| Libya | — |
| | 7 |
| | 19 |
|
Other International (b) | 5 |
| | 15 |
| | 12 |
|
| Total | 210 |
| | 210 |
| | 185 |
|
| Natural gas liquids (mbbld) | | | | | |
| United States | | | | | |
| Eagle Ford | 22 |
| | 23 |
| | 21 |
|
| Bakken | 9 |
| | 7 |
| | 6 |
|
| Oklahoma | 22 |
| | 20 |
| | 14 |
|
| Northern Delaware | 6 |
| | 4 |
| | 1 |
|
| Other U.S. | 1 |
| | 1 |
| | 1 |
|
| Africa | | | | | |
| E.G. | 9 |
| | 11 |
| | 11 |
|
Other International (b) | — |
| | — |
| | 1 |
|
| Total | 69 |
| | 66 |
| | 55 |
|
Natural gas (mmcfd) (c) | | | | | |
| United States | | | | | |
| Eagle Ford | 130 |
| | 129 |
| | 125 |
|
| Bakken | 46 |
| | 35 |
| | 25 |
|
| Oklahoma | 210 |
| | 213 |
| | 149 |
|
| Northern Delaware | 36 |
| | 26 |
| | 9 |
|
| Other U.S. | 16 |
| | 26 |
| | 40 |
|
| Africa | | | | | |
| E.G. | 365 |
| | 416 |
| | 459 |
|
| Libya | — |
| | 5 |
| | 4 |
|
Other International (b) | 6 |
| | 14 |
| | 22 |
|
| Total | 809 |
| | 864 |
| | 833 |
|
| Total sales volumes (mboed) | | | | | |
| United States | | | | | |
| Eagle Ford | 106 |
| | 108 |
| | 101 |
|
| Bakken | 103 |
| | 84 |
| | 56 |
|
| Oklahoma | 78 |
| | 74 |
| | 54 |
|
| Northern Delaware | 28 |
| | 20 |
| | 6 |
|
| Other U.S. | 8 |
| | 12 |
| | 17 |
|
| Africa | | | | | |
| E.G. | 85 |
| | 97 |
| | 109 |
|
| Libya | — |
| | 8 |
| | 20 |
|
Other International (b) | 6 |
| | 17 |
| | 16 |
|
| Total | 414 |
| | 420 |
| | 379 |
|
| |
(a) | The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons. |
| |
(b) | ExcludesOther International sales include sales volumes acquired from third parties for injectionthe U.K. and subsequent resale. |
| |
(c)
| Upgraded bitumen excluding blendstocks. |
Average Production Cost per Unit (a) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | | | | | | |
| (Dollars per boe) | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Other Int'l | | Disc Ops | |
Total |
| 2016 | $ | 9.84 |
| | $ | 29.36 |
| | $ | 13.35 |
| | $ | 2.17 |
| | N.M. | | $ | 2.17 |
| | $ | 23.13 |
| | $ | — |
| | $ | 11.02 |
|
| 2015 | 10.65 |
| | 38.42 |
| | 14.69 |
| | 2.37 |
| | N.M. | | 2.37 |
| | 27.23 |
| | — |
| | 12.62 |
|
| 2014 | 13.34 |
| | 46.63 |
| | 18.73 |
| | 4.03 |
| | N.M. | | 4.03 |
| | 47.06 |
| | 8.92 |
| | 15.37 |
|
| |
(a)
| Production, severancethe Atrush block in Kurdistan, which were both sold in 2019 and property taxes are excluded; however, shipping and handling as well as other operating expenses are includedsales volumes for the non-operated Sarsang block in the production costs usedKurdistan which was sold in this calculation.2018. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil- Note 5 to the consolidated financial statements for further information. |
| |
(c) | Includes natural gas acquired for injection and Gas Producing Activities - Results of Operations for Oil and Gas Production Activities for more information regarding production costs.subsequent resale. |
N.M. Not meaningful information due to limited sales.
Average Sales Price and Production Costs per Unit(a) are presented on a continuing operations basis by geographic area. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | North America | | Africa | |
| | | | |
| (Dollars per unit) | U.S. | | Canada | | Total | | E.G. | | Other | | Total | | Other Int'l | | Disc Ops | |
Total |
| 2016 | | | | | | | | | | | | | | | | |
Crude and condensate (bbl) | $ | 38.57 |
| | $ | — |
| | $ | 38.57 |
| | $ | 38.85 |
| | $ | 57.69 |
| | $ | 40.95 |
| | $ | 43.21 |
| | $ | — |
| | $ | 39.23 |
|
Natural gas liquids (bbl) | 13.15 |
| | — |
| | 13.15 |
| | 1.00 |
| (b) | — |
| | 1.00 |
| | 26.41 |
| | — |
| | 10.68 |
|
Natural gas (mcf) | 2.38 |
| | — |
| | 2.38 |
| | 0.24 |
| (b) | — |
| | 0.24 |
| | 4.80 |
| | — |
| | 1.26 |
|
Synthetic crude oil (bbl) | — |
| | 37.57 |
| | 37.57 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 37.57 |
|
| 2015 | | | | | | | | | | | | | | | | |
Crude and condensate (bbl) | $ | 43.50 |
| | $ | — |
| | $ | 43.50 |
| | $ | 42.83 |
| | $ | — |
| | $ | 42.83 |
| | $ | 53.91 |
| | $ | — |
| | $ | 44.14 |
|
Natural gas liquids (bbl) | 13.37 |
| | — |
| | 13.37 |
| | 1.00 |
| (b) | — |
| | 1.00 |
| | 32.53 |
| | — |
| | 11.16 |
|
Natural gas (mcf) | 2.66 |
| | — |
| | 2.66 |
| | 0.24 |
| (b) | — |
| | 0.24 |
| | 6.85 |
| | — |
| | 1.50 |
|
Synthetic crude oil (bbl) | — |
| | 40.13 |
| | 40.13 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 40.13 |
|
| 2014 | | | | | | | | | | | | | | | | |
Crude and condensate (bbl) | $ | 85.25 |
| | $ | — |
| | $ | 85.25 |
| | $ | 81.01 |
| | $ | 94.70 |
| | $ | 84.48 |
| | $ | 94.31 |
| | $ | 109.80 |
| | $ | 90.37 |
|
Natural gas liquids (bbl) | 33.42 |
| | — |
| | 33.42 |
| | 1.00 |
| (b) | — |
| | 1.00 |
| | 67.73 |
| | — |
| | 25.25 |
|
Natural gas (mcf) | 4.57 |
| | — |
| | 4.57 |
| | 0.24 |
| (b) | 3.11 |
| | 0.25 |
| | 8.27 |
| | 9.94 |
| | 2.55 |
|
Synthetic crude oil (bbl) | — |
| | 83.35 |
| | 83.35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 83.35 |
|
|
| | | | | | | | | | | |
| | December 31, |
| (Dollars per unit) | 2019 | | 2018 | | 2017 |
Average Sales Price per Unit (a) | | | | | |
| Crude oil and condensate (bbl) | | | | | |
| United States | $ | 55.80 |
| | $ | 63.11 |
| | $ | 49.35 |
|
| Africa | | | | | |
| E.G. | 48.99 |
| | 55.28 |
| | 46.02 |
|
| Libya | — |
| | 73.75 |
| | 60.72 |
|
| Total Africa | 48.99 |
| | 60.65 |
| | 53.11 |
|
Other International (b) | 64.71 |
| | 70.39 |
| | 52.66 |
|
| Total | $ | 55.54 |
| | $ | 63.32 |
| | $ | 50.38 |
|
| | | | | | |
| Natural gas liquids (bbl) | | | | | |
| United States | $ | 14.22 |
| | $ | 24.54 |
| | $ | 20.55 |
|
| Africa | | | | | |
E.G. (d) | 1.00 |
| | 1.00 |
| | 1.00 |
|
| Total Africa | 1.00 |
| | 1.00 |
| | 1.00 |
|
Other International (b) | 37.88 |
| | 41.66 |
| | 39.65 |
|
| Total | $ | 12.46 |
| | $ | 20.85 |
| | $ | 16.65 |
|
| | | | | | |
| Natural gas (mcf) | | | | | |
| United States | $ | 2.18 |
| | $ | 2.65 |
| | $ | 2.84 |
|
| Africa | | | | | |
E.G. (c) | 0.24 |
| | 0.24 |
| | 0.24 |
|
| Libya | — |
| | 4.57 |
| | 5.03 |
|
| Total Africa | 0.24 |
| | 0.30 |
| | 0.28 |
|
Other International (b) | 5.67 |
| | 8.03 |
| | 6.28 |
|
| Total | $ | 1.33 |
| | $ | 1.58 |
| | $ | 1.51 |
|
| | | | | | |
Average Production Costs per Unit (d) | | | | | |
| U.S. | $ | 9.08 |
| | $ | 9.83 |
| | $ | 9.49 |
|
| E.G. | 2.34 |
| | 1.91 |
| | 2.12 |
|
| Libya | — |
| | 4.35 |
| | 6.08 |
|
Other International (b) | 30.42 |
| | 30.02 |
| | 26.61 |
|
| Total | $ | 8.03 |
| | $ | 8.68 |
| | $ | 7.90 |
|
| |
(a) | Excludes gains or losses on commodity derivative instruments. |
| |
(b) | Other International sales include sales volumes for the U.K. and the Atrush block in Kurdistan, which were both sold in 2019 and sales volumes for the non-operated Sarsang block in Kurdistan which was sold in 2018. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for further information. |
| |
(c) | Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and/or 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.segment. |
| |
(d) | Production, severance and property taxes are excluded; however, shipping and handling as well as other operating expenses are included in 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 costs. |
Marketing
Our reportable operating segments include activities related to the marketing and transportation of substantially all of our crude oil and condensate, NGLs and natural gas and synthetic crude oil.gas. 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.
Major Customers
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. In 2019, sales to Marathon Petroleum Corporation, Flint Hills Resources, Valero Marketing and Supply, and Shell Trading and each of their respective affiliates, accounted for approximately 13%, 13%, 11% and 10% of our total revenues. In 2018, sales to Valero Marketing and Supply and Flint Hills Resources and their respective affiliates, each accounted for approximately 11% of our total revenues. In 2017, sales to Vitol and their respective affiliates accounted for approximately 10% of our total revenues.
Gross Delivery Commitments
We have committed to deliver gross quantities of crude oil and condensate, NGLs and natural gas and synthetic crude oil to customers under a variety of contracts. As of December 31, 2016,2019, the contracts for fixed and determinable quantities were at variable, market-based pricing and related primarily to the following sales commitments:
| | | | | 2017 | | 2018 | | 2019 | | Thereafter | | Commitment Period Through | | 2020 | | 2021 | | 2022 | | Thereafter | | Commitment Period Through |
| Eagle Ford | | | | | | | | | | | | | | | | |
Crude and condensate (mbbld) | | 105 |
| | 80 |
| | 66 |
| | 51 | | 2020 | | 51 |
| | — |
| | — |
| | — |
| | 2020 |
Natural gas (mmcfd) | | 210 |
| | 168 |
| | 168 |
| | 46 - 168 | | 2022 | | 120 |
| | 56 |
| | 36 |
| | — |
| | 2022 |
| Bakken | | | | | | | | | | | | | | | | |
Crude and condensate (mbbld) | | 5 |
| | 10 |
| | 10 |
| | 5-10 | | 2027 | | 10 |
| | 10 |
| | 10 |
| | 5 - 10 |
| | 2027 |
| OSM | | | | | | | | |
Synthetic crude oil (mbbld) | | 10 |
| | — |
| | — |
| | — | | |
Natural gas (mmcfd) | | | 3 |
| | 3 |
| | 3 |
| | 3 - 25 |
| | 2028 |
| Other United States | | | | | | | | | | |
Natural gas (mmcfd) | | | 4 |
| | 4 |
| | 1 |
| | — |
| | 2022 |
All of these contracts provide the optionsoption of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate. Certain volumetric requirements can also be met through purchases of third-party volumes.inadequate to satisfy our commitment. In addition to the sales contracts discussed above, we have entered into numerous agreements for transportation and processing of our equity production. Some of these contracts have volumetric requirements which could require monetary shortfall penalties if our production is inadequate to meet the terms.
Competition
Competition exists in all sectors of the oil and gas industry and we compete with major integrated and independent oil and gas companies, national oil companies, and to a lesser extent, companies that supply alternative sources of energy. We compete, 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 thereserves, acquisition of oil and natural gas leases and other properties, the marketing and delivery of our production into worldwide commodity markets and for the labor and equipment required for exploration and development of those properties. Principal methods of competing include geological, geophysical, and engineering research and technology, experience and expertise, economic analysis in connection with portfolio management, and safely operating oil and gas producing properties. 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 crude oil for the sale of our synthetic crude oil to refineries primarily in North America. Because not all refineries are able to process or refine synthetic crude oil in significant volumes, sufficient market demand may not exist at all times to absorb our share of the synthetic crude oil production from the AOSP at economically viable prices.
Environmental, Health and Safety Matters
The Health, Environmental, Safety and Corporate Responsibility Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental, health and safety matters. Our Corporate Health, Environment, Safety and Security organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations. Committees comprised of certain of our officers review our overall performance associated with various environmental compliance programs. We also have a Corporate Emergency Response Team which oversees our response to any major environmental or other emergency incident involving us or any of our properties.
Our businesses are subject to numerous laws and regulations relating to the protection of the environment, health and safety at the national, state and local levels. These laws and their implementing regulations and other similar state and local laws and rules can impose certain operational controls for minimization of pollution or recordkeeping, monitoring and reporting requirements or other operational or siting constraints on our business, result in costs to remediate releases of regulated substances, including crude oil and produced water, into the environment, or require 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. We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations.
New laws have been enacted or are otherwise being considered and regulations are being adopted by various regulatory agencies on a continuing basis and the costs of compliance with these new laws and regulations can only be broadly appraised until their implementation becomes more defined.
Air and Climate Change
Environmental advocacy groups and regulatory agencies in the United States and other countries have focused considerable attention on the emissions of carbon dioxide, methane and other greenhouse gases and their role in climate change. Developments in greenhouse gas initiatives may affect us and other similarly situated companies operating in the oil and gas industry. As part of our commitment to environmental stewardship and as required by law, 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.
Government entities and other groups have filed lawsuits in several states and other jurisdictions seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits allege damages as a result of global warming and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Marathon Oil has been named as a defendant in several of these lawsuits, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the claims made against us are without merit and will not have a material adverse effect on our consolidated financial position, results of operations or cash flow.
The EPA finalized a more stringent National Ambient Air Quality Standard ("NAAQS")NAAQS for ozone in October 2015. This more stringent ozone NAAQS could resultStates that contain any areas designated as non-attainment, and any tribes that choose to do so, will be required to complete development of implementation plans in the 2020-2022 time frame. The EPA may in the future designate additional areas being designated as non-attainment, including areas in which we operate, whichoperate. The EPA is also in the process of reviewing the ozone NAAQS to determine whether to maintain the 2015 standard or to promulgate a more stringent standard. This review is expected to be complete by December 2020. The implementation of the 2015 standard, or the promulgation of a future more stringent standard, 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 this revised regulation, 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. The EPA's final ruleUnited States Court of Appeals for the District of Columbia largely upheld EPA’s 2015 standard in August 2019. No party has been judicially challenged by both industry and other interested parties, and the outcomesought review of this litigation may also impact implementationdecision and, revisions to the rule.
In June 2016, the EPA published a suite of final rules specifically targeting methane emissions from the oil and gas industry, aggregation of air emissions sources and minor source permitting for operations on tribal lands. The EPA has also announced thattherefore, it intends to impose methane emission standards for existing sources and has issued information collection requests for oil and natural gas facilities. We are currently evaluating the impact of these rules on our operations. If we are unable to comply with the terms of these regulations, we could be required to forego construction or implement modifications to certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for non-compliance.
In 2010, the EPA promulgated rules that require us to monitor and submit an annual report on our greenhouse gas emissions. In October 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gas monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Further, state, national and international requirements to reduce greenhouse emissions are being proposed and in some cases promulgated (see discussion above regarding regulation of methane emissions from the oil and gas industry by the EPA). 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.is final.
In November 2016, the Bureau of Land Management (“BLM”)BLM issued a final rule to further restrict venting and/or flaring of gas from facilities subject to BLM jurisdiction, and to modify certain royalty requirements. These regulations are currently subject toBLM issued a challenge under the Congressional Review Act, which if successful, would result in complete withdrawaltwo-year stay of these requirements.requirements in December 2017. In September 2018, BLM published a final rule to rescind substantial portions of the rule. The rescission was challenged by multiple parties in the U.S. District Court for the Northern District of California. If not withdrawn, thisthe judicial challenges to the rule is expectedare successful and the rule were to come back into effect, the requirements would result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities. If we are unable to comply with the terms of these regulations, we could be required to forego certain operations. These regulations may also result in administrative, civil and/or criminal penalties for non-compliance.
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. Our business uses this technique extensively throughout our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local-level laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. For example, the U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process, and may be expected to do so in future legislative sessions. Further, variousVarious state and local-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.
For additional information, see Item 1A. Risk Factors.
Transportation
A number Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with these initiatives, the extent and magnitude of state and federal rules applythat impact cannot be reliably or accurately estimated due to the transportation of liquid hydrocarbons. In 2015, the U.S. Department of Transportation (“DOT”) finalized a rule relating to testingpresent uncertainty regarding any additional measures and classification of liquid hydrocarbons and imposing additional restrictions on the types of rail cars that mayhow they will be used in certain types of liquid hydrocarbon service. Similarly, in August 2016, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), a sub-agency of DOT, published a final rule setting additional safety requirements and retrofits for rail cars. PHMSA is also considering revising its regulations to require particular methods for conducting vapor pressure testing and sampling of unrefined petroleum-based products for transportation. Although our businesses do not own rail cars and purchasers of our liquid hydrocarbons make arrangements for its transportation, such regulations could increase transportation costs which are passed on to Marathon Oil by liquid hydrocarbon purchasers. In addition, PHMSA has proposed or announced the intention to propose various rules related to pipeline transportation of natural gas and/or liquid hydrocarbons. For example, in October 2015, PHMSA published a notice of proposed rulemaking amending its hazardous liquid pipeline safety regulations and in April 2016, published a notice of proposed rulemaking addressing natural gas transmission and gathering lines. Such regulations could increase the regulatory burden on our businesses where we own or operate pipelines or could otherwise increase costs to third parties that are passed on to Marathon Oil.implemented.
Water
In 2014, the EPA and the U.S. Army Corps of Engineers published proposed regulations which expand the surface waters that are regulated under the Clean Water Actfederal CWA and its various programs. While these regulations were finalized largely as proposed in 2015, the rule has beenwas stayed by the courts pending a substantive decision on the merits. In October 2019, EPA and the Army Corps of Engineers issued a final rule that repealed the 2015 regulations and reinstated the agencies’ narrower pre-2015 scope of federal CWA jurisdiction. In January 2020, EPA and the Army Corp of Engineers promulgated a new WOTUS definition that continues to provide a narrower scope of federal CWA jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal CWA jurisdiction. Judicial challenges to EPA’s October 2019 final rule are currently before multiple federal district courts and challenges to EPA’s January 2020 final rule are anticipated. If thisthe October 2019 final rule is vacated and the 2015 rule is ultimately implemented, the expansion of CWA jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.
Concentrations of CreditFor additional information, see Item 1A. RiskWe 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. In 2016, sales to Irving Oil and Valero Marketing and Supply and each of their respective affiliates accounted for approximately 17% and 10% of our total revenues. In 2015, sales to Irving Oil and Shell Oil and each of their respective affiliates accounted for approximately 13% and 11% of our total revenues. In 2014, sales to Shell Oil and its affiliates accounted for approximately 10% of our total revenues. Factors.
Trademarks, Patents and Licenses
We currently hold a number of U.S. and foreign patents and have various pending patent applications.patents. Although in the aggregate our trademarks patents and licensespatents are important to us, we do not regard any single trademark, patent, license or group of related trademarks patents or licensespatents as critical or essential to our business as a whole.
Employees
We had 2,117approximately 2,000 active, full-time employees as of December 31, 2016.2019.
Information About our Executive Officers of the Registrant
The executive officers of Marathon Oil and their ages as of February 1, 2017,2020, are as follows:
|
| | | | |
| Lee M. Tillman | | 5558 | | Chairman, President and Chief Executive Officer |
Sylvia J. KerriganDane E. Whitehead | | 5158 | | Executive Vice President and Chief Financial Officer |
| T. Mitch Little | | 56 | | Executive Vice President—Operations |
| Reginald D. Hedgebeth | | 52 | | Executive Vice President, General Counsel and Secretary |
T. Mitch Little | | 53 | | Executive Vice President—OperationsChief Administrative Officer |
| Patrick J. Wagner | | 52 | | Interim Chief Financial Officer and Vice President-Corporate Development and Strategy |
Catherine L. Krajicek | | 55 | | Executive Vice President—ConventionalCorporate Development and Strategy |
| Gary E. Wilson | | 5558 | | Vice President, Controller and Chief Accounting Officer |
Mr. Tillman was appointed by the board of directors as chairman of the board effective February 1, 2019. In August 2013, he was appointed as president and chief executive officer in August 2013. Mr. Tillman is also a member of our Board of Directors.officer. Prior to this appointment, Mr. Tillman served as vice president of engineering for ExxonMobil Development Company (a project design and execution company), where he was responsible for all global engineering staff engaged in major project concept selection, front-end design and engineering. Between 2007 and 2010, Mr. Tillman served as North Sea production manager and lead country manager for subsidiaries of ExxonMobil in Stavanger, Norway. Mr. Tillman began his career in the oil and gas industry at Exxon Corporation in 1989 as a research engineer and has extensive operations management and leadership experience.
Ms. KerriganMr. Whitehead was appointed executive vice president general counsel and secretarychief financial officer in October 2012, havingMarch 2017. Prior to this appointment, Mr. Whitehead served as executive vice president general counsel and secretarychief financial officer of both EP Energy Corp. and EP Energy LLC (oil and natural gas producer) since November 2009. Prior to these appointments, Ms. KerriganMay 2012. Between 2009 and 2012, Mr. Whitehead served as assistant general counsel since January 2003.senior vice president of strategy and enterprise business development and a member of El Paso Corporation’s executive committee. He joined El Paso Exploration & Production Company as senior vice president and chief financial officer in 2006. Before joining El Paso, Mr. Whitehead was vice president, controller and chief accounting officer of Burlington Resources Inc. (oil and natural gas producer), and formerly senior vice president and CFO of Burlington Resources Canada.
Mr. Little was appointed executive vice president of operations in August 2016 after having served as vice president, conventional since December 2015, vice president international and offshore exploration and production operations since September 2013, and as vice president, international production operations since September 2012. Prior to that, Mr. Little was resident manager of our Norway operations and served as general manager, worldwide drilling and completions. Mr. Little joined Marathon Oil in 1986 and has since held a number of engineering and management positions of increasing responsibility.
Mr. Hedgebeth was appointed executive vice president, general counsel and chief administrative officer in August 2019 after having served as senior vice president, general counsel and secretary since April 2017. Between 2009 and 2017, Mr. Hedgebeth served as general counsel, corporate secretary and chief compliance officer for Spectra Energy Corp (oil and natural gas pipeline company) and general counsel for Spectra Energy Partners, LP. Before joining Spectra Energy, Mr. Hedgebeth
served as senior vice president, general counsel and secretary with Circuit City Stores, Inc. (consumer electronics retail company), and vice president of legal for The Home Depot, Inc. (home improvement retail company).
Mr. Wagner was appointed executive vice president—president of corporate development and strategy in April 2014,November 2017 after having served as senior vice president of corporate development and strategy since March 2017, vice president of corporate development and interim chief financial officer since August 2016 has been serving as interim chief financial officer.and vice president of corporate development since April 2014. Prior to joining Marathon Oil,this appointment, he served as senior vice president, western business unit, for QR Energy LP (an oil and natural gas producer) and the affiliated Quantum Resources Management, which he joined in early 2012 as vice president, exploitation. Prior to that, Mr. Wagner was managing director in Houston for Scotia Waterous, the oil and gas arm of Scotiabank (an international banking services provider), from 2010 to 2012. Before joining Scotia, Mr. Wagner was vice president, Gulf of Mexico, for Devon Energy Corp. (an oil and natural gas producer), having joined Devon in 2003 as manager, international exploitation.
Ms. Krajicek was appointed vice president—conventional assets in August 2016 after having served as vice president of technology and innovation since December 2015. Prior to that, Ms. Krajicek served as vice president, health, environment, safety and security from January 2015 through December 2015. Ms. Krajicek joined Marathon Oil in 2007 and has since held a number of positions of increasing responsibility. Prior to joining the Company, Ms. Krajicek spent 22 years with Conoco and then ConocoPhillips (a multinational energy corporation), where she held a variety of reservoir engineering and asset management and development management positions for upstream and mid-stream businesses under development, both in the U.S. and internationally.
Mr. Wilson was appointed vice president, controller and chief accounting officer in October 2014. Prior to joining Marathon Oil, he served in various finance and accounting positions of increasing responsibility at Noble Energy, Inc. (a global
exploration and production company) since 2001, including as director corporate accounting from February 2014 through September 2014, director global operations services finance from October 2012 through February 2014, director controls and reporting from April 2011 through September 2012, and international finance manager from September 2009 through March 2011.
Available Information
Our website is www.marathonoil.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K and other reports and filings with the SEC are available free of charge on our website as soon as reasonably practicable after the reports are filed or furnished with the SEC. Information contained on our website is not incorporated into this Annual Report on Form 10-K or our other securities filings. Our filings are also available in hard copy, free of charge, by contacting ourus at 5555 San Felipe Street, Houston, Texas, 77056-2723, Attention: Investor Relations office.
The public may read and copy any materials we file withOffice, telephone: (713) 629-6600. Additionally, the SEC at its Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
Additionally, we make available free of charge on our website:
our Code of Business Conduct and Code of Ethics for Senior Financial Officers;
our Corporate Governance Principles; and
the charters of our Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating Committee and Health, Environmental, Safety and Corporate Responsibility Committee.
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“Disclosures Regarding Forward-Looking Statements"Statements” and other information included and incorporated by reference into this Annual Report on Form 10-K.
TheA substantial decline in crude oil and condensate, NGLs and natural gas and synthetic crude oil prices since 2014 has reducedwould reduce our operating results and cash flows and regardless of the recent increase in prices, could still adversely impact our future rate of growth and the carrying value of our assets.
PricesThe markets for crude oil and condensate, NGLs and natural gas have been volatile and synthetic crude oilare likely to continue to be volatile in the future, causing prices to fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil and condensate, NGLs natural gas and synthetic crude oil. Historically, the markets for crude oil and condensate, NGLs, natural gas and synthetic crude oil have been volatile and may continue to be volatile in the future. Although, prices for WTI and Brent crude oil, Henry Hub natural gas and natural gas liquids have increased in the last several months, prices are still significantly below their highs from 2014.gas. Many of the factors influencing prices of crude oil and condensate, NGLs and natural gas and synthetic crude oil are beyond our control. These factors include:
worldwide and domestic supplies of and demand for crude oil and condensate, NGLs and natural gas and synthetic crude oil;gas;
the cost of exploring for, developing and producing crude oil and condensate, NGLs and natural gas and synthetic crude oil;gas;
the ability of the members of OPEC and certain non-OPEC members, such as Russia, to agree to and maintain production controls;
the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
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;energy, such as nuclear, hydroelectric, wind or solar;
the effect of conservation efforts;
epidemics or pandemics;
technological advances affecting energy consumption and energy supply;
domestic and foreign governmental regulations and taxes;taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and
general economic conditions worldwide.
The long-term effects of these and other factors on the prices of crude oil and condensate, NGLs and natural gas and synthetic crude oil are uncertain. Historical declines in commodity prices have adversely affected our business by:
reducing the amount of crude oil and condensate, NGLs and natural gas and synthetic crude oil that we can produce economically;
reducing our revenues, operating income and cash flows;
causing us to reduce our capital expenditures, and delay or postpone some of our capital projects;
requiring us to impair the carrying value of our assets;
reducing the standardized measure of discounted future net cash flows relating to crude oil and condensate, NGLs and natural gas and synthetic crude oil;gas; and
increasing the costs of obtaining capital, such as equity and short- and long-term debt.
Future decreases in prices could have similar adverse effects on our business.
If crude oil and condensate, NGLs, natural gas and synthetic crude oil prices remain substantially below their 2014 highs or fall below current levels, it could adversely affect the abilities of our counterparties to perform their obligations to us, including abandonment obligations, which could negatively impact our financial results.
We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production, oil sands mining or transportation of crude oil and condensate, NGLs, natural gas and synthetic crude oil, with partners and other counterparties in order to share risks associated with those operations. In addition, we market our products to a variety of purchasers. If commodity prices remain at or fall below current levels, some of our counterparties may experience liquidity problems and may not be able to meet their financial and other obligations, including abandonment obligations, to us. The inability of our joint venture partners to fund their portion of the costs under our joint venture agreements, or the nonperformance by purchasers, contractors or other counterparties of their obligations to us, could negatively impact our operating results and cash flows.
Estimates of crude oil and condensate, NGLs and 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 reserves.
The proved reserve information included in this Annual Report on Form 10-K has been derived from engineering and geoscience estimates. Estimates of crude oil and condensate, NGLs and natural gas and synthetic crude oil reserves were prepared, in accordance with SEC regulations, by our in-house teams of reservoir engineers and geoscience professionals and were reviewed and approved by our Corporate Reserves Group. Prior to 2016, the synthetic crude oil reserves estimates were prepared by GLJ, aGroup and third-party consulting firm experienced in working with oil sands.consultants. Reserves were valued based on SEC pricing for the periods ended December 31, 2016, 20152019, 2018 and 2014,2017, as well as other conditions in existence at those dates. The table below provides the 20162019 SEC pricing for certain benchmark prices:
| | | | SEC Pricing 2016 | 2019 SEC Pricing |
WTI Crude oil (per bbl) | $ | 42.75 |
| $ | 55.69 |
|
Henry Hub natural gas (per mmbtu) | $ | 2.49 |
| $ | 2.58 |
|
Brent crude oil (per bbl) | $ | 43.53 |
| $ | 63.15 |
|
Mont Belvieu NGLs (per bbl) | $ | 15.89 |
| $ | 18.41 |
|
If commoditycrude oil prices were to significantly dropin the future average below average prices used to estimate 2016determine proved reserves (see table above), we would expect price related reserve revisions thatat December 31, 2019, it could have a material impactan adverse effect on our estimates of proved reserve volumes and the present value of our proved reserves. In this scenario, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserves or resource category.business. Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation, among other things.
Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of crude oil and condensate, NGLs and natural gas and bitumen that cannot be directly measured (bitumen is mined and then upgraded into synthetic crude oil.)measured. 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 analogous 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 impacts of regulation by governmental agencies;
assumptions concerning future operating costs, 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 and geoscientists, 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 estimated amounts:
the amount and timing of production;
the revenues and costs associated with that production; and
the amount and timing of future development expenditures.
If we are unsuccessful in acquiring or finding additional reserves, our future crude oil and condensate, NGLs and natural gas and synthetic crude oil production would decline, thereby reducing our cash flows and results of operations and impairing our financial condition.
The rate of production from crude oil and condensate, NGLs and natural gas and synthetic crude oil 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 willmay decline materially as crude oil and condensate, NGLs and natural gas and synthetic crude oil are produced. Accordingly, to the extent we are not successful in replacing the crude oil and condensate, NGLs and natural gas and synthetic crude oil we produce, our future revenues willmay decline. Creating and maintaining an inventory of prospects for future production depends on many factors, including:
obtaining rights to explore for, develop and produce crude oil and condensate, NGLs and natural gas and synthetic crude oil in promising areas;
drilling success;
the ability to complete long lead-time, capital-intensive projects timely and cost effectively;
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 crude oil and condensate, NGLs and natural gas involves numerous risks, including the risk that we may not encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
inflation in exploration and drilling costs;
fires, explosions, blowouts or surface cratering;
lack of, or disruption in, access to pipelines or other transportation methods; and
shortages or delays in the availability of services or delivery of equipment.
If crude oil and condensate, NGLs and natural gas prices decrease, it could adversely affect the abilities of our counterparties to perform their obligations to us which could negatively impact our financial results.
We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production, or transportation of crude oil and condensate, NGLs and natural gas, with partners, co-working interest owners, and other counterparties in order to share risks associated with those operations. In addition, we market our products to a variety of purchasers. If commodity prices decrease, some of our counterparties may experience liquidity problems and may not be able to meet their financial and other obligations to us. The inability of our joint venture partners or co-working interest owners to fund their portion of the costs under our joint venture agreements and joint operating agreements, or the nonperformance by purchasers, contractors or other counterparties of their obligations to us, could negatively impact our operating results and cash flows.
If we are unable to complete capital projects at their expected costs and in a timely manner, or if the market conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving drilling and completion activities, engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:
denial of or delay in receiving requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of components or construction materials;
increased costs or operational delays resulting from shortages of water;
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project’s debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
Any one or more of these factors could have a significant impact on our capital projects.
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.
We may incur substantial capital expenditures and operating costs as a result of compliance with and/orand changes in environmental, health, safety and security laws andlaw, regulations or requirements or initiatives, including those addressing the impact of global climate change, air emissions or water management, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Our businesses are currently subject to numerous laws, regulations and other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment such as the venting or flaring of natural gas, waste management, pollution prevention, greenhouse gas emissions, including carbon dioxide and methane, and the protection of endangered species as well as laws, regulations, and other requirements relating to public and employee safety and health and to facility security. Additionally, states in which we operate may impose additional regulations, legislation, or requirements or begin initiatives addressing the impact of global climate change, air emissions or water management. We have incurred and may continue to incur capital, operating and maintenance, and remediation expenditures as a result of these laws, regulations, and other requirements.requirements or initiatives that are being considered or otherwise implemented. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our operating results willcould be adversely affected. The specific impact of these laws, regulations, and other requirements may vary depending on a number of factors, including the age and location of operating facilities and production processes. We may also be required to make material expenditures to modify operations, install pollution control equipment, perform site clean-ups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows. We may become subject to liabilities that we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws, regulations, and other requirements could result in civil penalties or criminal fines and other enforcement actions against us.
We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. Our operations result in greenhouse gas emissions. Currently, various legislative or regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in countries where we operate, including the U.S., Canada, and the European Union. Internationally, the United Nations Framework Convention on Climate Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing global temperatures from rising more than 2 degrees Celsius. The agreement includes provisions that every country take some action to lower emissions, but there is no legal requirement for how or by what amount emissions should be lowered. The EPA has also finalized regulations targeting new sources of methane emissions from the oil and gas industry, and has issued requests for information on existing sources. Finalization of new legislation, regulations or international agreements in the future could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls at our facilities, and costs to administer and manage any potential greenhouse gas emissions or carbon trading or tax programs. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for crude oil and condensate, NGLs and natural gas, and synthetic crude oil, and create delays in our obtaining air pollution permits for new or modified facilities.
The potential adoption of federal, state and local legislative and regulatory initiatives related to hydraulic fracturing could result in increased compliance costs, operating restrictions or delays in the completion of oil and gas wells.
Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. Our business uses this technique extensively throughout our U.S. operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local-level laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. For example, the U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process, and may be expected to do so in future legislative sessions. Further, variousVarious state and local-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 2015
the Bureau of Land ManagementBLM issued a rule governing certain hydraulic fracturing practices on lands within their jurisdiction. Whilejurisdiction; however, this rule has been stayed nationwide by court ruling, further findings bywas rescinded in December 2017. This rescission is being judicially challenged before the court could result in additional changes to this new rule.U.S. District Court for the Northern District of California.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of crude oil and condensate, NGLs and natural gas, including from the shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local 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.
The potential adoption of federal, state and local legislative and regulatory initiatives intended to address potential induced seismic activity in the areas in which we operate could result in increased compliance costs, operating restrictions or delays in the completion of oil and gas wells.
State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. When caused by human activity, such events are called induced seismicity. Marathon does not currently own or operate water disposal wells in the current areas of interest but does contract for services that regularly inject produced water into underground injection wells. Separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to anomalous seismic events. Marathon does useuses hydraulic fracturing techniques throughout its U.S. operations.
While the scientific community and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity, some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, Oklahoma has taken numerous regulatory actions in response to concerns related to the operation of produced water disposal wells and induced seismicity, and has issued guidelines to operators in certain areas of the State curtailing injection of produced water due to seismic concerns. Marathon does not currently own or operate injection wells or contract for such services in these areas. Further, Oklahoma recently issued guidelines to operators for management of anomalous seismicity that may be related to hydraulic fracturing activities in the SCOOP/STACK area. In addition, a number of lawsuits have been filed in Oklahoma alleging damage from seismicity relating to disposal well operations. Marathon has not been named in any of those lawsuits.
Increased seismicity in Oklahoma or other areas could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and gas activities.
Worldwide political and economic developments and changes in law could adversely affect our
Our offshore operations and materially reduce our profitability and cash flows.
Local political and economic factors in global markets could have a material adverse effect on us. A total of 45% of our crude oil and condensate, NGLs, natural gas and synthetic crude oil volumes related to continuing operations in 2016 was derived from production outside the U.S. and 55% of our proved crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves as of December 31, 2016 were located outside the U.S. All of our synthetic crude oil production and proved reserves are located in Canada. We are, therefore, subject to the political, geographic and economicinvolve special risks and possible terrorist activities or other armed conflict attendant to doing business within or outside of the U.S. There are many risks associated with operations in countries such as E.G., Gabon, the Kurdistan Region of Iraq and Libya, and in global markets including:
changes in governmental policies relating to crude oil and condensate, NGLs, natural gas or synthetic crude oil and taxation;
other political, economic or diplomatic developments and international monetary fluctuations;
political and economic instability, war, acts of terrorism, armed conflict and civil disturbances;
the possibility that a government may seize our property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens; and
fluctuating currency values, hard currency shortages and currency controls.
For the past several years, there have been varying degrees of political instability and public protests, including demonstrations which have been marked by violence and numerous incidences of terrorist acts, within some countries in the Middle East, including Bahrain, Egypt, Iraq, Libya, Syria, Tunisia and Yemen. Some political regimes in these countries are threatened or have changed as a result of such unrest.
If such unrest continues to spread, conflicts could result in civil wars, regional conflicts, and regime changes resulting in governments that are hostile to the U.S. These may have the following results, among others:
volatility in global crude oil prices which could negatively impact us.
Offshore operations present technological challenges and operating risks because of the global economy,marine environment. Activities in offshore operations may pose risks because of the physical distance to oilfield service infrastructure and service providers. Environmental remediation and other costs resulting from spills or releases may result in slower economic growth ratessubstantial liabilities.
Our business could be negatively impacted by cyberattacks targeting our computer and reduced demand for our products;
negative impact on the world crude oil supply if transportation avenues are disrupted;
security concerns leading to the prolonged evacuationtelecommunications systems and infrastructure, or targeting those of our personnel;third-party service providers.
damageOur business, like other companies in the oil and gas industry, has become increasingly dependent on digital technologies, including technologies that are managed by third-party service providers on whom we rely to help us collect, host or the inability to access, production facilities or other operating assets;process information. Such technologies are integrated into our business operations and
inability used as a part of our serviceproduction and equipment providers to deliver items necessary for us to conduct our operations.
Continued hostilities in the Middle East and the occurrence or threat of future terrorist attacks, or other armed conflict, could adversely affect the economies of the U.S. and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. These risks could lead to increased volatility in prices for crude oil and condensate, NGLs, natural gas and synthetic crude oil. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate.
Actions of governments through tax legislation and other changes in law, executive order and commercial restrictions could reduce our operating profitability, bothdistribution systems in the U.S. and abroad. The U.S. government canabroad, including those systems used to transport production to market, to enable communications, and to provide a host of other support services for our business. Use of the internet and other public networks for communications, services, and storage, including “cloud” computing, exposes all users (including our business) to cybersecurity risks.
While we and our third-party service providers commit resources to the design, implementation, and monitoring of our information systems, there is no guarantee that our security measures will provide absolute security. Despite these security measures, we may not be able to anticipate, detect, or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or restrict us from doing businessmay not be recognized until launched, and because attackers are increasingly using techniques designed to circumvent controls and avoid detection. We and our third-party service providers may therefore be vulnerable to security events that are beyond our control, and we may be the target of cyber-attacks, as well as physical attacks, which could result in foreign countries. These restrictionsinformation security breaches and thosesignificant disruption to our business. Our information systems and related infrastructure have experienced attempted and actual minor breaches of foreign governments haveour cybersecurity in the past, limitedbut we have not suffered any losses or breaches which had a material effect on our abilitybusiness, operations or reputation relating to operate in,such attacks; however, there is no assurance that we will not suffer such losses or gain access to, opportunities in various countries and will continue to do sobreaches in the future. Changes in law could
As cyberattacks continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to investigate and remediate any information systems and related infrastructure security vulnerabilities. We may also adversely affect our results, including new regulations resulting in higher costsbe subject to transport our production by pipeline, rail car, truckregulatory investigations or vessel or the adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information or that could cause us to violate the non-disclosure laws of other countries.litigation relating from cybersecurity issues.
Our level of indebtedness may limit our liquidity and financial flexibility.
As of December 31, 2016,2019, our total debt was $7.3$5.5 billion, of which $686 millionand our next debt maturity is our $1.0 billion 2.8% senior unsecured notes due within 12 months.in 2022. Our indebtedness could have important consequences to our business, including, but not limited to, the following:
we may be more vulnerable to general adverse economic and industry conditions;
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
our flexibility in planning for, or reacting to, changes in our industry may be limited;
a financial covenant in our Credit Agreement stipulates that our total debt to capitalization ratio will not exceed 65% as of the last day of any fiscal quarter, and if exceeded, may make additional borrowings more expensive and affect our ability to plan for and react to changes in the economy and our industry;
we may be at a competitive disadvantage as compared to similar companies that have less debt; and
additional financing in the future for working capital, capital expenditures, acquisitions or development activities, general corporate or other purposes may have higher costs and more restrictive covenants.
We may incur additional debt in order to fund our capital expenditures, acquisitions or development activities, or for general corporate or other purposes. A higher level of indebtedness increases the risk that our financial flexibility may deteriorate. Our ability to meet our debt obligations and service our debt depends on future performance. General economic conditions, crude oil and condensate, NGLs and natural gas and synthetic crude oil prices, and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt. See Item 8. Financial Statements and Supplementary Data – Note 17 to the consolidated financial statements for a discussion of debt obligations. A further downgradeDifficulty in accessing capital or a significant increase in our credit rating could negatively impact our costcosts of and ability to accessaccessing capital which could adversely affect our business.
We receive debt ratings from the major credit rating agencies in the United States. Due to the declinevolatility in crude oil and U.S. natural gas prices in recent years, credit rating agencies reviewedreview companies in the energy industry periodically, including us. In the first quarter of 2016,At December 31, 2019, our corporate credit rating was downgraded byratings were: Standard & Poor'sPoor’s Global Ratings to BBB- (stable) fromServices BBB (stable), by; Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody'sMoody’s Investor Services, Inc. to Ba1 (negative) from Baa1Baa3 (stable). On October 11, 2016 Moody's subsequently revised their outlook of our corporate credit rating to stable from negative. The credit rating process is contingent upon a number of factors, many of which are beyond our control. A further downgrade of our credit ratings or other influences, including third-party groups promoting the divestment of fossil fuel equities or pressuring financial services companies to limit or curtail activities with fossil fuel companies, could negatively impact our cost of capital and our ability to access the capital markets, increase the interest rate and fees we pay on our revolving credit facility, and may limit or reduce credit lines with our bank counterparties. We could also be required to post letters of credit or other forms of collateral for certain contractual obligations, which could increase our costs and decrease our liquidity or letter of credit capacity under our unsecured revolving credit facility. Limitations on our ability to access capital could adversely impact the level of our capital spending program,budget, our ability to manage our debt maturities, or our flexibility to react to changing economic and business conditions.
Our commodity price risk management activities may prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty risk.
Global commodity prices are volatile. In order to mitigate commodity price volatility and increase the predictability of cash flows related to the marketing of our crude oil, NGLs, and natural gas, we, from time to time, enter into crude oil, NGLS, and natural gas hedging arrangements with respect to a portion of our expected production. While hedging arrangements are intended to mitigate commodity price volatility, we may be prevented from fully realizing the benefits of price increases above the price levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.Risk. OurPolitical and economic developments and changes in law or policy could adversely affect our operations and materially reduce our profitability and cash flows.
Local political and economic factors in U.S. and global markets could have a material adverse effect on us. We are subject to the political, geographic and economic risks and possible terrorist activities or other armed conflict attendant to doing business could be negatively impacted by cyber-attacks targetingwithin or outside of the U.S. There are also many risks associated with operations in E.G. including the possibility that
the government may seize our computer and telecommunications systems and infrastructure.property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens.
Our business, like other companiesChanges in the oilU.S. or global political and gas industry, has become increasingly dependent on digital technologies. Such technologies are integrated intoeconomic environment or any U.S. or global hostility or the occurrence or threat of future terrorist attacks, or other armed conflict, could adversely affect the economies of the U.S. and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our business operationsrevenues and used as a part ofmargins to decline and limit our future growth prospects. These risks could lead to increased volatility in prices for crude oil and condensate, NGLs and natural gasgas. In addition, these risks could increase instability in the financial and synthetic crude oilinsurance markets and make it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate. These risks could also cause damage to, or the inability to access, production facilities or other operating assets and distribution systemscould limit our service and equipment providers ability to deliver items necessary for us to conduct our operations.
Actions of governments through tax legislation or interpretations of tax law, and other changes in law, executive order and commercial restrictions could reduce our operating profitability, both in the U.S. and abroad, includingabroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those systems used to transport production to market. Use of the internet and other public networks for communications, services, and storage, including “cloud” computing, exposes users (including our business) to cybersecurity risks. While our information systems and related infrastructure experienced attempted and actual minor breaches of our cybersecurityforeign governments have in the past we have not suffered any losseslimited our ability to operate in, or breaches which had a material effect on our business, operations or reputation relatinggain access to, such attacks; however, there is no assurance that weopportunities in various countries and will not suffer such losses or breachescontinue to do so in the future. As cyber-attacks continueChanges in U.S. or foreign laws could also adversely affect our results, including new regulations resulting in higher costs to evolve, we may be requiredtransport our production by pipeline, rail car, truck or vessel or the adoption of government payment transparency regulations that could require us to expend significant additional resourcesdisclose competitively sensitive commercial information or that could cause us to continue to modify or enhance our protective measures or to investigate and remediate any information systems and related infrastructure security vulnerabilities.violate the non-disclosure laws of other countries.
Our operations may be adversely affected by pipeline, rail and other transportation capacity constraints.
The marketability of our production depends in part on the availability, proximity, and capacity of gathering and transportation pipeline facilities, rail cars, trucks and vessels. If any pipelines, rail cars, trucks or vessels become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport our crude oil and condensate, NGLs and natural gas, and synthetic crude oil, which could increase the costs and/or reduce the revenues we might obtain from the sale of our production. Both the cost and availability of pipelines, rail cars, trucks, or vessels to transport our crude oilproduction could be adversely impacted by new and expected state or federal regulations relating to transportation of crude oil.
If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.
We typically seek the acquisition of crude oil and condensate, NGLs, natural gas properties and synthetic crude oil properties.leases. Although we perform reviews of properties to be acquired in a manner that we believe is diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor may they permit us to become sufficiently familiar with the properties in order to fully assess possible deficiencies and potential problems. Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements. Moreover, there are numerous uncertainties inherent in estimating quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves (as previously discussed), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired
properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.
We operate in a highly competitive industry, and many of our competitors are larger and have available resources in excess of our own.
The oil and gas industry is highly competitive, and many competitors, including major integrated and independent oil and gas companies, as well as national oil companies, are larger and have substantially greater resources at their disposal than we do. We compete with these companies for the acquisition of oil and natural gas leases and other properties. We also compete with these companies for equipment and personnel, including petroleum engineers, geologists, geophysicists and other specialists, required to develop and operate those properties and in the marketing of crude oil and condensate, NGLs and natural gas and synthetic crude oil to end-users. Such competition can significantly increase costs and affect the availability of resources, which could provide our larger competitors a competitive advantage when acquiring equipment, leases and other properties. They may also be able to use their greater resources to attract and retain experienced personnel.
Many of our major projects and operations are conducted jointly with partners,other parties, which may decrease our ability to manage risk.
We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production or oil sands mining, with partnersother parties in order to share risks associated with those operations. However, these arrangements also may decrease our ability to manage risks and costs, particularly where we are not the operator. We could have limited influence over and control of the behaviors and performance of these operations. In addition, misconduct, fraud, noncompliance with applicable laws and regulations or improper activities by or on behalf of one or more of our partners or co-working interest owners could have a significant negative impact on our business and reputation.
Our operations are subject to business interruptions and casualty losses. We do not insure against all potential losses and therefore we could be seriously harmed by unexpected liabilities and increased costs.
Our North America E&PUnited States and International E&P operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, spills, tornadoes, hurricanes and other adverse weather, tsunamis, earthquakes, volcanic eruptions or nuclear or other disasters, labor disputes and accidents. Our OSM operations are subject to business interruptions due to breakdown or failure of equipment or processes and unplanned events such as fires, earthquakes, explosions or other interruptions. These same risks can be applied to the third-parties which transport our products from our facilities. A prolonged disruption in the ability of any pipelines, rail cars, trucks, or vessels to transport our production could contribute to a business interruption or increase costs.
Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. Various hazards have adversely affected us in the past, and damages resulting from a catastrophic occurrence in the future involving us or any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially large claims or in our being assessed potentially substantial fines by governmental authorities. We maintain insurance against many, but not all, potential losses or liabilities arising from operating hazards in amounts that we believe to be prudent. Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we have maintained insurance coverage for physical damage andincluding at times resulting business interruption to our major onshore and offshore facilities, with significant self-insured retentions. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for our insurance policies will change over time and could escalate. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, due to historical hurricane activity, the availability of insurance coverage for windstorms has changed and, in some instances, it is uneconomical. As a result, our exposure to losses from future windstorm activity has increased.
Litigation by private plaintiffs or government officials or entities could adversely affect our performance.
We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, privacy laws, contract disputes, royalty disputes or any other laws or regulations that apply to our operations. In some cases the plaintiff or plaintiffs seek alleged damages involving large classes of potential litigants, and may allege damages relating to extended periods of time or other alleged facts and circumstances. If we are not able to successfully defend such claims, they may result in substantial liability. We do not have insurance covering all of these potential liabilities. In addition to substantial liability, litigation may also seek injunctive relief which could have an adverse effect on our future operations.
In connection with our separation from MPC, MPC agreed to indemnify us for certain liabilities. However, there can be no assurance that the indemnity will be sufficient to protect us against the full amount of such liabilities, or that MPC’s ability to satisfy its indemnification obligations will not be impairedFor instance, government entities and other groups have filed lawsuits in the future.
Pursuant to the Separation and Distribution Agreement and the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC agreed to indemnify us for certain liabilities. However, third parties could seekseveral states seeking to hold us responsiblea wide variety of companies that produce fossil fuels liable for anythe alleged impacts of the liabilities that MPC agreedgreenhouse gas emissions and other alleged harm attributable to retain or assume, and there can be no assurance that the indemnification from MPC will be sufficient to protect us against the full amount of such liabilities, or that MPC will be able to fully satisfy its indemnification obligations. In addition, even if we ultimately succeed in recovering from MPC any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.
those fuels. The spin-off could result in substantial tax liability.
We obtained a private letter ruling from the IRS substantially to the effect that the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). If the factual assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in any material respect, then we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whether a distribution such as the spin-off satisfies certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Rather, the private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling. In connection with the spin-off, we also obtained an opinion of outside counsel, substantially to the effect that, the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the Code. The opinion relied on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by MPC and us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion is not binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail.
If, notwithstanding receipt of the private letter ruling and opinion of counsel, the spin-off were determined not to qualify under Section 355 of the Code, each U.S. holder of our common stock who received shares of MPC common stock in the spin-off would generally be treated as receiving a taxable distribution of property in an amount equal to the fair market value of the shares of MPC common stock received. That distribution would be taxable to each such stockholder as a dividend to the extent of our accumulated earnings and profits as of the effective date of the spin-off. For each such stockholder, any amount that exceeded those earnings and profits would be treated first as a non-taxable return of capital to the extent of such stockholder’s tax basis in its shares of our common stock with any remaining amount being taxed as a capital gain. We would be subject to tax as if we had sold all the outstanding shares of MPC common stock in a taxable sale for their fair market value and would recognize taxable gain in an amount equal to the excess of the fair market value of such shares over our tax basis in such shares.
Under the terms of the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC is generally responsible for any taxes imposed on MPC or us and our subsidiaries in the event that the spin-off and/or certain related transactions were to fail to qualify for tax-free treatmentlawsuits allege damages as a result of actions taken, or breachesglobal warming and the plaintiffs are seeking unspecified damages and abatement under various theories. Marathon Oil has been named as a defendant in several of representationsthese lawsuits, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. The ultimate outcome and warranties madeimpact to us
cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the Tax Sharing Agreement, by MPC or any of its affiliates. However, if the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment because of actions or failures to act by us or any of our affiliates, we would be responsible for all such taxes.
We may issue preferred stock whose terms could dilute the voting power or reduce the value of Marathon Oil common stock.
Our restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such preferences, powers and relative, participating, optional and other rights, including preferences over Marathon Oil common stock respecting dividends and distributions, as our Board of Directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of Marathon Oil common stock. For example, we could grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of the common stock.future.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The location and general character of our principal crude oil and condensate, NGLs and natural gas properties, oil sands mining properties and facilities, and other important physical properties have been described by segment under Item 1. Business.
Estimated net proved crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves are set forth in Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves. The basis for estimating these reserves is discussed in Item 1. Business – Reserves.
Item 3. Legal Proceedings
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
See Item 8. Financial Statements and Supplementary Data – Note 25 to the consolidated financial statements for a description of such legal and administrative proceedings. Environmental Proceedings
The following is a summary of certain proceedings involving us that were pending or contemplated as of December 31, 20162019, under federal state and internationalstate environmental laws. Except
Government entities have filed lawsuits in several states seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions and other alleged harm attributable to those fuels. The lawsuits allege damages as described herein, it is not possible to predict accuratelya result of global warming and the plaintiffs are seeking unspecified damages and abatement under various theories. Marathon Oil has been named as a defendant in several of these lawsuits, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. While the ultimate outcome of these matters; however, management’s belief set forth in the first paragraph under Legal Proceedings above takes such matters into account.
In July 2015,and impact to us cannot be predicted with certainty, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations. We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the fourth quarter of 2016 that includes a base penalty of $294,000 that will be reduced under the terms by mitigating corrective actions. We do not believe that any penalties or corrective action expenditures that may result from this matterthe claims made against us are without merit and will not have a material adverse effect on our consolidated financial position, results of operationoperations or cash flows.
In December 2016, we received a letter from the U.K. Department for Business, Energy and Industrial Strategy (“BEIS”) notifying us that they intend to impose a fine of €630,906 for a self-disclosed underreporting of generated carbon dioxide ("CO2") emissions. We made representations requesting a reduction in this proposed penalty on January 10, 2017. We do not believe that any penalties that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows. flow.
As of December 31, 2016,2019, we have sites across the country where remediation is being sought under environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation. Based on currently available information the accrued amount to address the clean-up and remediation costs connected with these sites is not material.
In December 2019, we received a Notice of Violation from the North Dakota Department of Environmental Quality and a verbal notice of enforcement in January 2020 from the North Dakota Industrial Commission, related to a release of produced water in North Dakota. In January 2020, we received a Notice of Violation from the EPA related to the Clean Air Act. Each enforcement action will likely result in monetary sanctions in excess of $100,000; however, we do not believe these enforcement actions would have a material adverse effect on our consolidated financial position, results of operations or cash flow.
If our assumptions relating to these costs prove to be inaccurate, future expenditures may exceed our accrued amounts.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The principal market on which Marathon Oil common stock is traded is the New York Stock Exchange ("NYSE"(“NYSE”), and is traded under the trading symbol ‘MRO’. As of January 31, 2017,2020, there were 35,29428,346 registered holders of Marathon Oil common stock.
The following table reflects high and low sales prices for Marathon Oil common stock and the related dividend per share by quarter for the past two years:
|
| | | | | | | | | | | |
| | 2016 | | 2015 |
| (Dollars per share) | High Price | | Low Price | | Dividends | | High Price | | Low Price | | Dividends |
| First Quarter | $12.82 | | $6.73 | | $0.05 | | $29.63 | | $25.47 | | $0.21 |
| Second Quarter | $15.27 | | $10.53 | | $0.05 | | $31.19 | | $25.92 | | $0.21 |
| Third Quarter | $16.80 | | $12.90 | | $0.05 | | $25.79 | | $14.04 | | $0.21 |
| Fourth Quarter | $18.80 | | $12.78 | | $0.05 | | $20.18 | | $12.38 | | $0.05 |
| Full Year | $18.80 | | $6.73 | | $0.20 | | $31.19 | | $12.38 | | $0.68 |
Dividends – Our Board of Directors intends to declare and pay dividends on Marathon Oil common stock based on our financial condition and results of operations, although it has no obligation under Delaware law or the Restated Certificaterestated certificate of Incorporationincorporation to do so. In determining our dividend policy, the Board of Directors will rely on our consolidated financial statements. Dividends on Marathon Oil common stock are limited to our legally available funds.
The following table provides information about purchases by Marathon Oil and its affiliated purchaser, during the quarter ended December 31, 2016,2019, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:
|
| | | | | | | | | | | | |
| Period | Total Number of Shares Purchased(a) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(b) | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b) |
| 10/01/16 – 10/31/16 | 51,396 |
| | $15.96 | | — |
| | $ | 1,500,285,529 |
|
| 11/01/16 – 11/30/16 | 919 |
| | $13.20 | | — |
| | $ | 1,500,285,529 |
|
| 12/01/16 – 12/31/16 | — |
| | — |
| | — |
| | $ | 1,500,285,529 |
|
| Total | 52,315 |
| | $15.91 | | — |
| | |
|
| | | | | | | | | | | | | |
| Period | Total Number of Shares Purchased(a) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(b) | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b) |
| 10/01/2019 - 10/31/2019 | 1,619,594 |
| | $ | 11.65 |
| | 1,567,951 |
| | $ | 1,452,022,646 |
|
| 11/01/2019 - 11/30/2019 | 155,575 |
| | $ | 11.56 |
| | 150,386 |
| | $ | 1,450,286,198 |
|
| 12/01/2019 - 12/31/2019 | 3,515,651 |
| | $ | 12.86 |
| | 3,514,490 |
| | $ | 1,405,076,614 |
|
| Total | 5,290,820 |
| | $ | 12.45 |
| | 5,232,827 |
| | |
| |
(a) | 52,31557,993 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements. |
| |
(b) | In January 2006, we announced a $2.0$2 billion share repurchase program. Our Board of directorsDirectors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0$2 billion in July 2007, and by $1.2 billion in December 2013 and by $950 million in July 2019 for a total authorized amount of $6.2$7.2 billion. The remaining share repurchase authorization as of December 31, 2016 is $1.5 billion. No repurchases were made under the program in 2016. |
Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination by the Board of Directors prior to completion. Shares repurchased as of December 31, 2019 were held as treasury stock.
Item 6. Selected Financial Data
| | | | Year Ended December 31, | Year Ended December 31, |
| (In millions, except per share data) | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
Statement of Income Data(c)(a) | | |
| | | | | | | | |
| | | | | | |
| Revenues | $ | 4,031 |
| | $ | 5,522 |
| | $ | 10,846 |
| | $ | 11,325 |
| | $ | 11,966 |
| |
| Total revenues and other income | | $ | 5,190 |
| | $ | 6,582 |
| | $ | 4,765 |
| | $ | 3,787 |
| | $ | 4,953 |
|
| Income (loss) from continuing operations | (2,140 | ) | | (2,204 | ) | | 969 |
| | 931 |
| | 856 |
| 480 |
| | 1,096 |
| | (830 | ) | | (2,087 | ) | | (1,701 | ) |
Discontinued operations(b) | | — |
| | — |
| | (4,893 | ) | | (53 | ) | | (503 | ) |
| Net income (loss) | (2,140 | ) | | (2,204 | ) | | 3,046 |
| | 1,753 |
| | 1,582 |
| 480 |
| | 1,096 |
| | (5,723 | ) | | (2,140 | ) | | (2,204 | ) |
Per Share Data(a)(b)(c) | | | | | | | | | | |
Per Share Data(a) | | | | | | | | | | |
| Basic: | | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 1.42 |
| | $ | 1.32 |
| | $ | 1.21 |
| $ | 0.59 |
| | $ | 1.30 |
| | $ | (0.97 | ) | | $ | (2.55 | ) | | $ | (2.51 | ) |
Discontinued operations(b) | | $ | — |
| | $ | — |
| | $ | (5.76 | ) | | $ | (0.06 | ) | | $ | (0.75 | ) |
| Net income (loss) | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 4.48 |
| | $ | 2.49 |
| | $ | 2.24 |
| $ | 0.59 |
| | $ | 1.30 |
| | $ | (6.73 | ) | | $ | (2.61 | ) | | $ | (3.26 | ) |
| Diluted: | | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 1.42 |
| | $ | 1.31 |
| | $ | 1.21 |
| $ | 0.59 |
| | $ | 1.29 |
| | $ | (0.97 | ) | | $ | (2.55 | ) | | $ | (2.51 | ) |
Discontinued operations(b) | | $ | — |
| | $ | — |
| | $ | (5.76 | ) | | $ | (0.06 | ) | | $ | (0.75 | ) |
| Net income (loss) | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 4.46 |
| | $ | 2.47 |
| | $ | 2.23 |
| $ | 0.59 |
| | $ | 1.29 |
| | $ | (6.73 | ) | | $ | (2.61 | ) | | $ | (3.26 | ) |
Statement of Cash Flows Data(b) | | | | | | | | | | |
| Statement of Cash Flows Data | | | | | | | | | | |
| Additions to property, plant and equipment related to continuing operations | $ | 1,245 |
| | $ | 3,476 |
| | $ | 5,160 |
| | $ | 4,443 |
| | $ | 4,361 |
| $ | (2,550 | ) | | $ | (2,753 | ) | | $ | (1,974 | ) | | $ | (1,204 | ) | | $ | (3,485 | ) |
| Dividends paid | 162 |
| | 460 |
| | 543 |
| | 508 |
| | 480 |
| (162 | ) | | (169 | ) | | (170 | ) | | (162 | ) | | (460 | ) |
| Dividends per share | $0.20 | | $0.68 | | $0.80 | | $0.72 | | $0.68 | $ | 0.20 |
| | $ | 0.20 |
| | $ | 0.20 |
| | $ | 0.20 |
| | $ | 0.68 |
|
| Balance Sheet Data at December 31 | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 31,094 |
| | $ | 32,311 |
| | $ | 35,983 |
| | $ | 35,588 |
| | $ | 35,269 |
| $ | 20,245 |
| | $ | 21,321 |
| | $ | 22,012 |
| | $ | 31,094 |
| | $ | 32,311 |
|
| Total long-term debt, including capitalized leases | 6,589 |
| | 7,276 |
| | 5,295 |
| | 6,362 |
| | 6,475 |
| 5,501 |
| | 5,499 |
| | 5,494 |
| | 6,581 |
| | 7,268 |
|
Leases:(c) | | | | | | | | | | |
| ROU asset | | 199 |
| | — |
| | — |
| | — |
| | — |
|
| Current portion of long-term lease liability | | 101 |
| | 62 |
| | 29 |
| | 30 |
| | 31 |
|
| Long-term lease liability | | 107 |
| | 155 |
| | 90 |
| | 146 |
| | 147 |
|
| |
(a) | Includes impairments to producing properties of $67 million, $412 million, $132 million, $96 million and $371 million in 2016, 2015, 2014, 2013 and 2012 and impairments to unproved properties of $195 million, $964 million, $306 million, $572 million and $227 million in 2016, 2015, 2014, 2013 and 2012 (see Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements). Includes a goodwill impairment of $340 million in 2015 related to the N.A. E&P reporting unit. (see Item 8. Financial Statements and Supplementary Data – Note 14 to the consolidated financial statements). |
| |
(b)
| We closed the sale of our Angola assets and our Norway business in 2014 (see Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements). The applicable periods have been recast to reflect as discontinued operations. |
| |
(c)
| December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million (seemillion. |
| |
(b) | We closed on the sale of our Canada business in 2017 and have reflected this business as Discontinued Operations in the periods presented. |
| |
(c) | Note the prospective adoption of the lease accounting standard on January 1, 2019. Therefore, current and long-term portions for leases in years 2018 through 2015 do not reflect adoption of the new lease accounting standard. See Item 8. Financial Statements and Supplementary Data – - Note 92 and Note 13 to the consolidated financial statements).statements for further information. |
Supplemental information affecting comparability of selected financial data is shown below.
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Proved property impairment | $ | 24 |
| | $ | 75 |
| | $ | 229 |
| | $ | 67 |
| | $ | 381 |
|
| Unproved property impairment | 98 |
| | 208 |
| | 246 |
| | 195 |
| | 655 |
|
| Goodwill impairment | — |
| | — |
| | — |
| | — |
| | 340 |
|
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the information under Item 8. Financial Statements and Supplementary Data and the other financial information found elsewhere in this Form 10-K. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See "Disclosures“Disclosures Regarding Forward-Looking Statements"Statements” (immediately prior to Part I) and Item 1A. Risk Factors.Factors. Each of our two reportable operating segments isare organized by geographic location and managed based upon both geographic location andaccording to the nature of the products and services it offers:offered.
North America E&PUnited States – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;the United States;
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North Americathe United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Executive SummaryOverview
During 2016 we continuedWe are an independent exploration and production company based in Houston, Texas. Our strategy is to deliver competitive and improving corporate level returns by focusing our efforts on capital and operating cost management, simplifying and concentrating our portfolio, and maintaining balance sheet strength and flexibility. In 2016, we achieved $1.3 billion of non-core asset sales which allowed us to be opportunistic with a high quality acquisitioninvestment in Oklahoma's STACK play. As a result, we further simplified and concentrated our portfolio to the lower cost, higher margin assets in the U.S. resource plays. Looking ahead, our goal is to return to annual production growth for both the company and U.S. resource plays within cash flows.
Our 2016 accomplishments are summarized below:
Relentless focus on costs
Reduced 2016 Capital Program spend to $1.1 billion, below $1.4 billion original budget
Reduced production expenses per boe in 2016
◦North America E&P - 19% reduction to $5.96 per boe
◦International E&P - 16% reduction to $5.05 per boe
◦Oil Sands Mining - 24% reduction to $27.89 per boe
Reduced average completed well costs in 2016 by 22% in the Oklahoma Resource Basins and 26% in(the Eagle Ford comparedin Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico). We will continue to 2015be guided by maintaining a strong balance sheet, prioritizing sustainable cash flow over a wide range of commodity prices and returning capital to shareholders.
Decreased total general and administrative costs by 18% in 2016 compared to last yearKey 2019 highlights include:
Simplifying and concentrating our portfolio
Closed on the Oklahoma STACK acquisition of 61,000 net acres
Concentrated asset base to lower cost, higher margin resource plays by closing on $1.3 billion in non-core asset sales
Strengthened balance sheet
Increased our liquidity to $5.8 billion at December 31, 2016 compared to $4.2 billion at December 31, 2015
◦Raised net $1.2 billion from an equity offering inIn the first quarter of 2016
◦Expanded2019, we closed the capacitysale of the revolving credit facility from $3.0 billion to $3.3 billionour working interest in the firstDroshky field (Gulf of Mexico) for a pre-tax gain of $42 million.
In the second quarter of 20162019, we closed on the sale of our 15% non-operated interest in the Atrush block in Kurdistan for proceeds of $63 million, before closing adjustments.
ImprovedIn July 2019, we closed on the sale of our cash-adjusted debt-to-capital ratio to 21% at December 31, 2016 compared toU.K. business for proceeds of approximately $95 million, reflecting the assumption by the buyer of working capital and cash equivalent balances, asset retirement obligations of $966 million, as well as pension obligations.
In the third quarter of 2019, we secured a 25% at December 31, 2015non-operated working interest partner in our Louisiana Austin Chalk acreage.
Profitable growth within cash flows
Increased U.S. resource play rig count by 50 percent inDuring the fourth quarter of 2016, while remaining under budget, and positioning to resume sequential production growth in the resource plays in the first half of 2017
Our 2016 significant operational updates and financial results included the following:
Operational Updates
Total company2019, we acquired approximately 18,000 net sales volumes of 404 mboed in 2016
We ended 2016 with 2,096 mmboe of proved reserves, with extension, discovery and other additions of 304 mmboe
Increased net sales volumes by 40% in the Oklahoma Resource Basins as we increased activity on our STACK and SCOOP acreage
Delivered basin-leading well results in the Bakken supported by enhanced completions and advantaged geology, while reducing production expense by approximately 30% year-over-year
Achieved record drilling efficiencyacres in the Eagle Ford for $191 million and record lowapproximately 40,000 acres in a Texas Delaware oil play in West Texas for $106 million.
Strengthened balance sheet and liquidity
In July 2019, the Board of Directors authorized a $950 million increase to our share purchase program. During 2019, we returned additional capital to shareholders by acquiring 24 million of common shares at a cost of $345 million, with $1.4 billion of repurchase authorization remaining at year-end.
Cash provided by operating activities from continuing operations decreased by 15%, compared to the same period last year, to $2.7 billion primarily as a result of decreased commodity price realizations.
During the fourth quarter 2019, completed costs during 2016 while continuingthree leverage neutral finance transactions that extend maturities, generate annual cash cost savings, and reflect our commitment to execute high intensity completionsmaintaining a strong balance sheet and investment grade credit ratings at all primary rating agencies.
Completed the Alba B3 Compression project in E.G., extending plateau productionFinancial and field lifeoperational results
Resumed liftings in Libya in December 2016; Force Majeure lifted in September 2016
EndedTotal net sales volumes for the year with 12 rigs operatingwere 414 mboed, including 323 mboed in the U.S. resource playsOur U.S. net sales volumes increased 8% and our wells to sales increased 11% compared to 2018.
Financial resultsAdded proved reserves of 110 mmboe for a reserve replacement ratio of 74%.
2016Our net lossincome per share from continuing operations was $0.59 in 2019 as compared to a net income per share of $2.1 billion versus 2015$1.30 last year. Included in 2019 net loss of $2.2 billion; included in the loss for 2016:income are:
| |
| ◦ | Non-cash charge relatedA decrease in revenues of approximately 14% compared to 2018, as a valuation allowanceresult of decreased commodity price realizations and lower net sales volumes in our International segment due to dispositions, partially offset by |
increased net sales volumes in the U.S.
| |
| ◦ | Our net gain on our deferred taxdisposal of assets of $1.3 billion (see Item 8. Financial Statements and Supplementary Data – Note 9decreased $269 million in 2019 primarily due to the consolidated financial statements)sale of our Libya subsidiary for a pre-tax gain of $255 million in 2018. |
| |
| ◦ | Reduction in segment sales revenuesExploration and impairment expenses decreased by $191 million to $173 million, year over year, primarily a result of $1.2 billion with a nearly even split between lower price realizations and decreased sales volumes |
| |
◦ | Non-cash charge of $262 million fornon-cash impairment charges on proved and unproved property impairments (Seeproperties in the prior year. See Item 8. Financial Statements and Supplementary Data - Note 1311 to the consolidated financial statementstatements for additional detail)further detail. |
| |
| ◦ | Production expense decreased 15% during 2019 as a result of dispositions in our International segment and our focus on reducing costs in our U.S. resource plays. |
| |
| ◦ | Income tax benefit was $88 million in 2019 primarily as a result of the $126 million settlement of the 2010-2011 U.S. Federal Tax Audit, primarily related to AMT credits. See Consolidated Results of Operations: 2019 compared to 2018 section below and Item 8. Financial Statements and Supplementary Data - Note 8 and Note 25 to the consolidated financial statements for further detail. |
Net cash provided by operating activities in 2016 was $1.1 billion, compared to $1.6 billion in 2015, reflecting the lower segment revenues
Outlook
Capital ProgramBudget
OurOn February 12, 2020, we announced our total 2020 Capital Budget of $2.4 billion, which includes $2.2 billion 2017 Capital Program will have over 90%of development capital and $200 million to fund REx. Our 2020 development capital budget is weighted towards the four U.S. resource plays with approximately 70% allocated to the higher return, lower cost U.S. resource plays. We intend to ramp up activity in Oklahoma as we progress our STACK and SCOOP acreage toward full field development, and in the Bakken where our enhanced completions recently achieved record results. Additionally, our Eagle Ford asset will continue to focus on driving capital efficiencies.and Bakken and the remaining allocated between the Northern Delaware and Oklahoma.
Our 20172020 Capital ProgramBudget is broken down by reportable operating segment in the table below:
|
| | | |
| (In millions) | Capital Program |
| North America E&P | $ | 2,107 |
|
| International E&P | 64 |
|
| Oil Sands Mining | 29 |
|
| Segment total | 2,200 |
|
| Corporate and other | 25 |
|
| Total Capital Program | $ | 2,225 |
|
|
| | | |
| (In millions) | Capital Budget |
United States(a) | $ | 2,370 |
|
International and corporate other(b) | 30 |
|
| Total Capital Budget | $ | 2,400 |
|
| |
(a) | Includes approximately $200 million of spend to fund REx. |
| |
(b) | International and corporate other includes our International segment and other corporate items. |
North America E&P – Approximately $2 billion of our 2017 Capital Program is allocated about one-third to each of our three core U.S. resource plays as follows:
Oklahoma Resource Basins - we expect to focus on STACK leasehold retention, STACK delineation and infill pilots in preparation for full field development. We plan to increase our Oklahoma rig count to average approximately 10 rigs in 2017, while bringing 90 to 100 gross operated wells to sales during the year. This includes four to five STACK infill pilots and two SCOOP infill pilots to sales, as well as testing additional secondary horizons.
Eagle Ford - we expect to maintain a six-rig drilling program and bring 155 to 170 gross operated wells to sales during 2017. With about two-thirds of the program focused in the high margin oil window, we plan to continue optimizing completion techniques with increased proppant and fluid loading, and average lateral lengths.
Bakken - we plan to focus on our highest return West and East Myrmidon areas where we completed several basin-leading wells in 2016. We will progress multiple enhanced completion trials as well as continue our focus on optimizing base production, while bringing 70 to 75 gross operated wells to sales during 2017. We expect to average approximately six drilling rigs in the Bakken in 2017.
International E&P, Oil Sands Mining, Corporate and other ��� Less than 10% of our Capital Program will be allocated to these segments for sustaining capital projects.
Operations
OurNet sales volumes increased by 8% in 2019 in the U.S. segment with new wells to sales across the U.S. resource plays. The International segment had lower net sales volumes from continuing operations averaged 404 mboed, 438 mboedin 2019 as a result of dispositions and 415 mboednatural decline in E.G. The following table presents a summary of our sales volumes for 2016, 2015 and 2014. each of our segments (refer to the Results of Operations section for a price-volume analysis for each of the segments).
|
| | | | | | | | | | | | |
| Net Sales Volumes | 2019 | | Increase
(Decrease) | | 2018 | | Increase
(Decrease) | | 2017 |
United States (mboed) | 323 |
| | 8 | % | | 298 | | 27 | % | | 234 |
International (mboed)(a) | 91 |
| | (25 | )% | | 122 | | (16 | )% | | 145 |
Total continuing operations (mboed) | 414 |
| | (1 | )% | | 420 | | 11 | % | | 379 |
| |
(a) | We closed on the sale of our Libya subsidiary in the first quarter of 2018, our interest in the Atrush block in Kurdistan in the second quarter of 2019 and our U.K. business in the third quarter of 2019. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for further information on dispositions. |
United States
Net sales volumes from continuing operations decreased by 8% to 404 mboed in 2016 relating to dispositions of certain non-core assets (23 mboed from Wyoming, West Texas, East Texas, North Louisiana and Gulf of Mexico)the segment were higher during the comparison periodyear ended December 31, 2019 primarily as well as lower completion activitya result of new wells to sales in the U.Sour U.S. resource plays. As liftings from Libya were sporadic during this 3-year period, a more representative comparison is net sales volumes from continuing operations excluding Libya, which was 401 mboed, 438 mboed and 408 mboed for 2016, 2015 and 2014. The table below provides additional detail regarding net sales volumes by segment:
|
| | | | | | | | | | | |
| Net Sales Volumes | 2016 | | Increase
(Decrease) | | 2015 | | Increase
(Decrease) | | 2014 |
North America E&P (mboed) | 223 | | (17 | )% | | 269 | | 13 | % | | 238 |
International E&P (mboed) | 122 | | 5 | % | | 116 | | (9 | )% | | 127 |
Oil Sands Mining (mbbld) (a) | 59 | | 11 | % | | 53 | | 6 | % | | 50 |
Total Continuing Operations (mboed) | 404 | | (8 | )% | | 438 | | 6 | % | | 415 |
(a) Includes blendstocks.
North America E&P
The following tables provide additional detaildetails regarding net sales volumes, sales mix and operational drilling activity:activity for our significant operations within this segment:
| | | Net Sales Volumes | 2016 | | Increase
(Decrease) | | 2015 | | Increase
(Decrease) | | 2014 | 2019 | | Increase
(Decrease) | | 2018 | | Increase
(Decrease) | | 2017 |
| Oklahoma Resource Basins | 35 | | 40% | | 25 | | 39% | | 18 | |
Equivalent Barrels (mboed) | | | | | | | | | | |
| Eagle Ford | 105 | | (22)% | | 134 | | 20% | | 112 | 106 |
| | (2 | )% | | 108 |
| | 7 | % | | 101 |
|
| Bakken | 54 | | (8)% | | 59 | | 16% | | 51 | 103 |
| | 23 | % | | 84 |
| | 50 | % | | 56 |
|
Other North America(a) | 29 | | (43)% | | 51 | | (11)% | | 57 | |
Total North America E&P (mboed) | 223 | | (17)% | | 269 | | 13% | | 238 | |
| Oklahoma | | 78 |
| | 5 | % | | 74 |
| | 37 | % | | 54 |
|
| Northern Delaware | | 28 |
| | 40 | % | | 20 |
| | 233 | % | | 6 |
|
| Other United States | | 8 |
| | (33 | )% | | 12 |
| | (29 | )% | | 17 |
|
Total United States (mboed) | | 323 |
| | 8 | % | | 298 |
| | 27 | % | | 234 |
|
|
| | | | | | | | | |
| Sales Mix - U.S. Resource Plays - 2019 | Eagle Ford | | Bakken | | Oklahoma | | Northern Delaware | | Total |
| Crude oil and condensate | 59% | | 84% | | 27% | | 58% | | 59% |
| Natural gas liquids | 21% | | 9% | | 28% | | 20% | | 18% |
| Natural gas | 20% | | 7% | | 45% | | 22% | | 23% |
|
| | | | | |
| Drilling Activity - U.S. Resource Plays | 2019 | | 2018 | | 2017 |
| Gross Operated | | | | | |
| Eagle Ford: | | | | | |
| Wells drilled to total depth | 127 | | 123 | | 182 |
| Wells brought to sales | 146 | | 149 | | 157 |
| Bakken: | | | | | |
| Wells drilled to total depth | 73 | | 78 | | 90 |
| Wells brought to sales | 105 | | 80 | | 39 |
| Oklahoma: | | | | | |
| Wells drilled to total depth | 68 | | 55 | | 86 |
| Wells brought to sales | 69 | | 57 | | 73 |
| Northern Delaware: | | | | | |
| Wells drilled to total depth | 51 | | 69 | | 27 |
| Wells brought to sales | 54 | | 52 | | 18 |
| |
| • | (a)Eagle Ford– In 2019, our net sales volumes were 106 mboed including oil sales of 63 mbbld. We brought 146 gross company-operated wells to sales across Karnes, Atascosa, and Gonzales counties with strong initial production rates. The third and fourth quarters of 2019 represented the two strongest quarters in the history of the asset on a 30-day initial production basis for oil. Eagle Ford fourth quarter oil mix increased to 63%, up from 57% in the prior-year quarter. Completed well costs during fourth quarter averaged $5.1 million, or 8% below the 2018 average.
|
Year ended December 31, 2016 decreases relating | |
| • | Bakken – In 2019, our net sales volumes of 103 mboed with oil sales volume of 86 mbbld. We brought 105 gross company-operated wells to assets soldsales in 2019.Fourth quarter 2019 was characterized by strong operations with the asset establishing new quarterly records for both drilling feet per day and completion stages per day. We continue to deliver capital efficiency and accretive financial returns, highlighted by a recent four-well pad in Myrmidon at an average completed well cost of $4.3 million. Wells to sales during the fourth quarter 2019 had an average completed well cost below $5 million, 17% below the 2018 average. |
| |
| • | Oklahoma – In 2019, our net sales volumes were 2378 mboed primarily consistingincluding oil sales volumes of Wyoming, West Texas, East Texas, North Louisiana and certain Gulf of Mexico assets.21 mbbld. During the fourth quarter, oil mix rose to 29% in 2019 from 24% in the fourth quarter 2018. We brought 69 gross company-operated wells to sales in 2019, including nine wells targeting the Springer formation in the SCOOP in the fourth quarter 2019. The nine Springer wells are demonstrating solid productivity. |
| |
| • | Northern Delaware – Our 2019 net sales volumes were 28 mboed with oil sales volumes of 16 mbbld. We brought 54 gross company-operated wells to sales, with a focus on the delineation of our Red Hills acreage in 2019. Since this transition to Red Hills delineation, we have brought online nine Upper Wolfcamp wells and four Bone Spring wells. We continue to advance learnings, reduce cost structure, and improve margins, exiting the year with about 90% of water and oil on pipe. |
International |
| | | | | | | | |
| Sales Mix - U.S. Resource Plays - 2016 | | Oklahoma Resource Basins | | Eagle Ford | | Bakken | | Total |
| Crude oil and condensate | | 25% | | 57% | | 81% | | 58% |
| Natural gas liquids | | 26% | | 21% | | 11% | | 19% |
| Natural gas | | 49% | | 22% | | 8% | | 23% |
|
| | | | | |
| Drilling Activity - U.S. Resource Plays | 2016 | | 2015 | | 2014 |
| Gross Operated | | | | | |
| Oklahoma Resource Basins: | | | | | |
| Wells drilled to total depth | 33 | | 20 | | 19 |
| Wells brought to sales | 28 | | 21 | | 18 |
| Eagle Ford: | | | | | |
| Wells drilled to total depth | 168 | | 251 | | 360 |
| Wells brought to sales | 168 | | 276 | | 310 |
| Bakken: | | | | | |
| Wells drilled to total depth | 3 | | 35 | | 83 |
| Wells brought to sales | 13 | | 56 | | 69 |
In 2016, we continued to focus on our U.S. unconventional resource plays. We acquired 61,000 net surface acres in the STACK play in Oklahoma, delivered basin-leading well results in the Bakken and further improved returns in the Eagle Ford with cost reductions, efficiency gains and enhanced completions. North America E&P segment average netNet sales volumes in 2016 decreased 17% when compared to 2015 largely as a result of the aforementioned dispositions in Wyoming, East Texas, North Louisiana and Gulf of Mexico, as well as base declines due to reduced completion activity. This decrease was partially offset by increases due to the Oklahoma STACK acquisition in the second-half of 2016.
Oklahoma Resource Basins – During 2016 we brought 28 gross wells to sales, of which 20segment were in the STACK Meramec, 6 were in the SCOOP Woodford and 2 were in the SCOOP Springer. We increased activitylower during the year from twoended December 31, 2019 primarily due to five rigs,E.G. planned maintenance activities and focused on protectingnatural field decline, coupled with the dispositions of our valuable acreage through leasehold drilling, delineation activity,U.K. business and enhancing well performance through enhanced completion designs. We also pursued technical advancement through data collection, analysis and participation in several infill spacing pilots.
In 2016, we drilled our first operated spacing pilotnon-operated interest in the STACK Meramec and we expect those wells to come to salesAtrush block in the first quarter of 2017. At year-end 2016, approximately 70% of our STACK leasehold was held by production and approximately 90% of our SCOOP acreage was held by production.
Eagle Ford - In 2016 we brought 168 gross wells to sales, of which 90 were in the Lower Eagle Ford, 53 were in the Upper Eagle Ford, and 25 were in the Austin Chalk. We continued efforts to utilize technology and drive efficiencies into the drilling process resulting in an average spud-to-TD of 7.9 days in 2016, compared to 10.6 days in 2015. Record low average completed well costs of $3.9 million per well were achieved the fourth quarter of 2016 (down 20 percent from year-ago quarter), despite increasing proppant loading per lateral foot by more than 70 percent compared to fourth quarter 2015.
Bakken – In 2016 we brought 13 wells to sales, of which 7 were in the Middle Bakken formation and 6 were in the Three Forks formation. We realized well performance improvements through high intensity completions and targeted application of
diversion techniques. In 2016, Myrmidon wells were pumped with 6 to 18 million pounds of proppant with 40 to 50 stages per well. Since December, we have mobilized four rigs to Myrmidon to support the development program.
North America E&P segment average net sales volumes in 2015 increased 13% when compared to 2014. Net liquid hydrocarbon sales volumes increased 24 mbbld and net natural gas sales volumes increased 41 mmcfd in 2015 primarily reflecting continued growth from our three core U.S. resource plays.
International E&P
Kurdistan. The following table provides details regarding net sales volumes from continuing operations:for our significant operations within this segment:
| | | Net Sales Volumes | 2016 | | Increase
(Decrease) | | 2015 | | Increase
(Decrease) | | 2014 | 2019 | | Increase
(Decrease) | | 2018 | | Increase
(Decrease) | | 2017 |
Equivalent Barrels (mboed) | | | | | | | | | | | | | | |
| Equatorial Guinea | 102 | | 5% | | 97 | | (7)% | | 104 | 85 |
| | (12 | )% | | 97 |
| | (11 | )% | | 109 |
|
United Kingdom(a) | 17 | | (11)% | | 19 | | 19% | | 16 | 5 |
| | (62 | )% | | 13 |
| | (7 | )% | | 14 |
|
| Libya | 3 | | 100% | | — | | (100)% | | 7 | — |
| | (100 | )% | | 8 |
| | (60 | )% | | 20 |
|
Total International E&P (mboed) | 122 | | 5% | | 116 | | (9)% | | 127 | |
| Net Sales Volumes of Equity Method Investees | |
| | |
| | |
| Other International | | 1 |
| | (75 | )% | | 4 |
| | 100 | % | | 2 |
|
| Total International | | 91 |
| | (25 | )% | | 122 |
| | (16 | )% | | 145 |
|
| Equity Method Investees | | | |
|
| | | |
|
| | |
LNG (mtd) | 5,874 | | —% | | 5,884 | | (10)% | | 6,535 | 4,933 |
| | (15 | )% | | 5,805 |
| | (10 | )% | | 6,423 |
|
Methanol (mtd) | 1,358 | | 45% | | 937 | | (14)% | | 1,092 | 1,082 |
| | (13 | )% | | 1,241 |
| | (10 | )% | | 1,374 |
|
Condensate & LPG (boed) | 13,430 | | 10% | | 12,208 | | (40)% | | 20,506 | |
Condensate and LPG (boed) | | 11,104 |
| | (15 | )% | | 13,034 |
| | (10 | )% | | 14,501 |
|
(a) Includes natural gas acquired for injection and subsequent resale of 5 mmcfd, 8 mmcfd and 6 mmcfd for 2016, 2015, and 2014.resale.
| |
| • | Equatorial Guinea – Net sales volumes in 2019 were lower than 2018 as a result of the planned triennial turnaround completed in 2019 and natural field decline. |
| |
| • | United Kingdom – During 2019, we closed on the sale of our U.K. business. See Note 5 to the consolidated financial statements for further information. |
| |
| • | Libya – During the first quarter of 2018, we closed on the sale of our subsidiary in Libya. See Note 5 to the consolidated financial statements for further information. |
| |
| • | Equity Method Investees – Net sales volumes in 2019 are tied to the volumes in Equatorial Guinea which were lower in the current year as noted above. |
International E&P segment average net sales volumes in 2016 increased 5% when compared to 2015. Sales volumes in E.G. were higher due to the completion and start-up of the Alba field compression project, which extends the production plateau and field life.In the U.K., the sales volumes slightly decreased as a result of downtime in the first quarter of 2016.
International E&P segment average net sales volumes in 2015 decreased 9% when compared to 2014. There were no liftings in Libya during 2015 as a result of ongoing civil unrest. Sales volumes in E.G. were lower due to a series of turnarounds and other maintenance activities performed at the Alba field, E.G. LNG and AMPCO facilities during the year. In the U.K., sales volumes increased as we completed the five-well Brae infill drilling program that began in 2014.
Oil Sands Mining
Our OSM operations consist of a 20% non-operated working interest in the AOSP. Our net synthetic crude oil sales volumes were 59 mbbld in 2016 compared to 53 mbbld in 2015 and 50 mbbld in 2014. The 2016 increase was a result of strong mine and upgrader performance coupled with less planned maintenance.
We've continued our alignment with the operator and other partners to focus on reducing the mine's cost and increasing reliability. As a result, there has been noticeable impact on the mine's cost structure with a 24% reduction in production expense to $27.89 per bbl for 2016 compared to 2015. See Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations for the 2016 compared to 2015 for additional detail on production expenses.
Market Conditions
OilCrude oil and gascondensate and NGLs benchmarks declined during 2016 anddecreased in 2019 as compared to the same period in 2018. As a result, we experienced declines in ourdecreased price realizations associated with those benchmarks. Although weWe continue to expect crude oil and condensate, NGLs and natural gas and NGLs benchmark prices to remain volatile based on global supply and demand, prices have improved subsequent to December 31, 2016.which will result in increases or decreases in our price realizations during 2020. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition – Critical Accounting Estimates for further discussion of how a further declinedeclines in these commodity prices could impact us.North America E&P
United States
The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for 2016, 20152019, 2018 and 2014:2017.
| | | | | 2016 | | Increase (Decrease) | | 2015 | Decrease | | 2014 | 2019 | | Increase (Decrease) | | 2018 | | Increase (Decrease) | | 2017 |
Average Price Realizations (a) | | | | | | | | | | | | | | | | | | |
Crude Oil and Condensate (per bbl) (b) | |
| $38.57 |
| | (11 | )% | |
| $43.50 |
| (49 | )% | | 85.25 |
| |
Natural Gas Liquids (per bbl) | | 13.15 |
| | (2 | )% | | 13.37 |
| (60 | )% | | 33.42 |
| |
Total Liquid Hydrocarbons (per bbl) | | 32.71 |
| | (14 | )% | | 37.85 |
| (51 | )% | | 77.02 |
| |
Natural Gas (per mcf) (c) | | 2.38 |
| | (11 | )% | | 2.66 |
| (42 | )% | | 4.57 |
| |
Crude oil and condensate (per bbl)(b) | | $ | 55.80 |
| | (12 | )% | | $ | 63.11 |
| | 28 | % | | $ | 49.35 |
|
Natural gas liquids (per bbl) | | 14.22 |
| | (42 | )% | | 24.54 |
| | 19 | % | | 20.55 |
|
Natural gas (per mcf)(c) | | 2.18 |
| | (18 | )% | | 2.65 |
| | (7 | )% | | 2.84 |
|
| Benchmarks | | | |
|
| | |
|
| | | | |
|
| | | |
|
| | |
WTI crude oil average of daily prices (per bbl) | |
| $43.47 |
| | (11 | )% | |
| $48.76 |
| (48 | )% | | 92.91 |
| $ | 57.04 |
| | (12 | )% | | $ | 64.90 |
| | 28 | % | | $ | 50.85 |
|
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)(d) | | 61.96 |
| | | | | | | | |
LLS crude oil average of daily prices (per bbl) | | 45.02 |
| | (14 | )% | | 52.33 |
| (46 | )% | | 96.64 |
| | |
|
| | 70.04 |
| | 30 | % | | 54.04 |
|
Mont Belvieu NGLs (per bbl) (d)(e) | | 17.40 |
| | 3 | % | | 16.94 |
| (48 | )% | | 32.52 |
| 17.81 |
| | (33 | )% | | 26.75 |
| | 21 | % | | 22.04 |
|
Henry Hub natural gas settlement date average (per mmbtu) | | 2.46 |
| | (8 | )% | | 2.66 |
| (40 | )% | | 4.42 |
| 2.63 |
| | (15 | )% | | 3.09 |
| | (1 | )% | | 3.11 |
|
| |
(a) | Excludes gains or losses on commodity derivative instruments. |
| |
(b) | Inclusion of realized gains (losses) on crude oil derivative instruments would have increasedimpacted average liquid hydrocarbon price realizations by $0.67 per barrel by $0.92bbl, $(4.60) per bbl, and $1.24$0.75 per bbl for 20162019, 2018, and 2015. There were no crude oil derivative instruments for 2014.2017. |
| |
(c) | Inclusion of realized gains (losses) on natural gas derivative instruments would have a de minimusminimal impact on average price realizations for the periods presented. |
| |
(d) | Benchmark change due to industry shift to MEH in the first quarter of 2019. |
| |
(e) | Bloomberg Finance LLP: Y-grade Mix NGL of 50%55% ethane, 25% propane, 10%5% butane, 5%8% isobutane and 10%7% natural gasoline. |
Crude oil and condensate – Our crude oil and condensate pricePrice realizations may differ from the benchmarkbenchmarks due to the quality and location of the product.
Natural gas liquids – The majority of our NGLssales volumes are sold at reference to Mont Belvieu prices.
Natural gas –A significant portion of our natural gas production in the U.S. isvolumes are sold at bid-week prices, or first-of-month indices relative to our specific producing areas.
International E&P
The following table presents our average price realizations and the related benchmark for crude oil for 2016, 20152019, 2018 and 2014:2017.
|
| | | | | | | | | | | | | | | | | | |
| | | 2016 | | Decrease | | 2015 | | Increase (Decrease) | | 2014 |
| Average Price Realizations | | | | | | | | | | |
Crude Oil and Condensate (per bbl) | |
| $41.70 |
| | (12 | )% | |
| $47.50 |
| | (46 | )% | |
| $87.23 |
|
Natural Gas Liquids (per bbl) | | 2.11 |
| | (25 | )% | | 2.81 |
| | 14 | % | | 2.46 |
|
Total Liquid Hydrocarbons (per bbl) | | 32.10 |
| | (12 | )% | | 36.67 |
| | (47 | )% | | 68.98 |
|
Natural Gas (per mcf) | | 0.52 |
| | (24 | )% | | 0.68 |
| | (6 | )% | | 0.72 |
|
| Benchmark | | | |
|
| | | |
|
| | |
Brent (Europe) crude oil (per bbl)(a) | |
| $43.55 |
| | (17 | )% | |
| $52.35 |
| | (47 | )% | |
| $99.02 |
|
|
| | | | | | | | | | | | | | | | | |
| | 2019 | | Increase (Decrease) | | 2018 | | Increase (Decrease) | | 2017 |
| Average Price Realizations | | | | | | | | | |
Crude oil and condensate (per bbl) | $ | 53.09 |
| | (17 | )% | | $ | 64.25 |
| | 21 | % | | $ | 53.05 |
|
Natural gas liquids (per bbl) | 1.40 |
| | (38 | )% | | 2.27 |
| | (28 | )% | | 3.15 |
|
Natural gas (per mcf) | 0.33 |
| | (39 | )% | | 0.54 |
| | (2 | )% | | 0.55 |
|
| Benchmark | | |
|
| | | |
|
| | |
Brent (Europe) crude oil (per bbl)(a) | $ | 64.36 |
| | (9 | )% | | $ | 71.06 |
| | 31 | % | | $ | 54.25 |
|
| |
(a) | Average of monthly prices obtained from EIAthe United States Energy Information Agency website. |
Our
United Kingdom
Crude oil and condensate –Generally sold in relation to the Brent crude benchmark. We closed on the sale of our U.K. liquid hydrocarbonbusiness on July 1, 2019.
Equatorial Guinea
Crude oil and condensate –Alba Field liquids production is primarily condensate and generally sold in relation to the Brent crude benchmark. Our production fromAlba Plant LLC processes the rich hydrocarbon gas which is supplied by the Alba field in E.G. is condensate and gas. Condensate is sold at market prices. TheField under a
fixed-price long term contract. Alba Plant LLC extracts NGLs and secondary condensate from gas, leaving dry natural gas. The processed NGLs arewhich is then sold by Alba Plant LLC at market prices, with our share of its income/lossthe revenue reflected in Incomeincome from equity method investments. Theinvestments on the consolidated statements of income. Alba Plant LLC delivers the processed dry natural gas fromto the Alba Plant is suppliedField for distribution and sale to AMPCO and EGHoldings under long-term contracts at fixed prices; therefore, our reported average realized prices for NGLs and naturalEG LNG.
Natural gas will not fully track market price movements. Because of the location and limited local demand for naturalliquids –Wet gas in E.G., we consider the prices under the contracts withis sold to Alba Plant LLC EGHoldingsat a fixed-price term contract resulting in realized prices not tracking market price. Alba Plant LLC extracts 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. EGHoldings and AMPCO process the gas into LNG and methanol,keeps NGLs, which are sold at market prices,price, with our share of their income/lossincome from Alba Plant LLC being reflected in the Incomeincome from equity method investments line item on the Consolidated Statementsconsolidated statements of Income. Although uncommon, any dryincome.
Natural gas not sold is returned offshore and re-injected into–Dry natural gas, processed by Alba Plant LLC on behalf of the Alba field for later production.
Oil Sands Mining
The Oil Sands Mining segment producesField, is sold by the Alba Field to EG LNG and AMPCO at fixed-price long term contracts resulting in realized prices not tracking market price. We derive additional value from the equity investment in our downstream gas processing units EG LNG and AMPCO. EG LNG sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outagesLNG on a market-based long term contract and AMPCO markets methanol at the mines or upgrader. Sales prices for synthetic crude oil historically tracked movements in the WTI crude oil and the WCS Canadian heavy crude oil benchmarks. The influence of each benchmark can change from period to period based on market dynamics.prices.
The following table presents our average price realizations and the related benchmarks that impacted both our revenues and variable costs for 2016, 2015 and 2014:
|
| | | | | | | | | | | | | | | | | | |
| | | 2016 | | Decrease | | 2015 | |
Decrease | | 2014 |
| Average Price Realizations | | | | | | | | | | |
Synthetic Crude Oil (per bbl) | |
| $37.57 |
| | (6 | %) | |
| $40.13 |
| | (52 | %) | |
| $83.35 |
|
| Benchmark | | | |
|
| | | |
|
| | |
WTI crude oil average of daily prices (per bbl) | |
| $43.47 |
| | (11 | %) | |
| $48.76 |
| | (48 | %) | |
| $92.91 |
|
WCS crude oil (per bbl)(a) | | 29.48 |
| | (16 | %) | | 35.28 |
| | (52 | %) | | 73.60 |
|
| |
(a)
| Average of monthly prices based upon average WTI adjusted for differentials unique to western Canada. |
Consolidated Results of Operations: 20162019 compared to 20152018
Sales and other operating revenues, including related partyRevenues from contracts with customers are summarizedpresented by segment in the following table:table below:
|
| | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | 2015 |
| Sales and other operating revenues, including related party | | |
| North America E&P | $ | 2,375 |
| $ | 3,358 |
|
| International E&P | 665 |
| 728 |
|
| Oil Sands Mining | 823 |
| 815 |
|
| Segment sales and other operating revenues, including related party | 3,863 |
| 4,901 |
|
| Unrealized gain (loss) on commodity derivative instruments | (110 | ) | 50 |
|
| Sales and other operating revenues, including related party | $ | 3,753 |
| $ | 4,951 |
|
|
| | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 |
| Revenues from contracts with customers | | | |
| United States | $ | 4,602 |
| | $ | 4,886 |
|
| International | 461 |
| | 1,016 |
|
| Segment revenues from contracts with customers | $ | 5,063 |
| | $ | 5,902 |
|
Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations. | | | | | Year Ended December 31, | | Increase (Decrease) Related to | | Year Ended December 31, | | | | Increase (Decrease) Related to | | |
| (In millions) | | 2015 | | Price Realizations | | Net Sales Volumes | | 2016 | | Year Ended December 31, 2018 | | Price Realizations | | Net Sales Volumes | | Year Ended December 31, 2019 |
North America E&P Price-Volume Analysis (a) | |
| Liquid hydrocarbons | | $ | 2,905 |
| | $ | (321 | ) | | $ | (543 | ) | | $ | 2,041 |
| |
| Natural gas | | 341 |
| | (32 | ) | | (35 | ) | | 274 |
| |
| Realized gain on commodity | | | | | | | | | |
| derivative instruments | | 78 |
| |
|
| | | | 44 |
| |
| Other sales | | 34 |
| | | | | | 16 |
| |
| Total | | $ | 3,358 |
| | | | | | $ | 2,375 |
| |
| International E&P Price-Volume Analysis | |
| Liquid hydrocarbons | | $ | 578 |
| | $ | (78 | ) | | $ | 46 |
| | $ | 546 |
| |
| United States Price/Volume Analysis | | United States Price/Volume Analysis |
| Crude oil and condensate | | | $ | 3,947 |
| | $ | (510 | ) | | $ | 450 |
| | $ | 3,887 |
|
| Natural gas liquids | | | 495 |
| | (223 | ) | | 35 |
| | 307 |
|
| Natural gas | | 108 |
| | (25 | ) | | 4 |
| | 87 |
| | 413 |
| | (75 | ) | | 11 |
| | 349 |
|
| Other sales | | 42 |
| | | | | | 32 |
| | 31 |
| | | | | | 59 |
|
| Total | | $ | 728 |
| | | | | | $ | 665 |
| | $ | 4,886 |
| | | | | | $ | 4,602 |
|
| Oil Sands Mining Price-Volume Analysis | |
| Synthetic crude oil | | $ | 781 |
| | $ | (61 | ) | | $ | 95 |
| | $ | 815 |
| |
| International Price/Volume Analysis | | International Price/Volume Analysis |
| Crude oil and condensate | | | $ | 888 |
| | $ | (83 | ) | | $ | (407 | ) | | $ | 398 |
|
| Natural gas liquids | | | 9 |
| | (3 | ) | | (1 | ) | | 5 |
|
| Natural gas | | | 86 |
| | (29 | ) | | (13 | ) | | 44 |
|
| Other sales | | 34 |
| | | | | | 8 |
| | 33 |
| | | | | | 14 |
|
| Total | | $ | 815 |
| | | | | | $ | 823 |
| | $ | 1,016 |
| | | | | | $ | 461 |
|
(a) Year ended December 31, 2015 includes 23 mboed relating to assets sold that are not contributing sales volumes in all or a portion of 2016, primarily consisting of Wyoming, East Texas, North Louisiana and certain Gulf of Mexico assets.
Marketing revenues decreased $293Net loss on commodity derivatives increased $58 million in 20162019 from 2015. Marketing activities include2018. We have multiple crude oil and natural gas derivative contracts indexed to NYMEX WTI and Henry Hub. We record commodity derivative gains/losses as the purchase of commodities from third partiesrespective index pricing and forward curves change each period. See Note 15 to the consolidated financial statements for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are primarily related to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.information.Income from equity method investments increased $30decreased $138 million primarily due to higher net sales volumes in the second half of 2016 at E.G. as a result of lower price realizations and lower net sales volumes due to the completion2019 triennial turnaround in E.G. and natural decline of the Alba field compression project. Additionally, a partial impairment of our investmentwhich resulted in anlower net sales volumes for equity method investee in 2015 of $12 million contributed to the increase in the current year.investments.
Net gain on disposal of assetsincreaseddecreased $269 million in 20162019 from 2015.2018. This decrease was primarily related to the 2018 sale of our Libya subsidiary for a pre-tax gain of $255 million. See Item 8. Financial Statements and Supplementary Data - Note 65 to the consolidated financial statements for information about these dispositions. Production expenses
Other income decreased $381$88 million in 20162019 from 2015. North America E&P declined $2382018 primarily due to the 2018 reduction of our U.K. asset retirement obligation, versus the 2019 indemnification of certain tax liabilities in connection with the closure of the 2010-2011 Federal Tax Audit with the IRS. This indemnity relates to tax and interest allocable to MPC as a result of the IRS Audit in accordance with the Tax Sharing Agreement. See Item 8. Financial Statements and Supplementary Data - Note 8 to the consolidated financial statements for detail about our asset retirement obligation. Production expenses decreased $130 million during 2019 from 2018. The International segment decreased $89 million primarily due to lower operational, maintenance and labor costs, coupled with lower net sales volumes resulting fromdispositions, which included the impactsale of our non-core asset dispositions and lower activity levels. International E&P declined $29 million largely due to lower operational and maintenance costs as well as a more favorable exchange rateU.K. business on expenses. OSMJuly 1, 2019. Our United States segment decreased $114$37 million primarily due to continued lower turnaroundreduced water hauling costs cost management, specifically staffingwith more water on pipe in the Northern Delaware and contract labor, and a favorable exchange rate on expenses denominatednon-core asset dispositions in foreign currencies.the Gulf of Mexico during 2018, slightly offset by increased water handling in Bakken due to more producing wells in 2019 than in 2018.
The 2016 production expense rate (expense per(per boe) for North America E&P declined primarily due to cost reductions that occurred at a rate faster than our production decline. The International E&P expense rate decreased in 2016 primarily due to reduced maintenance and project costsduring 2019 in the U.K. and benefited from the favorable exchange rate. The OSM expense rate decreased in 2016 primarily due to lower operational costs and the favorable exchange rate. United States as a result of continued focus on cost reduction as well as higher net sales volumes.
The following table provides production expense and production expense rates for each segment: |
| | | | | | |
| ($ per boe) | 2016 | 2015 |
| North America E&P |
| $5.96 |
|
| $7.38 |
|
| International E&P |
| $5.05 |
|
| $5.99 |
|
Oil Sands Mining (a) |
| $27.89 |
|
| $36.48 |
|
|
| | | | | | | | | | | | | | | | | |
| (In millions/$ per boe) | 2019 | 2018 | Increase (Decrease) | | 2019 | 2018 | Increase (Decrease) |
| Production Expense and Production Expense Rate | Expense | | Rate |
| United States | $ | 588 |
| $ | 625 |
| (6 | )% | | $ | 4.98 |
| $ | 5.75 |
| (13 | )% |
| International | $ | 126 |
| $ | 215 |
| (41 | )% | | $ | 3.76 |
| $ | 4.86 |
| (23 | )% |
(a) Production expense per synthetic crude oil barrel (before royalties) includes production costs, shippingShipping, handling and handling, taxes other than income and insurance costs and excludes pre-development costs.
Marketingoperating expenses decreased $287increased $30 million in 20162019 from the prior year, consistent with the decrease in marketing revenues discussed above.
Other operating expenses increased $73 million2018 primarily as a result of increased sales volumes in our United States segment, partially offset by the termination paymentsale of our Gulf of Mexico deepwater drilling rig.U.K. business in the International segment.
Exploration expenses decreased$988 $140 million during 2019 versus the comparable 2018. Decreases in 2016 compared to 2015, reflecting our strategic decision to transition out of conventional exploration. In 2016, unproved property impairments primarily consistedwere driven by changes in impairment assumptions based on actual development experience. Also in 2018, there was $32 million of non-cash charges related to our decision to not drill our remaining Gulf of Mexico leasesdry well costs and also included certain other unproved properties$16 million in North America. In 2015, unproved property impairments are duerelated to changes in our conventional exploration strategy (Gulf of Mexico, Canadian in-situ assets and Harir block in the Kurdistan Region of Iraq), and the sale of certain properties in the Gulf of Mexico, as well as our unproved property in Colorado.
Dry well costs in 2015 included the operated Solomon explorationRodo well in
Alba Block Sub Area B, offshore E.G. See Item 8. Financial Statements and Supplementary Data - Note 11 to the Gulfconsolidated financial statements for details of Mexico, our operated Sodalita West #1 exploratory well in E.G., and suspended well costs related to our Canadian in-situ assets at Birchwood.these items.The following table summarizes the components of exploration expenses:
| | | | Year Ended December 31, | Year Ended December 31, |
| (In millions) | 2016 | 2015 | 2019 | | 2018 | | Increase (Decrease) |
| Exploration Expenses | | | | | | |
| Unproved property impairments | $ | 195 |
| $ | 964 |
| $ | 98 |
| | $ | 208 |
| | (53 | )% |
| Dry well costs | 32 |
| 250 |
| 16 |
| | 47 |
| | (66 | )% |
| Geological and geophysical | 5 |
| 31 |
| 18 |
| | 21 |
| | (14 | )% |
| Other | 98 |
| 73 |
| 17 |
| | 13 |
| | 31 | % |
| Total exploration expenses | $ | 330 |
| $ | 1,318 |
| $ | 149 |
| | $ | 289 |
| | (48 | )% |
Exploration expenses are also discussed in Item 8. Financial Statements and Supplementary Data - Note 13 to the consolidated financial statements.
Depreciation, depletion and amortizationdecreased $562$44 million in 20162019 from the prior year2018 primarily as a result of net sales volume decreases indispositions which included the North America E&P segment, includingsale of our U.K. business and the impactsale of certain non-core asset dispositions and volume declines duein our United States segment. Adding to base declines andthe decrease were lower completion activity.2019 production volumes in E.G. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.
The DD&A rate (expense per(per boe), which is impacted by field-level changes in reserves, capitalized costs and sales volumes, reserves and capitalized costs, can also cause changesimpact our DD&A expense. The DD&A rate for International decreased primarily as a result of dispositions. Our United States DD&A rate decreased in 2019 primarily due to our DD&A. reserve additions as well as non-core asset dispositions in 2018.
The following table provides DD&A expense and DD&A expense rates for each segment. The DD&A rate for North America E&P decreased primarily due to a higher proved reserve base. The DD&A rate for International E&P declined primarily due to sales volume mix changes in E.G. and the U.K. for 2016.segment:
|
| | | | | | |
| ($ per boe) | 2016 | 2015 |
| North America E&P |
| $22.49 |
|
| $24.24 |
|
| International E&P |
| $6.21 |
|
| $6.95 |
|
| Oil Sands Mining |
| $11.32 |
|
| $12.48 |
|
|
| | | | | | | | | | | | | | | | | |
| (In millions/$ per boe) | 2019 | 2018 | Increase (Decrease) | | 2019 | 2018 | Increase (Decrease)
|
| DD&A Expense and DD&A Expense Rate | Expense | | Rate |
| United States | $ | 2,250 |
| $ | 2,217 |
| 1 | % | | $ | 19.07 |
| $ | 20.39 |
| (6 | )% |
| International | $ | 121 |
| $ | 197 |
| (39 | )% | | $ | 3.61 |
| $ | 4.44 |
| (19 | )% |
Impairmentsdecreased $685$51 million in 2016 versus 2015. Impairments in 2016 were primarily the result of lower forecasted commodity prices in conventional properties in Oklahoma and the Gulf of Mexico, and were also the result of revisions to estimated abandonment costs. Impairments in 2015 included $340 million for the goodwill impairment of the North America E&P reporting unit, and $335 million related to proved properties (primarily in Colorado and the Gulf of Mexico)2019 from 2018 as a result of lower forecasted commodity prices,anticipated sales of certain non-core proved properties in our International and $44 million associated with our disposition of natural gas assetsUnited States segments in East Texas, North Louisiana and Wilburton, Oklahoma.
the current period. See Item 8. Financial Statements and Supplementary Data - Note 13 and Note 1411 to the consolidated financial statement for additional detail.detail of proved property impairments each year. Taxes other than incomeincludes production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. The decline in revenue and sales volumes during 2016 resulted in a decline of $66 million compared to 2015. The following table summarizes the components of taxes other than income: |
| | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | 2015 |
| Production and severance | $ | 91 |
| $ | 131 |
|
| Ad valorem | 23 |
| 39 |
|
| Other | 54 |
| 64 |
|
| Total | $ | 168 |
| $ | 234 |
|
General and administrative expenses decreased$10638 million in 2019 compared to 2018. This was primarily due to cost savings realized from the 2015 workforce reductions including corresponding severance expenses.
Net interest and otherincreased $68 million primarily due to an increase in interest expense as a result of the increase in long-term debt in the second quarter of 2015. The components of net interest and other are detailed in Item 8. Financial Statements and Supplementary Data - Note 8 to the consolidated financial statements.decreased compensation costs.
Provision (benefit) for income taxesreflects an effective tax benefit rate of 73% and (25)%22% for 2016 and 2015. The increase2019, as compared to an effective income tax expense rate of the 2016 effective tax rate was primarily due to the valuation allowance increase of $1,346 million related to U.S. benefits on foreign taxes and other federal deferred tax assets.
23% for 2018. See Item 8. Financial Statements and Supplementary Data -
Note 98 to the consolidated financial statements for a discussion of the effective income tax rate. Segment Results: 20162019 compared to 20152018
Segment Income
Segment income(loss) for 2016 represents income which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and 2015 is summarizedoperations general and reconciledadministrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, certain property impairments, certain exploration expenses relating to a strategic decision to exit conventional exploration, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.
The following table reconciles segment income to net income (loss) in the following table.income:
|
| | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 |
| North America E&P | $ | (415 | ) | | $ | (486 | ) |
| International E&P | 228 |
| | 112 |
|
| Oil Sands Mining | (55 | ) | | (113 | ) |
| Segment income (loss) | (242 | ) | | (487 | ) |
| Items not allocated to segments, net of income taxes | (1,898 | ) | | (1,717 | ) |
| Net income (loss) | $ | (2,140 | ) | | $ | (2,204 | ) |
|
| | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | | Increase (Decrease) |
| United States | $ | 675 |
| | $ | 608 |
| | 11 | % |
| International | 233 |
| | 473 |
| | (51 | )% |
| Segment income | 908 |
| | 1,081 |
| | (16 | )% |
Items not allocated to segments, net of income taxes(a) | (428 | ) | | 15 |
| | (2,953 | )% |
| Net income | $ | 480 |
| | $ | 1,096 |
| | (56 | )% |
| |
(a) | See Item 8. Financial Statements and Supplementary Data - Note 7 to the consolidated financial statements for further detail about items not allocated to segments. |
North America E&PUnited States segment loss decreased $71income increased $67 million after-tax in 20162019 compared to 20152018 primarily due to a net gain on commodity derivatives in 2019 versus net loss on commodity derivatives in 2018, as well as lower exploration costs. This increase was partially offset by lower price realizations along with increases in certain expenses as a result of higher net sales volumes.
International segment incomedecreased $240 million after-tax in 2019 compared to 2018 primarily due to lower income from our equity method investments and our operations in E.G. as a result of lower net sales volumes and their impact to DD&A, productionprice realizations, offset by lower costs and taxes other thandue to dispositions. Sales volumes decreased due to the planned triennial turnaround in E.G. completed in the first quarter 2019 and natural field decline in E.G. The income which was nearly offset by lower revenues as a result of decreases in both price realizations and net sales volumes. The remainder of the decrease was duealso attributed to lower exploration expenses in 2016 relative to 2015.
International E&P segment incomeincreased $116 million in 2016 compared to 2015. The increase was largely due to lower exploration expenses in 2016, as our 2015 expense included costs relating to our transition outdispositions of our conventional exploration program. The remainder ofU.K. business and our non-operated interest in the increase was due to lower production costs and DD&A as a result of lower asset retirement costs and sales mix, and an increaseAtrush block in income from equity method investments, partially offset by lower price realizations.Kurdistan.
Oil Sands Mining segment loss decreased $58 million in 2016 compared to 2015 primarily due to higher sales volumes and lower production expenses, which were partially offset by lower price realizations.
Consolidated Results of Operations: 20152018 compared to 20142017
Sales and other operating revenues, including related partyare summarized by segment in the following table:
|
| | | | | | |
| | Year Ended December 31, |
| (In millions) | 2015 | 2014 |
| Sales and other operating revenues, including related party | | |
| North America E&P | $ | 3,358 |
| $ | 5,770 |
|
| International E&P | 728 |
| 1,410 |
|
| Oil Sands Mining | 815 |
| 1,556 |
|
| Segment sales and other operating revenues, including related party | 4,901 |
| 8,736 |
|
| Unrealized gain on crude oil derivative instruments | 50 |
| — |
|
| Sales and other operating revenues, including related party | $ | 4,951 |
| $ | 8,736 |
|
Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
|
| | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | Increase (Decrease) Related to | | Year Ended December 31, |
| (In millions) | | 2014 | | Price Realizations | | Net Sales Volumes | | 2015 |
| North America E&P Price-Volume Analysis |
| Liquid hydrocarbons | | $ | 5,240 |
| | $ | (3,006 | ) | | $ | 671 |
| | $ | 2,905 |
|
| Natural gas | | 516 |
| | (243 | ) | | 68 |
| | 341 |
|
| Realized gain on crude oil | | | | | | | | |
| derivative instruments | | — |
| | 78 |
| | | | 78 |
|
| Other sales | | 14 |
| | | | | | 34 |
|
| Total | | $ | 5,770 |
| | | | | | $ | 3,358 |
|
| International E&P Price-Volume Analysis |
| Liquid hydrocarbons | | $ | 1,240 |
| | $ | (509 | ) | | $ | (153 | ) | | $ | 578 |
|
| Natural gas | | 124 |
| | (8 | ) | | (8 | ) | | 108 |
|
| Other sales | | 46 |
| | | | | | 42 |
|
| Total | | $ | 1,410 |
| | | | | | $ | 728 |
|
| Oil Sands Mining Price-Volume Analysis |
| Synthetic crude oil | | $ | 1,525 |
| | $ | (842 | ) | | $ | 98 |
| | $ | 781 |
|
| Other sales | | 31 |
| | | | | | 34 |
|
| Total | | $ | 1,556 |
| | | | | | $ | 815 |
|
Marketing revenues decreased $1,539 million in 2015 from 2014. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are primarily related to the lower commodity price environment as well as lower marketed volumes in North America.
Income from equity method investments decreased $279 million primarily due to lower price realizations for LPG at our Alba Plant, LNG at our LNG facility and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing to the decrease were lower sales volumes due to planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.
Net gain on disposal of assets in 2015 was related to the sale of our operated producing properties in the greater Ewing Bank area and non-operated producing interests in the Petronius field in the Gulf of Mexico. The gain associated with those assets was partially offset by the loss on sale of East Africa exploration acreage in Ethiopia and Kenya. The net loss on disposal of assets in 2014 was primarily related to the sale of non-core acreage located in the far northwest portion of the Williston Basin. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.
Production expensesdecreased $552 million in 2015 from 2014. Our focus on cost discipline and efficiencies yielded sustainable savings in production costs. North America E&P declined $167 million due to lower operational, maintenance and labor costs. International E&P declined $131 million due to lower project work, repair, maintenance and turnaround costs, as
well as lower production volumes. OSM declined $254 million primarily due to cost management, especially staffing and contract labor, lower fuel and utility costs, and lower feedstock purchases given the increased mine and upgrader reliability, combined with a more favorable exchange rate on expenses denominated in the Canadian dollar.
The production expense rate (expense rate per boe) decreased for each of our segments as total production costs declined due to reasons described in the preceding paragraph. The North America E&P and OSM segments also experienced volume increases, which further contributed to the expense rate decline. The following table provides production expense rates for each segment:
|
| | | | | | |
| ($ per boe) | 2015 | 2014 |
| North America E&P |
| $7.38 |
|
| $10.25 |
|
| International E&P |
| $5.99 |
|
| $8.31 |
|
Oil Sands Mining (a) |
| $36.48 |
|
| $44.53 |
|
| |
(a) | Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs. |
Marketing expenses decreased $1,536 million in 2015 from the prior year, consistent with the decreases in marketing revenues discussed above.
Exploration expenses increased $525 million in 2015, primarily due to higher unproved property impairments in North America. During 2015, we made a strategic decision to reduce the overall level of our conventional exploration program; as a result, we impaired our Canadian in-situ assets, certain of our leases in the Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq. We also impaired unproved property in Colorado in 2015, which we deemed uneconomic given our forecasted natural gas prices.
Unproved property impairments in 2014 primarily were a result of Eagle Ford and Bakken leases that either expired or we decided not to drill or extend.
Dry well costs for 2015 include the operated Solomon well in the Gulf of Mexico, our operated Sodalita West #1 exploratory well in E.G., and suspended well costs related to our Canadian in-situ assets at Birchwood. Dry well costs in 2014 also included our operated Sodalita West #1 exploratory well in E.G. which was drilling over year-end 2014, the operated Key Largo well, outside-operated Perseus well and the outside operated second Shenandoah appraisal well, all of which are located in the Gulf of Mexico. In addition, 2014 also includes our exploration programs in the Kurdistan Region of Iraq, Ethiopia and Kenya.
The following table summarizes the components of exploration expenses:
|
| | | | | | |
| | Year Ended December 31, |
| (In millions) | 2015 | 2014 |
| Unproved property impairments | $ | 964 |
| $ | 306 |
|
| Dry well costs | 250 |
| 317 |
|
| Geological and geophysical | 31 |
| 85 |
|
| Other | 73 |
| 85 |
|
| Total exploration expenses | $ | 1,318 |
| $ | 793 |
|
Exploration expense are also discussed in Item 8. Financial Statements and Supplementary Data - Note 13 to the consolidated financial statements.
Depreciation, depletion and amortization increased $96 million in 2015 from the prior year primarily as a result of higher North America E&P net sales volumes from our three U.S. resource plays. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.
The DD&A rate (expense rate per boe), which is impacted by changes in proved reserves, capitalized costs and sales volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in the Eagle Ford. The International E&P rate increased primarily due to higher sales volumes from the Brae infill drilling program. |
| | | | | | |
| ($ per boe) | 2015 | 2014 |
| North America E&P |
| $24.24 |
|
| $26.95 |
|
| International E&P |
| $6.95 |
|
| $5.79 |
|
| Oil Sands Mining |
| $12.48 |
|
| $12.07 |
|
Impairments for 2015 included $340 million for the goodwill impairment of the North America E&P reporting unit, $335 million related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted commodity prices and $44 million associated with our disposition of natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma. Impairments for 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices. See Item 8. Financial Statements and Supplementary Data - Note 13 and Note 14 to the consolidated financial statement for additional detail.
Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenues and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $172 million in 2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income: |
| | | | | | |
| | Year Ended December 31, |
| (In millions) | 2015 | 2014 |
| Production and severance | $ | 131 |
| $ | 240 |
|
| Ad valorem | 39 |
| 74 |
|
| Other | 64 |
| 92 |
|
| Total | $ | 234 |
| $ | 406 |
|
General and administrative expenses decreased $64 million primarily due to cost savings realized from the workforce reductions that occurred during 2015. This decrease was partially offset by severance expenses of $55 million associated with the workforce reductions and an increase in pension settlement expense. Pension settlement expenses in 2015 totaled $119 million as compared to $99 million in 2014.
Net interest and other increased $29 million primarily due to increased interest expense associated with an increase in long-term debt. The components of net interest and other areA detailed in Item 8. Financial Statements and Supplementary Data - Note 8 to the consolidated financial statements.
Provision (benefit) for income taxesreflects an effective tax rate of (25)% and 29% for each of 2015 and 2014. See Item 8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements for a discussion of the effective income tax rate.
Discontinued operations is presented net of tax. We closedyear-over-year changes from the saleyear ended December 31, 2018 to December 31, 2017 can be found in the Management’s Discussion and Analysis section of our Angola assets and Norway business in 2014, and both are reflected as discontinued operationsAnnual Report on Form 10-K for 2014. Included in the discontinued operations for 2014 are after-tax gains of $532 million and $976 million related to the dispositions of Angola and Norway respectively. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements.year ended December 31, 2018.
Segment Results: 2015 compared to 2014
Segment income (loss) for 2015 and 2014 is summarized and reconciled to net income (loss) in the following table.
|
| | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2015 | | 2014 |
| North America E&P | $ | (486 | ) | | $ | 693 |
|
| International E&P | 112 |
| | 568 |
|
| Oil Sands Mining | (113 | ) | | 235 |
|
| Segment income (loss) | (487 | ) | | 1,496 |
|
| Items not allocated to segments, net of income taxes | $ | (1,717 | ) | | (527 | ) |
| Income (loss) from continuing operations | (2,204 | ) | | 969 |
|
| Discontinued operations | — |
| | 2,077 |
|
| Net income (loss) | $ | (2,204 | ) | | $ | 3,046 |
|
North America E&P segment income (loss) decreased $1,179 million in 2015 compared to 2014. The decrease was primarily due to lower price realizations, which was partially offset by the impacts from the increased net sales volumes from the three U.S resource plays and lower production costs (even though net sales volumes increased).
International E&P segment income decreased $456 million in 2015 compared to 2014. The decrease was largely due to lower liquid hydrocarbon price realizations as well as reduced income from equity investments. These declines were partially offset by lower production, operating and exploration expenses.
Oil Sands Mining segment income (loss) decreased $348 million in 2015 compared to 2014 primarily as result of lower price realizations, partially offset by higher sales volumes and reduced production expenses.
Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
Commodity prices are the most significant factor impacting our operating cash flows and the amount of capital available to reinvest into the business. In 2016,2019, we closed on the sale of certain non-core assets resultingexperienced a decrease in net proceeds of $1.2 billion, including closing adjustments, which allowed us to be opportunistic with a high quality acquisition in Oklahoma's STACK play. Our successful portfolio management allowed us to realize our goal of living withinoperating cash flows primarily as a result of lower commodity realizations, of which crude oil and condensate price realizations decreased by 12% to $55.54 per barrel.
During 2019 our cash flow highlights include:
We returned capital to shareholders by executing $345 million of share repurchases along with $162 million in 2016. Beyonddividend payments.
Asset acquisitions during the proceeds the non-core asset sales generated, the portfolio changes enhance our profitability by driving out higher unit cost operations and allowing for the more efficient allocationyear of our Capital Program to the high return opportunities in the U.S. resource plays. We plan to continue the progress we made in 2016 towards achieving profitable growth within$293 million were paid with cash flows as the price environment improves.on hand.
Steps taken to respond to the sustained low commodity prices during 2016 included the following strategic actions:
Divested of certain non-core assets resulting in net proceeds of $1.2 billion
Raised proceeds of $1.2 billion from an equity offering in the first quarter of 2016
•Reduced cash additions to property, plant and equipment to $1.2 billion, a 64% decrease compared to 2015
Expanded the capacity of the revolving credit facility from $3.0 billion to $3.3 billion in the first quarter of 2016
Improved cost structure by reducing total company production expenses by 23% and production expense per boe in 2016 by:
◦North America E&P - 19% reduction to $5.96 per boe
◦International E&P - 16% reduction to $5.05 per boe
◦Oil Sands Mining - 24% reduction to $27.89 per boe
Increased cashCash and cash equivalents by $1.3 billion from year-end 2015decreased $604 million to $858 million at December 31, 2019.
Progressed our 2017 commodity hedging programDuring the fourth quarter, we completed three leverage neutral finance transactions which covers approximately 40% of our expected U.S. crude oilextend maturities and natural gas production. Pricing for these hedges is discussed in further detail in Item 8. Financial Statements and Supplementary Data – Note 16 to the consolidated financial statementsgenerate annual cash savings.
At December 31, 2016,2019, we had approximately $5.8$3.9 billion of liquidity consisting of $2.5 billion$858 million in cash and cash equivalents and $3.3$3.0 billion available under our revolving credit facility. In September 2019, we entered into an amendment to our Credit Facility to reduce the maximum borrowing from $3.4 billion to $3.0 billion and extended the maturity date by one year to May 28, 2023. As previously discussed in the Outlook section, we are targeting a $2.2$2.4 billion Capital ProgramBudget for 2017.2020. We believe our current liquidity level, and balance sheet, along with our non-core asset disposition programcash flow from operations and ability to access the capital markets provides us with the flexibility to fund our business throughout the sustained loweracross a wide range of commodity price cycle. We will continue to evaluate the commodity price environment and our spending throughout 2017.environments.
Cash Flows
The following table presents sources and uses of cash and cash equivalents for 2016, 20152019 and 2014:2018:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Sources of cash and cash equivalents | |
| | |
| | |
| Continuing operations | $ | 1,073 |
| | $ | 1,565 |
| | $ | 4,736 |
|
| Discontinued operations | — |
| | — |
| | 751 |
|
| Disposals of assets | 1,219 |
| | 225 |
| | 3,760 |
|
| Issuance of common stock | 1,236 |
| | — |
| | — |
|
| Maturities of short-term investment | — |
| | 925 |
| | — |
|
| Borrowings, net | — |
| | 1,996 |
| | — |
|
| Other | 56 |
| | 91 |
| | 214 |
|
| Total sources of cash and cash equivalents | $ | 3,584 |
| | $ | 4,802 |
| | $ | 9,461 |
|
| Uses of cash and cash equivalents | | | | | |
| Cash additions to property, plant and equipment | $ | (1,245 | ) | | $ | (3,476 | ) | | $ | (5,160 | ) |
| Purchases of short-term investments | — |
| | (925 | ) | | — |
|
| Investing activities of discontinued operations | — |
| | — |
| | (376 | ) |
| Acquisitions | (902 | ) | | — |
| | (21 | ) |
| Purchases of common stock | — |
| | — |
| | (1,000 | ) |
| Commercial paper, net | — |
| | — |
| | (135 | ) |
| Debt repayments | (1 | ) | | (1,069 | ) | | (68 | ) |
| Debt issuance costs | — |
| | (19 | ) | | — |
|
| Dividends paid | (162 | ) | | (460 | ) | | (543 | ) |
| Other | (5 | ) | | (30 | ) | | (24 | ) |
| Total uses of cash and cash equivalents | $ | (2,315 | ) | | $ | (5,979 | ) | | $ | (7,327 | ) |
|
| | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 |
| Sources of cash and cash equivalents | |
| | |
|
| Operating activities | $ | 2,749 |
| | $ | 3,234 |
|
| Disposal of assets, net of cash transferred to the buyer | (76 | ) | | 1,264 |
|
| Borrowings | 600 |
| | — |
|
| Other | 65 |
| | 93 |
|
| Total sources of cash and cash equivalents | $ | 3,338 |
| | $ | 4,591 |
|
| Uses of cash and cash equivalents | | | |
| Additions to property, plant and equipment | $ | (2,550 | ) | | $ | (2,753 | ) |
| Additions to other assets | 36 |
| | (26 | ) |
| Acquisitions, net of cash acquired | (293 | ) | | (25 | ) |
| Purchases of common stock | (362 | ) | | (713 | ) |
| Debt repayments | (600 | ) | | — |
|
| Dividends paid | (162 | ) | | (169 | ) |
| Other | (11 | ) | | (6 | ) |
| Total uses of cash and cash equivalents | $ | (3,942 | ) | | $ | (3,692 | ) |
Cash flows generated from continuing operationsoperating activities in 20162019 were 15% lower than 2015 as the downturn in commodity prices continued to impact price realizations coupleddecreased 13% along with lower net sales volumes which negatively impactin our cash flows from operating activities. In 2016, our weighted average crude oilInternational segment as a result of E.G. planned maintenance and natural gas price realizations were down 11% and 16% as compared to the prior year.field decline, coupled with dispositions.
Proceeds from disposals
Disposals of assets in 2016 are2019 were primarily related to proceeds, net of the cash transferred to the buyer, with the sale of our U.K. business; partially offset by the proceeds received from the sale of our Wyoming upstream and midstream assets,a 25% non-operated working interest in the Louisiana Austin Chalk as well as the sale of certain other assetsour non-operated interest in West Texas and New Mexico. Disposalsthe Atrush block in Kurdistan. Proceeds from the disposals of assets for 2018 are primarily related to our non-operated interest in 2015 pertain toLibya, as well as the remaining proceeds from the sale of certain of our operated and non-operated producing properties in the Gulf of Mexico as well as natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma. Disposals in 2014 primarily reflect the proceeds from the sales of our Angola assets and our NorwayCanadian business. Disposition transactions are discussed in further detail in Item 8. Financial Statements and Supplementary Data – Note 65 to the consolidated financial statements. Issuance of common stock reflects net proceeds received in March 2016. See Item 8. Financial Statements and Supplementary Data - Note 23 to the consolidated financial statements for additional information.
Cash flows from discontinued operations primarily related to our Norway business, which we disposed of in fourth quarter 2014.
Borrowings reflect net proceeds received from the issuance of senior notes in June 2015. In November 2015, we repaid our $1 billion 0.90% senior notes upon maturity.
We announced an adjustment to our quarterly dividend starting in third quarter 2015, with the full-year impact resulting in a decrease of dividends paid in the current year.
During the third quarter of 2016, we closed the Oklahoma STACK acquisition for a purchase price of $902 million, net of cash acquired; see Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for further information concerning acquisitions.
Additions to property, plant and equipment arein 2019 totaled $2.6 billion, consistent with expectations (last year, we communicated our most significant use$2.6 billion Capital Budget consisted of cash$2.4 billion in development capital and cash equivalents. $200 million to fund resource play exploration.
The following table shows capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows for 2016, 2015 and 2014:flows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| North America E&P | $ | 936 |
| | $ | 2,553 |
| | $ | 4,698 |
|
| International E&P | 82 |
| | 368 |
| | 534 |
|
Oil Sands Mining (a) | 33 |
| | (10 | ) | | 212 |
|
| Corporate | 18 |
| | 25 |
| | 51 |
|
| Total capital expenditures | 1,069 |
| | 2,936 |
| | 5,495 |
|
| Change in capital expenditure accrual | 176 |
| | 540 |
| | (335 | ) |
| Additions to property, plant and equipment | $ | 1,245 |
| | $ | 3,476 |
| | $ | 5,160 |
|
(a) Reflects reimbursements earned from the governments of Canada and Alberta related |
| | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 |
United States (a) | $ | 2,550 |
| | $ | 2,620 |
|
| International | 16 |
| | 39 |
|
| Corporate | 25 |
| | 26 |
|
| Total capital expenditures | 2,591 |
| | 2,685 |
|
Change in capital expenditure accrual(a) | (41 | ) | | 68 |
|
| Total use of cash and cash equivalents for property, plant and equipment | $ | 2,550 |
| | $ | 2,753 |
|
| |
(a) | The change in capital expenditure accrual includes activity for assets classified as held for sale for the years presented. |
Additions to funds previously expended for Quest CCS capital equipment. Quest CCS was successfully completed and commissioned inother assets relates to deposits on our resource play exploration program.
In the fourth quarter of 2015.
There were no share repurchases in 2016 or 2015. During 2014,2019, we acquired 29approximately 18,000 net acres in the Eagle Ford for $191 million shares atand approximately 40,000 acres in a costTexas Delaware oil play in West Texas for $106 million.
During the fourth quarter 2019, we completed two separate financing transactions resulting in a debt borrowing of $1 billion. See$600 million and debt repayment of $600 million, which is further discussed in the Capital Resources section below. Also see Item 8. Financial Statements and Supplementary Data –- Note 2317 to the consolidated financial statements for discussiondetails of purchasesthese items During 2019 and 2018, the Board of common stock.Directors approved a $0.05 per share quarterly dividend. See Capital Requirements below for additional information about the fourth quarter 2019 dividend.
Available Liquidity and Capital Resources
In March 2016,September 2019, we issued 166,750,000 shares ofentered into an amendment to our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discountsCredit Facility to reduce the maximum borrowing from $3.4 billion to $3.0 billion and commissions, for net proceeds of $1,236 million. The proceeds were usedextended the maturity date by one year to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
Also in March 2016, we increased our $3 billion unsecured revolving credit facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the revolving credit facility, remain unaffected by the increase.May 28, 2023.
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our $3.3 billion revolving credit facility.Credit Facility. At December 31, 2016,2019, we had approximately $5.8$3.9 billion of liquidity consisting of $2.5 billion$858 million in cash and cash equivalents and $3.3$3.0 billion available under our revolving credit facility.Credit Facility. Our working capital requirements are supported by these sources and we may issue either commercial paper backed by our revolving Credit Facility or draw on our $3.3 billion revolving credit facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management.management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.
DueGeneral economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to decreases in crude oil and U.S. natural gas prices, credit rating agencies reviewed companies inaccess the industry earlier this year. During the first quarter of 2016, ourcapital markets. Our corporate credit rating was downgraded by:ratings as of December 31, 2019 are: Standard & Poor'sPoor’s Ratings Services to BBB- (stable) from BBB (stable); by Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). On October 11, 2016, Moody’s Investor Services, Inc. subsequently revised their outlook of our corporateBaa3 (stable). We are rated investment grade at all three primary credit rating agencies. In addition, we also have the ability to stable from negative. Any further rating downgradesborrow on our U.S. commercial paper program, which is backed by the revolving credit facility. A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors for a discussion of how a further downgrade in our credit ratings could affect us.
We may incur additional debt in order to fund our capital expenditures, acquisitions or development activities, or for general corporate or other purposes. A higher level of indebtedness could increase the risk that our liquidity and financial flexibility deteriorates. See Item 1A. Risk Factors for a further discussion of how our level of indebtedness could affect us. The June 23, 2016 referendum by British voters to exit the European Union (“Brexit”) provided volatility around European currencies and resulted in a decline in the value of the British pound, as compared to the U.S. dollar and other currencies. For our U.K. operations, a majority of our revenues are tied to global crude oil prices which are denominated in U.S. dollars while a significant portion of our operating and capital costs are denominated in British pounds. In addition, our U.K. operations have an asset retirement obligation, which represents a future cash commitment. In the longer term, any impact from Brexit on our U.K. operations will depend, in part, on the outcome of tariff, trade, regulatory, and other negotiations.
Capital Resources
Credit Arrangements and Borrowings
At December 31, 2016,2019, we had no borrowings against our revolving credit facility.Credit Facility or under our U.S. commercial paper program that is backed by the Credit Facility.
At December 31, 2016,2019, we had $7.3$5.5 billion in long-term debt outstanding, with our next debt maturity in the amount of $682 million due in the fourth quarter of 2017.
outstanding. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
On October 1, 2019, we closed a $600 million remarketing to investors of sub-series A bonds which are part of the $1.0 billion St. John the Baptist, State of Louisiana revenue refunding bonds originally issued and purchased in December 2017. The $600 million in proceeds from the conversion and remarketing were used to pay the purchase price of our converted 2017 bonds on the closing date. We continue to own the remaining $400 million of the revenue refunding bonds and have the right to convert and remarket them to investors at any time up to the 2037 maturity date.
On October 3, 2019, we redeemed our $600 million 2.7% senior unsecured notes due June 2020. Our next debt maturity is the $1.0 billion 2.8% senior unsecured notes due 2022.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known“well-known seasoned issuer"issuer” for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Asset Disposals
We have closed or announced $1.3 billion of non-core asset sales during 2016. In the largest transaction,third quarter of 2019, we announcedclosed on the sale of our Wyoming upstream and midstream assets and receivedU.K. business for proceeds of approximately $845 million. We also entered into multiple agreements to sell certain non-operated assets,$95 million, reflecting the assumption by the buyer of working capital and CO2 and waterflood assets in West Texas and New Mexico for combined proceedscash equivalent balances, asset retirement obligations of approximately $302 million. Additionally, we entered into separate agreements to sell our 10% working interest in$966 million, as well as the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds. We closed on certain of these asset sales in 2016, with the remaining asset sales expected to close inpension obligations.
In the second quarter of 2017.
See2019, we closed on the sale of our 15% non-operated interest in the Atrush block in Kurdistan for proceeds of $63 million, before closing adjustments. Disposition transactions are discussed in further detail in Item 8. Financial Statements and Supplementary Data –
Note 65 to the consolidated financial statements for additional discussion of these dispositions. statements.Cash-Adjusted Debt-To-Capital Ratio
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 21%31% at both December 31, 20162019 and 25% at December 31, 2015.
|
| | | | | | | |
| (Dollars in millions) | 2016 | | 2015 |
| Long-term debt due within one year | $ | 686 |
| | $ | 1 |
|
| Long-term debt | 6,589 |
| | 7,276 |
|
| Total debt | $ | 7,275 |
| | $ | 7,277 |
|
| Cash and cash equivalents | $ | 2,490 |
| | $ | 1,221 |
|
| Equity | $ | 17,541 |
| | $ | 18,553 |
|
| Calculation | | | |
| Total debt | $ | 7,275 |
| | $ | 7,277 |
|
| Minus cash and cash equivalents | 2,490 |
| | 1,221 |
|
| Total debt minus cash and cash equivalents | 4,785 |
|
| 6,056 |
|
| Total debt | $ | 7,275 |
| | $ | 7,277 |
|
| Plus equity | 17,541 |
| | 18,553 |
|
| Minus cash and cash equivalents | 2,490 |
| | 1,221 |
|
| Total debt plus equity minus cash, cash equivalents | $ | 22,326 |
|
| $ | 24,609 |
|
| Cash-adjusted debt-to-capital ratio | 21 | % | | 25 | % |
Capital Requirements
Capital Spending
Our approved Capital ProgramBudget for 20172020 is $2.2$2.4 billion. Additional details were previously discussed in Outlook.Outlook. Share Repurchase Program
TheIn 2019, we acquired approximately 24 million common shares at a cost of $345 million under our share repurchase program with remaining share repurchase authorization as of December 31, 2016 is $1.52019 of $1.4 billion.
Other Expected Cash Outflows
On January 25, 2017,29, 2020, our Board of Directors approved a dividend of $0.05 per share for the fourth quarter of 2016.2019. The dividend is payable on March 10, 20172020 to shareholders onof record on February 15, 2017.19, 2020.
We plan to make contributions of up to $60$28 million to our funded pension plans during 2017.2020. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $5$6 million and $21$18 million in 2017.2020.
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2016.2019.
| | | (In millions) | Total | | 2017 | | 2018- 2019 | | 2020- 2021 | | Later Years | Total | | 2020 | | 2021- 2022 | | 2023- 2024 | | Later Years |
Short and long-term debt (includes interest)(a) | $ | 11,318 |
| | $ | 1,042 |
| | $ | 1,654 |
| | $ | 1,102 |
| | $ | 7,520 |
| $ | 8,320 |
| | $ | 252 |
| | $ | 1,538 |
| | $ | 1,016 |
| | $ | 5,514 |
|
Lease obligations | 183 |
| | 36 |
| | 58 |
| | 55 |
| | 34 |
| 276 |
| | 114 |
| | 98 |
| | 6 |
| | 58 |
|
| Purchase obligations: | | | | | | | | | | | | | | | | | | |
Oil and gas activities(b)(c) | 151 |
| | 128 |
| | 14 |
| | 7 |
| | 2 |
| 52 |
| | 42 |
| | 2 |
| | 1 |
| | 7 |
|
Service and materials contracts(c)(d) | 764 |
| | 78 |
| | 93 |
| | 28 |
| | 565 |
| 126 |
| | 69 |
| | 54 |
| | 3 |
| | — |
|
| Transportation and related contracts | 1,606 |
| | 256 |
| | 483 |
| | 261 |
| | 606 |
| 1,872 |
| | 225 |
| | 520 |
| | 476 |
| | 651 |
|
Drilling rigs and fracturing crews(d) | 44 |
| | 44 |
| | — |
| | — |
| | — |
| |
| Other | 126 |
| | 20 |
| | 32 |
| | 22 |
| | 52 |
| |
Other (e) | | 33 |
| | 29 |
| | 4 |
| | — |
| | — |
|
| Total purchase obligations | 2,691 |
| | 526 |
| | 622 |
| | 318 |
| | 1,225 |
| 2,083 |
| | 365 |
| | 580 |
| | 480 |
| | 658 |
|
Other long-term liabilities reported in the consolidated balance sheet(e) | 370 |
| | 51 |
| | 69 |
| | 69 |
| | 181 |
| |
Total contractual cash obligations(f) | $ | 14,562 |
| | $ | 1,655 |
| | $ | 2,403 |
| | $ | 1,544 |
| | $ | 8,960 |
| |
Other long-term liabilities reported in the consolidated balance sheet(f) | | 410 |
| | 32 |
| | 52 |
| | 48 |
| | 278 |
|
Total contractual cash obligations(g) | | $ | 11,089 |
| | $ | 763 |
| | $ | 2,268 |
| | $ | 1,550 |
| | $ | 6,508 |
|
| |
(a) | Includes anticipated cash payments for interest of $359$252 million for 2017, $5722020, $503 million for 2018-2019, $5022021-2022, $415 million for 2020-20212023-2024 and $2,585 million$1.6 billion for the remaining years for a total of $4,018 million.$2.8 billion. |
| |
(b) | Includes project costs incurred as of December 31, 2019 for new build-to-suit office building in Houston, Texas. See Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements and Off-Balance Sheet Arrangements section below. |
| |
(c) | Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately. |
| |
(c)(d)
| Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services. |
| |
(d)(e)
| Some contracts may be canceled at an amount less than the contract amount. Were we to electIncludes any drilling rigs and fracturing crews that option where possible at December 31, 2016 our minimum commitment would be $42 million.are not considered lease obligations. |
| |
(e)(f)
| Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2026.2027. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity. |
| |
(f)(g)
| This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1,748$254 million. See Item 8. Financial Statements and Supplementary Data – Note 1812 to the consolidated financial statements. |
Transactions with Related Parties
We own a 63% working interest in the Alba field offshore E.G. Onshore E.G., we own a 52% interest in an LPG processing plant, a 60% interest in an LNG production facility and a 45% interest in a methanol production plant, each through equity method investees. We sell our natural gas from the Alba field to these equity method investees as the feedstock for their production processes.
Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under accounting principles generally accepted in the U.S. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.
We will issue stand-alone letters of credit when required by a business partner. Such letters of credit outstanding at December 31, 2016, 20152019, 2018 and 20142017 aggregated $166$14 million, $53$52 million and $101$89 million. Most of the letters of credit are in support of obligations recorded in the consolidated balance sheet. For example, they are issuedIn 2019, our letters of credit outstanding decreased as a result of our upgraded credit rating and the sale of our U.K. business (we no longer have requirements to counterparties to insure our payments for outstanding company debtsupport firm transportation agreements and future abandonment liabilities.liabilities).
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The new Houston office location is expected to be completed in 2021. The lessor and other participants are providing financing for up to $380 million, to fund the estimated project costs. As of December 31, 2019 project costs incurred totaled $58 million, primarily for land acquisition and initial design costs. The initial lease term is five years and will commence once construction is substantially complete and the new Houston office is ready for occupancy. At the end of the initial lease term, we can extend the term of the lease for an additional five years, subject to the approval of the
participants; purchase the property subject to certain terms and conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs. See Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements for further information on leases.
Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies
We have incurred and maywill continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected inoffset by the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.
Legislation These laws generally provide for control of pollutants released into the environment and regulations pertainingrequire responsible parties to climate change and greenhouse gas emissions have the potential to materially adversely impact our business, financial condition, resultsundertake remediation of operations and cash flows, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts cannothazardous waste disposal sites. Penalties may be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time framesimposed for compliance, and our ability to pass compliance costs on to our customers. For additional information see Item 1A. Risk Factors.noncompliance.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future.future on both state and federal levels. We strive to comply with all legal requirements regarding the environment, but as not all costs are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
Critical Accounting Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.
Estimated Quantities of Net Reserves
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved crude oil and condensate, NGLs and natural gas and synthetic crude oil reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties are used for testing impairment and the expected future taxable income available to realize deferred tax assets, also in part, rely on estimates of quantities of net reserves. Refer to the applicable sections below for further discussion of these accounting estimates.
The estimation of quantities of net reserves is a highly technical process performed by our petroleum engineers and geoscientists for crude oil and condensate, NGLs and natural gas, and synthetic crude oil, which is based upon several underlying assumptions. The reserve estimates may change as additional information becomes available and as contractual, operational, economic and political conditions change. We evaluate our reserves using drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The observed statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves. The data for a given reservoir may also change over time as a result of numerous factors including, but not limited to, additional development activity and future development costs, production history and continual reassessment of the viability of future production volumes under varying economic conditions.
Reserve estimates are based on an unweighted arithmetic average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC. The table below provides the 20162019 SEC pricing for certain benchmark prices:
| | | | SEC Pricing 2016 | 2019 SEC Pricing |
WTI Crude oil (per bbl) | $ | 42.75 |
| $ | 55.69 |
|
Henry Hub natural gas (per mmbtu) | $ | 2.49 |
| $ | 2.58 |
|
Brent crude oil (per bbl) | $ | 43.53 |
| $ | 63.15 |
|
Mont Belvieu NGLs (per bbl) | $ | 15.89 |
| $ | 18.41 |
|
When determining the December 31, 20162019 proved reserves for each property, the benchmark prices listed above were adjusted using price differentials that account for property-specific quality and location differences.
Estimates ofIf crude oil prices in the future cash flows associated with proved reserves are based on actual costs of developing and producingaverage below prices used to determine proved reserves at the end of the year. If commodity prices were to significantly drop below average prices used to estimate 2016 proved reserves (see table above), we would expect price related reserve revisions thatDecember 31, 2019, it could have a material impactan adverse effect on our estimates of proved reserve volumes and the present value of our proved reserves. In this scenario, our OSMbusiness. Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation, among other things. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, represent the largest riskdue to be reclassified to non-proved reserves or resource category.numerous factors (including future crude oil price and performance revisions). For further discussion of risks associated with our estimation of proved reserves, see Part I. Item 1A1A. Risk Factors.Factors.Depreciation and depletion of crude oil and condensate, NGLs and natural gas and synthetic crude oil producing properties is determined by the units-of-production method and could change with revisions to estimated proved reserves. While revisions of previous reserve estimates have not historically been significant to the depreciation and depletion rates of our segments, any reduction in proved reserves, could result in an acceleration of future DD&A expense. The following table illustrates, on average, the sensitivity of each segment'ssegment’s units-of-production DD&A per boe and pretax income to a hypothetical 10% change in 20162019 proved reserves based on 20162019 production.
|
| | | | | | | | | | | | | | | |
| | Impact of a 10% Increase in Proved Reserves | | Impact of a 10% Decrease in Proved Reserves |
| (In millions, except per boe) | DD&A per boe | | Pretax Income | | DD&A per boe | | Pretax Income |
| North America E&P | $ | (2.04 | ) | | $ | 167 |
| | $ | 2.50 |
| | $ | (204 | ) |
| International E&P | $ | (0.56 | ) | | $ | 25 |
| | $ | 0.69 |
| | $ | (31 | ) |
| Oil Sands Mining | $ | (0.99 | ) | | $ | 18 |
| | $ | 1.26 |
| | $ | (22 | ) |
|
| | | | | | | | | | | | | | | |
| | Impact of a 10% Increase in Proved Reserves | | Impact of a 10% Decrease in Proved Reserves |
| (In millions, except per boe) | DD&A per boe | | Pretax Income | | DD&A per boe | | Pretax Income |
| United States | $ | (1.73 | ) | | $ | 205 |
| | $ | 2.12 |
| | $ | (250 | ) |
| International | $ | (0.33 | ) | | $ | 11 |
| | $ | 0.40 |
| | $ | (13 | ) |
Asset Retirement Obligations
We have material legal, regulatory and contractual obligations to remove and dismantle long-lived assets and to restore land or seabed at the end of oil and gas production operations, including bitumen mining operations. A liability equal to the fair value of such obligations and a corresponding capitalized asset retirement cost are recognized on the balance sheet in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be made. The capitalized asset retirement cost is depreciated using the units-of-production method and the discounted liability is accreted over the period until the obligation is satisfied, the impacts of which are recognized as DD&A in the consolidated statements of income. In many cases, the satisfaction and subsequent discharge of these liabilities is projected to occur many years, or even decades, into the future. Furthermore, the legal, regulatory and contractual requirements often do not provide specific guidance regarding removal practices and the criteria that must be fulfilled when the removal and/or restoration event actually occurs.
Estimates of retirement costs are developed for each property based on numerous factors, such as the scope of the dismantlement, timing of settlement, interpretation of legal, regulatory and contractual requirements, type of production and processing structures, depth of water (if applicable), reservoir characteristics, depth of the reservoir, market demand for equipment, currently available dismantlement and restoration procedures and consultations with construction and engineering professionals. Inflation rates and credit-adjusted-risk-free interest rates are then applied to estimate the fair values of the obligations. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Changes in estimated asset retirement obligations for late life assets could result in future impairment charges. See Item 8. Financial Statements and Supplementary Data – Note 18 to the consolidated financial statements for disclosures regarding our asset retirement obligation estimates.
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of obligations that must be assessed, the number of underlying assumptions and the wide range of possible assumptions.
Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value, or range of present values, using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. See Item 8. Financial Statements and Supplementary Data – Note 1516 to the consolidated financial statements for disclosures regarding our fair value measurements. Significant uses of fair value measurements include:
assets and liabilities acquired in a business combination;
assets acquired in an asset acquisition;
impairment assessments of long-lived assets;
impairment assessments of goodwill;
recorded value of derivative instruments; and
recorded value of derivative instruments.pension plan assets.
The need to test long-lived assets and goodwill for impairment can be based on several indicators, including a significant reduction in prices of crude oil and condensate, NGLs and natural gas, or synthetic crude oil, sustained declines in our common stock, reductions to our Capital Program,Budget, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which the property is located.
Impairment Assessments of Long-Lived Assets
Long-lived assets in use are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of an impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value. During 20162019, proved property impairments were primarily as a result of anticipated sales for certain non-core proved properties in our United States segment and the sustained decline of commodity prices resulted in a downward revisionssale of our long-term commodity price assumptions which triggered an assessment of certain ofnon-operated interest in the Atrush block (Kurdistan) in our long-lived assets related to oil and gas producing properties for impairment.International segment. We estimated the fair values using an incomea market approach, based upon anticipated sales proceeds less costs to sell, and recognized impairments. As of the date of our last impairment assessment, our estimated undiscounted cash flows relating to our long-lived assets significantly exceeded their carrying values. Long-lived assets most at risk for future impairment (defined as those assets with estimated undiscounted cash flows that exceeded their carrying values by less than approximately 50%) had estimated undiscounted cash flows that exceeded their $269 million carrying value by $139 million. See Item 8. Financial Statements and Supplementary Data Note 13 and Note 15 to the consolidated financial statements for discussion of impairments recorded in 2016, 2015 and 2014 and the related fair value measurements.
Fair value calculated for the purpose of testing our long-lived assets for impairment is estimated using the present value of expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:
| |
| • | Future crude oil and condensate, NGLs and natural gas prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies and vehicle stocks. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in crude oil and condensate, NGLs and natural gas prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors for further discussion on commodity prices. |
| |
| • | Estimated quantities of crude oil and condensate, NGLs and natural gas. Such quantities are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors for further discussion on reserves. |
| |
| • | Expected timing of production. Production forecasts are the outcome of engineering studies which estimate reserves, as well as expected capital programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews. |
| |
| • | Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows. |
| |
| • | Future capital requirements. Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts. |
Future crude oil and condensate, NGLs, natural gas and synthetic crude oil prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies and vehicle stocks. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in crude oil and condensate, NGLs, natural gas and synthetic crude oil prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors for further discussion on commodity prices.
Estimated quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil. Such quantities are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors for further discussion on reserves.
Expected timing of production. Production forecasts are the outcome of engineer studies which estimate reserves, as well as expected capital development programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews.
Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.
Future capital requirements. Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.
We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. An estimate of the sensitivity to changes in assumptions in our undiscounted cash flow calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future undiscounted cash flows would likely be partially offset by lower costs. As of December 31, 2019 our estimated undiscounted cash flows relating to our remaining long-lived assets significantly exceeded their carrying values. See Item 8. Financial Statements and Supplementary Data Note 11 and Note 16 to the consolidated financial statements for discussion of impairments recorded in 2019, 2018 and 2017 and the related fair value measurements. Impairment Assessments of Goodwill
Goodwill must beis tested for impairment at least annually,on an annual basis, or between annual tests if an event occurswhen events or changes in circumstances change that would more likely than not reduceindicate the fair value of a reporting unitmay have been reduced below its carrying amount.value. Goodwill is tested for impairment at the reporting unit level. We performedOur reporting units are the same as our annual impairment test in April 2016 for thereporting segments, of which only International E&P reporting unit and no impairment was required. Based on the results of these assessments, we fully impaired the goodwill associated with our North America E&P reporting unit.includes goodwill. As of the dateDecember 31, 2019, our consolidated balance sheet included goodwill of our last goodwill impairment assessment, our International E&P reporting unit fair value exceeded its book value of $115 million by 26%.
We estimate the fair values of the International E&P reporting unit using a combination of market and income approaches.$95 million. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Our policy is to first assess the qualitative factors in order to determine whether the fair value of our International reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test; macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determined that it is more likely than not that the fair value of the International reporting unit is less than its carrying amount, a quantitative goodwill test is performed. The quantitative goodwill test is performed using a combination of market and income approaches. The market approach referencedreferences observable inputs specific to us and our industry.industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach calculated the present value of expected futureutilizes discounted cash flows, which wereare based on forecasted assumptions. Key assumptions to the income approach are the same as those described above regarding our impairment assessment of long-lived assets.long lived assets and are consistent with those that management uses to make business decisions.
During the second quarter of 2019, we performed our annual impairment test of goodwill using the qualitative assessment. Our qualitative assessment considered the significant excess fair value over carrying value in our most recent step 1 test (second quarter of 2017) and noted a general improvement in the qualitative factors above. After assessing the totality of the qualitative factors which could have a positive or negative impact on goodwill, our assessment did not indicate that it is more likely than not that the fair value is less than its carrying value. As a result, we concluded that no impairment to goodwill was required for our International reporting unit. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in such assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. See Item Item��8. Financial Statements and Supplementary Data Note 14 to the consolidated financial statements for additional discussion of goodwill. Derivatives
We record all derivative instruments at fair value. Fair value measurements for all our derivative instruments are based on observable market-based inputs that are corroborated by market data and are discussed in Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.Risk.
Pension Plan Assets
Pension plan assets are measured at fair value. See Item 8. Financial Statements and Supplementary Data – Note 19 to the consolidated financial statements for discussion of the fair value of plan assets and the presentation of the fair value of our defined benefit pension plan’s assets by level within the fair value hierarchy as of December 31, 2019 and 2018. Income Taxes
We are subject to income taxes in numerous taxing jurisdictions worldwide. Estimates of income taxes to be recorded involve interpretation of complex tax laws and assessment of the effects of foreign taxes on our U.S. federal income taxes.
Uncertainty exists regarding tax positions taken in previously filed tax returns which remain subject to examination, along with positions expected to be taken in future returns. We provide for unrecognized tax benefits, based on the technical merits, when it is more likely than not that an uncertain tax position will not be sustained upon examination. Adjustments are made to
the uncertain tax positions when facts and circumstances change, such as the closing of a tax audit; court proceedings; changes in applicable tax laws, including tax case rulings and legislative guidance; or expiration of the applicable statute of limitations.
We have recorded deferred tax assets and liabilities, measured at enacted tax rates, for temporary differences between book basis and tax basis, tax credit carryforwards and operating loss carryforwards. WeIn accordance with U.S. GAAP accounting standards, we routinely assess the realizability of our deferred tax assets and reduce such assets, to the expected realizable amount, by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider the preponderance of evidence concerning the realization of the deferred tax asset. We must consider any prudent and feasible tax planning strategies that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets, if we can implement the strategies and if we expect to implement them in the event the forecasted conditions actually occur. This assessment requires analysis of all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies.strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the forecasts of future income (loss) in the realizable period.
We expect to be in a cumulative loss position in early 2017, which constitutes significant objective negative evidence as to the future realizability of the value of our deferred tax assets. As a result, we are limited in our ability to consider forecasts for taxable income in future years in connection with In making our assessment ofregarding valuation allowances, we weight the realizability of our foreign tax credits and other federal deferred tax assets. Additionally, we considered the reversals of existing deferred tax assets and liabilities related to temporary differences between the book and tax basis of our assets and liabilities and concluded that it is more likely than not that a portion of our deferred tax assets would not be realized. Therefore, we increased our valuation allowanceevidence based on our federal deferred tax assets by $1,346 million in 2016. Our remaining U.S. operating loss carryforwards of $1.8 billion, which expire in 2035 and 2036, represent the federal deferred tax asset most at risk for an additional valuation allowance at December 31, 2016. See further detail in Item 8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements.objectivity.
We base our future taxable income estimates on projected financial information which we believe to be reasonably likely to occur. Numerous judgments and assumptions are inherent in the estimation of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes. Future operating conditions can be affected by numerous factors, including (i) future crude oil and condensate, NGLs and natural gas and synthetic crude oil prices, (ii) estimated quantities of crude oil and condensate, NGLs and natural gas, and synthetic crude oil, (iii) expected timing of production, and (iv) future capital requirements. These assumptions are described in further detail above regarding our impairment assessment of long-lived assets, see above for further detail describing these assumptions.assets. An estimate of the sensitivity to changes in assumptions resulting in future taxable income calculations is not practicable, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future taxable income would likely be partially offset by lower costs.capital expenditures.
Based on the assumptions and judgments described above, as of December 31, 2019, we reflect a valuation allowance in our consolidated balance sheet of $699 million against our gross deferred tax assets of $2.4 billion in various jurisdictions in which we operate. Our gross deferred tax assets consist primarily of federal U.S. operating loss carryforwards of $655 million, which will expire in 2035 - 2037, and $829 million which can be carried forward indefinitely. Since December 31, 2016, we have maintained a full valuation allowance on our net federal deferred tax assets. If objective negative evidence in the form of cumulative losses are no longer present and additional weight is given to subjective evidence such as forecasted projections of taxable income in future years, we would adjust the amount of the federal deferred tax assets considered realizable and reduce the provision for income taxes in the period of adjustment. See Item 8. Financial Statements and Supplementary Data – Note 8 to the consolidated financial statements for further detail. Pension and Other Postretirement Benefit Obligations
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:
the discount rate for measuring the present value of future plan obligations;
the expected long-term return on plan assets;
the rate of future increases in compensation levels; and
health care cost projections.
We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our U.S. pension plans and our other U.S. postretirement benefit plans due to the different projected benefit payment patterns. In determining the assumed discount rates, our methods include a review of market yields on high-quality corporate debt and use of our third-party actuary'sactuary’s discount rate model. This model calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield curve derived from bond yields. The yield curve represents a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used are rated AA or higher by a recognized rating agency, only non-callable bonds are included and outlier bonds (bonds that have a yield to maturity that significantly deviates from the average yield within each maturity grouping) are removed. Each issue is required to have at least $250$300 million par value outstanding. The constructed yield curve is based on those bonds representing the 50% highest yielding issuances within each defined maturity group.
Of the assumptions used to measure obligations and estimated annual net periodic benefit cost as of December 31, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. The hypothetical impacts of a
0.25% change in the discount rates of 4.02% for our U.S. pension plans and 3.98% for our other U.S. postretirement benefit plans is summarized in the table below:
|
| | | | | | | | | | | | | | | |
| | Impact of a 0.25% Increase in Discount Rate | | Impact of a 0.25% Decrease in Discount Rate |
| (In millions) | Obligation | | Expense | | Obligation | | Expense |
| U.S. pension plans | $ | (5 | ) | | $ | — |
| | $ | 6 |
| | $ | — |
|
| Other U.S. postretirement benefit plans | $ | (5 | ) | | $ | — |
| | $ | 5 |
| | $ | — |
|
The asset rate of return assumption for the funded U.S. plan considers the plan'splan’s asset mix (currently targeted at approximately 55% equity and 45% other fixed income securities), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Decreasing the 6.75% asset rate of return assumption by 0.25% would not have a significant impact on our defined benefit pension expense.
Compensation change assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans. Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.
Item 8. Financial Statements and Supplementary Data – Note 2019 to the consolidated financial statements includes detailed information about the assumptions used to calculate the components of our annual defined benefit pension and other postretirement plan expense, as well as the obligations and accumulated other comprehensive income reported on the consolidated balance sheets. Contingent Liabilities
We accrue contingent liabilities for environmental remediation, tax deficiencies related to operating taxes, as well as tax disputes and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances outside legal counsel is utilized.
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.
Accounting Standards Not Yet Adopted
See Item 8. Financial Statements and Supplementary Data – Note 2 to the consolidated financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks related to the volatility of crude oil and condensate, NGLs, and natural gas and synthetic crude oil prices as the volatility of these prices continues to impact our industry. We expect commodity prices to remain volatile and unpredictable in the future. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. We employ various strategies, including the use of financial derivative instruments, to manage the risks related to these fluctuations. We are at risk for changes in the fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction. While the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods, we believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.
See Item 8. Financial Statements and Supplementary Data – NotesNote 15 and Note 16 to the consolidated financial statements for more information about the fair value measurement of our derivatives, the amounts recorded in our consolidated balance sheets and statements of income and the related notional amounts. Commodity Price Risk
Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. However, management will periodically protect prices on forecasted sales to support cash flow and liquidity, as deemed appropriate. We may use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our business. Our consolidated results for 20162019, 2018 and 20152017 were impacted by crude oil and natural gas derivatives related to a portion of our forecasted North America E&PUnited States sales. The table below provides a summary of open positions as
As of December 31, 20162019, we had various open commodity derivatives related to crude oil and natural gas with a net asset position of $4 million. Based on the weighted average price for those contracts: |
| | | | | | | |
Crude Oil (a) |
| | 2017 |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
Three-Way Collars (b) | | | | | | | |
| Volume (Bbls/day) | 50,000 | | 50,000 | | 30,000 | | 30,000 |
| Price per Bbl: | | | | | | | |
| Ceiling | $58.42 | | $58.42 | | $59.60 | | $59.60 |
| Floor | $50.30 | | $50.30 | | $54.00 | | $54.00 |
| Sold put | $43.50 | | $43.50 | | $47.00 | | $47.00 |
Sold Call Options (c) | | | | | | | |
| Volume (Bbls/day) | 35,000 | | 35,000 | | 35,000 | | 35,000 |
| Price per Bbl | $61.91 | | $61.91 | | $61.91 | | $61.91 |
| |
(a)
| Subsequent to December 31, 2016, we entered into 10,000 Bbls/day of fixed-price swaps with a weighted average price of $54.00 indexed to WTI for February - March of 2017. |
| |
(b)
| Subsequent to December 31, 2016, we entered into 20,000 Bbls/day of three-way collars for July - December of 2017 with a ceiling price of $61.52, a floor price of $56.00, and a sold put price of $49.00. |
| |
(c)
| Call options settle monthly. |
|
| | | | | |
| Natural Gas |
| | 2017 | 2018 |
| | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |
Three-Way Collars (a) | | | | | |
| Volume (MMBtu/day) | 60,000 | 90,000 | 90,000 | 90,000 | 20,000 |
| Price per MMBtu | | | | | |
| Ceiling | $3.46 | $3.54 | $3.54 | $3.61 | $3.56 |
| Floor | $2.84 | $3.01 | $3.01 | $3.04 | $3.00 |
| Sold put | $2.35 | $2.48 | $2.48 | $2.52 | $2.50 |
| Swap | | | | | |
| Volume (MMBtu/day) | 20,000 | 20,000 | 20,000 | 20,000 | — |
| Price per MMBtu | 2.93 | 2.93 | 2.93 | 2.93 | — |
| |
(a)
| Subsequent to December 31, 2016, we entered into three-way collars of 30,000 MMBtus/day for April - September of 2017 with a ceiling price of $3.70, a floor price of $3.35, and a sold put price of $2.75; 30,000 MMBtus/day for October - December of 2017 with a ceiling price of $4.00, a floor price of $3.45, and a sold put price of $2.85; and 70,000 MMBtus/day for January - December of 2018 with a ceiling price of $3.62, a floor price of $3.00, and a sold put price of $2.50. |
The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change inDecember 31, 2019, published NYMEX WTI and Henry Hub futures prices, ona hypothetical 10% increase or decrease (per bbl for crude oil and per MMBtu for natural gas) would change the fair values of our opennet commodity derivative instruments as of December 31, 2016:open positions to the following: | | | (In millions) | Hypothetical Price Increase of 10% | Hypothetical Price Decrease of 10% | Hypothetical Price Increase of 10% | | Hypothetical Price Decrease of 10% |
| Crude oil derivatives | (79 | ) | 56 |
| $ | (65 | ) | | $ | 50 |
|
| Natural gas derivatives | (11 | ) | 13 |
| (1 | ) | | — |
|
| Total | (90 | ) | 69 |
| $ | (66 | ) | | $ | 50 |
|
Interest Rate Risk
At December 31, 2016,2019, our portfolio of long-term debt was substantiallyis comprised of fixed rate instruments. We currently manage our exposure to interest rate movements by utilizing interest rate swap agreements that effectively convert a portionfixed-rate instruments with an outstanding balance of our fixed rate debt to floating interest rate debt. As of December 31, 2016, we had multiple interest rate swap agreements with a total notional of $900 million designated as fair value hedges. We additionally use forward starting interest rate swaps to manage our risk of interest rate changes during the period prior to anticipated borrowings. As of December 31, 2016, we had multiple forward starting interest rate swap agreements with a total notional of $750 million designated as cash flow hedges.
$5.5 billion. Our sensitivity to interest rate movements and corresponding changes in the fair value of our fixed ratefixed-rate debt portfolio affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices different than carrying value. Sensitivity analysis
We also manage our exposure to interest rate movements by utilizing interest rate swap agreements to hedge variations in cash flows related to the 1-month LIBOR component of future lease payments on our future Houston office. At December 31, 2019, we had forward starting interest rate swap agreements with a total notional of $320 million designated as cash flow hedges. The incremental change on the fair value of a hypothetical 10% increase in interest rates by $3 million, resulting in a fair value of $5 million. The incremental effectchange on the fair value of a hypothetical 10% decrease in interest rates on financial assets and liabilities asthese interest rate swaps by $2 million, resulting in a fair value of December 31, 2016, is provided in the following table.less than $1 million.
|
| | | | | | | |
| | | | Incremental |
| | | | Change in |
| (In millions) | Fair Value | | Fair Value |
Financial assets (liabilities): (a) | | | |
| Interest rate cash flow hedges | 64 |
| (b) | (16 | ) |
| Interest rate fair value hedges | $ | 4 |
| (b) | $ | 1 |
|
| Long-term debt, including amounts due within one year | $ | (7,449 | ) | (b)(c) | $ | (265 | ) |
| |
(a)
| Fair values of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table. |
| |
(b)
| Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities. |
| |
(c)
| Excludes capital leases. |
Counterparty Risk
We are also exposed to financial risk in the event of nonperformance by counterparties. If commodity prices continue to remain low,fall below current levels, some of our counterparties may experience liquidity problems and may not be able to meet their financial obligations to us. We review the creditworthiness of counterparties and use master netting agreements when appropriate.
Item 8. Financial Statements and Supplementary Data
Index
Management’s Responsibilities for Financial Statements
To the Stockholders of Marathon Oil Corporation:
The accompanying consolidated financial statements of Marathon Oil Corporation and its consolidated subsidiaries ("(“Marathon Oil"Oil”) are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.
Marathon Oil seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organization arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.
The Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit and Finance Committee. This Committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.
|
| | | | |
| /s/ Lee M. Tillman | | /s/ Patrick J. Wagner | Dane E. Whitehead | |
| Chairman, President and Chief Executive Officer | | InterimExecutive Vice President and Chief Financial Officer and Vice President-Corporate Development and Strategy | | |
Management’s Report on Internal Control over Financial Reporting
To the Stockholders of Marathon Oil Corporation:
Marathon Oil’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13(a) – 15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
An evaluation of the design and effectiveness of our internal control over financial reporting, based on the 2013 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on the results of this evaluation, Marathon Oil’s management concluded that its internal control over financial reporting was effective as of December 31, 2016.2019.
The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 20162019 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
|
| | | |
| /s/ Lee M. Tillman | | /s/ Patrick J. WagnerDane E. Whitehead | |
| Chairman, President and Chief Executive Officer | | InterimExecutive Vice President and Chief Financial Officer and Vice President-Corporate Development and Strategy | |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Marathon Oil Corporation:Corporation
In our opinion,Opinions on the consolidated financial statements listed inFinancial Statements and Internal Control over Financial Reporting
We have audited the accompanying index present fairly, in all material respects, the financial positionconsolidated balance sheet of Marathon Oil Corporation and its subsidiaries (the “Company”) atas of December 31, 20162019 and 2015,2018, and the resultsrelated consolidated statements of their operationsincome, of comprehensive income, of stockholders’ equity and theirof cash flows for each of the three years in the period ended December 31, 2016,2019, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016,2019, based on criteria established in Internal Control - Integrated Framework - 2013 (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management'sManagement’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on thesethe Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our integrated audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the consolidated financial statement presentation.statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Condensate, Natural Gas Liquids (NGLs) and Natural Gas Reserves on Proved Oil and Gas Properties, Net
As described in Notes 1 and 10 to the consolidated financial statements, the Company’s consolidated property, plant and equipment, net balance was $17,000 million as of December 31, 2019, and depreciation, depletion, and amortization (DD&A) expense for the year ended December 31, 2019 was $2,397 million, both of which substantially relate to proved oil and gas properties. The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under this method, capitalized costs to acquire oil and natural gas properties are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. As discussed by management, reserve estimates may change as a result of a number of factors, including but not limited to, changes in contractual, operational, economic and political conditions; additional development activity and future development costs; production history; and continual reassessment of the viability of future production volumes under varying economic conditions. The estimates of oil and gas reserves have been developed by specialists, specifically petroleum engineers and geoscientists.
The principal considerations for our determination that performing procedures relating to the impact of proved oil and condensate, NGLs and natural gas reserves on proved oil and gas properties, net is a critical audit matter are there was significant judgment by management, including the use of specialists, when developing the estimates of proved oil and gas reserves, which in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures to evaluate the significant assumptions used in developing those estimates, including future development costs and future production volumes.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and condensate, NGLs and natural gas reserves and the calculation of DD&A expense. These procedures also included, among others, evaluating the significant assumptions used by management in developing these estimates, including future development costs and future production volumes, and testing the unit-of-production rate used to calculate DD&A expense. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of these estimates. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as the methods and assumptions used by the specialist. The procedures performed also included tests of the data used by the specialists and an evaluation of the specialists’ findings. Evaluating the significant assumptions relating to the estimates of proved oil and condensate, NGLs and natural gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the current and past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 24, 201720, 2020
We have served as the Company’s auditor since 1982.
MARATHON OIL CORPORATION
Consolidated Statements of Income
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except per share data) | 2016 | | 2015 | | 2014 |
| Revenues and other income: | | | | | |
| Sales and other operating revenues, including related party | $ | 3,753 |
| | $ | 4,951 |
| | $ | 8,736 |
|
| Marketing revenues | 278 |
| | 571 |
| | 2,110 |
|
| Income from equity method investments | 175 |
| | 145 |
| | 424 |
|
| Net gain (loss) on disposal of assets | 389 |
| | 120 |
| | (90 | ) |
| Other income | 55 |
| | 74 |
| | 78 |
|
| Total revenues and other income | 4,650 |
| | 5,861 |
| | 11,258 |
|
| Costs and expenses: | | | | | |
| Production | 1,313 |
| | 1,694 |
| | 2,246 |
|
| Marketing, including purchases from related parties | 282 |
| | 569 |
| | 2,105 |
|
| Other operating | 511 |
| | 438 |
| | 462 |
|
| Exploration | 330 |
| | 1,318 |
| | 793 |
|
| Depreciation, depletion and amortization | 2,395 |
| | 2,957 |
| | 2,861 |
|
| Impairments | 67 |
| | 752 |
| | 132 |
|
| Taxes other than income | 168 |
| | 234 |
| | 406 |
|
| General and administrative | 484 |
| | 590 |
| | 654 |
|
| Total costs and expenses | 5,550 |
| | 8,552 |
| | 9,659 |
|
| Income (loss) from operations | (900 | ) | | (2,691 | ) | | 1,599 |
|
| Net interest and other | (335 | ) | | (267 | ) | | (238 | ) |
| Income (loss) from continuing operations before income taxes | (1,235 | ) | | (2,958 | ) | | 1,361 |
|
| Provision (benefit) for income taxes | 905 |
| | (754 | ) | | 392 |
|
| Income (loss) from continuing operations | (2,140 | ) | | (2,204 | ) | | 969 |
|
| Discontinued operations | — |
| | — |
| | 2,077 |
|
| Net income (loss) | $ | (2,140 | ) | | $ | (2,204 | ) | | $ | 3,046 |
|
| Per Share Data | | | | | |
| Basic: | | | | | |
| Income (loss) from continuing operations | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 1.42 |
|
| Discontinued operations | $ | — |
| | $ | — |
| | $ | 3.06 |
|
| Net income (loss) | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 4.48 |
|
| Diluted: | | | | | |
| Income (loss) from continuing operations | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 1.42 |
|
| Discontinued operations | $ | — |
| | $ | — |
| | $ | 3.04 |
|
| Net income (loss) | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 4.46 |
|
| Dividends | $ | 0.20 |
| | $ | 0.68 |
| | $ | 0.80 |
|
| Weighted average shares: | | | | | |
| Basic | 819 |
| | 677 |
| | 680 |
|
| Diluted | 819 |
| | 677 |
| | 683 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Net income (loss) | $ | (2,140 | ) | | $ | (2,204 | ) | | $ | 3,046 |
|
| Other comprehensive income (loss) | | | | | |
| Postretirement and postemployment plans | | | | | |
| Change in actuarial loss and other | 16 |
| | 228 |
| | (52 | ) |
| Income tax benefit (provision) | (4 | ) | | (86 | ) | | 25 |
|
| Postretirement and postemployment plans, net of tax | 12 |
| | 142 |
| | (27 | ) |
| Derivative hedges | | | | | |
| Net unrecognized gain | 61 |
| | — |
| | 1 |
|
| Income tax provision | (22 | ) | | — |
| | — |
|
| Derivative hedges, net of tax | 39 |
| | — |
| | 1 |
|
| Other, net of tax | 1 |
| | — |
| | (1 | ) |
| Other comprehensive income (loss) | 52 |
| | 142 |
| | (27 | ) |
| Comprehensive income (loss) | $ | (2,088 | ) | | $ | (2,062 | ) | | $ | 3,019 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except per share data) | 2019 | | 2018 | | 2017 |
| Revenues and other income: | | | | | |
| Revenues from contracts with customers | $ | 5,063 |
| | $ | 5,902 |
| | $ | 4,247 |
|
| Net loss on commodity derivatives | (72 | ) | | (14 | ) | | (36 | ) |
| Marketing revenues | — |
| | — |
| | 162 |
|
| Income from equity method investments | 87 |
| | 225 |
| | 256 |
|
| Net gain on disposal of assets | 50 |
| | 319 |
| | 58 |
|
| Other income | 62 |
| | 150 |
| | 78 |
|
| Total revenues and other income | 5,190 |
| | 6,582 |
| | 4,765 |
|
| Costs and expenses: | | | | | |
| Production | 712 |
| | 842 |
| | 716 |
|
| Marketing, including purchases from related parties | — |
| | — |
| | 168 |
|
| Shipping, handling and other operating | 605 |
| | 575 |
| | 431 |
|
| Exploration | 149 |
| | 289 |
| | 409 |
|
| Depreciation, depletion and amortization | 2,397 |
| | 2,441 |
| | 2,372 |
|
| Impairments | 24 |
| | 75 |
| | 229 |
|
| Taxes other than income | 311 |
| | 299 |
| | 183 |
|
| General and administrative | 356 |
| | 394 |
| | 371 |
|
| Total costs and expenses | 4,554 |
| | 4,915 |
| | 4,879 |
|
| Income (loss) from operations | 636 |
| | 1,667 |
| | (114 | ) |
| Net interest and other | (244 | ) | | (226 | ) | | (270 | ) |
| Other net periodic benefit costs | 3 |
| | (14 | ) | | (19 | ) |
| Loss on early extinguishment of debt | (3 | ) | | — |
| | (51 | ) |
| Income (loss) from continuing operations before income taxes | 392 |
| | 1,427 |
| | (454 | ) |
| Provision (benefit) for income taxes | (88 | ) | | 331 |
| | 376 |
|
| Income (loss) from continuing operations | 480 |
| | 1,096 |
| | (830 | ) |
| Loss from discontinued operations | — |
| | — |
| | (4,893 | ) |
| Net income (loss) | $ | 480 |
| | $ | 1,096 |
| | $ | (5,723 | ) |
| Per basic share: | | | | | |
| Income (loss) from continuing operations | $ | 0.59 |
| | $ | 1.30 |
| | $ | (0.97 | ) |
| Loss from discontinued operations | $ | — |
| | $ | — |
| | $ | (5.76 | ) |
| Net income (loss) | $ | 0.59 |
| | $ | 1.30 |
| | $ | (6.73 | ) |
| Per diluted share: | | | | | |
| Income (loss) from continuing operations | $ | 0.59 |
| | $ | 1.29 |
| | $ | (0.97 | ) |
| Loss from discontinued operations | $ | — |
| | $ | — |
| | $ | (5.76 | ) |
| Net income (loss) | $ | 0.59 |
| | $ | 1.29 |
| | $ | (6.73 | ) |
| Weighted average common shares outstanding: | | | | | |
| Basic | 810 |
| | 846 |
| | 850 |
|
| Diluted | 810 |
| | 847 |
| | 850 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Balance SheetsStatements of Comprehensive Income |
| | | | | | | |
| | December 31, |
| (In millions, except par values and share amounts) | 2016 | | 2015 |
| Assets | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 2,490 |
| | $ | 1,221 |
|
| Receivables, less reserve of $6 and $4 | 877 |
| | 912 |
|
| Inventories | 227 |
| | 313 |
|
| Other current assets | 71 |
| | 144 |
|
| Total current assets | 3,665 |
| | 2,590 |
|
| Equity method investments | 931 |
| | 1,003 |
|
| Property, plant and equipment, less accumulated depreciation, | |
| | |
|
| depletion and amortization of $22,214 and $23,260 | 25,718 |
| | 27,061 |
|
| Goodwill | 115 |
| | 115 |
|
| Other noncurrent assets | 665 |
| | 1,542 |
|
| Total assets | $ | 31,094 |
| | $ | 32,311 |
|
| Liabilities | | | |
| Current liabilities: | | | |
| Accounts payable | 1,078 |
| | 1,313 |
|
| Payroll and benefits payable | 129 |
| | 133 |
|
| Accrued taxes | 94 |
| | 132 |
|
| Other current liabilities | 253 |
| | 150 |
|
| Long-term debt due within one year | 686 |
| | 1 |
|
| Total current liabilities | 2,240 |
| | 1,729 |
|
| Long-term debt | 6,589 |
| | 7,276 |
|
| Deferred tax liabilities | 2,438 |
| | 2,441 |
|
| Defined benefit postretirement plan obligations | 345 |
| | 403 |
|
| Asset retirement obligations | 1,697 |
| | 1,601 |
|
| Deferred credits and other liabilities | 244 |
| | 308 |
|
| Total liabilities | 13,553 |
| | 13,758 |
|
| Commitments and contingencies |
| |
|
|
| Stockholders’ Equity | | | |
| Preferred stock - no shares issued or outstanding (no par value, | | | |
| 26 million shares authorized) | — |
| | — |
|
| Common stock: | | | |
| Issued – 937 million and 770 million shares, respectively (par value $1 per share, 1.1 billion shares authorized) | 937 |
| | 770 |
|
| Securities exchangeable into common stock – no shares issued | |
| | |
|
| or outstanding (no par value, 29 million shares authorized) | — |
| | — |
|
| Held in treasury, at cost – 90 million and 93 million shares | (3,431 | ) | | (3,554 | ) |
| Additional paid-in capital | 7,446 |
| | 6,498 |
|
| Retained earnings | 12,672 |
| | 14,974 |
|
| Accumulated other comprehensive loss | (83 | ) | | (135 | ) |
| Total stockholders' equity | 17,541 |
| | 18,553 |
|
| Total liabilities and stockholders' equity | $ | 31,094 |
| | $ | 32,311 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | | 2017 |
| Net income (loss) | $ | 480 |
| | $ | 1,096 |
| | $ | (5,723 | ) |
| Other comprehensive income (loss), net of tax | | | | | |
| Postretirement and postemployment plans: | | | | | |
| Change in actuarial gain and other | 54 |
| | 117 |
| | 21 |
|
| Income taxes on postretirement and postemployment plans | (38 | ) | | 4 |
| | 7 |
|
| Postretirement and postemployment plans, net of tax | 16 |
| | 121 |
| | 28 |
|
| Derivative hedges: | | | | | |
| Net unrecognized gain (loss) | 2 |
| | — |
| | (13 | ) |
| Reclassification of gains on terminated derivative hedges | — |
| | — |
| | (47 | ) |
| Income taxes on derivative hedges | — |
| | — |
| | 21 |
|
| Derivative hedges, net of tax | 2 |
| | — |
| | (39 | ) |
| Foreign currency translation: | | | | | |
| Net recognized loss reclassified to discontinued operations | — |
| | — |
| | 34 |
|
| Foreign currency translation adjustment related to sale of U.K. business | 30 |
| | — |
| | — |
|
| Income taxes on foreign currency translation | (7 | ) | | — |
| | (4 | ) |
| Foreign currency translation, net of tax | 23 |
| | — |
| | 30 |
|
| Other, net of tax | 1 |
| | 4 |
| | 2 |
|
| Other comprehensive income | 42 |
| | 125 |
| | 21 |
|
| Comprehensive income (loss) | $ | 522 |
| | $ | 1,221 |
| | $ | (5,702 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Increase (decrease) in cash and cash equivalents | | | | | |
| Operating activities: | |
| | | | |
| Net income (loss) | $ | (2,140 | ) | | $ | (2,204 | ) | | $ | 3,046 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| | | | |
| Discontinued operations | — |
| | — |
| | (2,077 | ) |
| Depreciation, depletion and amortization | 2,395 |
| | 2,957 |
| | 2,861 |
|
| Impairments | 67 |
| | 752 |
| | 132 |
|
| Exploratory dry well costs and unproved property impairments | 227 |
| | 1,214 |
| | 623 |
|
| Net (gain) loss on disposal of assets | (389 | ) | | (120 | ) | | 90 |
|
| Deferred income taxes | 811 |
| | (806 | ) | | 88 |
|
| Net (gain) loss on derivative instruments | 63 |
| | (126 | ) | | (4 | ) |
| Net cash received (paid) in settlement of derivative instruments | 61 |
| | 55 |
| | (5 | ) |
| Pension and other postretirement benefits, net | (3 | ) | | 1 |
| | (34 | ) |
| Stock based compensation | 48 |
| | 44 |
| | 52 |
|
| Equity method investments, net | 17 |
| | 33 |
| | 27 |
|
| Changes in: | | | | | |
| Current receivables | 50 |
| | 817 |
| | 119 |
|
| Inventories | 75 |
| | 36 |
| | (11 | ) |
| Current accounts payable and accrued liabilities | (133 | ) | | (965 | ) | | (33 | ) |
| All other operating, net | (76 | ) | | (123 | ) | | (138 | ) |
| Net cash provided by continuing operations | 1,073 |
| | 1,565 |
| | 4,736 |
|
| Net cash provided by discontinued operations | — |
| | — |
| | 751 |
|
| Net cash provided by operating activities | 1,073 |
| | 1,565 |
| | 5,487 |
|
| Investing activities: | | | | | |
| Additions to property, plant and equipment | (1,245 | ) | | (3,476 | ) | | (5,160 | ) |
| Acquisitions, net of cash acquired | (902 | ) | | — |
| | (21 | ) |
| Disposal of assets | 1,219 |
| | 225 |
| | 3,760 |
|
| Equity method investments - return of capital | 55 |
| | 77 |
| | 61 |
|
| Investing activities of discontinued operations | — |
| | — |
| | (376 | ) |
| Purchases of short term investments | — |
| | (925 | ) | | — |
|
| Maturities of short term investments | — |
| | 925 |
| | — |
|
| All other investing, net | (1 | ) | | (28 | ) | | (10 | ) |
| Net cash used in investing activities | (874 | ) | | (3,202 | ) | | (1,746 | ) |
| Financing activities: | | | | | |
| Borrowings | — |
| | 1,996 |
| | — |
|
| Debt repayments | (1 | ) | | (1,069 | ) | | (68 | ) |
| Purchases of common stock | — |
| | — |
| | (1,000 | ) |
| Issuance of common stock | 1,236 |
| | — |
| | — |
|
| Dividends paid | (162 | ) | | (460 | ) | | (543 | ) |
| All other financing, net | 1 |
| | (5 | ) | | 18 |
|
| Net cash provided by (used in) financing activities | 1,074 |
| | 462 |
| | (1,593 | ) |
| Effect of exchange rate changes on cash: | | | | | |
| Continuing operations | (4 | ) | | (2 | ) | | (2 | ) |
| Discontinued operations | — |
| | — |
| | (12 | ) |
| Net increase (decrease) in cash and cash equivalents | 1,269 |
| | (1,177 | ) | | 2,134 |
|
| Cash and cash equivalents at beginning of period | 1,221 |
| | 2,398 |
| | 264 |
|
| Cash and cash equivalents at end of period | $ | 2,490 |
| | $ | 1,221 |
| | $ | 2,398 |
|
|
| | | | | | | |
| | December 31, |
| (In millions, except par values and share amounts) | 2019 | | 2018 |
| Assets | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 858 |
| | $ | 1,462 |
|
| Receivables, less reserve of $11 and $11 | 1,122 |
| | 1,079 |
|
| Inventories | 72 |
| | 96 |
|
| Other current assets | 83 |
| | 257 |
|
| Current assets held for sale | — |
| | 27 |
|
| Total current assets | 2,135 |
| | 2,921 |
|
| Equity method investments | 663 |
| | 745 |
|
| Property, plant and equipment, less accumulated depreciation, depletion and amortization of $18,003 and $21,830 | 17,000 |
| | 16,804 |
|
| Goodwill | 95 |
| | 97 |
|
| Other noncurrent assets | 352 |
| | 723 |
|
| Noncurrent assets held for sale | — |
| | 31 |
|
| Total assets | $ | 20,245 |
| | $ | 21,321 |
|
| Liabilities | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 1,307 |
| | $ | 1,320 |
|
| Payroll and benefits payable | 112 |
| | 154 |
|
| Accrued taxes | 118 |
| | 181 |
|
| Other current liabilities | 208 |
| | 170 |
|
| Current liabilities held for sale | — |
| | 7 |
|
| Total current liabilities | 1,745 |
| | 1,832 |
|
| Long-term debt | 5,501 |
| | 5,499 |
|
| Deferred tax liabilities | 186 |
| | 199 |
|
| Defined benefit postretirement plan obligations | 183 |
| | 195 |
|
| Asset retirement obligations | 243 |
| | 1,081 |
|
| Deferred credits and other liabilities | 234 |
| | 279 |
|
| Noncurrent liabilities held for sale | — |
| | 108 |
|
| Total liabilities | 8,092 |
| | 9,193 |
|
| Commitments and contingencies |
| |
|
|
| Stockholders’ Equity | | | |
| Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized) | — |
| | — |
|
| Common stock: | | | |
| Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at December 31, 2019 and December 31, 2018) | 937 |
| | 937 |
|
| Held in treasury, at cost – 141 million shares and 118 million shares | (4,089 | ) | | (3,816 | ) |
| Additional paid-in capital | 7,207 |
| | 7,238 |
|
| Retained earnings | 7,993 |
| | 7,706 |
|
| Accumulated other comprehensive income | 105 |
| | 63 |
|
| Total stockholders’ equity | 12,153 |
| | 12,128 |
|
| Total liabilities and stockholders’ equity | $ | 20,245 |
| | $ | 21,321 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ EquityCash Flows
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Equity of Marathon Oil Stockholders | | |
| (In millions) | Preferred Stock | | Common Stock | | Securities Exchangeable into Common Stock | | Treasury Stock | | Additional Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Equity |
| December 31, 2013 Balance | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (2,903 | ) | | $ | 6,592 |
| | $ | 15,135 |
| | $ | (250 | ) | | $ | 19,344 |
|
| Shares issued - stock-based | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | 276 |
| | (57 | ) | | — |
| | — |
| | 219 |
|
| Shares repurchased | — |
| | — |
| | — |
| | (1,015 | ) | | — |
| | — |
| | — |
| | (1,015 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 3,046 |
| | — |
| | 3,046 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) |
| Dividends paid | — |
| | — |
| | — |
| | — |
| | — |
| | (543 | ) | | — |
| | (543 | ) |
| December 31, 2014 Balance | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (3,642 | ) | | $ | 6,531 |
| | $ | 17,638 |
| | $ | (277 | ) | | $ | 21,020 |
|
| Shares issued - stock-based | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | 96 |
| | (32 | ) | | — |
| | — |
| | 64 |
|
| Shares repurchased | — |
| | — |
| | — |
| | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) |
| Net income | — |
| | — |
| | — |
| | — |
| | — |
| | (2,204 | ) | | — |
| | (2,204 | ) |
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 142 |
| | 142 |
|
| Dividends paid | — |
| | — |
| | — |
| | — |
| | — |
| | (460 | ) | | — |
| | (460 | ) |
| December 31, 2015 Balance | $ | — |
| | $ | 770 |
| | $ | — |
| | $ | (3,554 | ) | | $ | 6,498 |
| | $ | 14,974 |
| | $ | (135 | ) | | $ | 18,553 |
|
| Shares issued - stock-based | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | 128 |
| | (86 | ) | | — |
| | — |
| | 42 |
|
| Shares repurchased | — |
| | — |
| | — |
| | (5 | ) | | — |
| | — |
| | — |
| | (5 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | (35 | ) | | — |
| | — |
| | (35 | ) |
| Net loss | — |
| | — |
| | — |
| | — |
| | — |
| | (2,140 | ) | | — |
| | (2,140 | ) |
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 52 |
| | 52 |
|
| Dividends paid | — |
| | — |
| | — |
| | — |
| | — |
| | (162 | ) | | — |
| | (162 | ) |
| Common stock issuance | — |
| | 167 |
| | — |
| | — |
| | 1,069 |
| | — |
| | — |
| | 1,236 |
|
| December 31, 2016 Balance | $ | — |
| | $ | 937 |
| | $ | — |
| | $ | (3,431 | ) | | $ | 7,446 |
| | $ | 12,672 |
| | $ | (83 | ) | | $ | 17,541 |
|
| | | | | | | | | | | | | | | | |
| (Shares in millions) | Preferred Stock | | Common Stock | | Securities Exchangeable into Common Stock | | Treasury Stock | | | | | | | | |
| December 31, 2013 Balance | — |
| | 770 |
| | — |
| | 73 |
| | | | | | | | |
| Shares issued - stock-based | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | (7 | ) | | | | | | | | |
| Shares repurchased | — |
| | — |
| | — |
| | 29 |
| | | | | | | | |
| December 31, 2014 Balance | — |
| | 770 |
| | — |
| | 95 |
| | | | | | | | |
| Shares issued - stock-based | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | (2 | ) | | | | | | | | |
| Shares repurchased | — |
| | — |
| | — |
| | — |
| | | | | | | | |
| December 31, 2015 Balance | — |
| | 770 |
| | — |
| | 93 |
| | | | | | | | |
| Shares issued - stock-based | | | | | | | | | | | | | | | |
| compensation | — |
| | — |
| | — |
| | (3 | ) | | | | | | | | |
| Shares repurchased | — |
| | — |
| | — |
| | — |
| | | | | | | | |
| Common stock issuance | — |
| | 167 |
| | — |
| | — |
| | | | | | | | |
| December 31, 2016 Balance | — |
| | 937 |
| | — |
| | 90 |
| |
| | | | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | | 2017 |
| Increase (decrease) in cash and cash equivalents | | | | | |
| Operating activities: | |
| | | | |
| Net income (loss) | $ | 480 |
| | $ | 1,096 |
| | $ | (5,723 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations: | |
| | | | |
| Discontinued operations | — |
| | — |
| | 4,893 |
|
| Depreciation, depletion and amortization | 2,397 |
| | 2,441 |
| | 2,372 |
|
| Impairments | 24 |
| | 75 |
| | 229 |
|
| Exploratory dry well costs and unproved property impairments | 114 |
| | 255 |
| | 323 |
|
| Net gain on disposal of assets | (50 | ) | | (319 | ) | | (58 | ) |
| Loss on early extinguishment of debt | 3 |
| | — |
| | 51 |
|
| Deferred income taxes | (34 | ) | | 52 |
| | (61 | ) |
| Net loss on derivative instruments | 72 |
| | 14 |
| | 36 |
|
| Net settlements of derivative instruments | 52 |
| | (281 | ) | | 45 |
|
| Pension and other post retirement benefits, net | (52 | ) | | (65 | ) | | (46 | ) |
| Stock-based compensation | 60 |
| | 53 |
| | 49 |
|
| Equity method investments, net | 18 |
| | 45 |
| | 20 |
|
| Changes in: | | | | | |
| Current receivables | 52 |
| | (133 | ) | | (334 | ) |
| Inventories | 3 |
| | (1 | ) | | 10 |
|
| Current accounts payable and accrued liabilities | (187 | ) | | 179 |
| | 297 |
|
| Other current assets and liabilities | (4 | ) | | (22 | ) | | 1 |
|
| All other operating, net | (199 | ) | | (155 | ) | | (116 | ) |
| Net cash provided by operating activities from continuing operations | 2,749 |
| | 3,234 |
| | 1,988 |
|
| Investing activities: | | | | | |
| Additions to property, plant and equipment | (2,550 | ) | | (2,753 | ) | | (1,974 | ) |
| Additions to other assets | 36 |
| | (26 | ) | | (25 | ) |
| Acquisitions, net of cash acquired | (293 | ) | | (25 | ) | | (1,891 | ) |
| Disposal of assets, net of cash transferred to the buyer | (76 | ) | | 1,264 |
| | 1,787 |
|
| Equity method investments - return of capital | 64 |
| | 57 |
| | 64 |
|
| All other investing, net | 1 |
| | 13 |
| | (5 | ) |
| Net cash used in investing activities from continuing operations | (2,818 | ) | | (1,470 | ) | | (2,044 | ) |
| Financing activities: | | | | | |
| Borrowings | 600 |
| | — |
| | 988 |
|
| Debt repayments | (600 | ) | | — |
| | (2,764 | ) |
| Debt extinguishment costs | (2 | ) | | — |
| | (46 | ) |
| Purchases of common stock | (362 | ) | | (713 | ) | | (11 | ) |
| Dividends paid | (162 | ) | | (169 | ) | | (170 | ) |
| All other financing, net | (9 | ) | | 23 |
| | — |
|
| Net cash used in financing activities | (535 | ) | | (859 | ) | | (2,003 | ) |
| Net increase in cash and cash equivalents of discontinued operations (Note 5) | — |
| | — |
| | 130 |
|
| Effect of exchange rate on cash and cash equivalents | — |
| | (2 | ) | | 4 |
|
| Net increase (decrease) in cash and cash equivalents | (604 | ) | | 903 |
| | (1,925 | ) |
| Cash and cash equivalents at beginning of period | 1,462 |
| | 563 |
| | 2,488 |
|
| Cash and cash equivalents included in current assets held for sale | — |
| | (4 | ) | | — |
|
| Cash and cash equivalents at end of period | $ | 858 |
| | $ | 1,462 |
| | $ | 563 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ Equity |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total Equity of Marathon Oil Stockholders | | |
| (In millions) | Preferred Stock | | Common Stock | | Treasury Stock | | Additional Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total Equity |
| December 31, 2016 Balance | $ | — |
| | $ | 937 |
| | $ | (3,431 | ) | | $ | 7,446 |
| | $ | 12,672 |
| | $ | (83 | ) | | $ | 17,541 |
|
Shares issued - stock-based compensation | — |
| | — |
| | 117 |
| | (50 | ) | | — |
| | — |
| | 67 |
|
| Shares repurchased | — |
| | — |
| | (11 | ) | | — |
| | — |
| | — |
| | (11 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | (17 | ) | | — |
| | — |
| | (17 | ) |
| Net loss | — |
| | — |
| | — |
| | — |
| | (5,723 | ) | | — |
| | (5,723 | ) |
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | 21 |
|
| Dividends paid ($0.20 per share) | — |
| | — |
| | — |
| | — |
| | (170 | ) | | — |
| | (170 | ) |
| December 31, 2017 Balance | $ | — |
| | $ | 937 |
| | $ | (3,325 | ) | | $ | 7,379 |
| | $ | 6,779 |
| | $ | (62 | ) | | $ | 11,708 |
|
Shares issued - stock-based compensation | — |
| | — |
| | 221 |
| | (109 | ) | | — |
| | — |
| | 112 |
|
| Shares repurchased | — |
| | — |
| | (712 | ) | | — |
| | — |
| | — |
| | (712 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | (32 | ) | | — |
| | — |
| | (32 | ) |
| Net income | — |
| | — |
| | — |
| | — |
| | 1,096 |
| | — |
| | 1,096 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | 125 |
| | 125 |
|
| Dividends paid ($0.20 per share) | — |
| | — |
| | — |
| | — |
| | (169 | ) | | — |
| | (169 | ) |
| December 31, 2018 Balance | $ | — |
| | $ | 937 |
| | $ | (3,816 | ) | | $ | 7,238 |
| | $ | 7,706 |
| | $ | 63 |
| | $ | 12,128 |
|
| Cumulative-effect adjustment (Note 2) | — |
| | — |
| | — |
| | — |
| | (31 | ) | | — |
| | (31 | ) |
Shares issued - stock-based compensation | — |
| | — |
| | 89 |
| | (26 | ) | | — |
| | — |
| | 63 |
|
| Shares repurchased | — |
| | — |
| | (362 | ) | | — |
| | — |
| | — |
| | (362 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) |
| Net income | — |
| | — |
| | — |
| | — |
| | 480 |
| | — |
| | 480 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | 42 |
| | 42 |
|
| Dividends paid ($0.20 per share) | — |
| | — |
| | — |
| | — |
| | (162 | ) | | — |
| | (162 | ) |
| December 31, 2019 Balance | $ | — |
| | $ | 937 |
| | $ | (4,089 | ) | | $ | 7,207 |
| | $ | 7,993 |
| | $ | 105 |
| | $ | 12,153 |
|
| | | | | | | | | | | | | | |
| (Shares in millions) | Preferred Stock | | Common Stock | | Treasury Stock | | | | | | | | |
| December 31, 2016 Balance | — |
| | 937 |
| | 90 |
| | | | | | | | |
Shares issued - stock-based compensation | — |
| | — |
| | (3 | ) | | | | | | | | |
| December 31, 2017 Balance | — |
| | 937 |
| | 87 |
| | | | | | | | |
Shares issued - stock-based compensation | — |
| | — |
| | (6 | ) | | | | | | | | |
| Shares repurchased | — |
| | — |
| | 37 |
| | | | | | | | |
| December 31, 2018 Balance | — |
| | 937 |
| | 118 |
| | | | | | | | |
Shares issued - stock-based compensation | — |
| | — |
| | (2 | ) | | | | | | | | |
| Shares repurchased | — |
| | — |
| | 25 |
| | | | | | | | |
| December 31, 2019 Balance | — |
| | 937 |
| | 141 |
| |
| | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
1. Summary of Principal Accounting Policies
We are a global energyan independent exploration and production company engaged in exploration, production and marketing of crude oil and condensate, NGLs and natural gas; as well as production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.; and oil sands mining, bitumen transportation and upgrading, and marketing of synthetic crude oil and vacuum gas oil in Canada.
Basis of presentation and principles applied in consolidation– These consolidated financial statements, including notes have been prepared in accordance with U.S. GAAP. These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.
Equity method investments– Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenuerevenues and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheet.
Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if themay have occurred. When a loss is deemed to be other than temporary. When the losshave occurred and is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Differences in the basis
Discontinued operations – As a result of the investments and the separate net asset valuesale of the investees, if any, are amortized into income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.
Reclassifications – We have reclassified certain prior year amounts between operating cash flow categories to present it on a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.
Discontinuedour Canadian business in 2017, we reflected this business as discontinued operations – in all historical periods presented. Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. As a resultSee Note 5 for discussion of the sale of our Angola assets and our Norway businessdivestiture in 2014 (see Note 6), these businesses are reflected as discontinued operations.further detail.Use of estimates– The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.
Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See unaudited Supplementary Data - Supplementary Information on Oil and Gas Producing Activities for further detail. Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, goodwill, valuation of derivative instruments and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.
Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred,associated with the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.
In the lower 48 states of the U.S., production volumes of crude oil and condensate, NGLs and natural gas are recognized when our performance obligation is satisfied, which typically occurs at the point where control transfers to the customer based on contract terms. Revenue is measured as the amount the company expects to receive in exchange for transferring commodities to the customer. Our hydrocarbon sales are typically based on prevailing market-based prices and may include quality or location differential adjustments. Payment is generally due within 30 days of delivery.
We typically incur shipping and handling costs prior to control transferring to the customer and account for these activities as fulfillment costs. These costs are reflected in shipping, handling and other operating expense line in our consolidated statement of income.
Our U.S. production of crude oil and condensate, NGLs and natural gas is generally sold immediately and transported to market. In our international locations,segment, liquid hydrocarbon production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic crude oil.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.
Short-term Investments - Our short-term investments are comprised of bank time deposits with original maturities of greater than three months but less than twelve months. They are classified as held-to-maturity investments, which are recorded at amortized cost.
Accounts receivable – The majority of our receivables are from purchasers of commodities or joint interest owners in properties we operate, or from purchasers of commodities, both of which are recorded at estimated or invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews, we may require a standby letter of credit or a financial guarantee. Uncollectible accountsWe routinely assess the collectability of receivable are
MARATHON OIL CORPORATION
Notesbalances to Consolidated Financial Statements
reserved against the allowance for uncollectible accounts when it is determined the receivable will not be collected anddetermine if the amount of anythe reserve may be reasonably estimated.in allowance for doubtful accounts is sufficient.
Inventories – Crude oil and natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or marketnet realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.indicate.
We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and datedate to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.
Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, interest ratecommodity locational risk and foreign currency exchangeinterest rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk are classified in operating activities. Our derivative instruments contain no significant contingent credit features.
Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio and foreign currency forwards to manage our exposure to changes in the value of foreign currency denominated liabilities.portfolio. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.
Cash flow hedges– We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings as well as to stabilize future lease payments on our future Houston office, and designate them as cash flow hedges. Derivative instruments designated as cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The effective portion of changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until the hedged item istransaction affects earnings and are then reclassified to net income when the underlying forecasted transaction is recognized ininto net income. IneffectiveBeginning in 2019, ineffective portions of a cash flow hedge’s change in fair valuehedge are recognized currently within net interest and other on the consolidated statements of income.no longer measured or disclosed separately. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable or the entire accumulated gain or loss recognizedcash flow hedge is no longer expected to be highly effective, subsequent changes in other comprehensive income is immediately reclassified intofair value of the derivatives instrument are recorded in net income.
Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price riskand locational risks on the forecasted sale of crude oil, NGLs, and natural gas and synthetic crude oil that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.
Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. If significant transfers occur, they would be disclosed in Note 15 to the consolidated financial statements.
Property, plant and equipment– We use the successful efforts method of accounting for oil and gas producing activities, which include bitumen mining and upgrading.activities.
Property acquisition costs – Costs to acquire mineral interests in oil and natural gas properties, or in oil sands mines, to drill and equip exploratory wells in progress and those that find proved reserves, and to drill and equip development wells and to construct or expand oil sands mines and upgrading facilities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties which include bitumen mining and upgrading facilities, are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities, as well as property, plant and equipment unrelated to oil and gas producing activities, are recorded at cost and depreciateddepreciated on a straight-line basis over the estimated useful lives of the assets as summarized below.
|
| | |
| Type of Asset | | Range of Useful Lives |
| Office furniture, equipment and computer hardware | | 34 to 15 years |
| Pipelines | | 105 to 40 years |
Plants, facilities mine equipment and infrastructure | | 3 to 40 years |
Impairments – We evaluateevaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, and our bitumen mining and upgrading facilities, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of income.
Dispositions – When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reflected in net gain (loss) on disposal of assets in our consolidated statements of income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized either when the assets are classified as held for sale, or are measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model depending on timing of the sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.
Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to a reporting unit. The fair value of a reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.
Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.
Environmental costs – We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable. Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets.
Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities, which include our bitumen mining facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, gathering systems, wells and related structures and restoration costs of land, and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water,facilities and equipment, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.
Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis based on estimated proved developed reserves for oil and gas production facilities, which include our bitumen mining facilities, while accretion escalatesof the liability occurs over the useful lives of the assets.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Deferred income taxes – Deferred tax assets and liabilities, measured at enacted tax rates, are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include whether we are in a cumulative loss position in recent years, our reversal of temporary differences, and our expectation to generate sufficient future taxable income. We use the liability method in determining our provision and liabilities for our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.
Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected volatility of our stock price and the stock price in relation to the strike price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.
The fair value of our restricted stock awards, restricted stock units and commonDirector restricted stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity whenRestricted Stock Awards, restricted stock awardsunits, and Director restricted stock units are granted. removed from Treasury Stock at grant, vesting, and distribution, respectively.
The fair value of our cash-settled stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement. The fair value of our stock-settled stock-based performance units is estimated using the Monte Carlo simulation method at grant date only. Since these awards are settled in stock, they are classified as equity.
Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.
2. Accounting Standards
Not Yet Adopted
In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated statements of cash flows and related disclosures.
In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated statements of cash flows and related disclosures.Financial instruments – credit losses
In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss"“expected loss” model as opposed to the current "incurred loss"“incurred loss” model. This standard is effective for us in the first quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We will adopt this standard during the first quarter of 2017, we do not believe it will have a material effect on our consolidated results of operations, financial position or cash flows.
In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect theThe adoption of this standard to havedid not result in a significantmaterial impact on our consolidated results of operations, financial position orand cash flows.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2014 and August 2015, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and shall be applied retrospectively to each prior reporting period presented ("full retrospective method") or with the cumulative effect of initially applying the update recognized at the date of initial application ("modified retrospective method"). While early adoption is permitted, we plan to adopt this new standard in the first quarter of 2018 using the modified retrospective method. We continue to assess our contracts that will be subject to this standard and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.
Recently Adopted
Lease accounting standard
In May 2015,February 2016, the FASB issued ana new leasing accounting standard, which modified the definition of a lease and established comprehensive accounting and financial reporting requirements for leasing arrangements. It requires lessees to recognize a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term of greater than 12 months on the balance sheet. On January 1, 2019, we adopted the new lease accounting standard using the modified retrospective method and applied to all leases that existed as of that date. It does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. As a result of the adoption, we recorded a cumulative-effect adjustment to stockholders’ equity of $31 million. We continue presenting all prior comparative periods without any restatements. See Note 13for further information.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Hedge accounting standard
In August 2017, the FASB issued a new accounting standards update that removesamends the requirementhedge accounting model to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient.enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured usingreduces the net asset value per share practical expedientoverall complexity of documenting, assessing and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient.measuring hedge effectiveness. This standard was effective for us in the first quarter of 2016 and was applied on a retrospective basis. This standard only modifies disclosure requirements; as such, there was no impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine whether an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard was effective for us in the first quarter of 2016. The adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard was effective for us in the fourth quarter of 2016.2019. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
| |
3. | Variable Interest Entities |
The owners of the AOSP, in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership ("Corridor Pipeline") to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $2 million current liability recorded at December 31, 2016 and 2015. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $474 million as of December 31, 2016. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.
4.3. Income (Loss)(loss) and Dividends per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income (loss) per share assumes exercise of stock options in all years,periods, provided the effect is not antidilutive. The per share calculations below exclude 13$6 million, 13$6 million and 411 million stock options in 2016, 20152019, 2018 and 20142017 that were antidilutive.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except per share data) | 2019 | | 2018 | | 2017 |
| Income (loss) from continuing operations | $ | 480 |
| | $ | 1,096 |
| | $ | (830 | ) |
| Loss from discontinued operations | — |
| | — |
| | (4,893 | ) |
| Net income (loss) | $ | 480 |
| | $ | 1,096 |
| | $ | (5,723 | ) |
| | | | | | |
| Weighted average common shares outstanding | 810 |
| | 846 |
| | 850 |
|
| Effect of dilutive securities | — |
| | 1 |
| | — |
|
| Weighted average common shares, diluted | 810 |
| | 847 |
| | 850 |
|
| Per basic share: | |
| | |
| | |
| Income (loss) from continuing operations | $ | 0.59 |
| | $ | 1.30 |
| | $ | (0.97 | ) |
| Loss from discontinued operations | $ | — |
| | $ | — |
| | $ | (5.76 | ) |
| Net income (loss) | $ | 0.59 |
| | $ | 1.30 |
| | $ | (6.73 | ) |
| Per diluted share: | | | | | |
| Income (loss) from continuing operations | $ | 0.59 |
| | $ | 1.29 |
| | $ | (0.97 | ) |
| Loss from discontinued operations | $ | — |
| | $ | — |
| | $ | (5.76 | ) |
| Net income (loss) | $ | 0.59 |
| | $ | 1.29 |
| | $ | (6.73 | ) |
| Dividends per share | $ | 0.20 |
| | $ | 0.20 |
| | $ | 0.20 |
|
4. Acquisitions
2019 – United States Segment
In the fourth quarter of 2019, we acquired approximately 40,000 net acres in a Texas Delaware oil play in West Texas from multiple sellers for $106 million. We accounted for these transactions as an asset acquisition, allocating the purchase price to unproved property within property, plant and equipment.
During the fourth quarter of 2019, we acquired a 100% working interest in approximately 18,000 net acres in the Eagle Ford from Rocky Creek Resources, LLC and RCR Midstream, LLC for $191 million in cash, subject to post-closing adjustments. We accounted for this transaction as a business combination, with the entire purchase price allocated between proved property, unproved property, and other assets, all within property, plant and equipment.
The fair values of the assets acquired were measured using the market approach, specifically the market comparable technique. The fair values were based on market-corroborated inputs, which were derived from observable market data; such inputs represent Level 2 inputs. As the acquisition date was December 31, 2019, there is not a pro forma effect of this transaction on our consolidated statement of income.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except per share data) | 2016 | | 2015 | | 2014 |
| Income (loss) from continuing operations | $ | (2,140 | ) | | $ | (2,204 | ) | | $ | 969 |
|
| Discontinued operations | — |
| | — |
| | 2,077 |
|
| Net income (loss) | $ | (2,140 | ) | | $ | (2,204 | ) | | $ | 3,046 |
|
| | | | | | |
| Weighted average common shares outstanding | 819 |
| | 677 |
| | 680 |
|
| Effect of dilutive securities | — |
| | — |
| | 3 |
|
| Weighted average common shares, diluted | 819 |
| | 677 |
| | 683 |
|
| Per basic share: | |
| | |
| | |
| Income (loss) from continuing operations | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 1.42 |
|
| Discontinued operations | $ | — |
| | $ | — |
| | $ | 3.06 |
|
| Net income (loss) | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 4.48 |
|
| Per diluted share: | | | | | |
| Income (loss) from continuing operations | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 1.42 |
|
| Discontinued operations | $ | — |
| | $ | — |
| | $ | 3.04 |
|
| Net income (loss) | $ | (2.61 | ) | | $ | (3.26 | ) | | $ | 4.46 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
5. Acquisitions
2016 - North America E&P2017 – United States Segment
On August 1, 2016,In the fourth quarter of 2017, we closed on our acquisition of PayRock Energy Holdings, LLC ("PayRock"), a portfolio company of EnCap Investments, including approximately 61,000 net surface acresadditional acreage in the oil windowNorthern Delaware basin of the Anadarko Basin STACK playNew Mexico from a private seller for $63 million in Oklahoma. The purchase price of $904 million, subject to closing adjustments was paid with cash on hand. Weand accounted for this transaction as an asset acquisition, allocating the purchase price to unproved property within property, plant and equipment.
In the second quarter of 2017, we closed on 2 acquisitions which included approximately 91,000 net acres in the Permian basin of New Mexico. The first acquisition with a majorityBC Operating, Inc. and other entities closed for approximately $1.1 billion in cash and the second acquisition with Black Mountain Oil & Gas and other private sellers closed for approximately $700 million in cash. These acquisitions were paid with cash on hand and accounted for as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment.
In the fourth quarter of 2014, we acquired additional acres in the SCOOP, at a cost of $58 million after final settlement adjustments.5. Dispositions
United States Segment
In the third quarter of 2014,2018, we acquired acreage in the Oklahoma Resource Basins, at a cost of $68 million after final settlement adjustments.
6. Dispositions
2016 - North America E&P Segment
In September 2016, we entered into an agreement to sell certain non-operated CO2 and waterflood assets in West Texas and New Mexico. The sale closed in late October for proceeds of $235 million, and we recognized a total pre-tax gain of $63 million. During the third quarter 2016, we sold certain non-operated assets primarily in West Texas and New Mexico to multiple purchasers for combined proceeds of approximately $67 million, and recognized a total pre-tax gain of $55 million.
In April 2016, we announcedon the sale of our Wyoming upstream and midstream assets. Duringnon-core, non-operated conventional properties, primarily in the second quarter, we receivedGulf of Mexico, for combined net proceeds of approximately $690$16 million, and recorded pre-tax gain of $266 million with the remaining asset sales closing in November 2016 for proceeds of $155 million, excludingbefore closing adjustments. A pre-tax gain of $38$32 million was recognized in the fourththird quarter 2016.of 2018.
In MarchInternational Segment
On July 1, 2019, we closed on the sale of our U.K. business (Marathon Oil U.K. LLC and April 2016, we entered into separate agreements to sell our 10%Marathon Oil West of Shetlands Limited), for proceeds of $95 million which reflects the assumption by RockRose Energy PLC (“RockRose”) of the U.K. business’ working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Coloradocapital and certain undeveloped acreage in West Texas for a combined totalcash equivalent balances of approximately $80$345 million in proceeds. We closed on certainDecember 31, 2018. During the third quarter of 2019, we recorded a $6 million liability and corresponding expense related to the asset salesestimated fair value of our exposure to surety bonds we continued to hold that guaranteed decommissioning liabilities of Marathon Oil U.K. LLC. In November 2019, RockRose posted replacement security and recognized a net pre-tax lossaccordingly, we reversed the aforementioned $6 million (see Note 25 for further detail). Income before taxes relating to our U.K. business for the year ended December 31, 2019 and 2018, was $33 million and $261 million, respectively. See Note 12 and Note 19 for additional details on sale of $48 million in 2016, withU.K. ARO and the remaining asset sales expecteddefined benefit pension plan as it relates to close inthis disposition. In the second quarter of 2017.
2015 - North America E&P Segment
In November 2015,2019, we entered into an agreement to sellclosed on the sale of our operated producing properties15% non-operated interest in the greater Ewing Bank area and non-operated producing interestsAtrush block in the Petronius and Neptune fields in the Gulf of Mexico. The transaction closed in December 2015, excluding the Neptune field,Kurdistan for proceeds of $111 million. A $228$63 million, pretax gainbefore closing adjustments. This property was recorded in the fourth quarter of 2015. Assetsclassified as held for sale in the December 31, 2015 consolidated balance sheet were related to the Neptune field that was pending at that date and included $31 million inDecember 31, 2018, with total assets of $58 million and $54 milliontotal liabilities of total liabilities. The Neptune field transaction closed during$17 million.
In the first quarter of 2016 for cash proceeds of $4 million.
In August 2015,2018, we closed on the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assetssubsidiary, Marathon Oil Libya Limited, which held our 16.33% non-operated interest in the Waha concessions in Libya, to a subsidiary of Total S.A. (Elf Aquitaine SAS) for proceeds of $100approximately $450 million, excluding closing adjustments, and recordedrecognized a pretax losspre-tax gain of $1$255 million. During
Canadian Business – Discontinued Operations
On May 31, 2017 we closed on the secondsale of our Canadian business, which included our 20% non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing. At closing we received two notes receivable for a combined $750 million for the remaining proceeds, which was received in the first quarter of 2015,2018. In the first quarter of 2017, we recorded a non-cash impairment charge of $44 million$6.6 billion (after-tax of $4.96 billion) primarily related to thesethe property, plant and equipment of our Canadian business. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets (see Note 15).
2015 - International E&P Segment
Inheld for sale were determined based upon the third quarter of 2015, we entered into agreementsanticipated sales proceeds less costs to sell, our East Africa exploration acreagewhich resulted in Ethiopia and Kenya. A pretaxa level 2 classification. As the effective date of the transaction was January 1, 2017, we recorded a loss of $109 million was recorded in the third quarter of 2015. This transaction closed during the first quarter of 2016.
2014 - North America E&P Segment
In June 2014, we closed theon sale of non-core acreage located in the far northwest portion of the Williston Basin for proceeds of $90 million. A pretax loss of $91$43 million was recorded induring the second quarter of 2014.
MARATHON OIL CORPORATION
Notes2017 due to Consolidated Financial Statements
2014 - International E&P Segment
In June 2014, we entered into an agreement to sellresults of operations from our NorwayCanadian business including the operated Alvheim FPSO, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea. The transaction closed in the fourth quarter of 2014 for proceeds of $2.1 billion, before netting $589 million cashthat were transferred to the buyer. A $976 million after-tax gain on the sale of Norway business was recorded in the fourth quarter of 2014. Included in this after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.buyer upon closing.
Our NorwayCanadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for theall periods prior to and including 2014. Selectpresented. The following table contains select amounts reported in discontinued operations were as follows:
|
| | | |
| (In millions) | Year Ended December 31, 2014 |
| Revenues applicable to discontinued operations | $ | 1,981 |
|
| Pretax income from discontinued operations | $ | 1,693 |
|
| Pretax gain on disposition of discontinued operations | $ | 1,406 |
|
In the first quarter of 2014, we closed the sales of our 10% non-operated working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. A $532 million after-tax gain on the sale of our Angola assets was recorded in 2014. Included in this after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.
Our Angola operations are reflected as discontinued operations in thehistorical consolidated statements of income and the consolidated statements of cash flows for the periods prior to and including 2014. Select amounts reported inas discontinued operations were as follows:operations:
|
| | | |
| (In millions) | December 31, 2014 |
| Revenues applicable to discontinued operations | $ | 58 |
|
| Pretax income from discontinued operations | $ | 51 |
|
| Pretax gain on disposition of discontinued operations | $ | 426 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | |
| | | Year Ended December 31, |
| (In millions) | | 2017 |
| Total revenue and other income | | $ | 431 |
|
| Net loss on disposal of assets | | (43 | ) |
| Total revenues and other income | | 388 |
|
| Costs and expenses: | | |
| Production | | 254 |
|
| Depreciation, depletion and amortization | | 40 |
|
| Impairments | | 6,636 |
|
| Other | | 25 |
|
| Total costs and expenses | | 6,955 |
|
| Pretax loss from discontinued operations | | (6,567 | ) |
| Benefit for income taxes | | (1,674 | ) |
| Loss from discontinued operations | | $ | (4,893 | ) |
|
| | | | |
| | | Year Ended December 31, |
| (In millions) | | 2017 |
| Cash flow from discontinued operations: | | |
| Operating activities | | $ | 141 |
|
| Investing activities | | (13 | ) |
| Changes in cash included in current assets held for sale | | 2 |
|
| Net increase in cash and cash equivalents of discontinued operations | | $ | 130 |
|
6. Revenues
The majority of our revenues are derived from the sale of crude oil and condensate, NGLs and natural gas under spot and term agreements with our customers in the United States and various international locations.
The following tables present our revenues from contracts with customers disaggregated by product type and geographic areas.
United States
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2019 |
| (In millions) | Eagle Ford | | Bakken | | Oklahoma | | Northern Delaware | | Other U.S. | | Total |
| Crude oil and condensate | $ | 1,358 |
| | $ | 1,686 |
| | $ | 425 |
| | $ | 316 |
| | $ | 102 |
| | $ | 3,887 |
|
| Natural gas liquids | 114 |
| | 46 |
| | 116 |
| | 26 |
| | 5 |
| | 307 |
|
| Natural gas | 121 |
| | 39 |
| | 156 |
| | 16 |
| | 17 |
| | 349 |
|
| Other | 7 |
| | — |
| | — |
| | — |
| | 52 |
| | 59 |
|
| Revenues from contracts with customers | $ | 1,600 |
| | $ | 1,771 |
| | $ | 697 |
| | $ | 358 |
| | $ | 176 |
| | $ | 4,602 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2018 |
| (In millions) | Eagle Ford | | Bakken | | Oklahoma | | Northern Delaware | | Other U.S. | | Total |
| Crude oil and condensate | $ | 1,554 |
| | $ | 1,568 |
| | $ | 426 |
| | $ | 235 |
| | $ | 164 |
| | $ | 3,947 |
|
| Natural gas liquids | 205 |
| | 62 |
| | 181 |
| | 38 |
| | 9 |
| | 495 |
|
| Natural gas | 145 |
| | 38 |
| | 184 |
| | 20 |
| | 26 |
| | 413 |
|
| Other | 8 |
| | — |
| | — |
| | — |
| | 23 |
| | 31 |
|
| Revenues from contracts with customers | $ | 1,912 |
| | $ | 1,668 |
| | $ | 791 |
| | $ | 293 |
| | $ | 222 |
| | $ | 4,886 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
International
|
| | | | | | | | | | | | | | | |
| | Year Ended December 31, 2019 |
| (In millions) | E.G. | | U.K. | | Other International | | Total |
| Crude oil and condensate | $ | 271 |
| | $ | 107 |
| | $ | 20 |
| | $ | 398 |
|
| Natural gas liquids | 4 |
| | 1 |
| | — |
| | 5 |
|
| Natural gas | 32 |
| | 12 |
| | — |
| | 44 |
|
| Other | — |
| | 14 |
| | — |
| | 14 |
|
| Revenues from contracts with customers | $ | 307 |
| | $ | 134 |
| | $ | 20 |
| | $ | 461 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2018 |
| (In millions) | E.G. | | U.K. | | Libya | | Other International | | Total |
| Crude oil and condensate | $ | 342 |
| | $ | 282 |
| | $ | 187 |
| | $ | 77 |
| | $ | 888 |
|
| Natural gas liquids | 4 |
| | 5 |
| | — |
| | — |
| | 9 |
|
| Natural gas | 37 |
| | 40 |
| | 9 |
| | — |
| | 86 |
|
| Other | 1 |
| | 32 |
| | — |
| | — |
| | 33 |
|
| Revenues from contracts with customers | $ | 384 |
| | $ | 359 |
| | $ | 196 |
| | $ | 77 |
| | $ | 1,016 |
|
In 2019, sales to Marathon Petroleum Corporation, Flint Hills Resources, Valero Marketing and Supply, and Shell Trading and each of their respective affiliates, accounted for approximately 13%, 13%, 11%, and 10%, respectively, of our total revenues. In 2018, sales to Valero Marketing and Supply and Flint Hills Resources and their respective affiliates, each accounted for approximately 11% of our total revenues. In 2017, sales to Vitol and their respective affiliates accounted for approximately 10% of our total revenues.
The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.
In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheet.
Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.
We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangements. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships and such reimbursements will continue to not be recorded as revenues within the scope of the revenue accounting standard.
In addition, we commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. We concluded that those marketing activities are carried out as part of the collaborative arrangement. Therefore, we act as a principal only in regards to the sale of our share of production and recognize revenue for the volumes associated with our net production.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Crude oil and condensate
For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels.
Natural gas and NGLs
When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.
The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost, since we make those payments in exchange for distinct services. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.
We have “percentage-of-proceeds” arrangements with some midstream entities where they retain a percentage of the proceeds collected for selling our processed natural gas and NGLs as compensation for their processing and marketing services. We recognize revenue for the gross sales volumes and recognize the proceeds retained by midstream companies as shipping and handling cost.
Contract receivables and liabilities
The following table provides information about receivables and contract assets (liabilities) from contracts with customers.
|
| | | | | | |
| | December 31, |
| (In millions) | 2019 | 2018 |
| Receivables from contracts with customers, included in receivables, less reserves | $ | 837 |
| $ | 714 |
|
| Contract asset (liability) | $ | — |
| $ | (1 | ) |
The contract liability balance on January 1, 2019 relates to the advance consideration received from customers for crude oil sales and processing services in the U.K. Subsequent to the sale of our U.K. business, we no longer hold this contract liability.
Changes in the contract asset (liability) balance during the period are as follows.
|
| | | |
| (In millions) | Year Ended December 31, 2019 |
| Contract asset (liability) balance as of January 1, 2019 | $ | (1 | ) |
| Revenue recognized as performance obligations are satisfied | 74 |
|
| Amounts invoiced to customers | (52 | ) |
Contract asset (liability) transferred to buyer(a) | (21 | ) |
| Contract asset (liability) balance as of December 31, 2019 | $ | — |
|
| |
(a) | Refer to Note 5 for further information on the sale of our U.K. business. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
7. Segment Information
We have three2 reportable operating segments. EachBoth of these segments isare organized and managed based upon both geographic location and the nature of the products and services it offers:offered.
North America E&P ("N.A. E&P"United States (“U.S.”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;the United States
International E&P ("Int'l E&P"(“Int’l”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America andthe United States as well as produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income (loss) represents income (loss) which excludes certain items not allocated to our operating segments, net of income taxes, attributable to the operating segments.taxes. A portion of our corporate and operations support general and administrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, certain property impairments, change in tax expense associated withcertain exploration expenses relating to a tax rate change, changes in our valuation allowance,strategic decision to exit conventional exploration, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.
As discussed in Note 6, we closed5, the sale of our Angola assets and our NorwayCanadian business in 2014, and both are2017 is reflected as discontinued operations and is excluded from the International E&P segment.segment information in all periods presented. |
| | | | | | | | | | | | | | | |
| | Year Ended December 31, 2019 |
| (In millions) | U.S. | | Int’l | | Not Allocated to Segments | | Total |
| Revenues from contracts with customers | $ | 4,602 |
| | $ | 461 |
| | $ | — |
| | $ | 5,063 |
|
| Net gain (loss) on commodity derivatives | 52 |
| | — |
| | (124 | ) | (b) | (72 | ) |
| Income from equity method investments | — |
| | 87 |
| | — |
| | 87 |
|
| Net gain on disposal of assets | — |
| | — |
| | 50 |
| (c) | 50 |
|
| Other income | 13 |
| | 9 |
| | 40 |
| | 62 |
|
| Less costs and expenses: | | | | | | | |
| Production | 588 |
| | 126 |
| | (2 | ) | | 712 |
|
| Shipping, handling and other operating | 561 |
| | 26 |
| | 18 |
| | 605 |
|
| Exploration | 149 |
| | — |
| | — |
| | 149 |
|
| Depreciation, depletion and amortization | 2,250 |
| | 121 |
| | 26 |
| | 2,397 |
|
| Impairments | — |
| | — |
| | 24 |
| (d) | 24 |
|
| Taxes other than income | 311 |
| | — |
| | — |
| | 311 |
|
| General and administrative | 127 |
| | 25 |
| | 204 |
| | 356 |
|
| Net interest and other | — |
| | — |
| | 244 |
| | 244 |
|
| Other net periodic benefit costs | — |
| | (3 | ) | | — |
| (e) | (3 | ) |
| Loss on early extinguishment of debt | — |
| | — |
| | 3 |
| | 3 |
|
| Income tax provision (benefit) | 6 |
| | 29 |
| | (123 | ) | | (88 | ) |
| Segment income (loss) | $ | 675 |
| | $ | 233 |
| | $ | (428 | ) | | $ | 480 |
|
| Total assets | $ | 17,781 |
| | $ | 1,530 |
| | $ | 934 |
| | $ | 20,245 |
|
Capital expenditures(a) | $ | 2,550 |
| | $ | 16 |
| | $ | 25 |
| | $ | 2,591 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2016 | | | Not Allocated | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
| Sales and other operating revenues | $ | 2,375 |
| | $ | 665 |
| | $ | 823 |
| | $ | (110 | ) | (c) | $ | 3,753 |
|
| Marketing revenues | 135 |
| | 105 |
| | 38 |
| | — |
| | 278 |
|
| Total revenues | 2,510 |
| | 770 |
| | 861 |
| | (110 | ) | | 4,031 |
|
| Income from equity method investments | — |
| | 175 |
| | — |
| | — |
| | 175 |
|
| Net gain on disposal of assets and other income | 28 |
| | 32 |
| | 2 |
| | 382 |
| (d) | 444 |
|
| Less: | | | | | | | | | |
| Production expenses | 486 |
| | 226 |
| | 601 |
| | — |
| | 1,313 |
|
| Marketing costs | 142 |
| | 103 |
| | 37 |
| | — |
| | 282 |
|
| Exploration expenses | 127 |
| | 17 |
| | 7 |
| | 179 |
| (e) | 330 |
|
| Depreciation, depletion and amortization | 1,835 |
| | 276 |
| | 239 |
| | 45 |
| | 2,395 |
|
| Impairments | 20 |
| | — |
| | — |
| | 47 |
| (f) | 67 |
|
Other expenses (a) | 422 |
| | 78 |
| | 33 |
| | 462 |
| (g) | 995 |
|
| Taxes other than income | 149 |
| | — |
| | 17 |
| | 2 |
| | 168 |
|
| Net interest and other | — |
| | — |
| | — |
| | 335 |
| | 335 |
|
| Income tax provision (benefit) | (228 | ) | | 49 |
| | (16 | ) | | 1,100 |
| (h) | 905 |
|
| Segment income (loss) / Net income (loss) | $ | (415 | ) | | $ | 228 |
| | $ | (55 | ) | | $ | (1,898 | ) | | $ | (2,140 | ) |
Capital expenditures (b) | $ | 936 |
| | $ | 82 |
| | $ | 33 |
| | $ | 18 |
| | $ | 1,069 |
|
| |
(a) | Includes other operating expensesaccruals and general and administrative expenses.excludes acquisitions. |
| |
(b) | Includes accruals.Unrealized loss on commodity derivative instruments (see Note 15). |
| |
(c) | Unrealized loss on commodity derivative instruments.Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico) and the sale of our U.K. business (see Note 5). |
| |
(d) | Primarily related to net gain on disposala result of assets(see anticipated sales of non-core proved properties in our International and United States segments (see Note 6)11). |
(e) Primarily related to impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases (See Note 13).
| |
(f)
| Proved property impairments (see Note 13). |
| |
(h)
| Increased valuation allowance on certain of our deferred tax assets $1,346 million (see Note 9). |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | | | | |
| | Year Ended December 31, 2018 |
| (In millions) | U.S. | | Int’l | | Not Allocated to Segments | | Total |
| Revenues from contracts with customers | $ | 4,886 |
| | $ | 1,016 |
| | $ | — |
| | $ | 5,902 |
|
| Net gain (loss) on commodity derivatives | (281 | ) | | — |
| | 267 |
| (b) | (14 | ) |
| Income from equity method investments | — |
| | 225 |
| | — |
| | 225 |
|
| Net gain on disposal of assets | — |
| | — |
| | 319 |
| (c) | 319 |
|
| Other income | 16 |
| | 12 |
| | 122 |
| (d) | 150 |
|
| Less costs and expenses: | | | | | | | |
| Production | 625 |
| | 215 |
| | 2 |
| | 842 |
|
| Shipping, handling and other operating | 499 |
| | 70 |
| | 6 |
| | 575 |
|
| Exploration | 246 |
| | 3 |
| | 40 |
| (e) | 289 |
|
| Depreciation, depletion and amortization | 2,217 |
| | 197 |
| | 27 |
| | 2,441 |
|
| Impairments | — |
| | — |
| | 75 |
| (f) | 75 |
|
| Taxes other than income | 301 |
| | — |
| | (2 | ) | | 299 |
|
| General and administrative | 146 |
| | 32 |
| | 216 |
| | 394 |
|
| Net interest and other | — |
| | — |
| | 226 |
| | 226 |
|
| Other net periodic benefit costs | — |
| | (9 | ) | | 23 |
| (g) | 14 |
|
| Income tax provision (benefit) | (21 | ) | | 272 |
| | 80 |
|
| 331 |
|
| Segment income | $ | 608 |
| | $ | 473 |
| | $ | 15 |
| | $ | 1,096 |
|
| Total assets | $ | 17,321 |
| | $ | 2,083 |
| | $ | 1,917 |
| | $ | 21,321 |
|
Capital expenditures(a) | $ | 2,620 |
| | $ | 39 |
| | $ | 26 |
| | $ | 2,685 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2015 | | | Not Allocated | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
| Sales and other operating revenues | $ | 3,358 |
| | $ | 728 |
| | $ | 815 |
| | $ | 50 |
| (c) | $ | 4,951 |
|
| Marketing revenues | 396 |
| | 103 |
| | 72 |
| | — |
| | 571 |
|
| Total revenues | 3,754 |
| | 831 |
| | 887 |
| | 50 |
| | 5,522 |
|
| Income (loss) from equity method investments | — |
| | 157 |
| | — |
| | (12 | ) | (d) | 145 |
|
| Net gain on disposal of assets and other income | 24 |
| | 27 |
| | 21 |
| | 122 |
| (e) | 194 |
|
| Less: | | | | | | | | | |
| Production expenses | 724 |
| | 255 |
| | 715 |
| | — |
| | 1,694 |
|
| Marketing costs | 401 |
| | 99 |
| | 69 |
| | — |
| | 569 |
|
| Exploration expenses | 362 |
| | 101 |
| | — |
| | 855 |
| (f) | 1,318 |
|
| Depreciation, depletion and amortization | 2,377 |
| | 295 |
| | 236 |
| | 49 |
| | 2,957 |
|
| Impairments | 2 |
| | — |
| | 5 |
| | 745 |
| (g) | 752 |
|
Other expenses (a) | 462 |
| | 92 |
| | 34 |
| | 440 |
| (h) | 1,028 |
|
| Taxes other than income | 215 |
| | — |
| | 18 |
| | 1 |
| | 234 |
|
| Net interest and other | — |
| | — |
| | — |
| | 267 |
| | 267 |
|
| Income tax provision (benefit) | (279 | ) | | 61 |
| | (56 | ) | | (480 | ) | (i) | (754 | ) |
| Segment income (loss) / Net Income (loss) | $ | (486 | ) | | $ | 112 |
| | $ | (113 | ) | | $ | (1,717 | ) | | $ | (2,204 | ) |
Capital expenditures (b) | $ | 2,553 |
| | $ | 368 |
| | $ | (10 | ) | | $ | 25 |
| | $ | 2,936 |
|
| |
(a) | Includes other operating expensesaccruals and general and administrative expenses.excludes acquisitions. |
| |
(b) | Includes accruals.Unrealized gain on commodity derivative instruments (seeNote 15). |
| |
(c) | UnrealizedPrimarily related to the gain on commodity derivative instruments.sale of our Libya subsidiary(see Note 5). |
| |
(d) | Partial impairmentPrimarily a reduction of investmentasset retirement obligations in equity method investee (See our International segment (see Note 15)12). |
| |
(e) | Primarily related to gain on sale of our propertiesdry well expense and interests in the Gulf of Mexico, partially offset by the loss on sale of East Africa exploration acreage(see Note 6). |
(f) Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 13).
| |
(g)
| Goodwill impairment (see Note 14) and provedunproved property impairments associated with the Rodo well in Alba Block Sub Area B, offshore E.G. (see Note 15)10). |
| |
(h)(f)
| Due to the anticipated sales of certain non-core proved properties in our International and United States segments (see Note 11). |
(i) Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note 9).
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2014 | | | Not Allocated | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
| Sales and other operating revenues | $ | 5,770 |
| | $ | 1,410 |
| | $ | 1,556 |
| | $ | — |
| | $ | 8,736 |
|
| Marketing revenues | 1,839 |
| | 219 |
| | 52 |
| | — |
| | 2,110 |
|
| Total revenues | 7,609 |
| | 1,629 |
| | 1,608 |
| | — |
| | 10,846 |
|
| Income from equity method investments | — |
| | 424 |
| | — |
| | — |
| | 424 |
|
| Net gain (loss) on disposal of assets and other income | 23 |
| | 57 |
| | 4 |
| | (96 | ) | (c) | (12 | ) |
| Less: | | | | | | | | | |
| Production expenses | 891 |
| | 386 |
| | 969 |
| | — |
| | 2,246 |
|
| Marketing costs | 1,836 |
| | 217 |
| | 52 |
| | — |
| | 2,105 |
|
| Exploration expenses | 608 |
| | 185 |
| | — |
| | — |
| | 793 |
|
| Depreciation, depletion and amortization | 2,342 |
| | 269 |
| | 206 |
| | 44 |
| | 2,861 |
|
| Impairments | 23 |
| | — |
| | — |
| | 109 |
| (d) | 132 |
|
Other expenses (a) | 473 |
| | 197 |
| | 54 |
| | 392 |
| (e) | 1,116 |
|
| Taxes other than income | 385 |
| | — |
| | 20 |
| | 1 |
| | 406 |
|
| Net interest and other | — |
| | — |
| | — |
| | 238 |
| | 238 |
|
| Income tax provision (benefit) | 381 |
| | 288 |
| | 76 |
| | (353 | ) | | 392 |
|
| Segment income (loss) / Income from continuing operations | $ | 693 |
| | $ | 568 |
| | $ | 235 |
| | $ | (527 | ) | | $ | 969 |
|
Capital expenditures (b) | $ | 4,698 |
| | $ | 534 |
| | $ | 212 |
| | $ | 51 |
| | $ | 5,495 |
|
(a) Includes other operating expenses and general and administrative expenses.
(b) Includes accruals.
(c) Primarily related to the sale of non-core acreage in our North America E&P segment (See Note 6).
(d) Proved property impairments (See Note 15).
(e) Includes pension settlement loss of $99 million (See Note 20).
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Revenues from external customers are attributed to geographic areas based upon selling location. The following summarizes revenues from external customers by geographic area.
|
| | | | | | | | | | | | | | | |
| Year Ended December 31, 2017 |
| (In millions) | U.S. | | Int’l | | Not Allocated to Segments | | Total |
| Revenues from contracts with customers | $ | 3,093 |
| | $ | 1,154 |
| | $ | — |
| | $ | 4,247 |
|
| Net gain (loss) on commodity derivatives | 45 |
| | — |
| | (81 | ) | (b) | (36 | ) |
| Marketing revenues | 29 |
| | 133 |
| | — |
| | 162 |
|
| Income from equity method investments | — |
| | 256 |
| | — |
| | 256 |
|
| Net gain on disposal of assets | 1 |
| | — |
| | 57 |
| (c) | 58 |
|
| Other income | 12 |
| | 6 |
| | 60 |
| | 78 |
|
| Less costs and expenses: | | | | | | | |
| Production | 476 |
| | 239 |
| | 1 |
| | 716 |
|
| Marketing costs | 36 |
| | 132 |
| | — |
| | 168 |
|
| Shipping, handling and other operating | 354 |
| | 77 |
| | — |
| | 431 |
|
| Exploration | 154 |
| | 5 |
| | 250 |
| (d) | 409 |
|
| Depreciation, depletion and amortization | 2,011 |
| | 328 |
| | 33 |
| | 2,372 |
|
| Impairments | 4 |
| | — |
| | 225 |
| (e) | 229 |
|
| Taxes other than income | 173 |
| | — |
| | 10 |
| | 183 |
|
| General and administrative | 119 |
| | 30 |
| | 222 |
| | 371 |
|
| Net interest and other | — |
| | — |
| | 270 |
| (f) | 270 |
|
| Other net periodic benefit costs | — |
| | (8 | ) | | 27 |
| (g) | 19 |
|
| Loss on early extinguishment of debt | — |
| | — |
| | 51 |
| (h) | 51 |
|
| Income tax provision | 1 |
| | 372 |
| | 3 |
| | 376 |
|
| Segment income (loss) | $ | (148 | ) | | $ | 374 |
| | $ | (1,056 | ) | | $ | (830 | ) |
| Total assets | $ | 16,863 |
| | $ | 4,201 |
| | $ | 948 |
| | $ | 22,012 |
|
Capital expenditures(a) | $ | 2,081 |
| | $ | 42 |
| | $ | 27 |
| | $ | 2,150 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| United States | $ | 2,400 |
| | $ | 3,804 |
| | $ | 7,609 |
|
| Canada | 861 |
| | 887 |
| | 1,608 |
|
Libya(a) | 54 |
| | — |
| | 244 |
|
| Other international | 716 |
| | 831 |
| | 1,385 |
|
| Total revenues | $ | 4,031 |
| | $ | 5,522 |
| | $ | 10,846 |
|
| |
(a) | See Includes accruals and excludes acquisitions. |
| |
(c) | Primarily related to the sale of Libya operations.certain conventional assets in Oklahoma and Colorado(see Note 5). |
| |
(d) | Primarily related to unproved property impairments associated with certain non-core properties within our International segment (see Note 11). |
| |
(e) | Primarily related to proved property impairments associated with certain non-core properties within our International segment (see Note 11). |
| |
(f) | Includes a gain of $46 million resulting from the termination of our forward starting interest rate swaps (seeNote 15). |
| |
(g) | Includes pension settlement loss of $32 million (see Note 19). |
| |
(h) | Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes (see Note 17). |
In 2016, sales to Irving Oil and Valero Marketing and Supply and each of their respective affiliates accounted for approximately 17% and 10% of our total revenues. In 2015, sales to Irving Oil and Shell Oil and each of their respective affiliates accounted for approximately 13% and 11% of our total revenues. In 2014, sales to Shell Oil and its affiliates accounted for approximately 10% of our total revenues.
The following summarizes revenues by product line were.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Crude oil and condensate | $ | 2,605 |
| | $ | 3,963 |
| | $ | 8,170 |
|
| Natural gas liquids | 198 |
| | 203 |
| | 371 |
|
| Natural gas | 356 |
| | 464 |
| | 693 |
|
| Synthetic crude oil | 816 |
| | 781 |
| | 1,525 |
|
| Other | 56 |
| | 111 |
| | 87 |
|
| Total revenues | $ | 4,031 |
| | $ | 5,522 |
| | $ | 10,846 |
|
The following summarizes property, plant and equipment and equity method investments.
|
| | | | | | | |
| | December 31, |
| (In millions) | 2019 | | 2018 |
| United States | $ | 16,507 |
| | $ | 16,094 |
|
| Equatorial Guinea | 1,156 |
| | 1,333 |
|
Other international(a) | — |
| | 122 |
|
| Total long-lived assets | $ | 17,663 |
| | $ | 17,549 |
|
| |
(a) | The decrease in 2019 is due to the sale of our non-operated interest in the Atrush block in Kurdistan and the sale of our U.K. business (see Note 5). |
|
| | | | | | | |
| | December 31, |
| (In millions) | 2016 | | 2015 |
| United States | $ | 14,272 |
| | $ | 15,353 |
|
| Canada | 8,991 |
| | 9,197 |
|
| Equatorial Guinea | 1,794 |
| | 1,917 |
|
| Other international | 1,592 |
| | 1,597 |
|
| Total long-lived assets | $ | 26,649 |
| | $ | 28,064 |
|
8. Other Items
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Interest: | | | | | |
| Interest income | $ | 14 |
| | $ | 9 |
| | $ | 7 |
|
| Interest expense | (402 | ) | | (358 | ) | | (309 | ) |
| Income on interest rate swaps | 13 |
| | 11 |
| | 12 |
|
| Interest capitalized | 23 |
| | 26 |
| | 20 |
|
| Total interest | (352 | ) | | (312 | ) | | (270 | ) |
| Other: | | | | | |
| Net foreign currency gain (loss) | 2 |
| | 23 |
| | 21 |
|
| Other | 15 |
| | 22 |
| | 11 |
|
| Total other | 17 |
| | 45 |
| | 32 |
|
| Net interest and other | $ | (335 | ) | | $ | (267 | ) | | $ | (238 | ) |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Foreign currency – Aggregate foreign currency gains were included in the consolidated statements of income as follows: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Net interest and other | $ | 2 |
| | $ | 23 |
| | $ | 21 |
|
| Provision for income taxes | (32 | ) | | (11 | ) | | (12 | ) |
| Aggregate foreign currency gains | $ | (30 | ) | | $ | 12 |
| | $ | 9 |
|
9.8. Income Taxes
Income (loss) from continuing operations before income taxes were:
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | | 2019 | | 2018 | | 2017 |
| United States | | $ | 43 |
| | $ | 642 |
| | $ | (783 | ) |
| Foreign | | 349 |
| | 785 |
| | 329 |
|
| Total | | $ | 392 |
| | $ | 1,427 |
| | $ | (454 | ) |
Income tax provisions (benefits) for continuing operations were: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| (In millions) | Current | | Deferred | | Total | | Current | | Deferred | | Total | | Current | | Deferred | | Total |
| Federal | $ | (116 | ) | | $ | (3 | ) | | $ | (119 | ) | | $ | 6 |
| | $ | — |
| | $ | 6 |
| | $ | (32 | ) | | $ | 41 |
| | $ | 9 |
|
| State and local | 4 |
| | 3 |
| | 7 |
| | (1 | ) | | (23 | ) | | (24 | ) | | (14 | ) | | 2 |
| | (12 | ) |
| Foreign | 58 |
| | (34 | ) | | 24 |
| | 274 |
| | 75 |
| | 349 |
| | 483 |
| | (104 | ) | | 379 |
|
| Total | $ | (54 | ) | | $ | (34 | ) | | $ | (88 | ) | | $ | 279 |
| | $ | 52 |
| | $ | 331 |
| | $ | 437 |
| | $ | (61 | ) | | $ | 376 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| (In millions) | Current | | Deferred | | Total | | Current | | Deferred | | Total | | Current | | Deferred | | Total |
| Federal | $ | 2 |
| | $ | 836 |
| | $ | 838 |
| | $ | (43 | ) | | $ | (687 | ) | | $ | (730 | ) | | $ | 15 |
| | $ | 62 |
| | $ | 77 |
|
| State and local | 2 |
| | 8 |
| | 10 |
| | (8 | ) | | (18 | ) | | (26 | ) | | 8 |
| | (58 | ) | | (50 | ) |
| Foreign | 90 |
| | (33 | ) | | 57 |
| | 103 |
| | (101 | ) | | 2 |
| | 281 |
| | 84 |
| | 365 |
|
| Total | $ | 94 |
| | $ | 811 |
| | $ | 905 |
| | $ | 52 |
| | $ | (806 | ) | | $ | (754 | ) | | $ | 304 |
| | $ | 88 |
| | $ | 392 |
|
A reconciliation of the federal statutory income tax rate applied to income (loss) from continuing operations before income taxes to the provision (benefit) for income taxes follows: |
| | | | | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| Statutory rate applied to income (loss) from continuing operations before income taxes | (35 | %) | | (35 | %) | | 35 | % |
| Effects of foreign operations, including foreign tax credits | 5 |
| | (2 | ) | | (6 | ) |
| Change in permanent reinvestment assertion | — |
| | — |
| | (19 | ) |
| Adjustments to valuation allowances | 102 |
| | 3 |
| | 21 |
|
| Change in tax law | 1 |
| | 5 |
| | — |
|
| Goodwill impairment | — |
| | 4 |
| | — |
|
| Other | — |
| | — |
| | (2 | ) |
| Effective income tax expense (benefit) rate on continuing operations | 73 | % | | (25 | %) | | 29 | % |
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| (In millions) | | 2019 | | 2018 | | 2017 |
| Total pre-tax income (loss) from continuing operations | | $ | 392 |
| | $ | 1,427 |
| | $ | (454 | ) |
| Total income tax expense (benefit) | | $ | (88 | ) | | $ | 331 |
| | $ | 376 |
|
| Effective income tax rate (benefit) on continuing operations | | (22 | )% | | 23 | % | | 83 | % |
| | | | | | | |
Income taxes at the statutory tax rate(a)(b) | | $ | 83 |
| | $ | 300 |
| | $ | (159 | ) |
| Effects of foreign operations | | (29 | ) | | 214 |
| | 140 |
|
| Adjustments to valuation allowances | | (28 | ) | | (177 | ) | | 446 |
|
| State income taxes | | 11 |
| | (17 | ) | | (19 | ) |
| Tax law change | | — |
| | — |
| | (35 | ) |
| Other federal tax effects | | (125 | ) | | 11 |
| | 3 |
|
| Income tax expense (benefit) on continuing operations | | $ | (88 | ) | | $ | 331 |
| | $ | 376 |
|
| |
(a) | Includes income tax benefits primarily related to our U.S. federal income taxes where we have maintained a full valuation allowance since December 2016. |
| |
(b) | As a result of the Tax Reform Legislation (see below), the U.S. corporate income tax rate was reduced to 21% in 2018. The U.S. corporate income tax rate was 35% in 2017. |
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments appearsis reported in the "Not“Not Allocated to Segments"Segments” column of the tables in Note 7.7. Effects of foreign operations – The effects of foreign operations decreased our tax expense in 2019 due to tax benefits related to our U.K. operations and pre-tax income in jurisdictions with effective tax rates lower than the U.S. The effects of foreign operations increased our tax expense in 2016, increased our tax benefit in 2015,2018 and decreased our tax expense in 20142017 due to a shift in pretaxthe mix of pre-tax income mix between high and low tax jurisdictions.jurisdictions, including Libya where the tax rate was 93.5%. Excluding Libya, the effective tax rates on continuing operations would be an expense of 73%14% in 2016,2018 and 5% in 2017. As a benefitresult of 25%the sale of our Libya subsidiary in 2015, and anthe first quarter of 2018, we do not expect to incur further tax expense of 27% in 2014.related to Libya.
Change in permanent reinvestment assertiontax law – We have not elected anyOn December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Tax Reform Legislation”). Tax Reform Legislation, which is also commonly referred to as “U.S. tax reform”, significantly changing U.S. corporate income tax laws by, among other things, reducing the U.S. corporate income tax rate to 21% starting in 2018, and repeal of ourthe corporate alternative minimum tax (“AMT”), and a one-time deemed repatriation of accumulated foreign earnings to be considered permanently reinvested abroad in 2016.earnings. In the secondfourth quarter of 2015,2017, we removedremeasured our assertion for previously unremitted foreign earningsdeferred taxes at 21%, in accordance with U.S. GAAP. The impact of approximately $1 billion associatedthe remeasurement on our federal deferred tax assets and liabilities was equally offset by an adjustment to our valuation allowance with no material impact to current year earnings. In accordance with Staff Accounting Bulletin No. 118 (“SAB 118”) we finalized our Canadian operations. Foreign tax credits associated with these Canadian earnings are sufficient to offset any incremental U.S. tax liabilities, and therefore, no additional net deferred U.S. taxes were recorded. Inposition in the secondfourth quarter of 2014, we removed our assertion for previously unremitted foreign earnings associated2018 with our U.K. operationsno material changes made to be permanently reinvested outsidepositions considered provisional as of December 31, 2017.
Other federal tax effects – The decrease in other federal tax effects is primarily related to the U.S. The U.K. statutory tax rate was in excesssettlement of the 2010-2011 U.S. statutoryFederal Tax Audit (“IRS Audit”) in the first quarter of 2019. The release of the accrued tax rate and therefore foreignpositions resulted in a $126 million tax benefit, primarily related to AMT credits, associated with these earnings exceeded any incremental U.S. tax liabilities. see Note 25 for further detail.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Adjustments to valuation allowances - As a result of the sustained decline in commodity prices we expect to be in a cumulative loss position in early 2017 which constitutes significant negative evidence when assessing the need for a valuation allowance and limits our ability to consider other subjective positive evidence, such as forecasted projections for taxable income in future years. As such, in the fourth quarter of 2016, we increased the valuation allowance against foreign tax credits and other federal deferred tax assets. Additionally, we decreased the valuation allowance on foreign deferred tax assets associated with the disposition of certain foreign operations.
In 2015, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2015. Additionally, in 2015 we increased the valuation allowance on deferred tax assets associated with our foreign operations as a result of pretax losses in certain jurisdictions.
In 2014, we increased the valuation allowance against foreign tax credits as a result of removing the permanent reinvestment assertion on our U.K. operations since the U.K. statutory tax rate is in excess of the U.S. statutory tax rate per discussion above.
Change in tax law – On September 15, 2016, the U.K. government enacted legislation reducing the rate of the Petroleum Revenue Tax from 35% to 0% and reducing the Supplemental Charge Tax from 20% to 10%. As a result of this legislation, we reduced our deferred tax asset by $6 million and recorded a non-cash deferred tax expense in the third quarter of 2016. On June 29, 2015, the Alberta government enacted legislation to increase the provincial corporate tax rate from 10% to 12%. As a result of this legislation, we recorded a non-cash deferred tax expense of $135 million in the second quarter of 2015.
Deferred tax assets and liabilities resulted from the following: | | | | Year Ended December 31, | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | 2019 | | 2018 |
| Deferred tax assets: | | | | | | |
| Employee benefits | $ | 228 |
| | $ | 260 |
| $ | 90 |
| | $ | 75 |
|
| Operating loss carryforwards | 1,065 |
| | 563 |
| 1,685 |
| | 1,304 |
|
| Capital loss carryforwards | 4 |
| | 17 |
| 1 |
| | 2 |
|
| Foreign tax credits | 4,430 |
| | 4,335 |
| 611 |
| | 611 |
|
| Other credit carryforwards | 35 |
| | 35 |
| |
| Investments in subsidiaries and affiliates | 91 |
| | 17 |
| |
| Other | 88 |
| | 73 |
| 27 |
| | 4 |
|
| Valuation allowances: | | | | |
| Federal | (4,166 | ) | | (2,820 | ) | |
| State, net of federal benefit | (53 | ) | | (56 | ) | |
| Foreign | (84 | ) | | (162 | ) | |
| Subtotal | | 2,414 |
| | 1,996 |
|
| Valuation allowance | | (699 | ) | | (721 | ) |
| Total deferred tax assets | 1,638 |
| | 2,262 |
| 1,715 |
| | 1,275 |
|
| Deferred tax liabilities: | | | | | | |
| Property, plant and equipment | 3,672 |
| | 3,376 |
| 1,861 |
| | 1,018 |
|
| Accrued revenue | | 40 |
| | 60 |
|
| Other | 68 |
| | 105 |
| — |
| | 3 |
|
| Total deferred tax liabilities | 3,740 |
| | 3,481 |
| 1,901 |
| | 1,081 |
|
| Net deferred tax liabilities | $ | 2,102 |
| | $ | 1,219 |
| $ | 186 |
| | $ | — |
|
| Net deferred tax assets | | $ | — |
| | $ | 194 |
|
TaxOperating loss carryforwards – At December 31, 20162019, our operating loss carryforwards, includes $1.8 billionrelating to tax years beginning prior to January 1, 2018, before valuation allowance, include $655 million from the U.S. that expire in 2035 and 2036.- 2037. Our operating loss carryforwards in the U.S. for tax years beginning after December 31, 2017, before our valuation allowance, include $829 million which can be carried forward indefinitely. Foreign operating loss carryforwards include $975$20 million from Canada that begin to expire in 2029 through 2036, $332 million from the Kurdistan Region of Iraq that expire in 2017 through 2021, $83 million from Libya that expires in 2026 and $8 million from E.G. that expire in 2017 through 2021.2020. State operating loss carryforwards of $1,359$181 million expire in 20172020 through 2036. 2038.
Foreign tax credit carryforwardscredits– At December 31, 2019, we reflect foreign tax credits of $3,906$611 million, which will expire in years 2022 through 2026.
Valuation allowances– We consider whether it is more likely than not that some portion or allAt December 31, 2019, we reflect a valuation allowance in our consolidated balance sheet of $699 million against our net deferred tax assets will not be realized. Inin various jurisdictions in which we operate. The decrease in valuation allowance primarily relates to current year activity.
Property, plant and equipment – At December 31, 2019, we reflected a deferred tax liability of $1.9 billion. The increase primarily relates to the event it is more likely than not that some portion or allsale of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. The estimated realizability ofU.K. business and corresponding reduction in the benefit of ourasset retirement obligations and current year activity in the U.S.
Net deferred tax asset is assessed considering a preponderance of evidence. This assessment requires analysis of all available positiveassets and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies. Negative evidence includes losses in recent years as well as the forecasts of future income (loss)liabilities were classified in the realizable period.consolidated balance sheets as follows:
|
| | | | | | | |
| | December 31, |
| (In millions) | 2019 | | 2018 |
| Assets: |
| |
|
| Other noncurrent assets | $ | — |
| | $ | 393 |
|
| Liabilities: |
| |
|
| Noncurrent deferred tax liabilities | 186 |
| | 199 |
|
| Net deferred tax liabilities | $ | 186 |
| | $ | — |
|
| Net deferred tax assets | $ | — |
| | $ | 194 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
We expect to be in a cumulative loss position in early 2017 which constitutes significant negative evidence as to the future realizability of the value of our deferred tax assets. As a result, we are limited in our ability to consider forecasts for taxable income in future years in connection with our assessment of the realizability of our foreign tax credits and other federal deferred tax assets. Additionally, we considered the reversals of existing deferred tax assets and liabilities related to temporary differences between the book and tax basis of our assets and liabilities and concluded that it is more likely than not that a portion of our deferred tax assets would not be realized. Therefore, we increased our valuation allowance on our federal deferred tax assets by $1,346 million in 2016 related to U.S. benefits on foreign taxes and other federal deferred tax assets. If objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as forecasted projections of taxable income in future years, we would adjust the amount of the federal deferred tax assets considered realizable and reduce the provision for income taxes in the period of adjustment.
Federal valuation allowances increased $45 million in 2015 related to U.S. benefits on foreign taxes accrued in 2015. Federal valuation allowances decreased $222 million in 2014 primarily due to the sale of our Norway and Angola businesses.
Foreign valuation allowances decreased $78 million in 2016 primarily due to the disposal of our Ethiopia, Kenya, and certain E.G. assets. Foreign valuation allowances increased $54 million in 2015 primarily due to deferred tax assets generated in the Kurdistan Region of Iraq, E.G. and Gabon. Foreign valuation allowances decreased $41 million in 2014 primarily due to the disposal of our Angolan assets.
Net deferred tax liabilities were classified in the consolidated balance sheets as follows: |
| | | | | | | |
| | December 31, |
| (In millions) | 2016 |
| 2015 |
| Assets: |
|
|
|
| Other current assets | $ | — |
|
| $ | — |
|
| Other noncurrent assets | 336 |
|
| 1,222 |
|
| Liabilities: |
|
|
|
| Other current liabilities | — |
|
| — |
|
| Noncurrent deferred tax liabilities | 2,438 |
|
| 2,441 |
|
| Net deferred tax liabilities | $ | 2,102 |
|
| $ | 1,219 |
|
We are continuouslyroutinely undergoing examination of our U.S. federal income tax returns byexaminations in the IRS. Such audits have been completed through the 2014 tax year, with the exception of 2010-11,jurisdictions in which are currently under IRS appeals. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.
operate. As of December 31, 20162019, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:
|
| |
United States(a) | 2008-2015 |
Canada | 2010-20152008-2018 |
| Equatorial Guinea | 2007-2015 |
Libya | 2012-2015 |
United Kingdom | 2008-20152007-2018 |
| |
(a) | Includes federal and state jurisdictions. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table summarizes the activity in unrecognized tax benefits:
|
| | | | | | | | | | | |
| (In millions) | 2019 | | 2018 | | 2017 |
| Beginning balance | $ | 263 |
| | $ | 126 |
| | $ | 66 |
|
| Additions for tax positions of prior years | 13 |
| | 152 |
| | 83 |
|
| Reductions for tax positions of prior years | (152 | ) | | (15 | ) | | (3 | ) |
| Settlements | (111 | ) | | — |
| | (20 | ) |
| Ending balance | $ | 13 |
| | $ | 263 |
| | $ | 126 |
|
|
| | | | | | | | | | | |
| (In millions) | 2016 | | 2015 | | 2014 |
| Beginning balance | $ | 65 |
| | $ | 80 |
| | $ | 146 |
|
| Additions for tax positions related to the current year | — |
| | — |
| | — |
|
| Additions for tax positions of prior years | 6 |
| | 1 |
| | 11 |
|
| Reductions for tax positions of prior years | (5 | ) | | — |
| | (68 | ) |
| Settlements | — |
| | (7 | ) | | (9 | ) |
| Statute of limitations | — |
| | (9 | ) | | — |
|
| Ending balance | $ | 66 |
| | $ | 65 |
| | $ | 80 |
|
If the unrecognized tax benefits as of December 31, 20162019 were recognized, $25$13 million would affect our effective income tax rate. As of December 31, 2016,2019, there are $20$5 million uncertain tax positions for which it is reasonably possible that the amount wouldcould significantly increase or decreasechange during the next twelve months. During the first quarter of 2019, we withdrew our appeal related to the Brae area decommissioning costs in the U.K., thus the uncertain tax positions previously established are now considered effectively settled with no tax expense or benefit impact. Also, in the first quarter of 2019, we settled the 2010-2011 IRS Audit, resulting in a tax benefit of $126 million. See Note 25 for further detail. Pursuant to the Tax Sharing Agreement we entered into with Marathon Petroleum Corporation (“MPC”) in connection with the 2011 spin-off transaction, MPC agreed to indemnify us for certain liabilities. In addition to the benefit from the settlement of the IRS Audit in the first quarter of 2019, we recorded a current receivable and other income of $42 million for indemnity payments due from MPC for tax expense and interest we had previously recognized. The indemnity relates to tax and interest allocable to MPC as a result of the IRS Audit. During the second quarter of 2019, we paid the IRS and were subsequently reimbursed by MPC for settlement of their indemnity obligation.
Interest and penalties are recorded as part of the tax provision and were $1$6 million, $1$2 million and $6$27 million related to unrecognized tax benefits in 2016, 20152019, 2018 and 2014.2017. As of December 31, 20162019 and 2015, $152018, $3 million and $14$27 million of interest and penalties were accrued related to income taxes.
Pretax income (loss) from continuing operations included amounts attributable to foreign sources of $204 million, $(654) million and $1,180 million in 2016, 2015 and 2014.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
10.9. Inventories
Crude oil and natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or marketnet realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
|
| | | | | | | |
| | December 31, |
| (In millions) | 2019 | | 2018 |
| Crude oil and natural gas | $ | 10 |
| | $ | 11 |
|
| Supplies and other items | 62 |
| | 85 |
|
| Inventories | $ | 72 |
| | $ | 96 |
|
|
| | | | | | | |
| | December 31, |
| (In millions) | 2016 | | 2015 |
| Crude oil, natural gas and bitumen | $ | 31 |
| | $ | 35 |
|
| Supplies and other items | 196 |
| | 278 |
|
| Inventories at cost | $ | 227 |
| | $ | 313 |
|
11. Equity Method Investments and Related Party Transactions
During 2016, 2015 and 2014 only our equity method investees were considered related parties and they included:
EGHoldings, in which we have a 60% noncontrolling interest. EGHoldings is engaged in LNG production activity.
•Alba Plant LLC, in which we have a 52% noncontrolling interest. Alba Plant LLC processes LPG.
AMPCO, in which we have a 45% interest. AMPCO is engaged in methanol production activity.
Our equity method investments are summarized in the following table:
|
| | | | | | | | | |
| | Ownership as of | | December 31, |
| (In millions) | December 31, 2016 | | 2016 | | 2015 |
| EGHoldings | 60% | | $ | 550 |
| | $ | 603 |
|
| Alba Plant LLC | 52% | | 215 |
| | 230 |
|
| AMPCO | 45% | | 165 |
| | 169 |
|
| Other investments | | | 1 |
| | 1 |
|
| Total | | | $ | 931 |
| | $ | 1,003 |
|
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $192 million in 2016, $178 million in 2015 and $451 million in 2014.
Summarized financial information for equity method investees is as follows:
|
| | | | | | | | | | | |
| (In millions) | 2016 | | 2015 | | 2014 |
| Income data – year: | | | | | |
| Revenues and other income | $ | 770 |
| | $ | 769 |
| | $ | 1,349 |
|
| Income from operations | 346 |
| | 313 |
| | 826 |
|
| Net income | 313 |
| | 280 |
| | 728 |
|
| Balance sheet data – December 31: | | | | | |
| Current assets | $ | 525 |
| | $ | 467 |
| | |
| Noncurrent assets | 1,173 |
| | 1,317 |
| | |
| Current liabilities | 218 |
| | 211 |
| | |
| Noncurrent liabilities | 47 |
| | 41 |
| | |
Revenues from related parties were $54 million, $51 million and $56 million in 2016, 2015 and 2014, with the majority related to EGHoldings in all years. Purchases from related parties were $103 million, $207 million and $207 million in 2016, 2015 and 2014 with the majority related to Alba Plant LLC in all years.
Current receivables from related parties at December 31, 2016 and 2015, were $23 million, and $29 million. Payables to related parties were $11 million and $5 million at December 31, 2016 and 2015, with the majority related to Alba Plant LLC.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
12. Property, Plant and Equipment
|
| | | | | | | |
| | December 31, |
| (In millions) | 2016 | | 2015 |
| North America E&P | $ | 14,158 |
| | $ | 15,226 |
|
| International E&P | 2,470 |
| | 2,533 |
|
| Oil Sands Mining | 8,991 |
| | 9,197 |
|
| Corporate | 99 |
| | 105 |
|
| Net property, plant and equipment | $ | 25,718 |
| | $ | 27,061 |
|
Our Libya operations have been interrupted in recent years due to civil unrest. On September 14, 2016, Force Majeure was lifted and production resumed in October 2016 at our Waha concession. During December 2016, liftings resumed from the Es-Sider crude oil terminal.
As of December 31, 2016, our net property, plant and equipment investment in Libya is approximately $768 million, and total proved reserves (unaudited) in Libya are 206 mmboe. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of $768 million by a significant amount.
Deferred exploratory well costs were as follows: |
| | | | | | | | | | | |
| | December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Amounts capitalized less than one year after completion of drilling | $ | 131 |
| | $ | 352 |
| | $ | 484 |
|
| Amounts capitalized greater than one year after completion of drilling | 118 |
| | 85 |
| | 126 |
|
| Total deferred exploratory well costs | $ | 249 |
| | $ | 437 |
| | $ | 610 |
|
| Number of projects with costs capitalized greater than one year after | | | | | |
| completion of drilling | 3 |
| | 2 |
| | 3 |
|
| | |
| | | | | | |
| (In millions) | 2016 | | 2015 | | 2014 |
| Beginning balance | $ | 437 |
| | $ | 610 |
| | $ | 793 |
|
| Additions | 299 |
| | 610 |
| | 647 |
|
| Charges to expense | (23 | ) | | (148 | ) | | (45 | ) |
| Transfers to development | (388 | ) | | (635 | ) | | (579 | ) |
Dispositions(a) | (76 | ) | | — |
| | (206 | ) |
| Ending balance | $ | 249 |
| | $ | 437 |
| | $ | 610 |
|
| |
(a)
| Includes sale of GOM assets in 2016, and the sale of Angola assets and Norway business in 2014. |
Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2016 are summarized by geographical area below:
|
| | | |
| (In millions) | |
| Gabon | $ | 64 |
|
| E.G. | 54 |
|
| Total | $ | 118 |
|
Well costs that have been suspended for longer than one year are associated with three projects. Management believes these projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development based on current plans.
Gabon - The Diaba-1B well reached total depth in the third quarter of 2013. Additional 3D seismic data was acquired in late 2014 in the western part of the block, and depth processing continued through the third quarter of 2016. We continue to utilize this data to facilitate evaluation of additional resource potential on the offshore Diaba License to support decisions regarding the exploration program.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
E.G. – The Corona well on Block D offshore E.G. was drilled in 2004,10. Property, Plant and we acquired an additional interest in the well in 2012. We plan to develop Block D through a unitization with the Alba field. Negotiations have been substantially completedEquipment
|
| | | | | | | |
| | December 31, |
| (In millions) | 2019 | | 2018 |
| United States | $ | 16,427 |
| | $ | 16,011 |
|
International(a) | 493 |
| | 710 |
|
| Not allocated to segments | 80 |
| | 83 |
|
| Net property, plant and equipment | $ | 17,000 |
| | $ | 16,804 |
|
| |
(a) | The International decrease is due to dispositions of our non-operated interest in the Atrush block in Kurdistan and our U.K. business during 2019 (see Note 5). |
At December 31, 2019, 2018 and we are awaiting approval from the host government.
Drilling was completed on the Rodo well in Alba Block Sub Area B, offshore E. G. in the first quarter of 2015, and we have since completed a seismic feasibility study. In early 2017 we received approval to perform a seismic reprocessing programhad total deferred exploratory well costs as follows:
|
| | | | | | | | | | | |
| | December 31, |
| (In millions) | 2019 | | 2018 | | 2017 |
| Amounts capitalized less than one year after completion of drilling | $ | 278 |
| | $ | 297 |
| | $ | 263 |
|
| Amounts capitalized greater than one year after completion of drilling | — |
| | — |
| | 32 |
|
| Total deferred exploratory well costs | $ | 278 |
| | $ | 297 |
| | $ | 295 |
|
Number of projects with costs capitalized greater than one year after completion of drilling | — |
| | — |
| | 1 |
|
| | | | | | |
| (In millions) | 2019 | | 2018 | | 2017 |
| Beginning balance | $ | 297 |
| | $ | 295 |
| | $ | 249 |
|
| Additions | 218 |
| | 262 |
| | 212 |
|
Charges to expense(a) | (5 | ) | | (35 | ) | | (64 | ) |
| Transfers to development | (230 | ) | | (197 | ) | | (102 | ) |
Dispositions(b) | (2 | ) | | (28 | ) | | — |
|
| Ending balance | $ | 278 |
| | $ | 297 |
| | $ | 295 |
|
| |
(a) | 2018 includes $32 million related to the Rodo well in Alba Block Sub Area B, offshore E.G. 2017 includes $64 million as a result of our agreement to sell Diaba License G4-223 in the Republic of Gabon (see Note 11 for further detail). |
| |
(b) | 2018 includes the sale of our Libya subsidiary. |
We had 0 exploratory well costs capitalized greater than one year as of December 31, 2019 and after completion, will evaluate drilling opportunities within Sub Area B.
December 31, 2018.
13.11. Impairments and Exploration Expenses
Impairments
The following table summarizes impairment charges of proved properties:properties from continuing operations. Additionally, it presents the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| (In millions) | Fair Value | | Impairment | | Fair Value | | Impairment | | Fair Value | | Impairment |
| Long-lived assets held for use | $ | 56 |
| | $ | 24 |
| | $ | 113 |
| | $ | 75 |
| | $ | 179 |
| | $ | 229 |
|
| |
| • | 2019 – Impairments of $24 million, to an aggregate fair value of $56 million, were primarily a result of proved property impairments primarily as a result of anticipated sales for certain non-core proved properties in our United States segment and the sale of our non-operated interest in the Atrush block (Kurdistan) in our International segment. The related fair value was measured using the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. |
| |
| • | 2018 – Impairments in our International and United States segments of $75 million, to a fair value of $113 million, were largely the result of anticipated sales for certain non-core proved properties. The related fair value measurement utilized the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (in millions) | 2016 | | 2015 | | 2014 |
| Total impairments | $ | 67 |
| | $ | 752 |
| | $ | 132 |
|
2016 - Impairments of $67 million consisted primarily of proved properties in Oklahoma | |
| • | 2017 – Impairments in our International segment were primarily a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core proved properties of $136 million, to an aggregate fair value of $103 million. These fair values were measured using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per boe which resulted in a Level 2 classification. |
Impairments in our United States segment were $89 million, to an aggregate fair value of $76 million, and related to Gulf of Mexico and certain conventional Oklahoma assets primarily as a result of lower forecasted long-term commodity prices. The fair values were measured using an income approach based upon internal estimates of future production levels, prices and discount rate. Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and revisions to estimated abandonment costs.
2015 - Impairments included $340 millionlocation differentials and forecasted operating expenses for the goodwill impairmentremaining estimated life of the North America E&P reporting unit,reservoir which resulted in a Level 3 classification.
See Note 5 for discussion of the divestitures in further detail and $335 million related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted commodity prices, and $44 million associated with our disposition of natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma. 2014 - Impairments of $132 million consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices.
See Note 7 for relevant detail regarding segment presentation, Note 14presentation.12. Asset Retirement Obligations
Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land at the end of oil and gas production operations. Changes in asset retirement obligations for further detail regarding the goodwill impairment and Note 15 for fair value measurements related to impairments of proved properties and long-lived assets.
Exploration expense
The following table summarizes the components of exploration expenses:periods ended December 31 were as follows:
|
| | | | | | | |
| (In millions) | 2019 | | 2018 |
| Beginning balance | $ | 1,145 |
| | $ | 1,483 |
|
| Incurred liabilities, including acquisitions | 34 |
| | 21 |
|
| Settled liabilities, including dispositions | (1,110 | ) | | (117 | ) |
| Accretion expense (included in depreciation, depletion and amortization) | 31 |
| | 70 |
|
| Revisions of estimates | 46 |
| | (204 | ) |
Held for sale(a) | 108 |
| | (108 | ) |
Ending balance(b) | $ | 254 |
| | $ | 1,145 |
|
| |
(a) | In the fourth quarter 2018, we entered into an agreement to sell our working interest in the Droshky field (Gulf of Mexico), including our $98 million asset retirement obligation; this transaction closed during the first quarter of 2019. |
| |
(b) | $944 million of the 2018 ending balance relates to our asset retirement obligations in the U.K., the sale of which closed in 2019. |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Exploration Expenses | | | | | |
| Unproved property impairments | $ | 195 |
| | $ | 964 |
| | $ | 306 |
|
| Dry well costs | 32 |
| | 250 |
| | 317 |
|
| Geological and geophysical | 5 |
| | 31 |
| | 85 |
|
| Other | 98 |
| | 73 |
| | 85 |
|
| Total exploration expenses | $ | 330 |
| | $ | 1,318 |
| | $ | 793 |
|
| |
| • | Settled liabilities primarily relates to the sale of our U.K. business, which closed during the third quarter of 2019, and the sale of the Droshky field (Gulf of Mexico). |
| |
| • | Held for sale reflects a transfer to settled liabilities during 2019. This transfer was primarily related to the Droshky field (Gulf of Mexico) which was considered held for sale at year-end 2018 and closed in the first quarter of 2019. |
| |
| • | Ending balance includes $11 million classified as short-term at December 31, 2019. |
Unproved property impairments2018
| |
| • | Settled liabilities include dispositions, primarily related to the sale of non-core, non-operated conventional properties in the Gulf of Mexico as well as retirements in the U.K. |
| |
| • | Revisions of estimates were primarily due to the acceleration of U.K. abandonment activities to capture favorable market conditions and lower estimated abandonment costs. |
| |
| • | Held for sale primarily related to the Droshky field, which was considered held for sale at year-end 2018. |
| |
| • | Ending balance primarily relates to the U.K. and includes $64 million classified as short-term at December 31, 2018. |
2016 - Primarily a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases and also includes certain other unproved properties in North America.73
2015 - Primarily due to changes in our conventional exploration strategy (Gulf of Mexico, Canadian in-situ assets and Harir block in the Kurdistan Region of Iraq), relinquishment of certain properties in the Gulf of Mexico, the operated Solomon exploration well in the Gulf of Mexico and our unproved property in Colorado as a result of the proved property impairment mentioned above.
2014 - Primarily consists of Eagle Ford and Bakken leases that either expired or we decided not to drill or extend.
See Note 7 for relevant detail regarding segment presentation of unproved property impairments.MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Dry13. Leases
Supplemental balance sheet information related to leases was as follows: |
| | | | |
| (In millions) | | December 31, 2019 |
| Operating Leases: | Balance Sheet Location: | |
| ROU asset | Other noncurrent assets | $ | 199 |
|
| Current portion of long-term lease liability | Other current liabilities | $ | 101 |
|
| Long-term lease liability | Deferred credits and other liabilities | $ | 107 |
|
In determining our ROU assets and long-term lease liabilities, the new lease standard requires certain accounting policy decisions, while also providing a number of optional practical expedients for transition accounting. Our accounting policies and the practical expedients utilized are summarized below:
Implemented an accounting policy to not recognize any right-of-use assets and lease liabilities related to short-term leases on the balance sheet.
Implemented an accounting policy to not separate the lease and nonlease components for all asset classes, except for vessels.
Elected the package of practical expedients which allows us to not reassess our prior conclusions regarding the lease identification and lease classification for contracts that commenced or expired prior to the effective date.
Elected the practical expedient pertaining to land easements which allows us to continue accounting for existing agreements under the previous accounting policies as nonlease transactions. Any modifications of existing contracts or new agreements will be assessed under the new lease accounting guidance and may become leases in the future.
We enter into various lease agreements to support our operations including drilling rigs, well costs
2016 - Lower dry well expensefracturing equipment, compressors, buildings, aircraft, vessels, vehicles and miscellaneous field equipment. We primarily act as a resultlessee in these transactions and all of our existing leases are classified as either short-term or long-term operating leases.
The majority of the strategic decisiondrilling rig agreements and all of fracturing equipment agreements are classified as short-term leases based on the noncancellable period for which we have the right to transition outuse the equipment and assessment of options present in each agreement. We also incur variable lease costs under these agreements primarily related to chemicals and sand used in fracturing operations or various additional on-demand equipment and labor. The lease costs associated with the drilling rigs and fracturing equipment are primarily capitalized as part of the well costs.
Our long-term leases are comprised of compressors, buildings, drilling rigs, aircraft, vessels, vehicles and miscellaneous field equipment. Our lease agreements may require both fixed and variable payments; none of the variable payments are rate or index-based, therefore only fixed payments were considered for recognizing lease liabilities and ROU assets related to long-term leases. Also, based on our conventional exploration programelection not to separate the lease and nonlease components, fixed payments related to equipment, crew and other nonlease components are included in the previous year.initial measurement of lease liabilities and ROU assets for all asset classes, except for vessels. For vessels, the contractual consideration was allocated between lease and nonlease components based on estimates provided by service providers.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
2015 - IncludesOur leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease liabilities and ROU assets only when we are the operated Solomon exploration well insignatory to a contract as an operator of joint properties. Such lease liabilities and ROU assets are determined based on gross contractual obligations. As we use the Gulfleased assets for joint operations, we have the contractual right to recover the other working interest owners’ share of Mexico,lease costs. As a result, our operated Sodalita West #1 exploratory well in E.G.lease costs are presented on a net basis, reduced for any costs recoverable from other working interest owners. The table below presents our net lease costs as of December 31, 2019 with the majority of operating lease costs expensed as incurred, while the majority of the short-term and suspended wellvariable lease costs relatedare capitalized into property, plant and equipment.
|
| | | |
| (In millions) | Year Ended December 31, 2019 |
| Lease costs: | |
Operating lease costs(a) | $ | 84 |
|
Short-term lease costs(b) | 321 |
|
Variable lease costs(c) | 107 |
|
| Total lease costs | $ | 512 |
|
| | |
| Other information: | |
| Cash paid for amounts included in the measurement of operating lease liabilities | $ | 100 |
|
ROU assets obtained in exchange for new operating lease liabilities(d) | $ | 293 |
|
| |
(a) | Represents our net share of the ROU asset amortization and the interest expense. |
| |
(b) | Represents our net share of lease costs arising from leases of less than one year but longer than one month that were not included in the lease liability. |
| |
(c) | Represents our net share of variable lease payments that were not included in the lease liability. |
| |
(d) | Represents the cumulative value of ROU assets recognized at lease inception during the year of 2019. This amount is then amortized as we utilize the ROU asset, the net effect of which is the ending ROU asset of $199 million (first table above). |
We use our Canadian in-situ assets at Birchwood.
2014 - Includes the operated Key Largo well, outside-operated Perseus wellperiodic incremental borrowing rate to discount future contractual payments to their present values. The weighted average lease term and the outside-operated second Shenandoah appraisal well,discount rate relevant to long-term leases were two years and 4% as of December 31, 2019. The remaining annual undiscounted cash flows associated with long-term leases and the reconciliation of these cash flows to the lease liabilities recognized on the consolidated balance sheet is summarized below. |
| | | |
| (In millions) | Operating Lease Obligations |
| 2020 | $ | 114 |
|
| 2021 | 63 |
|
| 2022 | 35 |
|
| 2023 | 5 |
|
| 2024 | 1 |
|
| Thereafter | — |
|
| Total undiscounted lease payments | $ | 218 |
|
| Less: amount representing interest | 10 |
|
| Total operating lease liabilities | $ | 208 |
|
| Less: current portion of long-term lease liability as of December 31, 2019 | 101 |
|
| Long-term lease liability as of December 31, 2019 | $ | 107 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
At December 31, 2018, future minimum commitments under the previous accounting standard, ASC 840, for operating lease obligations having noncancellable lease terms in excess of one year were as follows:
|
| | | |
| (In millions) | Operating Lease Obligations |
| 2019 | $ | 62 |
|
| 2020 | 54 |
|
| 2021 | 35 |
|
| 2022 | 12 |
|
| 2023 | 5 |
|
| Thereafter | 49 |
|
| Sublease rentals | — |
|
| Total minimum lease payments | $ | 217 |
|
* Future minimum commitments for capital lease obligations were NaN as of December 31, 2018.
Our wholly-owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in Equatorial Guinea, which is occupied by EGHoldings, a related party equity method investee –see Note 23. The lease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease agreement are summarized below. |
| | | |
| (In millions) | Operating Lease Future Cash Receipts |
| 2020 | $ | 6 |
|
| 2021 | 6 |
|
| 2022 | 6 |
|
| 2023 | 6 |
|
| 2024 | 6 |
|
| Thereafter | 60 |
|
| Total undiscounted cash flows | $ | 90 |
|
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The new Houston office location is expected to be completed in 2021. The lessor and other participants are providing financing for up to $380 million, to fund the estimated project costs. As of which are located inDecember 31, 2019, project costs incurred totaled approximately $58 million, primarily for land acquisition and initial design costs. The initial lease term is five years and will commence once construction is substantially complete and the Gulfnew Houston office is ready for occupancy. At the end of Mexico. In addition, 2014 also includes our exploration programs in the Kurdistan Regioninitial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of Iraq, Ethiopiathe participants; purchase the property subject to certain terms and Kenya.conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
14. Goodwill
As of December 31, 2019, our consolidated balance sheet included goodwill of $95 million. Goodwill is tested for impairment on an annual basis, in April of each year, or between annual tests when events or changes in circumstances indicate the fair value of a reporting unit with goodwill may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. We estimatedfirst assess the qualitative factors in order to determine whether the fair valuesvalue of our International reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test, macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determined that it is more likely than not that the fair value of the International E&P reporting unit is less than its carrying amount, a quantitative goodwill test is performed. The quantitative goodwill test is performed using a combination of market and income approaches. The market approach referencedreferences observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilizedutilizes discounted cash flows, which wereare based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbonhydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements, operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuation methodologiesThis quantitative goodwill test would represent Level 3 fair value measurements. We believe
During the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in such assumptions could result in materially different calculationssecond quarter of fair value and determinations of whether or not an impairment is indicated.
We2019, we performed our annual impairment teststest of goodwill using the qualitative assessment. Our qualitative assessment considered the significant excess fair value over carrying value in April of 2016, 2015our most recent step 1 test (second quarter 2017) and 2014 and no impairment was required. Asnoted a general improvement in the qualitative factors above. After assessing the totality of the date ofqualitative factors which could have a positive or negative impact on goodwill, our last impairment assessment did not indicate that it is more likely than not that the fair value ofis less than its carrying value. As a result, we concluded that no impairment to goodwill was required for our International E&P reporting unit exceeded its book value of $115 million by 26%. Subsequent to our goodwill impairment test in April 2015, triggering events (downward revisions to forecasted commodity price assumptions and sustained price declines in our common stock) required us to reassess our goodwill for impairment asunit.
As of December 31, 2015. We recorded an impairment of goodwill for2019 and 2018 our International segment is the North America E&Ponly reporting unit during the fourth quarter of 2015.
segment which includes goodwill. The table below displays the allocated beginning goodwill balances bybalance of our International segment along with changes in the carrying amount of goodwill for 20162019 and 2015:2018:
|
| | | | |
| (In millions) | | International |
| 2018 | | |
| Beginning balance, gross | | $ | 115 |
|
| Less: accumulated impairments | | — |
|
| Beginning balance, net | | 115 |
|
Dispositions(a) | | (18 | ) |
| Impairment | | — |
|
| Ending balance, net | | $ | 97 |
|
| 2019 | | |
| Beginning balance, gross | | $ | 97 |
|
| Less: accumulated impairments | | — |
|
| Beginning balance, net | | 97 |
|
| Dispositions | | (2 | ) |
| Impairment | | — |
|
| Ending balance, net | | $ | 95 |
|
| |
(a) | Primarily related to the sale of our Libya subsidiary (see Note 5). |
|
| | | | | | | | | | | | | | | |
| (In millions) | N.A. E&P | | Int'l E&P | | OSM | | Total |
| 2015 | | | | | | | |
| Beginning balance, gross | $ | 344 |
| | $ | 115 |
| | $ | 1,412 |
| | $ | 1,871 |
|
| Less: accumulated impairments | — |
| | — |
| | (1,412 | ) | | (1,412 | ) |
| Beginning balance, net | 344 |
| | 115 |
| | — |
| | 459 |
|
| Dispositions | (4 | ) | | — |
| | — |
| | (4 | ) |
| Impairment | (340 | ) | | — |
| | — |
| | (340 | ) |
| Ending balance, net | $ | — |
| | $ | 115 |
| | $ | — |
| | $ | 115 |
|
| 2016 | | | | | | | |
| Beginning balance, gross | $ | — |
| | $ | 115 |
| | $ | 1,412 |
| | $ | 1,527 |
|
| Less: accumulated impairments | — |
| | — |
| | (1,412 | ) | | (1,412 | ) |
| Beginning balance, net | — |
| | 115 |
| | — |
| | 115 |
|
| Dispositions | — |
| | — |
| | — |
| | — |
|
| Impairment | — |
| | — |
| | — |
| | — |
|
| Ending balance, net | $ | — |
| | $ | 115 |
| | $ | — |
| | $ | 115 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
15. Derivatives
See Note 16 for further information regarding the fair value measurement of derivative instruments. See Note 1for discussion of the types of derivatives we may use and the reasons for them. All of our commodity derivatives and interest rate derivatives are/were subject to enforceable master netting arrangements or similar agreements under which we report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets. |
| | | | | | | | | | | | | |
| | December 31, 2019 | | |
| (In millions) | Asset | | Liability | | Net Asset (Liability) | | Balance Sheet Location |
| Not Designated as Hedges | | | | | | | |
| Commodity | $ | 9 |
| | $ | 1 |
| | $ | 8 |
| | Other current assets |
| Commodity | 1 |
| | — |
| | 1 |
| | Other noncurrent assets |
| Commodity | — |
| | 5 |
| | (5 | ) | | Other current liabilities |
| Total Not Designated as Hedges | $ | 10 |
| | $ | 6 |
| | $ | 4 |
| | |
| | | | | | | | |
| Cash Flow Hedges | | | | | | |
| Interest Rate | $ | 2 |
| | $ | — |
| | $ | 2 |
| | Other noncurrent assets |
| Total Designated Hedges | $ | 2 |
| | $ | — |
| | $ | 2 |
| | |
| Total | $ | 12 |
| | $ | 6 |
| | $ | 6 |
| | |
15. |
| | | | | | | | | | | | | |
| | December 31, 2018 | | |
| (In millions) | Asset | | Liability | | Net Asset (Liability) | | Balance Sheet Location |
| Not Designated as Hedges | | | | | | | |
| Commodity | $ | 131 |
| | $ | — |
| | $ | 131 |
| | Other current assets |
| Commodity | — |
| | 4 |
| | (4 | ) | | Deferred credits and other liabilities |
| Total Not Designated as Hedges | $ | 131 |
| | $ | 4 |
| | $ | 127 |
| | |
Derivatives Not Designated as Hedges
Terminated Interest Rate Swaps
During the second quarter of 2017, we de-designated forward starting interest rate swaps used to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that was refinanced in the third quarter of 2017. In the third quarter of 2017, we terminated our forward starting interest rate swaps for proceeds of $54 million and recognized a gain of $46 million in net interest. See Note 17for further detail. The following table sets forth the net impact of the terminated forward starting interest rate swap derivatives de-designated as cash flow hedges on other comprehensive income (loss).
|
| | | | |
| | | Year Ended December 31, |
| (In millions) | | 2017 |
| Interest Rate Swaps | | |
| Beginning balance | | $ | 60 |
|
| Change in fair value recognized in other comprehensive income | | (13 | ) |
| Reclassification from other comprehensive income | | (47 | ) |
| Ending balance | | $ | — |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Commodity Derivatives
We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted United States sales through 2021. These commodity derivatives consist of three-way collars and basis swaps. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes; the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI price plus the difference between the floor and the sold put price. These crude oil derivatives were not designated as hedges.
The following table sets forth outstanding derivative contracts as of December 31, 2019 and the weighted average prices for those contracts:
|
| | | | | | | | | | | | | | | | | | | | |
| | 2020 | | | 2021 |
| Crude Oil | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | | Full Year |
| NYMEX WTI Three-Way Collars | | | | | | | | | | |
| Volume (Bbls/day) | 60,000 |
| | 60,000 |
| | 60,000 |
| | 60,000 |
| | | — |
|
| Weighted average price per Bbl: | | | | | | | | | | |
| Ceiling | $ | 66.04 |
| | $ | 66.04 |
| | $ | 63.74 |
| | $ | 63.74 |
| | | $ | — |
|
| Floor | $ | 55.00 |
| | $ | 55.00 |
| | $ | 55.00 |
| | $ | 55.00 |
| | | $ | — |
|
| Sold put | $ | 47.67 |
| | $ | 47.67 |
| | $ | 48.00 |
| | $ | 48.00 |
| | | $ | — |
|
Basis Swaps - Argus WTI Midland(a) | | | | | | | | | | |
| Volume (Bbls/day) | 15,000 |
| | 15,000 |
| | 15,000 |
| | 15,000 |
| | | — |
|
| Weighted average price per Bbl | $ | (0.94 | ) | | $ | (0.94 | ) | | $ | (0.94 | ) | | $ | (0.94 | ) | | | $ | — |
|
Basis Swaps - NYMEX WTI / ICE Brent(b) | | | | | | | | | | |
| Volume (Bbls/day) | 5,000 |
| | 5,000 |
| | 5,000 |
| | 5,000 |
| | | 808 |
|
| Weighted average price per Bbl | $ | (7.24 | ) | | $ | (7.24 | ) | | $ | (7.24 | ) | | $ | (7.24 | ) | | | $ | (7.24 | ) |
| Natural Gas | | | | | | | | | | |
| Three-Way Collars | | | | | | | | | | |
| Volume (MMBtu/day) | 100,000 |
| | — |
| | — |
| | — |
| | | — |
|
| Weighted average price per MMBtu: | | | | | | | | | | |
| Ceiling | $ | 3.32 |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| Floor | $ | 2.75 |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| Sold put | $ | 2.25 |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| |
(a) | The basis differential price is indexed against Argus WTI Midland. |
| |
(b) | The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI. |
Between January 1, 2020 and February 10, 2020, we entered into 20,000 bbls/day of three-way collars for 2020 with a ceiling price of $66.37, a floor price of $55.00 and a sold put price of $48.00.
The mark-to-market impact and settlement of these commodity derivative instruments appears in the table below and is reflected in net gain (loss) on commodity derivatives in the consolidated statements of income. |
| | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | 2017 |
| Mark-to-market gain (loss) | $ | (124 | ) | | $ | 267 |
| $ | (81 | ) |
| Net settlements of commodity derivative instruments | $ | 52 |
| | $ | (281 | ) | $ | 45 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Derivatives Designated as Cash Flow Hedges
During 2019, we entered into forward starting interest rate swaps with a total notional amount of $320 million to hedge variations in cash flows related to the 1-month London Interbank Offered Rate (“LIBOR”) component of future lease payments of our future Houston office. These swaps will settle monthly on the same day the lease payment is made with the first swap settlement occurring in January 2022. We expect the first lease payment to commence sometime in the period from December 2021 to May 2022. The last swap will mature on September 9, 2026. See Note 13for further details regarding the lease of the new Houston office. The following table presents information about our interest rate swap agreements, including the weighted average LIBOR-based, fixed rate.
|
| | | | | | | | | | | | | |
| | December 31, 2019 | | December 31, 2018 |
| (In millions, except fixed rates) | Aggregate Notional Amount | | Weighted Average, LIBOR | | Aggregate Notional Amount | | Weighted Average, LIBOR |
| Interest rate swaps | $ | 320 |
| | 1.514 | % | | $ | — |
| | — | % |
At December 31, 2019, accumulated other comprehensive income included deferred gains of $2 million related to forward starting interest rate swaps. No amounts related to these swaps are expected to impact the consolidated statements of income in the next 12 months.
16. Fair Value Measurements
Fair valuesValues – Recurring
The following tablestables’ present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 by hierarchy level.
|
| | | | | | | | | | | | | | | |
| | December 31, 2019 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative instruments, assets | | | | | | | |
Commodity(a) | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 7 |
|
| Interest rate | — |
| | 2 |
| | — |
| | 2 |
|
| Derivative instruments, assets | $ | — |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
|
| Derivative instruments, liabilities | | | | | | | |
Commodity(a) | $ | (3 | ) | | $ | — |
| | $ | — |
| | $ | (3 | ) |
| Derivative instruments, liabilities | $ | (3 | ) | | $ | — |
| | $ | — |
| | $ | (3 | ) |
| Total | $ | (3 | ) | | $ | 9 |
| | $ | — |
| | $ | 6 |
|
| | | | | | | | |
| | December 31, 2018 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative instruments, assets | | | | | | | |
Commodity(a) | $ | 21 |
| | $ | 106 |
| | $ | — |
| | $ | 127 |
|
| Derivative instruments, assets | $ | 21 |
| | $ | 106 |
| | $ | — |
| | $ | 127 |
|
| Derivative instruments, liabilities | | | | | | | |
| Derivative instruments, liabilities | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Total | $ | 21 |
| | $ | 106 |
| | $ | — |
| | $ | 127 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, 2016 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative instruments, assets | | | | | | | |
Commodity (a) | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Interest rate | — |
| | 68 |
| | — |
| | 68 |
|
| Derivative instruments, assets | $ | — |
| | $ | 68 |
| | $ | — |
| | $ | 68 |
|
| Derivative instruments, liabilities | | | | | | | |
| Commodity | $ | — |
| | $ | 60 |
| | $ | — |
| | $ | 60 |
|
| Derivative instruments, liabilities | $ | — |
| | $ | 60 |
| | $ | — |
| | $ | 60 |
|
| | | | | | | | |
| | December 31, 2015 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative instruments, assets | | | | | | | |
Commodity (a) | $ | — |
| | $ | 51 |
| | $ | — |
| | $ | 51 |
|
| Interest rate | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | 8 |
|
| Derivative instruments, assets | $ | — |
| | $ | 59 |
| | $ | — |
| | $ | 59 |
|
| Derivative instruments, liabilities | | | | | | | |
Commodity (a) | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Derivative instruments, liabilities | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
(a) Derivative instruments are recorded on a net basis in our balance sheet (see Note 16). | |
(a) | Derivative instruments are recorded on a net basis in our consolidated balance sheet (see Note 15). |
Commodity derivatives include three-way collars call options and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. InputsFor basis swaps, inputs to the models include only commodity prices and interest rates and are categorized as Level 1 because all assumptions and inputs are observable in active markets throughout the term of the instruments. For three-way collars, inputs to the models include commodity prices, interest rates, and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
Both our interest rate swaps and
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 1615 for additional discussion ofdetails on the types of derivative instruments we use. forward starting interest swaps. Fair valuesValues – Goodwill
See Note 14for detail information relating to goodwill. Fair Values – Nonrecurring
The following table shows the values of assets, by major category, measured at fair valueSee Note 5 and Note 11 for detail on a nonrecurring basis in periods subsequent to their initial recognition. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| (In millions) | Fair Value | | Impairment | | Fair Value | | Impairment | | Fair Value | | Impairment |
| Long-lived assets held for use | $ | 15 |
| | $ | 67 |
| | $ | 56 |
| | $ | 412 |
| | $ | 43 |
| | $ | 132 |
|
Long-lived assets held for use that were impaired are discussed below. Theour fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs. Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses for the remaining estimated life of the reservoir.
North America E&P
In the third quarter of 2016, impairments of $47 million were recorded consisting primarily of conventional non-core proved properties in Oklahomanonrecurring items, such as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $15 million. During the fourth quarter of 2016, we recorded an impairment of $17 million as a result of abandonment cost revisions related to the Ozona development in the Gulf of Mexico which ceased production in 2013.
In the third quarter of 2015, impairments of $333 million were recorded primarily related to certain producing assets in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices, to an aggregate fair value of $41 million.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
During the second quarter of 2015, we recorded an impairment charge of $44 million related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale. The fair values were measured using a probability weighted income approach based on both the anticipated sale price and held-for-use model.
In the third quarter of 2014, impairments of $53 million were recorded to Gulf of Mexico properties as a result of estimated abandonment cost and other revisions, to an aggregate fair value of $19 million. In addition, two fields were impaired a total of $47 million to an aggregate fair value of $24 million primarily due to lower forecasted commodity prices.
During 2014, we recorded impairments of $30 million as a result of abandonment cost revisions relating to the Ozona development in the Gulf of Mexico which ceased production in 2013.
Other impairments of long-lived assets held for use in 2016, 2015, and 2014 were a result of reduced drilling expectations, reductions of estimated reserves or lower forecasted commodity prices.
International E&P
In the third quarter of 2015, a partial impairment of $12 million was recorded to an investment in an equity method investee as a result of lower forecasted commodity prices, to a fair value of $604 million. The impairment was reflected in income from equity method investments in our consolidated statement of income.
Oil Sands Mining
In the fourth quarter of 2015, impairments of $26 million were recorded related to long-lived assets used in debottlenecking projects. Based on an evaluation by the operator, it was determined that the projects would not continue due to a need to reduce capital intensity and improve efficiency.impairments.
Fair valuesValues – Financial instrumentsInstruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, the current portion of our long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair valuevalues by individual balance sheet line item at December 31, 20162019 and 2015.2018.
| | | | December 31, | December 31, |
| | 2016 | | 2015 | 2019 | | 2018 |
| (In millions) | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount | Fair Value | | Carrying Amount | | Fair Value | | Carrying Amount |
| Financial assets | | | | | | | | | | | | | | |
| Other current assets | $ | 7 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| |
| Current assets | | $ | 4 |
| | $ | 4 |
| | $ | 3 |
| | $ | 3 |
|
| Other noncurrent assets | 119 |
| | 121 |
| | 104 |
| | 118 |
| 26 |
| | 38 |
| | 76 |
| | 81 |
|
| Total financial assets | $ | 126 |
| | $ | 128 |
| | $ | 104 |
| | $ | 118 |
| $ | 30 |
| | $ | 42 |
| | $ | 79 |
| | $ | 84 |
|
| Financial liabilities | | | | | | | | | | | | | | |
| Other current liabilities | $ | 68 |
| | $ | 75 |
| | $ | 34 |
| | $ | 33 |
| $ | 62 |
| | $ | 90 |
| | $ | 37 |
| | $ | 58 |
|
Long-term debt, including current portion(a) | 7,449 |
| | 7,292 |
| | 6,723 |
| | 7,291 |
| 6,174 |
| | 5,529 |
| | 5,469 |
| | 5,528 |
|
| Deferred credits and other liabilities | 114 |
| | 107 |
| | 97 |
| | 95 |
| 99 |
| | 86 |
| | 93 |
| | 88 |
|
| Total financial liabilities | $ | 7,631 |
| | $ | 7,474 |
| | $ | 6,854 |
| | $ | 7,419 |
| $ | 6,335 |
| | $ | 5,705 |
| | $ | 5,599 |
| | $ | 5,674 |
|
| |
(a) | Excludes capital leases, debt issuance costs and interest rate swap adjustments.costs. |
Fair values of our notes receivable and our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
MostAll of our long-term debt instruments are publicly-traded.publicly traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of suchour debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements17. Debt
Revolving Credit Facility
16. Derivatives
For further information regarding the fair value measurement of derivative instruments see Note 15. See Note 1 for discussion of the types of derivatives we use and the reasons for them. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.
|
| | | | | | | | | | | | | |
| | December 31, 2016 | | |
| (In millions) | Asset | | Liability | | Net Asset | | Balance Sheet Location |
| Fair Value Hedges | | | | |
|
| | |
| Interest rate | $ | 3 |
| | $ | — |
| | $ | 3 |
| | Other current assets |
| Interest rate | 1 |
| | — |
| | 1 |
| | Other noncurrent assets |
| Cash Flow Hedges | | | | | | | |
| Interest rate | $ | 64 |
| | $ | — |
| | $ | 64 |
| | Other noncurrent assets |
| Total Designated Hedges | $ | 68 |
| | $ | — |
| | $ | 68 |
| | |
| | | | | | | | |
| Not Designated as Hedges | | | | | | | |
| Commodity | $ | — |
| | $ | 60 |
| | $ | (60 | ) | | Other current liabilities |
| Total Not Designated as Hedges | $ | — |
| | $ | 60 |
| | $ | (60 | ) | | |
| Total | $ | 68 |
| | $ | 60 |
| | $ | 8 |
| | |
|
| | | | | | | | | | | | | |
| | December 31, 2015 | | |
| (In millions) | Asset | | Liability | | Net Asset | | Balance Sheet Location |
| Fair Value Hedges | | | | | | | |
| Interest rate | $ | 8 |
| | $ | — |
| | $ | 8 |
| | Other noncurrent assets |
| Total Designated Hedges | $ | 8 |
| | $ | — |
| | $ | 8 |
| | |
| | | | | | | | |
| Not Designated as Hedges | | | | | | | |
| Commodity | $ | 51 |
| | $ | 1 |
| | $ | 50 |
| | Other current assets |
| Total Not Designated as Hedges | 51 |
| | 1 |
| | 50 |
| | |
| Total | $ | 59 |
| | $ | 1 |
| | $ | 58 |
| | |
Derivatives Designated as Fair Value Hedges
The following table presents by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
|
| | | | | | | | | | | |
| | December 31, 2016 | | December 31, 2015 |
| | Aggregate Notional Amount | Weighted Average, LIBOR-Based, | | Aggregate Notional Amount | Weighted Average, LIBOR-Based, |
| Maturity Dates | (in millions) | Floating Rate | | (in millions) | Floating Rate |
| October 1, 2017 | $ | 600 |
| 5.10 | % | | $ | 600 |
| 4.73 | % |
| March 15, 2018 | $ | 300 |
| 5.04 | % | | $ | 300 |
| 4.66 | % |
The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income is summarized in the table below. There is no ineffectiveness related to the fair value hedges.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | | | | | | | | | |
| | | Gain (Loss) |
| | | Year Ended December 31, |
| (In millions) | Income Statement Location | 2016 | | 2015 | | 2014 |
| Derivative | | | | | | |
| Interest rate | Net interest and other | $ | (4 | ) | | $ | — |
| | $ | — |
|
| Foreign currency | Discontinued operations | — |
| | — |
| | (36 | ) |
| Hedged Item | | |
| | |
| | |
| Debt | Net interest and other | $ | 4 |
| | $ | — |
| | $ | — |
|
| Accrued taxes | Discontinued operations | — |
| | — |
| | 36 |
|
The table above includes foreign currency forwards in 2014 which hedged the current Norwegian tax liability of the Norway business, which was subsequently reported as discontinued operations. The open positions were transferred to the purchaser of our Norway business upon closing of the sale in the fourth quarter of 2014.
Derivatives Designated as Cash Flow Hedges
During the third quarter of 2016,In September 2019, we entered into forward starting interest rate swapsa fourth amendment to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that is probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. The occurrence of the forecasted transaction is probable and each respective derivative contract can be tied to an anticipated underlying dollar notional amount. At conclusion of the hedge in the first quarter of 2018, the final value will be reclassified from accumulated other comprehensive income into earnings. At December 31, 2016, the forward starting interest rate swaps continued to qualify as an effective hedge. The ineffectiveness related to this hedge resulted in a charge of $4 million in 2016. See Note 22 for a summary of amounts reclassified from accumulated other comprehensive loss.
The following table presents, by maturity date, information about our forward starting interest rate swap agreements, including the rate. |
| | | | | | |
| | | December 31, 2016 |
| | | Aggregate Notional Amount | | Weighted Average, LIBOR |
| Maturity Dates | | (in millions) | | Fixed Rate |
| March 15, 2018 | | $ | 750 |
| | 1.57% |
The following table sets forth the net impact of the derivatives designated as cash flow hedges on other comprehensive income (loss). |
| | | | | | | | | |
| | | December 31, |
| (In millions) | | 2016 | | 2015 |
| Cash Flow Hedges | | | | |
| Beginning balance | | $ | — |
| | $ | — |
|
| Change in fair value recognized in accumulated other comprehensive loss | | 64 |
| | — |
|
| Reclassification from other comprehensive income (loss) | | (4 | ) | | — |
|
| Ending balance | | $ | 60 |
| | $ | — |
|
At December 31, 2016, accumulated other comprehensive loss included a gain of $39 million, net of tax, related to interest rate cash flow hedges. We do not expect any material reclassification to earnings as an adjustment to net interest and other during the next 12 months.
Derivatives Not Designated as Hedges
We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December 2018. These commodity derivatives consist of three-way collars, swaps, and call options. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of December 31, 2016 and the weighted average prices for those contracts:
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
|
| | | | | | | |
Crude Oil (a) |
| | 2017 |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
Three-Way Collars (b) | | | | | | | |
| Volume (Bbls/day) | 50,000 | | 50,000 | | 30,000 | | 30,000 |
| Price per Bbl: | | | | | | | |
| Ceiling | $58.42 | | $58.42 | | $59.60 | | $59.60 |
| Floor | $50.30 | | $50.30 | | $54.00 | | $54.00 |
| Sold put | $43.50 | | $43.50 | | $47.00 | | $47.00 |
Sold Call Options (c) | | | | | | | |
| Volume (Bbls/day) | 35,000 | | 35,000 | | 35,000 | | 35,000 |
| Price per Bbl | $61.91 | | $61.91 | | $61.91 | | $61.91 |
(a) Subsequent to December 31, 2016, we entered into 10,000 Bbls/day of fixed-price swaps with a weighted average price of $54.00 indexed to WTI for February - March of 2017.
(b) Subsequent to December 31, 2016, we entered into 20,000 Bbls/day of three-way collars for July - December of 2017 with a ceiling price of $61.52, a floor price of $56.00, and a sold put price of $49.00.
(c) Call options settle monthly.
|
| | | | | |
| Natural Gas |
| | 2017 | |
| | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | 2018 |
Three-Way Collars (a) | | | | | |
| Volume (MMBtu/day) | 60,000 | 90,000 | 90,000 | 90,000 | 20,000 |
| Price per MMBtu | | | | | |
| Ceiling | $3.46 | $3.54 | $3.54 | $3.61 | $3.56 |
| Floor | $2.84 | $3.01 | $3.01 | $3.04 | $3.00 |
| Sold put | $2.35 | $2.48 | $2.48 | $2.52 | $2.50 |
| Swaps | | | | | |
| Volume (MMBtu/day) | 20,000 | 20,000 | 20,000 | 20,000 | — |
| Price per MMBtu | $2.93 | $2.93 | $2.93 | $2.93 | $— |
(a) Subsequent to December 31, 2016, we entered into three-way collars of 30,000 MMBtus/day for April - September of 2017 with a ceiling price of $3.70, a floor price of $3.35, and a sold put price of $2.75; 30,000 MMBtus/day for October - December of 2017 with a ceiling price of $4.00, a floor price of $3.45, and a sold put price of $2.85; and 70,000 MMBtus/day for January - December of 2018 with a ceiling price of $3.62, a floor price of $3.00, and a sold put price of $2.50.
The mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the years ended December 31, 2016 and 2015. There were no commodity derivative instruments during 2014. The 2016 impact was a net loss of $66 million compared to a net gain of $128 million in 2015. Net settlements of commodity derivative instruments for the years ended December 31, 2016 and 2015 was $44 million compared to $78 million, comparatively.
On June 1, 2015, we entered into Treasury rate locks, which expired on the same day, to hedge against timing differences as it related to our Notes offering (see Note 17). Following the execution of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
17. Debt
Short-term debt
As of December 31, 2016, we had no borrowings against our unsecured revolving credit facility (as amended,(the “Credit Facility”) to reduce the "Credit Facility"), as described below.
Revolving Credit Facility
In March 2016,maximum borrowing from $3.4 billion to $3.0 billion and extended the maturity date by one year to May 28, 2023. As of December 31, 2019, we increasedhad 0 borrowings against our $3.0 billion unsecured Credit Facility to $3.3 billion and maintained a maturity date of May 2020. Fees on the unused commitment of each lender, as well as the borrowing optionsor under our U.S. commercial paper program that is backed by the Credit Facility, remain unaffected by this increase. We have the ability to request two one-year extensions and an option to increase the commitment amount by up to an additional $200 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.Facility.
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of December 31, 2016,2019, we were in compliance with this covenant with a debt-to-capitalization ratio of 29%31%.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Long-term debt
The following table details our long-term debt:
|
| | | | | | | |
| | December 31, |
| (In millions) | 2016 | | 2015 |
| Senior unsecured notes: | | | |
6.000% notes due 2017(a) | 682 |
| | 682 |
|
5.900% notes due 2018(a) | 854 |
| | 854 |
|
7.500% notes due 2019(a) | 228 |
| | 228 |
|
2.700% notes due 2020(a) | 600 |
| | 600 |
|
2.800% notes due 2022(a) | 1,000 |
| | 1,000 |
|
9.375% notes due 2022 (b) | 32 |
| | 32 |
|
Series A notes due 2022 (b) | 3 |
| | 3 |
|
8.500% notes due 2023 (b) | 70 |
| | 70 |
|
8.125% notes due 2023 (b) | 131 |
| | 131 |
|
3.850% notes due 2025(a) | 900 |
| | 900 |
|
6.800% notes due 2032(a) | 550 |
| | 550 |
|
6.600% notes due 2037(a) | 750 |
| | 750 |
|
5.200% notes due 2045(a) | 500 |
| | 500 |
|
| Capital leases: | | | |
| Capital lease obligation of consolidated subsidiary due 2017 – 2049 | 9 |
| | 9 |
|
| Other obligations: | | | |
| 5.125% obligation relating to revenue bonds due 2037 | 1,000 |
| | 1,000 |
|
Total(b) | 7,309 |
| | 7,309 |
|
| Unamortized discount | (9 | ) | | (10 | ) |
Fair value adjustments(c) | 7 |
| | 17 |
|
| Unamortized debt issuance cost | (35 | ) | | (39 | ) |
| Amounts due within one year | (683 | ) | | (1 | ) |
| Total long-term debt | $ | 6,589 |
| | $ | 7,276 |
|
|
| | | | | | | |
| | December 31, |
| (In millions) | 2019 | | 2018 |
| Senior unsecured notes: | | | |
2.700% notes due 2020(a) | $ | — |
| | $ | 600 |
|
2.800% notes due 2022(a) | 1,000 |
| | 1,000 |
|
9.375% notes due 2022(b) | 32 |
| | 32 |
|
Series A notes due 2022(b) | 3 |
| | 3 |
|
8.500% notes due 2023(b) | 70 |
| | 70 |
|
8.125% notes due 2023(b) | 131 |
| | 131 |
|
3.850% notes due 2025(a) | 900 |
| | 900 |
|
4.400% notes due 2027(a) | 1,000 |
| | 1,000 |
|
6.800% notes due 2032(a) | 550 |
| | 550 |
|
6.600% notes due 2037(a) | 750 |
| | 750 |
|
5.200% notes due 2045(a) | 500 |
| | 500 |
|
Bonds:(c) | | | |
| 2.00% bonds due 2037 | 200 |
| | — |
|
| 2.10% bonds due 2037 | 200 |
| | — |
|
| 2.20% bonds due 2037 | 200 |
| | — |
|
Total(b) | 5,536 |
| | 5,536 |
|
| Unamortized discount | (7 | ) | | (8 | ) |
| Unamortized debt issuance cost | (28 | ) | | (29 | ) |
| Total long-term debt | $ | 5,501 |
| | $ | 5,499 |
|
| |
(a) | These notes contain a make-whole provision allowing us to repay the debt at a premium to market price. |
| |
(b) | In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 20162019 may be declared immediately due and payable. |
| |
(c) | See Notes 15Mandatory purchase dates for these bonds: April 1, 2023 for the 2.00% bonds; July 1, 2024 for the 2.10% bonds; and 16July 1, 2026 for information on interest rate swaps.the 2.20% bonds. Subsequent to the various mandatory purchase dates, we will also have the right to convert and remarket these any time up to the 2037 maturity date. |
On October 3, 2019, we redeemed our $600 million 2.7% senior unsecured notes due June 2020.
The following table shows future debt payments:
|
| | | |
| (In millions) | |
| 2020 | $ | — |
|
| 2021 | — |
|
| 2022 | 1,035 |
|
| 2023 | 401 |
|
| 2024 | 200 |
|
| Thereafter | 3,900 |
|
| Total long-term debt, including current portion | $ | 5,536 |
|
Debt Issuance
On October 1, 2019, we closed a $600 million remarketing to investors of sub-series A bonds which are part of the $1.0 billion St. John the Baptist, State of Louisiana revenue refunding bonds originally issued and purchased in December 2017. The $600 million in proceeds from the conversion and remarketing were used to pay the purchase price of our converted 2017 bonds on the closing date. We continue to own the remaining $400 million of the revenue refunding bonds and have the right to convert and remarket them to investors at any time up to the 2037 maturity date.
18. Incentive Based Compensation
Description of stock-based compensation plans – The Marathon Oil Corporation 2019 Incentive Compensation Plan (the “2019 Plan”) was approved by our stockholders in May 2019 and authorizes the Compensation Committee of the Board of Directors to grant stock options, stock appreciation rights (“SARs”), stock awards (including restricted stock and restricted stock unit awards), performance unit awards and cash awards to employees. The 2019 Plan also allows us to provide equity compensation to our non-employee directors. No more than 27.9 million shares of our common stock may be issued under the 2019 Plan. In connection with the granting of an award under the 2019 Plan, the number of shares available for issuance under the 2019 Plan will be reduced by one share for each share of our common stock in respect of which the award is granted, except that awards that by their terms do not permit settlement in shares of our common stock will not reduce the number of shares of common stock available for issuance under the 2019 Plan.
Shares subject to awards under the 2019 Plan that are forfeited, terminated or expire unexercised become available for future grants. In addition, the number of shares of our common stock reserved for issuance under the 2019 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2019 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.
After approval of the 2019 Plan, 0 new grants were or will be made from any prior plans. Any awards previously granted under any prior plans shall continue to be exercisable in accordance with their original terms and conditions.
Stock-based awards under the plans
Stock options – We grant stock options under the 2019 Plan. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. In general, our stock options vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.
SARs – At December 31, 2019, there are 0 SARs outstanding.
Restricted stock– We grant restricted stock under the 2019 Plan. The restricted stock awards granted to officers generally vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest ratably over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares of restricted stock are not transferable and are held by our transfer agent.
Stock-based performance units – We grant stock-based performance units to officers under the 2019 Plan. At the grant date, each unit represents the value of one share of our common stock. These units are settled in shares, and the number of shares of our common stock to be paid is based on the vesting percentage, which can be from 0 to 200% based on performance achieved over a three-year performance period, and as determined by the Compensation Committee of the Board of Directors. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of our Board of Directors. Dividend equivalents may accrue during the performance period and would be paid in cash at the end of the performance period based on the amount of dividends credited generally over the performance period on shares of our common stock that represent the value of the units granted multiplied by the vesting percentage.
Restricted stock units – We maintain an equity compensation program for our non-employee directors. All non-employee directors receive annual grants of common stock units. Any units granted prior to 2012 must be held until completion of board service, at which time the non-employee director will receive common shares. For units granted between 2012 and 2016, common shares will generally vest following completion of board service or three years from the date of grant, whichever is earlier. For awards issued in 2017 and later, directors may elect to defer settlement of their common stock units until after they cease serving on the Board. Absent such an election to defer, common shares will vest upon the earlier of three years from the date of grant or completion of board service. Under the 2019 Plan, we also grant restricted stock units to officers, which generally vest three years from the date of the grant and restricted stock units to certain non-officer employees, which generally vest ratably over a three-year period. Both awards are contingent on the recipient’s continued employment. Grants of restricted stock units to these non-officer employees are generally based on their performance and for retention purposes. Common shares will be issued for these restricted stock units after vesting. Prior to vesting, recipients of restricted stock units typically receive dividend equivalent payments, but they may not vote.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Debt IssuanceTotal stock-based compensation expense – Total employee stock-based compensation expense was $60 million, $53 million and $50 million in 2019, 2018 and 2017. Due to the full valuation allowance on our net federal deferred tax assets, we recognized no tax benefit during these years. Cash received upon exercise of stock option awards was $1 million and $26 million for 2019 and 2018. There was no cash received upon exercise of stock option awards 2017. There were 0 tax benefits realized for deductions for stock awards settled during 2019, 2018 and 2017.
On June 10, 2015,Stock option awards – During 2019, 2018 and 2017 we issued $2 billion aggregate principal amountgranted stock option awards to officer employees. The weighted average grant date fair value of unsecured senior notes which consist ofthese awards was based on the following series:weighted average Black-Scholes assumptions:
•$600 million of 2.70% senior notes due June 1, 2020 |
| | | | | | | | | | | |
| 2019 | | 2018 | | 2017 |
| Exercise price per share | $ | 16.79 |
| | $ | 14.52 |
| | $ | 15.80 |
|
| Expected annual dividend yield | 1.2 | % | | 1.4 | % | | 1.3 | % |
| Expected life in years | 5.82 |
| | 6.45 |
| | 6.4 |
|
| Expected volatility | 43 | % | | 43 | % | | 42 | % |
| Risk-free interest rate | 2.5 | % | | 2.8 | % | | 2.1 | % |
| Weighted average grant date fair value of stock option awards granted | $ | 6.62 |
| | $ | 5.83 |
| | $ | 6.07 |
|
•$900 million of 3.85% senior notes due June 1, 2025
•$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The aggregate net proceeds were used to repay our $1 billion 0.90% senior notes that matured in November 2015, and the remainder for general corporate purposes.
The following table shows future debt payments:is a summary of stock option award activity in 2019. |
| | | |
| (In millions) | |
| 2017 | $ | 683 |
|
| 2018 | 854 |
|
| 2019 | 228 |
|
| 2020 | 600 |
|
| 2021 | — |
|
| Thereafter | 4,944 |
|
| Total long-term debt, including current portion | $ | 7,309 |
|
|
| | | | | | | | | | | | |
| | Number of Shares | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term | | Aggregate Intrinsic Value (in millions) |
| Outstanding at beginning of year | 6,180,007 | | $ | 24.39 |
| | | | |
| Granted | 648,526 | | $ | 16.79 |
| | | | |
| Exercised | (84,804) | | $ | 8.17 |
| | | | |
| Canceled | (1,083,998) | | $ | 25.45 |
| | | | |
| Outstanding at end of year | 5,659,731 | | $ | 23.55 |
| | 5 years | | $ | 3 |
|
| Exercisable at end of year | 4,323,312 |
| | $ | 25.96 |
| | 4 years | | $ | 3 |
|
| Expected to vest | 1,319,850 |
| | $ | 15.76 |
| | 8 years | | $ | — |
|
The intrinsic value of stock option awards exercised during 2018 was $13 million while it was immaterial during 2019 and 2017.
As of December 31, 2019, unrecognized compensation cost related to stock option awards was $5 million, which is expected to be recognized over a weighted average period of 1 year. 18. Asset Retirement Obligations
Asset retirement obligations primarily consistRestricted stock awards and restricted stock units – The following is a summary of estimated costs to remove, dismantlerestricted stock and restore land or seabed at the end of oil and gas production operations, including bitumen mining operations. Changesrestricted stock unit award activity in asset retirement obligations were as follows:2019.
|
| | | | | | | |
| | For Year Ended December 31, |
| (In millions) | 2016 | | 2015 |
| Beginning balance | $ | 1,635 |
| | $ | 1,958 |
|
| Incurred liabilities, including acquisitions | 15 |
| | 47 |
|
| Settled liabilities, including dispositions | (74 | ) | | (289 | ) |
| Accretion expense (included in depreciation, depletion and amortization) | 85 |
| | 105 |
|
| Revisions of estimates | 94 |
| | (132 | ) |
| Held for sale | (7 | ) | | (54 | ) |
| Ending balance | $ | 1,748 |
| | $ | 1,635 |
|
|
| | | | | | |
| | Awards | | Weighted Average Grant Date Fair Value |
| Unvested at beginning of year | 8,504,946 |
| | $ | 14.04 |
|
| Granted | 4,113,190 |
| | $ | 16.65 |
|
| Vested and Exercised | (3,813,221 | ) | | $ | 12.64 |
|
| Canceled | (1,630,529 | ) | | $ | 15.78 |
|
| Unvested at end of year | 7,174,386 |
| | $ | 15.88 |
|
2016
Settled liabilities include dispositions, primarily related to the GulfThe vesting date fair value of Mexicorestricted stock awards which vested during 2019, 2018 and Wyoming as well as retirements in the Gulf2017 was $48 million, $48 million and $39 million. The weighted average grant date fair value of Mexico.
Revisions of estimates were primarily due to changes in timing of abandonment activities as well as changes in cost estimated in the U.K.
Ending balance includes $50 million classified as short-termrestricted stock awards was $15.88, $14.04 and $14.24 for awards unvested at December 31, 2016.2019, 2018 and 2017.
As of December 31, 2019 there was $65 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 1 year.
Stock-based performance unit awards – During 2019, 2018 and 2017 we granted 656,636, 754,140 and 563,631 stock-based performance unit awards to officers. At December 31, 2019, there were 1,282,296 units outstanding. Total stock-based performance unit awards expense was $7 million in 2019, $13 million in 2018 and $8 million in 2017.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
2015
Settled liabilities include dispositions, primarilyThe key assumptions used in the GulfMonte Carlo simulation to determine the fair value of Mexicostock-based performance units granted in 2019, 2018 and the East Texas, North Louisiana and Wilburton, Oklahoma as well as retirements in the Gulf of Mexico and the U.K.
2017 were:Revisions of estimates were primarily due to changes in timing of activities in the U.K. and lower estimated costs across the assets. |
| | | | | | | | | | | |
| | 2019(a) | | 2018 | | 2017(b) |
| Valuation date stock price | $ | 16.79 |
| | $ | 13.69 |
| | $ | 13.58 |
|
| Expected annual dividend yield | 1.2 | % | | 1.5 | % | | N/A |
|
| Expected volatility | 43 | % | | 41 | % | | N/A |
|
| Risk-free interest rate | 2.5 | % | | 1.5 | % | | N/A |
|
| Fair value of stock-based performance units outstanding | $ | 20.66 |
| | $ | 17.29 |
| | $ | 14.18 |
|
Held for sale is related to our Neptune field in the Gulf of Mexico.
Ending balance includes $34 million classified as short-term at December 31, 2015.
19. Supplemental Cash Flow Information
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 |
| Net cash used in operating activities: | | | | | |
| Interest paid (net of amounts capitalized) | $ | (375 | ) | | $ | (325 | ) | | $ | (279 | ) |
Income taxes paid to taxing authorities (a) | (84 | ) | | (171 | ) | | (1,679 | ) |
| Net cash provided by (used in) financing activities: | | | | | |
| Commercial paper, net: | | | | | |
| Issuances | $ | — |
| | $ | — |
| | $ | 2,345 |
|
| Repayments | — |
| | — |
| | (2,480 | ) |
| Commercial paper, net | $ | — |
| | $ | — |
| | $ | (135 | ) |
| Noncash investing activities, related to continuing operations: | | | | | |
| Asset retirement cost increase (decrease) | $ | 111 |
| | $ | (85 | ) | | $ | 151 |
|
| Asset retirement obligations assumed by buyer | 40 |
| | 251 |
| | 359 |
|
| Increase in capital expenditure accrual | — |
| | — |
| | 335 |
|
| |
(a) | Income taxes paid to taxing authorities includes $1,312 millionRepresents key assumptions at grant date, as 2019 performance unit awards are settled in 2014 related to discontinued operations.stock. |
| |
(b) | N/A as these stock-based performance unit awards vested as of December 31, 2019 and as such the value is based on the final payout. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
20.19. Defined Benefit Postretirement Plans and Defined Contribution Plan
We have noncontributory defined benefit pension plans covering substantially all domestic employees, as well as U.K. employees who were hired before April 2010. Certain employees located in E.G., who are U.S. or U.K. based, also participate in these plans.employees. Benefits under these plans are based on plan provisions specific to each plan. For the U.K.
We also had a noncontributory defined benefit pension plan covering eligible U.K. employees that was transferred to the principal employer and plan trustees reached a decision to closebuyer in connection with the plan to future benefit accruals effectivesale of our U.K. business during 2019. See Note 5 for further information on this disposition. During the year ended December 31, 2015.2019, we reclassified $20 million from accumulated other comprehensive income to pension assets upon remeasurement of the plan. We also have defined benefit plans for other postretirement benefits covering our U.S. employees. Health care benefits are provided up to age 65 through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Post-age 65 health care benefits are provided to certain U.S. employees on a defined contribution basis. Life insurance benefits are provided to certain retiree beneficiaries. These other postretirement benefits are not funded in advance. Employees hired after 2016 are not eligible for any postretirement health care or life insurance benefits.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Obligations and funded status– The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| | 2019 | | 2018 | | 2019 | | 2018 |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | U.S. |
| Accumulated benefit obligation | $ | 343 |
| | $ | — |
| | $ | 320 |
| | $ | 511 |
| | $ | 89 |
| | $ | 96 |
|
| | | | | | | | | | | | |
| Change in pension benefit obligations: | | | | | | | | | | | |
| Beginning balance | $ | 326 |
| | $ | 511 |
| | $ | 384 |
| | $ | 599 |
| | $ | 96 |
| | $ | 221 |
|
| Service cost | 19 |
| | — |
| | 18 |
| | — |
| | 1 |
| | 2 |
|
| Interest cost | 12 |
| | 8 |
| | 12 |
| | 14 |
| | 3 |
| | 7 |
|
| Plan amendment | — |
| | — |
| | — |
| | 3 |
| | — |
| | (99 | ) |
Divestiture(a) | — |
| | (549 | ) | | — |
| | — |
| | — |
| | — |
|
| Actuarial loss (gain) | 48 |
| | 36 |
| | (20 | ) | | (38 | ) | | 9 |
| | (15 | ) |
| Foreign currency exchange rate changes | — |
| | 6 |
| | — |
| | (29 | ) | | — |
| | — |
|
| Settlements paid | (45 | ) | | — |
| | (62 | ) | | (23 | ) | | — |
| | — |
|
| Benefits paid | (6 | ) | | (12 | ) | | (6 | ) | | (15 | ) | | (20 | ) | | (20 | ) |
| Ending balance | $ | 354 |
| | $ | — |
| | $ | 326 |
| | $ | 511 |
| | $ | 89 |
| | $ | 96 |
|
| Change in fair value of plan assets: | | | | | | | | | | | |
| Beginning balance | $ | 203 |
| | $ | 594 |
| | $ | 216 |
| | $ | 670 |
| | $ | — |
| | $ | — |
|
| Actual return on plan assets | 44 |
| | 68 |
| | (6 | ) | | (21 | ) | | — |
| | — |
|
| Employer contributions | 40 |
| | 8 |
| | 61 |
| | 17 |
| | 20 |
| | 20 |
|
| Foreign currency exchange rate changes | — |
| | 8 |
| | — |
| | (34 | ) | | — |
| | — |
|
Divestiture(a) | — |
| | (666 | ) | | — |
| | — |
| | — |
| | — |
|
| Settlements paid | (45 | ) | | — |
| | (62 | ) | | (23 | ) | | — |
| | — |
|
| Benefits paid | (6 | ) | | (12 | ) | | (6 | ) | | (15 | ) | | (20 | ) | | (20 | ) |
| Ending balance | $ | 236 |
| | $ | — |
| | $ | 203 |
| | $ | 594 |
| | $ | — |
| | $ | — |
|
| Funded status of plans at December 31 | $ | (118 | ) | | $ | — |
| | $ | (123 | ) | | $ | 83 |
| | $ | (89 | ) | | $ | (96 | ) |
| Amounts recognized in the consolidated balance sheets: | | | | | | | | | | | |
| Noncurrent assets | $ | — |
| | $ | — |
| | $ | — |
| | $ | 83 |
| | $ | — |
| | $ | — |
|
| Current liabilities | (6 | ) | | — |
| | (5 | ) | | — |
| | (18 | ) | | (19 | ) |
| Noncurrent liabilities | (112 | ) | | — |
| | (118 | ) | | — |
| | (71 | ) | | (77 | ) |
| Accrued benefit cost | $ | (118 | ) | | $ | — |
| | $ | (123 | ) | | $ | 83 |
| | $ | (89 | ) | | $ | (96 | ) |
| Pretax amounts in accumulated other comprehensive loss: | | | | | | | | | | | |
| Net loss | $ | 85 |
| | $ | — |
| | $ | 90 |
| | $ | 59 |
| | $ | 23 |
| | $ | 14 |
|
| Prior service cost | (29 | ) | | — |
| | (36 | ) | | 5 |
| | (129 | ) | | (147 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| | 2016 | | 2015 | | 2016 | | 2015 |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | U.S. |
| Accumulated benefit obligation | 386 |
| | 583 |
| | 518 |
| | 579 |
| | 227 | | 260 |
| Change in benefit obligations: | | | | | | | | | | | |
| Beginning balance | $ | 525 |
| | $ | 579 |
| | $ | 894 |
| | $ | 651 |
| | $ | 260 |
| | $ | 279 |
|
| Service cost | 25 |
| | — |
| | 29 |
| | 14 |
| | 2 |
| | 3 |
|
| Interest cost | 16 |
| | 23 |
| | 25 |
| | 25 |
| | 11 |
| | 11 |
|
Plan amendment(a) | — |
| | 1 |
| | (88 | ) | | 1 |
| | (38 | ) | | — |
|
| Actuarial loss (gain) | 78 |
| | 139 |
| | 26 |
| | (29 | ) | | 11 |
| | (20 | ) |
| Foreign currency exchange rate changes | — |
| | (108 | ) | | — |
| | (35 | ) | | — |
| | — |
|
| Divestiture | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Liability (gain)/loss due to curtailment(b) | — |
| | — |
| | (18 | ) | | (23 | ) | | — |
| | 2 |
|
| Settlements paid | (240 | ) | | (36 | ) | | (335 | ) | | — |
| | — |
| | — |
|
| Benefits paid | (7 | ) | | (15 | ) | | (8 | ) | | (25 | ) | | (19 | ) | | (15 | ) |
| Ending balance | $ | 397 |
| | $ | 583 |
| | $ | 525 |
| | $ | 579 |
| | $ | 227 |
| | $ | 260 |
|
| Change in fair value of plan assets: | | | | | | | | | | | |
| Beginning balance | $ | 354 |
| | $ | 608 |
| | $ | 574 |
| | $ | 622 |
| | $ | — |
| | $ | — |
|
| Actual return on plan assets | 25 |
| | 129 |
| | 8 |
| | 8 |
| | — |
| | — |
|
| Employer contributions | 95 |
| | 18 |
| | 115 |
| | 36 |
| | 20 |
| | 15 |
|
| Foreign currency exchange rate changes | — |
| | (109 | ) | | — |
| | (33 | ) | | — |
| | — |
|
| Divestiture | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Settlements paid | (240 | ) | | (36 | ) | | (335 | ) | | — |
| | — |
| | — |
|
| Benefits paid | (7 | ) | | (15 | ) | | (8 | ) | | (25 | ) | | (20 | ) | | (15 | ) |
| Ending balance | $ | 227 |
| | $ | 595 |
| | $ | 354 |
| | $ | 608 |
| | $ | — |
| | $ | — |
|
| Funded status of plans at December 31 | $ | (170 | ) | | $ | 12 |
| | $ | (171 | ) | | $ | 29 |
| | $ | (227 | ) | | $ | (260 | ) |
| Amounts recognized in the consolidated balance sheets: |
| Noncurrent assets | — |
| | 12 |
| | — |
| | 29 |
| | — |
| | — |
|
| Current liabilities | (4 | ) | | — |
| | (8 | ) | | — |
| | (21 | ) | | (20 | ) |
| Noncurrent liabilities | (166 | ) | | — |
| | (163 | ) | | — |
| | (206 | ) | | (240 | ) |
| Accrued benefit cost | $ | (170 | ) | | $ | 12 |
| | $ | (171 | ) | | $ | 29 |
| | $ | (227 | ) | | $ | (260 | ) |
| Pretax amounts in accumulated other comprehensive loss: |
| Net loss (gain) | $ | 130 |
| | $ | 81 |
| | $ | 171 |
| | $ | 61 |
| | $ | 25 |
| | $ | 14 |
|
| Prior service cost (credit) | (55 | ) | | 4 |
| | (65 | ) | | 4 |
| | (63 | ) | | (28 | ) |
| |
(a) | The plan amendment in 2015 was a freezeRefer to Note 5 for further information on the sale of the final average pay used in the legacy formula of the defined benefit pension plan. |
| |
(b)
| Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under theour U.K. pension plan effective December 31, 2015.business. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Components of net periodic benefit cost from continuing operations and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | U.S. | | U.S. |
| Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | |
| Service cost | $ | 19 |
| | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | 1 |
| | $ | 2 |
| | $ | 2 |
|
| Interest cost | 12 |
| | 8 |
| | 12 |
| | 14 |
| | 13 |
| | 17 |
| | 3 |
| | 7 |
| | 8 |
|
| Expected return on plan assets | (10 | ) | | (11 | ) | | (11 | ) | | (24 | ) | | (13 | ) | | (30 | ) | | — |
| | — |
| | — |
|
| Amortization: | | | | | | | | | | | | | | | | | |
| - prior service credit | (7 | ) | | — |
| | (10 | ) | | — |
| | (10 | ) | | — |
| | (19 | ) | | (8 | ) | | (7 | ) |
| - actuarial loss | 7 |
| | — |
| | 11 |
| | — |
| | 8 |
| | 1 |
| | 1 |
| | 1 |
| | — |
|
Net settlement loss(a) | 12 |
| | — |
| | 18 |
| | 3 |
| | 28 |
| | 4 |
| | — |
| | — |
| | — |
|
Net periodic benefit cost(b) | $ | 33 |
| | $ | (3 | ) | | $ | 38 |
| | $ | (7 | ) | | $ | 48 |
| | $ | (8 | ) | | $ | (14 | ) | | $ | 2 |
| | $ | 3 |
|
| Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax): | | | | | | | | | | | | | | | | | |
| Actuarial loss (gain) | $ | 14 |
| | $ | (21 | ) | | $ | (4 | ) | | $ | 8 |
| | $ | 28 |
| | $ | (26 | ) | | $ | 9 |
| | $ | (15 | ) | | $ | 5 |
|
| Amortization of actuarial gain (loss) | (19 | ) | | (41 | ) | | (29 | ) | | (3 | ) | | (36 | ) | | (4 | ) | | (1 | ) | | (1 | ) | | — |
|
| Prior service cost (credit) | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
| | (99 | ) | | — |
|
| Amortization of prior service credit (cost) | 7 |
| | (6 | ) | | 10 |
| | — |
| | 10 |
| | — |
| | 19 |
| | 8 |
| | 7 |
|
| Total recognized in other comprehensive (income) loss | $ | 2 |
| | $ | (68 | ) | | $ | (23 | ) | | $ | 8 |
| | $ | 2 |
| | $ | (30 | ) | | $ | 27 |
| | $ | (107 | ) | | $ | 12 |
|
| Total recognized in net periodic benefit cost and other comprehensive (income) loss | $ | 35 |
| | $ | (71 | ) | | $ | 15 |
| | $ | 1 |
| | $ | 50 |
| | $ | (38 | ) | | $ | 13 |
| | $ | (105 | ) | | $ | 15 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | U.S. | | U.S. |
| Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | |
| Service cost | $ | 25 |
| | $ | — |
| | $ | 29 |
| | $ | 14 |
| | $ | 31 |
| | $ | 16 |
| | $ | 2 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 16 |
| | 23 |
| | 25 |
| | 25 |
| | 35 |
| | 27 |
| | 11 |
| | 11 |
| | 13 |
|
| Expected return on plan assets | (18 | ) | | (35 | ) | | (30 | ) | | (37 | ) | | (34 | ) | | (32 | ) | | — |
| | — |
| | — |
|
| Amortization: | | | | | | | | | | | | | | | | | |
| - prior service cost (credit) | (10 | ) | | 1 |
| | (7 | ) | | 1 |
| | 5 |
| | 1 |
| | (3 | ) | | (4 | ) | | (6 | ) |
| - actuarial loss | 14 |
| | — |
| | 22 |
| | 2 |
| | 29 |
| | 1 |
| | — |
| | 1 |
| | — |
|
Net curtailment loss (gain)(a) | — |
| | — |
| | (5 | ) | | 4 |
| | — |
| | — |
| | — |
| | (7 | ) | | — |
|
Net settlement loss(b) | 97 |
| | 6 |
| | 119 |
| | — |
| | 99 |
| | — |
| | — |
| | — |
| | — |
|
Net periodic benefit cost(c) | $ | 124 |
| | $ | (5 | ) | | $ | 153 |
| | $ | 9 |
| | $ | 165 |
| | $ | 13 |
| | $ | 10 |
| | $ | 4 |
| | $ | 10 |
|
| Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax): | | | | | | | | | | | | | | | | | |
Actuarial loss (gain)(d) | $ | 70 |
| | $ | 41 |
| | $ | 30 |
| | $ | (25 | ) | | $ | 149 |
| | $ | 33 |
| | $ | 11 |
| | $ | (21 | ) | | $ | 42 |
|
| Amortization of actuarial gain (loss) | (111 | ) | | (6 | ) | | (134 | ) | | (2 | ) | | (128 | ) | | (1 | ) | | — |
| | (1 | ) | | — |
|
| Prior service cost (credit) | — |
| | 1 |
| | (89 | ) | | 1 |
| | — |
| | — |
| | (38 | ) | | — |
| | (42 | ) |
| Amortization of prior service credit (cost) | 10 |
| | (1 | ) | | 7 |
| | (5 | ) | | (5 | ) | | (1 | ) | | 3 |
| | 13 |
| | 6 |
|
| Total recognized in other comprehensive (income) loss | $ | (31 | ) | | $ | 35 |
| | $ | (186 | ) | | $ | (31 | ) | | $ | 16 |
| | $ | 31 |
| | $ | (24 | ) | | $ | (9 | ) | | $ | 6 |
|
| Total recognized in net periodic benefit cost and other comprehensive (income) loss | $ | 93 |
| | $ | 30 |
| | $ | (33 | ) | | $ | (22 | ) | | $ | 181 |
| | $ | 44 |
| | $ | (14 | ) | | $ | (5 | ) | | $ | 16 |
|
| |
(a) | Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015. |
| |
(b)
| Settlement lossesSettlements are recorded whenrecognized as they occur, once it is probable that lump sum payments from a plan infor a periodgiven year will exceed the plan’s total service and interest costs for the period.that year. |
| |
(c)(b)
| Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years. |
| |
(d)
| Activity in 2014 includes the impact of the sale of our Norway business in the fourth quarter of 2014. |
The estimated net loss and prior service credit for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 20172020 are $10$9 million and $10$7 million. The estimated net loss and prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2017 is $72020 are $2 million and $18 million.
Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2016, 20152019, 2018 and 2014.2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| (In millions) | U.S. | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | U.S. | | U.S. |
| Weighted average assumptions used to determine benefit obligation: | | | | | | | | | | | | | | | |
| Discount rate | 3.13 | % | | 4.26 | % | | 2.90 | % | | 3.55 | % | | 2.50 | % | | 2.91 | % | | 4.09 | % | | 3.54 | % |
| Rate of compensation increase | 4.50 | % | | 4.00 | % | | — | % | | 4.00 | % | | — | % | | 4.50 | % | | 4.00 | % | | 4.00 | % |
| Weighted average assumptions used to determine net periodic benefit cost: | | | | | | | | | | | | | | | |
| Discount rate | 3.70 | % | | 3.88 | % | | 2.50 | % | | 3.86 | % | | 2.70 | % | | 4.09 | % | | 3.54 | % | | 3.98 | % |
| Expected long-term return on plan assets | 6.25 | % | | 6.50 | % | | 3.70 | % | | 6.50 | % | | 4.50 | % | | — | % | | — | % | | — | % |
| Rate of compensation increase | 4.00 | % | | 4.00 | % | | — | % | | 4.00 | % | | — | % | | 4.00 | % | | 4.00 | % | | 4.00 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 |
| (In millions) | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | U.S. | | U.S. |
| Weighted average assumptions used to determine benefit obligation: | | | | | | | | | | | | | | | | | |
| Discount rate | 4.02 | % | | 2.70 | % | | 4.04 | % | | 3.90 | % | | 3.71 | % | | 3.70 | % | | 3.98 | % | | 4.36 | % | | 4.01 | % |
Rate of compensation increase (a) | 4.00 | % | | — |
| | 4.00 | % | | — |
| | 4.00 | % | | 3.60 | % | | 4.00 | % | | 4.00 | % | | 4.00 | % |
| Weighted average assumptions used to determine net periodic benefit cost: | | | | | | | | | | | | | | | | | |
| Discount rate | 3.66 | % | | 3.90 | % | | 3.79 | % | | 3.70 | % | | 3.98 | % | | 4.60 | % | | 4.36 | % | | 3.93 | % | | 4.69 | % |
| Expected long-term return on plan assets | 6.75 | % | | 5.50 | % | | 6.75 | % | | 5.70 | % | | 6.75 | % | | 5.70 | % | | — |
| | — |
| | — |
|
Rate of compensation increase (a) | 4.00 | % | | — |
| | 4.00 | % | | 3.60 | % | | 5.00 | % | | 4.90 | % | | 4.00 | % | | 4.00 | % | | 5.00 | % |
| |
(a)
| No future benefits will be incurred for the U.K. plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this plan. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Expected long-term return on plan assets – The expected long-term return on plan assets assumption for our U.S. funded plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group which utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plan’s asset allocation. To determine the expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on the actual asset allocation to develop the overall expected long-term return on plan assets assumption.
Assumed weighted average health care cost trend rates
|
| | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| Initial health care trend rate | 8.25 | % | | 8.00 | % | | 6.88 | % |
| Ultimate trend rate | 4.50 | % | | 4.50 | % | | 5.00 | % |
| Year ultimate trend rate is reached | 2025 |
| | 2024 |
| | 2024 |
|
Employer provided subsidies for post-65 retiree health care coverage were frozen effective January 1, 2017 at January 1, 2016 established amount levels. Company contributions are funded to a Health Reimbursement Account on the retiree’s behalf to subsidize the retiree’s cost of obtaining health care benefits through a private exchange.exchange (the “post-65 retiree health benefits”). Therefore, a 1% change in health care cost trend rates would not have a material impact on either the service and interest cost components and the postretirement benefit obligations.
In the fourth quarter of 2018, we terminated the post-65 retiree health benefits effective as of December 31, 2020. The post-65 retiree health benefits will no longer be provided after that date. In addition, the pre-65 retiree medical coverage subsidy has been frozen as of January 1, 2019, and the ability for retirees to opt in and out of this coverage, as well as pre-65 retiree dental and vision coverage, has also been eliminated. Retirees must enroll in connection with retirement for such coverage, or they lose eligibility. These plan changes reduced our retiree medical benefit obligation by approximately $99 million at December 31, 2018.
Plan investment policies and strategies – The investment policies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with applicable legal requirements; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plan'splan’s investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.
U.S. plan – The plan’s current targeted asset allocation is comprised of 55% equity securities and 45% other fixed income securities. Over time, as the plan’s funded ratio (as defined by the investment policy) improves, in order to reduce volatility in returns and to better match the plan’s liabilities, the allocation to equity securities will decrease while the amount allocated to fixed income securities will increase. The plan'splan’s assets are managed by a third-party investment manager.
International plan – Our international plan's target asset allocation is comprisedAs mentioned above, the plan covering eligible U.K. employees that was transferred to the buyer in connection with the sale of 60% equity securities and 40% fixed income securities. The plan assets are invested in eight separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers whose performance is measured independently by a third-party asset servicing consulting firm.our U.K. business during 2019.
Fair value measurements – Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 20162019 and 2015.2018.
Cash and cash equivalents – Cash and cash equivalents are valued using a market approach and are considered Level 1. This investment also includes a cash reserve account (a collective short-term investment fund) that is valued using an income approach and is considered Level 2.
Equity securities–Investments in common stock preferred stock, and real estate investment trusts ("REIT") are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership.partnership, determined using a combination of market, income and cost approaches, plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. These private equity investments are considered Level 3. Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and are therefore considered Level 1. Investments in pooled funds are valued using a market approach, at the net asset value ("NAV") of units held. Thethese various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. Theseindex and are considered Level 2.
Fixed income securities– Fixed income securities are valued using a market approach. U.S. treasury notes and exchange traded funds ("ETFs"(“ETFs”) are valued at the closing price reported in an active market and are considered Level 1. Corporate bonds, private placements, and other bondsGNMA/FNMA/FHLMC pools are valued using calculated yield curves created by models that incorporate various market factors. Primarily investments are held in U.S. and non-U.S. corporate bonds in diverse industries and are considered Level 2. Forward contracts included under government securities are traded in the over-the-counter market and occur between two parties only with no intermediary. The details of each contract such as trade size, price and maturity are tailored to each security and negotiated between the two parties, as such, these investments are considered Level 3. Other bondsfixed income investments include zero coupon and interest rate swaps. Investments in pooled funds are valued using a market
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
primarily consist of securities issued by governmental agenciesapproach, and municipalities. The investment in the commingled fund is valued using the NAV of units held and is considered Level 2. The commingled fund consists of an equity and fixed income portfolio with underlying investments held in U.S. and non-U.S. securities. Pooled funds primarily have investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds.bonds and are considered Level 2.
Other – Other investments are comprised ofan international insurance carrier contract and the majority of the underlying investments consist of a mix of non-U.S. publicly traded equity securities valued at the closing price reported in an active market and fixed income securities valued using calculated yield curves. This asset is considered Level 2. The other investments, an unallocated annuity contract, two limited liability companies, and real estateestate. All are considered Level 3, as significant inputs to determine fair value are unobservable.
Commingled funds – The investment in the commingled funds are valued using the net asset value of units held as a practical expedient. The commingled funds consist of equity and fixed income portfolios with underlying investments held in U.S. and non-U.S. securities.
The following tables present the fair values of our defined benefit pension plan'splan’s assets, by level within the fair value hierarchy, as of December 31, 20162019 and 2015.2018.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2016 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l |
| Cash and cash equivalents | $ | 8 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8 |
| | $ | 5 |
|
| Equity securities: | | | | | | | | | | | | | | | |
| Common and preferred stock | 82 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 82 |
| | — |
|
| REIT and private equity | — |
| | — |
| | — |
| | — |
| | 20 |
| | — |
| | 20 |
| | — |
|
| Mutual and pooled funds | — |
| | 201 |
| | — |
| | 159 |
| | — |
| | — |
| | — |
| | 360 |
|
| Fixed income securities: | | | | | | | | | | | | | | | |
| U.S. treasury notes and ETFs | 11 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 11 |
| | — |
|
| Corporate and other bonds | — |
| | — |
| | 60 |
| | — |
| | — |
| | — |
| | 60 |
| | — |
|
| Pooled funds | — |
| | — |
| | 11 |
| | 230 |
| | — |
| | — |
| | 11 |
| | 230 |
|
| REIT and swaps | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 21 |
| | — |
|
| Total investments, at fair value | 101 |
| | 206 |
| | 71 |
| | 389 |
| | 41 |
| | — |
| | 213 |
| | 595 |
|
Commingled funds (a) | | | | | | | | | | | | | 14 |
| | — |
|
| Total investments | $ | 101 |
| | $ | 206 |
| | $ | 71 |
| | $ | 389 |
| | $ | 41 |
| | $ | — |
| | $ | 227 |
| | $ | 595 |
|
|
| | | | | | | | | | | | | | | |
| | December 31, 2019 |
| (In millions) | Level 1 | Level 2 | Level 3 | Total |
Cash and cash equivalents(a) | $ | (7 | ) | | $ | — |
| | $ | — |
| | $ | (7 | ) |
| Equity securities: | | | | | | | |
| Common stock | 75 |
| | — |
| | — |
| | 75 |
|
| Private equity | — |
| | — |
| | 10 |
| | 10 |
|
| Pooled funds | — |
| | — |
| | — |
| | — |
|
| Fixed income securities: | | | | | | | |
| Corporate | — |
| | 2 |
| | — |
| | 2 |
|
| Exchange traded funds | 3 |
| | — |
| | — |
| | 3 |
|
| Government | 31 |
| | 11 |
| | 5 |
| | 47 |
|
| Pooled funds | — |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | 18 |
| | 18 |
|
| Total investments, at fair value | 102 |
| | 13 |
| | 33 |
| | 148 |
|
Commingled funds(b) | — |
| | — |
| | — |
| | 88 |
|
| Total investments | $ | 102 |
| | $ | 13 |
| | $ | 33 |
| | $ | 236 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2018 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l |
Cash and cash equivalents(a) | $ | (1 | ) | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | 5 |
|
| Equity securities: | | | | | | | | | | | | | | | |
| Common stock | 75 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 75 |
| | — |
|
| Private equity | — |
| | — |
| | — |
| | — |
| | 14 |
| | — |
| | 14 |
| | — |
|
| Pooled funds | — |
| | — |
| | — |
| | 191 |
| | — |
| | — |
| | — |
| | 191 |
|
| Fixed income securities: | | | | | | | | | | | | | | | |
| Corporate | — |
| | — |
| | 4 |
| | — |
| | — |
| | — |
| | 4 |
| | — |
|
| Government | 22 |
| | — |
| | 9 |
| | — |
| | 3 |
| | — |
| | 34 |
| | — |
|
| Pooled funds | — |
| | — |
| | — |
| | 398 |
| | — |
| | — |
| | — |
| | 398 |
|
| Other | — |
| | — |
| | — |
| | — |
| | 17 |
| | — |
| | 17 |
| | — |
|
| Total investments, at fair value | 96 |
| | 5 |
| | 13 |
| | 589 |
| | 34 |
| | — |
| | 143 |
| | 594 |
|
Commingled funds(b) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
|
| Total investments | $ | 96 |
| | $ | 5 |
| | $ | 13 |
| | $ | 589 |
| | $ | 34 |
| | $ | — |
| | $ | 203 |
| | $ | 594 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2015 |
| (In millions) | Level 1 | | Level 2 | | Level 3 | | Total |
| U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l | | U.S. | | Int’l |
| Cash and cash equivalents | $ | 47 |
| | $ | 6 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 48 |
| | $ | 6 |
|
| Equity securities: | | | | | | | | | | | | | | | |
| Common and preferred stock | 115 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 115 |
| | — |
|
| REIT and private equity | 1 |
| | — |
| | — |
| | — |
| | 23 |
| | — |
| | 24 |
| | — |
|
| Mutual and pooled funds | — |
| | 218 |
| | — |
| | 152 |
| | — |
| | — |
| | — |
| | 370 |
|
| Fixed income securities: | | | | | | | | | | | | | | | |
| U.S. treasury notes and ETFs | 12 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | — |
|
| Corporate and other bonds | — |
| | — |
| | 105 |
| | — |
| | — |
| | — |
| | 105 |
| | — |
|
| Pooled funds | — |
| | — |
| | — |
| | 232 |
| | — |
| | — |
| | — |
| | 232 |
|
| REIT and Swaps | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 25 |
| | — |
| | 25 |
| | — |
|
| Total investments, at fair value | 175 |
| | 224 |
| | 108 |
| | 384 |
| | 48 |
| | — |
| | 331 |
| | 608 |
|
Commingled funds (a) | | | | | | | | | | | | | 23 |
| | — |
|
| Total investments | $ | 175 |
| | $ | 224 |
| | $ | 108 |
| | $ | 384 |
| | $ | 48 |
| | $ | — |
| | $ | 354 |
| | $ | 608 |
|
| |
(a) | The negative cash balance was due to the timing of when investment trades occur and when they settle. |
| |
(b) | After the adoption of the FASB update for the fair value hierarchy, we separately report the investments for which fair value was measured using the net asset value per share as a practical expedient. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. See Note 2 for further information on the FASB update. |
The activity during the year ended December 31, 20162019 and 2015,2018, for the assets using Level 3 fair value measurements was immaterial.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Cash flows
Estimated future benefit payments– The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 20162019 and reflect expected future services, as appropriate, are to be paid in the years indicated.
|
| | | | | | | | | | | |
| | Pension Benefits | | Other Benefits |
| (In millions) | U.S. | | Int’l | | U.S. |
| 2017 | $ | 34 |
| | $ | 17 |
| | $ | 21 |
|
| 2018 | 35 |
| | 17 |
| | 21 |
|
| 2019 | 34 |
| | 18 |
| | 20 |
|
| 2020 | 35 |
| | 18 |
| | 19 |
|
| 2021 | 34 |
| | 20 |
| | 19 |
|
| 2022 through 2025 | 163 |
| | 116 |
| | 78 |
|
|
| | | | | | | |
| (In millions) | Pension Benefits | | Other Benefits |
| 2020 | $ | 39 |
| | $ | 18 |
|
| 2021 | 35 |
| | 10 |
|
| 2022 | 31 |
| | 9 |
|
| 2023 | 29 |
| | 8 |
|
| 2024 | 27 |
| | 7 |
|
| 2025 through 2029 | 116 |
| | 25 |
|
Contributions to defined benefit plans – We expect to make contributions to the funded pension plansplan of up to $60$28 million in 2017.2020. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $5$6 million and $21$18 million in 2017.2020.
Contributions to defined contribution plans– We contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $18 million, $22 million and $20 million $20 millionin 2019, 2018 and $25 million in 2016, 2015 and 2014.
2017.
21. Incentive Based Compensation
Description of stock-based compensation plans – The Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 Plan") was approved by our stockholders in May 2016 and authorizes the Compensation Committee of the Board of Directors to grant stock options, SARs, stock awards (including restricted stock and restricted stock unit awards) and performance unit awards to employees. The 2016 Plan also allows us to provide equity compensation to our non-employee directors. No more than 55 million shares of our common stock may be issued under the 2016 Plan. For stock options and SARs, the number of shares available for issuance under the 2016 Plan will be reduced by one share for each share of our common stock in respect of which the award is granted. For stock awards (including restricted stock and restricted stock unit awards), the number of shares available for issuance under the 2016 Plan will be reduced by 2.41 shares for each share of our common stock in respect of which the award is granted.
Shares subject to awards under the 2016 Plan that are forfeited, are terminated or expire unexercised become available for future grants. In addition, the number of shares of our common stock reserved for issuance under the 2016 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2016 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.
After approval of the 2016 Plan, no new grants were or will be made from any prior plans. Any awards previously granted under any prior plans shall continue to be exercisable in accordance with their original terms and conditions.
Stock-based awards under the plans
Stock options – We grant stock options under the 2016 Plan. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. In general, our stock options vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.
SARs - At December 31, 2016, there are no SARs outstanding.
Restricted stock – We grant restricted stock under the 2016 Plan. The restricted stock awards granted to officers generally vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest ratably over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares of restricted stock are not transferable and are held by our transfer agent.
Stock-based performance units – We grant stock-based performance units to officers under the 2016 Plan. At the grant date, each unit represents the value of one share of our common stock. These units are settled in cash, and the amount of the payment is based on (1) the vesting percentage, which can be from zero to 200% based on performance achieved and (2) the
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
value of our common stock on the date vesting is determined by the Compensation Committee of the Board of Directors. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of our Board of Directors. Dividend equivalents may accrue during the performance period and would be paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.
Restricted stock units – We maintain an equity compensation program for our non-employee directors under the 2016 Plan. All non-employee directors receive annual grants of common stock units. Common shares will generally be issued for units granted on or after January 1, 2012 following completion of board service or three years from the date of grant, whichever is earlier. Directors may elect to defer units granted in 2017 or subsequent years until after completion of board service. Any units granted prior to 2012 must be held until completion of board service, at which time the non-employee director will receive common shares. We also grant restricted stock units to certain non-officer international employees which generally vest ratably over a three-year period, contingent on the recipient's continued employment. Grants of restricted stock units to these non-officer international employees are based on their performance and for retention purposes. Common shares will be issued for these restricted stock units after vesting. Prior to vesting, recipients of restricted stock units typically receive dividend equivalent payments, but they may not vote.
Total stock-based compensation expense – Total employee stock-based compensation expense was $51 million, $57 million and $70 million in 2016, 2015 and 2014, while the total related income tax benefits were $19 million, $20 million and $25 million in the same years. In 2016, 2015 and 2014, cash received upon exercise of stock option awards was $1 million, $9 million and $136 million. Tax benefits realized for deductions for stock awards settled during 2014 totaled $51 million. There were no tax benefits realized for deductions for stock awards settled during 2015 and 2016.
Stock option awards – During 2016 and 2015, we granted stock option awards to officer employees. During 2014, we granted stock option awards to both officer and non-officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:
|
| | | | | | | | |
| 2016 | | 2015 | | 2014 |
| Exercise price per share | $7.22 | | $29.06 | | $34.49 |
| Expected annual dividend yield | 2.8 | % | | 2.9 | % | | 2.3 | % |
| Expected life in years | 6.3 |
| | 6.2 |
| | 5.9 |
|
| Expected volatility | 36 | % | | 32 | % | | 38 | % |
| Risk-free interest rate | 1.4 | % | | 1.7 | % | | 1.8 | % |
| Weighted average grant date fair value of stock option awards granted | $1.97 | | $6.84 | | $10.50 |
The following is a summary of stock option award activity in 2016.
|
| | | | | | | | | | |
| | Number | | Weighted Average | | Weighted Average Remaining | | Average Intrinsic Value |
| | of Shares | | Exercise Price | | Contractual Term | | (in millions) |
| Outstanding at beginning of year | 12,665,419 | | $29.97 | | | | |
| Granted | 1,680,000 | | $7.22 | | | | |
| Exercised | (46,191) | | $17.44 | | | | |
| Canceled | (2,383,695) | | $25.47 | | | | |
| Outstanding at end of year | 11,915,533 | | $27.71 | | 4 years | | $ | — |
|
| Exercisable at end of year | 9,856,556 |
| | $30.15 | | 3 years | | $ | — |
|
| Expected to vest | 2,051,140 |
| | $16.05 | | 9 years | | $ | — |
|
The intrinsic value of stock option awards exercised during 2015 and 2014 were $6 million and $83 million. The intrinsic value in 2016 is not material.
As of December 31, 2016, unrecognized compensation cost related to stock option awards was $3 million, which is expected to be recognized over a weighted average period of one year.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Restricted stock awards and restricted stock units – The following is a summary of restricted stock and restricted stock unit award activity in 2016.
|
| | | | |
| | Awards | | Weighted Average Grant Date Fair Value |
| Unvested at beginning of year | 4,017,344 |
| | $30.76 |
| Granted | 5,725,655 |
| | $8.57 |
| Vested & Exercised | (1,498,431 | ) | | $31.67 |
| Canceled | (1,311,035 | ) | | $19.13 |
| Unvested at end of year | 6,933,533 |
| | $14.44 |
The vesting date fair value of restricted stock awards which vested during 2016, 2015 and 2014 was $16 million, $26 million and $70 million. The weighted average grant date fair value of restricted stock awards was $14.44, $30.76 and $34.04 for awards unvested at December 31, 2016, 2015 and 2014.
As of December 31, 2016 there was $63 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of one year.
Stock-based performance unit awards – During 2016, 2015 and 2014 we granted 1,205,517, 382,335 and 221,491 stock-based performance unit awards to officers. At December 31, 2016, there were 1,249,719 units outstanding. Total stock-based performance unit awards expense was $6 million in both 2016 and 2014. We had no stock-based performance unit awards expense in 2015.
The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units granted in 2016, 2015 and 2014 were:
|
| | | | | | | |
| | 2016 | | 2015 | | 2014 (a) |
| Valuation date stock price | $17.31 | | $17.31 | | n/a |
| Expected annual dividend yield | 1.1 | % | | 1.1 | % | | n/a |
| Expected volatility | 58 | % | | 68 | % | | n/a |
| Risk-free interest rate | 1.3 | % | | 0.9 | % | | n/a |
| Fair value of stock-based performance units outstanding | $19.37 | | $11.17 | | n/a |
(a)As of December 31, 2016, there were no 2014 performance unit awards outstanding.
22.20. Reclassifications Out of Accumulated Other Comprehensive LossIncome (Loss)
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:income (loss):
|
| | | | | | | | |
| | Year Ended December 31, | | |
| (In millions) | 2016 | 2015 | | Income Statement Line |
| Postretirement and postemployment plans | | | |
| Amortization of actuarial loss | $ | (14 | ) | $ | (24 | ) | | General and administrative |
| Net settlement loss | (103 | ) | (119 | ) | | General and administrative |
| Net curtailment gain | — |
| 8 |
| | General and administrative |
| Derivative hedges | | | | |
| Ineffective portion of derivative hedge | 4 |
| — |
| | Net interest and other |
| | (113 | ) | (135 | ) | | Income (loss) from operations |
| | 41 |
| 51 |
| | Benefit for income taxes |
| Total reclassifications to expense | $ | (72 | ) | $ | (84 | ) | | Net income (loss) |
|
| | | | | | | | |
| | Year Ended December 31, | |
| (In millions) | 2019 | | 2018 | Income Statement Line |
| Postretirement and postemployment plans | | | | |
| Amortization of prior service credit | $ | 26 |
| | $ | 18 |
| Other net periodic benefit costs |
| Amortization of actuarial loss | (8 | ) | | (12 | ) | Other net periodic benefit costs |
| Net settlement loss, net of tax | (12 | ) | | (20 | ) | Other net periodic benefit costs |
| | 6 |
| | (14 | ) | |
| Other |
| |
| |
U.K pension plan transferred to buyer (a)(b) | 83 |
| | — |
| |
Foreign currency translation adjustment related to sale of U.K. business(b) | 30 |
| | — |
| |
Income taxes related to sale of U.K. business (b) | (45 | ) | | — |
| |
| | 68 |
| | — |
| Net gain on disposal of assets |
| Other insignificant items, net of tax | 1 |
| | — |
| Net interest and other |
| Total reclassifications to expense, net of tax | $ | 75 |
| | $ | (14 | ) | Net income (loss) |
| |
(a) | See Note 19for detailon the U.K. pension plan. |
| |
(b) | See Note 5 for detail on the U.K. disposition. |
23. Stockholders’ Equity
In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
21. Supplemental Cash Flow Information
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | | 2017 |
| Included in operating activities: | | | | | |
| Interest paid, net of amounts capitalized | $ | 269 |
| | $ | 270 |
| | $ | 379 |
|
Income taxes paid to taxing authorities, net of refunds received(a) | 73 |
| | 287 |
| | 391 |
|
| Noncash investing activities, related to continuing operations: | | | | | |
| Increase (decrease) in asset retirement costs | $ | 80 |
| | $ | (183 | ) | | $ | (202 | ) |
Asset retirement obligations assumed by buyer(b) | 1,082 |
| | 82 |
| | 14 |
|
| Notes receivable for disposition of assets | — |
| | — |
| | 748 |
|
| |
(a) | 2019, 2018 and 2017 includes $90 million, $37 million and $1 million, related to tax refunds. 2017 included a payment of $108 million made to the U.K. tax authorities to preserve our appeal rights, see Note 25 for additional discussion. |
| |
(b) | In 2019, our dispositions include the sale of the Droshky field (Gulf of Mexico), the sale of our non-operated interest in the Atrush block in Kurdistan and the sale of our U.K. business. See Note 5 for further detail on dispositions. |
Other noncash investing activities include accrued capital expenditures as of December 31, 2019, 2018 and 2017 of $288 million, $250 million and$329 million.
22. Other Items
Net interest and other
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | | 2017 |
| Interest: | | | | | |
| Interest income | $ | 25 |
| | $ | 32 |
| | $ | 34 |
|
| Interest expense | (280 | ) | | (280 | ) | | (380 | ) |
| Income on interest rate swaps | — |
| | — |
| | 53 |
|
| Interest capitalized | — |
| | — |
| | 3 |
|
| Total interest | (255 | ) | | (248 | ) | | (290 | ) |
| Other: | | | | | |
| Net foreign currency gain (loss) | 4 |
| | 9 |
| | 8 |
|
| Other | 7 |
| | 13 |
| | 12 |
|
| Total other | 11 |
| | 22 |
| | 20 |
|
| Net interest and other | $ | (244 | ) | | $ | (226 | ) | | $ | (270 | ) |
Foreign currency– Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2019 | | 2018 | | 2017 |
| Net interest and other | $ | 4 |
| | $ | 9 |
| | $ | 8 |
|
| Provision for income taxes | 2 |
| | 10 |
| | 57 |
|
| Aggregate foreign currency gains | $ | 6 |
| | $ | 19 |
| | $ | 65 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
There23. Equity Method Investments
During 2019, 2018 and 2017 our equity method investees were noconsidered related parties and included:
EGHoldings, in which we have a 60% noncontrolling interest. EGHoldings is engaged in LNG production activity.
•Alba Plant LLC, in which we have a 52% noncontrolling interest. Alba Plant LLC processes LPG.
AMPCO, in which we have a 45% noncontrolling interest. AMPCO is engaged in methanol production activity.
Our equity method investments are summarized in the following table:
|
| | | | | | | | | |
| | Ownership as of | | December 31, |
| (In millions) | December 31, 2019 | | 2019 | | 2018 |
| EGHoldings | 60% | | $ | 310 |
| | $ | 402 |
|
| Alba Plant LLC | 52% | | 163 |
| | 167 |
|
| AMPCO | 45% | | 190 |
| | 176 |
|
| Total | | | $ | 663 |
| | $ | 745 |
|
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $105 million in 2019, $270 million in 2018 and $276 million in 2017.
Summarized financial information for equity method investees is as follows:
|
| | | | | | | | | | | |
| (In millions) | 2019 | | 2018 | | 2017 |
| Income data – year: | | | | | |
| Revenues and other income | $ | 832 |
| | $ | 1,269 |
| | $ | 1,294 |
|
| Income from operations | 250 |
| | 588 |
| | 631 |
|
| Net income | 187 |
| | 459 |
| | 508 |
|
| Balance sheet data – December 31: | | | | | |
| Current assets | $ | 455 |
| | $ | 559 |
| | |
| Noncurrent assets | 1,049 |
| | 931 |
| | |
| Current liabilities | 284 |
| | 253 |
| | |
| Noncurrent liabilities | 183 |
| | 87 |
| | |
Revenues from related parties were $42 million, $48 million and $60 million in 2019, 2018 and 2017, respectively, with the majority related to EGHoldings in all years. We had 0 purchases from related parties during both 2019 and 2018, and $132 million in 2017, with the majority related to Alba Plant LLC.
Current receivables from related parties at December 31, 2019 and 2018 were $28 million and $25 million, with the majority related to EGHoldings and Alba Plant LLC for 2019 and EGHoldings in 2018. Payables to related parties were $11 million and $15 million at December 31, 2019 and 2018, respectively, with the majority related to Alba Plant LLC.
24. Stockholders’ Equity
On July 31, 2019, the Board of Directors authorized an extension of the share repurchases during 2016 or 2015. In 2014repurchase program, which increased the remaining share repurchase authorization to $1.5 billion. During 2019, we acquired 29approximately 24 million of common shares at a cost of $1 billion under our share repurchase program, initially authorized in 2006, bringing our total repurchases to 121$345 million, which were held as treasury stock. During 2018, we acquired 36 million of common shares at a cost of $4.7 billion.$700 million under the same program. As of December 31, 20162019 the total remaining share repurchase authorization was $1.5$1.4 billion. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations or proceeds from potential asset sales or cash from available borrowings to acquire shares.sales. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables.
24. LeasesMARATHON OIL CORPORATION
We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for capital lease obligations and for operating lease obligations having noncancellable lease terms in excess of one year are as follows:
Notes to Consolidated Financial Statements
|
| | | | | | | |
| (In millions) | Capital Lease Obligations | | Operating Lease Obligations |
| 2017 | $ | 2 |
| | $ | 28 |
|
| 2018 | 1 |
| | 28 |
|
| 2019 | 1 |
| | 27 |
|
| 2020 | 1 |
| | 27 |
|
| 2021 | 1 |
| | 26 |
|
| Later years | 15 |
| | 19 |
|
| Sublease rentals | — |
| | — |
|
| Total minimum lease payments | $ | 21 |
| | $ | 155 |
|
| Less imputed interest costs | (12 | ) | | |
| Present value of net minimum lease payments | $ | 9 |
| | |
Operating lease rental expense related to continuing operations was $93 million, $104 million and $120 million in 2016, 2015 and 2014.
25. Commitments and Contingencies
Following the sale of our U.K. business to RockRose, we continued to hold outstanding surety bonds which guaranteed our decommissioning liabilities related to the Marathon Oil U.K. LLC assets. We issued these surety bonds in November 2018 with a notional value of approximately £92 million and an expiration date of December 31, 2019. RockRose was contractually required to post a replacement security to cover 2020 by no later than December 1, 2019. During the third quarter of 2019, we recorded a $6 million liability and corresponding expense related to the estimated fair value of our exposure to surety bonds. In November 2019, RockRose posted replacement security and accordingly, we reversed the aforementioned $6 million. See Note 5for discussion of the U.K. sale in further detail. In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly-owned subsidiary, signed a series of agreements to process third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G. MEGPL is a signatory to the agreements related to our equity method investee, Alba Plant LLC. These agreements contain clauses that cause MEGPL to indemnify the owners of the Alen Unit against actions or inaction by Alba Plant LLC. Pursuant to these agreements, MEGPL agreed to indemnify third party property or events, including environmental assessments, injury to Alba Plant LLC’s personnel, and damage to or loss of Alba Plant LLC’s automobiles. At this time, we cannot reasonably estimate this obligation as we do not have any history of prior indemnification claims, as completion of the plant modifications is not expected to finish until 2021, and as such, we do not have any history of environmental discharge or contamination. Therefore, we have not recorded a liability with respect to these indemnification clauses since the amount of potential future payments under such guarantees is not determinable.
We are routinely undergoing examination of our U.S. federal income tax returns by the IRS. With the closure of the 2010-2011 IRS Audit referenced in Note 8, these audits have been completed through the 2016 tax year with the exception of the following item. During the third quarter of 2017, we received a partnership adjustment notification related to the 2010 and 2011 tax years, for which we filed a Tax Court Petition in the fourth quarter of 2017. During the third quarter of 2019, we received the court decision which ruled in our favor for all material items. At December 31, 2019, all issues have been effectively settled related to the partnership audit. Various groups, including the State of North Dakota and three Indian tribes represented by the Bureau of Indian Affairs, have been involved in a dispute regarding the ownership of certain lands underlying the Missouri River and Little Missouri River. As a result, as of December 31, 2019, we have recorded a $93 million liability in suspended royalty and working interest revenue, including interest, and have recorded a long-term receivable of $20 million for capital and expenses.
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.
Environmental matters – We are subjecthave incurred and will continue to federal, state, localincur capital, operating and foreignmaintenance, and remediation expenditures as a result of environmental laws and regulations relating toregulations. If these expenditures, as with all costs, are not ultimately offset by the environment.prices we receive for our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.
At December 31, 20162019 and 2015,2018, accrued liabilities for remediation were not significant.material. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.
Guarantees– We have entered into a performance guarantee related to asset retirement obligations with aggregate maximum potential undiscounted payments totaling $30 million as of December 31, 2016. Under the terms of this guarantee arrangement, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements.
Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Contract commitments – At December 31, 20162019 and 2015,2018, contractual commitments to acquire property, plant and equipment totaled $144$41 million and $371$57 million.
In connection with the sale of our operated producing properties in the greater Ewing Bank area and non-operated producing interests in the Petronius and Neptune fields in the Gulf of Mexico, we retained an overriding royalty interest in the properties. As part of the sale agreement, proceeds associated with the production of our override up to $70were $46 million as of December 31, 2019, and are dedicated solely to the satisfaction of the corresponding future abandonment obligations of the properties. The term of our override ends once sales proceeds equal $70 million.
Select Quarterly Financial Data (Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2016 | | 2015 |
| (In millions, except per share data) | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. | | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. |
| Revenues | $ | 772 |
| | $ | 959 |
| | $ | 1,100 |
| | $ | 1,200 |
| | $ | 1,484 |
| | $ | 1,490 |
| | $ | 1,384 |
| | $ | 1,164 |
|
Income (loss) before income taxes (a) | (683 | ) | | (238 | ) | | (290 | ) | | (24 | ) | | (420 | ) | | (392 | ) | | (1,145 | ) | | (1,001 | ) |
Net income (loss) (b) | $ | (407 | ) | | $ | (170 | ) | | $ | (192 | ) | | $ | (1,371 | ) | | $ | (276 | ) | | $ | (386 | ) | | $ | (749 | ) | | $ | (793 | ) |
| | | | | | | | | | | | | | | | |
| Basic net income (loss) per share | ($0.56) | | ($0.20) | | ($0.23) | | ($1.62) | | ($0.41) | | ($0.57) | | ($1.11) | | ($1.17) |
| Diluted net income (loss) per share | ($0.56) | | ($0.20) | | ($0.23) | | ($1.62) | | ($0.41) | | ($0.57) | | ($1.11) | | ($1.17) |
| Dividends paid per share | $0.05 | | $0.05 | | $0.05 | | $0.05 | | $0.21 | | $0.21 | | $0.21 | | $0.05 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | |
(In millions, except per share data) | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. | | 1st Qtr. | | 2nd Qtr. | | 3rd Qtr. | | 4th Qtr. | |
| Revenues from contracts with customers | $ | 1,200 |
| | $ | 1,381 |
| | $ | 1,249 |
| | $ | 1,233 |
| | $ | 1,537 |
| | $ | 1,447 |
| | $ | 1,538 |
| | $ | 1,380 |
| |
| Income (loss) before income taxes | 27 |
| (a) | 193 |
| | 175 |
| | (3 | ) | (a) | 524 |
| | 140 |
| | 357 |
| | 406 |
| (b) |
| Net income (loss) | $ | 174 |
| | $ | 161 |
| | $ | 165 |
| | $ | (20 | ) | | $ | 356 |
| | $ | 96 |
| | $ | 254 |
| | $ | 390 |
| |
| | | | | | | | | | | | | | | | | |
| Income (loss) per basic and diluted share: | | | | | | | | | | | | | | | | |
| Net income (loss) | $ | 0.21 |
| | $ | 0.20 |
| | $ | 0.21 |
| | $ | (0.03 | ) | | $ | 0.42 |
| | $ | 0.11 |
| | $ | 0.30 |
| | $ | 0.47 |
| |
| Dividends paid per share | $ | 0.05 |
| | $ | 0.05 |
| | $ | 0.05 |
| | $ | 0.05 |
| | $ | 0.05 |
| | $ | 0.05 |
| | $ | 0.05 |
| | $ | 0.05 |
| |
| |
(a) | Includes impairments to producing properties of $47 million in the thirdThe first and fourth quarter of 2016, $282019 includes mark-to-market loss on commodity derivatives of $113 million in the 4thand $55 million. |
| |
(b) | The fourth quarter of 2015, $3332018 includes a mark-to-market gain on commodity derivatives of $336 million in the third quarter of 2015, and $44 million in the second quarter of 2015. Also includes unproved property impairments and exploratory dry well costs of $118 million in the second quarter of 2016, $302$49 million in the fourth quarter of 2015, and $553 million in the third quarter of 2015 (see2018. (See Item 8. Financial Statements and Supplementary Data – - Note 1311 to the consolidated financial statements). IncludesAdditionally, the first quarter of 2018 includes a goodwill impairmentgain on sale of $340 million in 2015 related to the N.A. E&P reporting unit. (seeour Libya subsidiary of $255 million. (See Item 8. Financial Statements and Supplementary Data – - Note 145 to the consolidated financial statements). |
| |
(b)
| Includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million in the fourth quarter of 2016 (see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements). |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
The supplementary information is disclosed by the following geographic areas: the U.S.; Canada; E.G.; Other Africa, which primarily includes activities in Gabon, Kenya, Ethiopia and Libya; and Other International ("(“Other Int’l"Int’l”), which includes the U.K., Gabon and the Kurdistan Region of Iraq. For further details on our dispositions that affect the information included in this supplemental information, see Note 5. Preparation of Reserve Estimates
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Crude oil and condensate, NGLs, natural gas and our historical synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group (“CRG”), which includes our Director of Corporate Reserves and his staff of Reserve Coordinators. Crude oil and condensate, NGLs and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators (“QREs”). QREs are petro-technical professionals located throughout our organization who meet the qualifications we have established for employees engaged in estimating reserves and resources. QREs have the education, experience, and training necessary to estimate reserves and resources in a manner consistent with all external reserve estimation regulations and internal resource estimation directives and practices. QREs generally hold at least a Bachelor of Science degree in the appropriate technical field, have a minimum of five years of industry experience with at least three years in reserve estimation and have completed our QRE training course. All reserves changes (including proved) must be approved by our CRG. Additionally, any change to proved reserve estimates in excess of 5 mmboe on a total field basis, within a single month, must be approved by the Director of Corporate Reserves.
The 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 New Mexico. In his 33 years with Marathon Oil, he has held numerous engineering and management positions, including managing reservoir engineering and geoscience for our Eagle Ford development in South Texas. He is a 25 year member of the Society of Petroleum Engineers (“SPE”).
Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The observed statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves.
Audits of Estimates
We closedhave established a robust series of internal controls, policies and processes intended to ensure the salequality and accuracy of our Angola assetsinternal reserve estimates. We also engage third-party consultants to audit our estimates of proved reserves. Our policy requires that audits are provided for fields that comprise at least 80% of our total proved reserves over a rolling four-year period, adjusted for dispositions. We conduct our audits on a one-year in arrears basis and accordingly, our third-party consultants have not yet performed any audits of our reserve estimates for the year-ended December 31, 2019. In calculating our proved reserve audit coverage percentage, we only include the most recent year a field was audited within the rolling four-year period. To illustrate, our third-party proved reserve audits conducted during 2019 were for reserve estimates as of December 31, 2018 and covered reserves in Oklahoma (284 mmboe) and Eagle Ford (386 mmboe). The reserve audits conducted during 2018 were for reserve estimates as of December 31, 2017 and included reserves in Bakken (321 mmboe), which is reflected net of 2018 production in calculating our audit coverage as of December 31, 2019. The reserve audits conducted during 2017 were for reserve estimates as of December 31, 2016 and included reserves in Equatorial Guinea (151 mmboe), which is reflected net of 2017 and 2018 production in calculating our audit coverage as of December 31, 2019. On this basis, our third-party reserve audits covered 92% of our total proved reserves, excluding dispositions. An audit tolerance at a field level of +/- 10% to our internal estimates has been established. All audits conducted during this period fell within the established tolerance.
For the reserve estimates as of December 31, 2016, Netherland, Sewell & Associates, Inc. (“NSAI”) prepared a reserves certification for the Alba field in E.G. The NSAI summary report is filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have multiple years of industry experience, having worked for large, international oil and gas companies before joining NSAI. NSAI’s technical team members meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE. The senior technical advisor has over 15 years of practical experience in petroleum engineering and the estimation and evaluation of reserves and is a registered Professional Engineer in the State of Texas. The second team member has over 13 years of practical experience in petroleum geosciences and is a licensed Professional Geoscientist in the State of Texas.
Ryder Scott Company performed audits for reserve estimates of our fields as of December 31, 2018 and 2017. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 37 years of industry experience, having worked for a major financial advisory services group before joining Ryder Scott. He is a 25 year member of SPE and is a registered Professional Engineer in the State of Texas.
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
EstimatedQuantities of Proved Oil and Gas Reserves
The estimation of net recoverable quantities of crude oil and condensate, NGLs, natural gas and our Norway businesshistorical synthetic crude oil is a highly technical process which is based upon several underlying assumptions that are subject to change. Proved reserves are determined using “SEC Pricing”, calculated as an unweighted arithmetic average of the first-day-of-the-month closing price for each month. As discussed in 2014,Item 1A. Risk Factors and bothItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates, commodity prices are shown as discontinued operations ("Disc Ops")volatile which can have an impact on proved reserves. If crude oil prices in prior periods.the future average below prices used to determine proved reserves at December 31, 2019, it could have an adverse effect on our estimates of proved reserve volumes and the value of our business. Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation, among other things. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors (including future crude oil price and performance revisions). The table below provides the 2019 SEC pricing for certain benchmark prices:
|
| | | |
| | 2019 SEC Pricing |
WTI Crude oil (per bbl) | $ | 55.69 |
|
Henry Hub natural gas (per mmbtu) | $ | 2.58 |
|
Brent crude oil (per bbl) | $ | 63.15 |
|
Mont Belvieu NGLs (per bbl) | $ | 18.41 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves
The estimation of net recoverable quantities of crude oil and condensate, natural gas liquids, natural gas and synthetic crude oil is a highly technical process which is based upon several underlying assumptions that are subject to change. Proved reserves are determined using "SEC Pricing", calculated as an unweighted arithmetic average of the first-day-of-the-month closing price for each month. If commodity pricing were to significantly drop-below average prices used to estimate 2016 proved reserves (see table below), we would expect price related reserve revisions that could have a material impact on proved reserve volumes and the present value of our proved reserves. In this scenario, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserve or resource category. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Critical Accounting Estimates – Estimated Quantities of Net Reserves for the table providing our 2016 SEC pricing of benchmark prices and the underlying assumptions used. For a discussion of our reserve estimation process, including the use of third-party audits, see Item 1. Business – Reserves.
The table below provides the 2016 SEC pricing for certain benchmark prices: |
| | | |
| | SEC Pricing 2016 |
WTI Crude oil (per bbl) | $ | 42.75 |
|
Henry Hub natural gas (per mmbtu) | $ | 2.49 |
|
Brent crude oil (per bbl) | $ | 43.53 |
|
Mont Belvieu NGLs (per bbl) | $ | 15.89 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves
|
| | | | | | | | | | | | | | | | | | | | | | | |
| (mmbbl) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Other Int'l | | Cont Ops | | Disc Ops | | Total |
| Crude oil and condensate | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2014 | 497 |
| | — |
| | 64 |
| | 215 |
| | 25 |
| | 801 |
| | 91 |
| | 892 |
|
| Revisions of previous estimates | 36 |
| | — |
| | (1 | ) | | (4 | ) | | 1 |
| | 32 |
| | 10 |
| | 42 |
|
| Improved recovery | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Purchases of reserves in place | 6 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| | — |
| | 6 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | | |
| other additions | 153 |
| | — |
| | 1 |
| | — |
| | 7 |
| | 161 |
| | 3 |
| | 164 |
|
| Production | (57 | ) | | — |
| | (7 | ) | | (3 | ) | | (4 | ) | | (71 | ) | | (17 | ) | | (88 | ) |
| Sales of reserves in place | (3 | ) | | — |
| | — |
| | — |
| | — |
| | (3 | ) | | (87 | ) | | (90 | ) |
| End of year - 2014 | 634 |
| | — |
| | 57 |
| | 208 |
| | 29 |
| | 928 |
| | — |
| | 928 |
|
| Revisions of previous estimates | (109 | ) | | — |
| | 2 |
| | (7 | ) | | (2 | ) | | (116 | ) | | — |
| | (116 | ) |
| Improved recovery | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Purchases of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 122 |
| | — |
| | — |
| | — |
| | — |
| | 122 |
| | — |
| | 122 |
|
| Production | (62 | ) | | — |
| | (7 | ) | | — |
| | (5 | ) | | (74 | ) | | — |
| | (74 | ) |
| Sales of reserves in place | (6 | ) | | — |
| | — |
| | — |
| | — |
| | (6 | ) | | — |
| | (6 | ) |
| End of year - 2015 | 580 |
| | — |
| | 52 |
| | 201 |
| | 22 |
| | 855 |
| | — |
| | 855 |
|
| Revisions of previous estimates | (97 | ) | | — |
| | 1 |
| | (28 | ) | | 3 |
| | (121 | ) | | — |
| | (121 | ) |
| Improved recovery | 4 |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
| Purchases of reserves in place | 12 |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | 12 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 189 |
| | — |
| | — |
| | — |
| | 1 |
| | 190 |
| | — |
| | 190 |
|
| Production | (48 | ) | | — |
| | (8 | ) | | (1 | ) | | (4 | ) | | (61 | ) | | — |
| | (61 | ) |
| Sales of reserves in place | (77 | ) | | — |
| | — |
| | — |
| | — |
| | (77 | ) | | — |
| | (77 | ) |
| End of year - 2016 | 563 |
| | — |
| | 45 |
| | 172 |
| | 22 |
| | 802 |
| | — |
| | 802 |
|
| Proved developed reserves: | | | | | | | | | | | | | | | |
| Beginning of year - 2014 | 241 |
| | — |
| | 37 |
| | 176 |
| | 19 |
| | 473 |
| | 77 |
| | 550 |
|
| End of year - 2014 | 294 |
| | — |
| | 30 |
| | 175 |
| | 19 |
| | 518 |
| | — |
| | 518 |
|
| End of year - 2015 | 327 |
| | — |
| | 25 |
| | 173 |
| | 16 |
| | 541 |
| | — |
| | 541 |
|
| End of year - 2016 | 238 |
| | — |
| | 45 |
| | 172 |
| | 13 |
| | 468 |
| | — |
| | 468 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | | | |
| Beginning of year - 2014 | 256 |
| | — |
| | 27 |
| | 39 |
| | 6 |
| | 328 |
| | 14 |
| | 342 |
|
| End of year - 2014 | 340 |
| | — |
| | 27 |
| | 33 |
| | 10 |
| | 410 |
| | — |
| | 410 |
|
| End of year - 2015 | 253 |
| | — |
| | 27 |
| | 28 |
| | 6 |
| | 314 |
| | — |
| | 314 |
|
| End of year - 2016 | 325 |
| | — |
| | — |
| | — |
| | 9 |
| | 334 |
| | — |
| | 334 |
|
|
| | | | | | | | | | | | | | |
| (mmbbl) | U.S. | | E.G.(a) | | Libya(b) | | Other Int'l(c) | | Cont Ops(d) |
| Crude oil and condensate | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2017 | 563 |
| | 45 |
| | 172 |
| | 22 |
| | 802 |
|
| Revisions of previous estimates | 9 |
| | (2 | ) | | — |
| | 8 |
| | 15 |
|
| Purchases of reserves in place | 18 |
| | — |
| | — |
| | — |
| | 18 |
|
| Extensions, discoveries and other additions | 30 |
| | 4 |
| | — |
| | — |
| | 34 |
|
| Production | (49 | ) | | (8 | ) | | (7 | ) | | (4 | ) | | (68 | ) |
| Sales of reserves in place | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| End of year - 2017 | 570 |
| | 39 |
| | 165 |
| | 26 |
| | 800 |
|
| Revisions of previous estimates | 49 |
| | 3 |
| | — |
| | 3 |
| | 55 |
|
| Extensions, discoveries and other additions | 42 |
| | — |
| | — |
| | 2 |
| | 44 |
|
| Production | (63 | ) | | (6 | ) | | (3 | ) | | (5 | ) | | (77 | ) |
| Sales of reserves in place | (3 | ) | | — |
| | (162 | ) | | (1 | ) | | (166 | ) |
| End of year - 2018 | 595 |
| | 36 |
| | — |
| | 25 |
| | 656 |
|
| Revisions of previous estimates | 34 |
| | 3 |
| | — |
| | — |
| | 37 |
|
| Purchases of reserves in place | 9 |
| | — |
| | — |
| | — |
| | 9 |
|
| Extensions, discoveries and other additions | 53 |
| | — |
| | — |
| | — |
| | 53 |
|
| Production | (69 | ) | | (6 | ) | | — |
| | (2 | ) | | (77 | ) |
| Sales of reserves in place | (3 | ) | | — |
| | — |
| | (23 | ) | | (26 | ) |
| End of year - 2019 | 619 |
| | 33 |
| | — |
| | — |
| | 652 |
|
| Proved developed reserves: | | | | | | | | | |
| Beginning of year - 2017 | 238 |
| | 45 |
| | 172 |
| | 13 |
| | 468 |
|
| End of year - 2017 | 263 |
| | 39 |
| | 165 |
| | 17 |
| | 484 |
|
| End of year - 2018 | 287 |
| | 36 |
| | — |
| | 22 |
| | 345 |
|
| End of year - 2019 | 304 |
| | 30 |
| | — |
| | — |
| | 334 |
|
| Proved undeveloped reserves: | | | | | | | | | |
| Beginning of year - 2017 | 325 |
| | — |
| | — |
| | 9 |
| | 334 |
|
| End of year - 2017 | 307 |
| | — |
| | — |
| | 9 |
| | 316 |
|
| End of year - 2018 | 308 |
| | — |
| | — |
| | 3 |
| | 311 |
|
| End of year - 2019 | 315 |
| | 3 |
| | — |
| | — |
| | 318 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| (mmbbl) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Other Int'l | | Cont Ops | | Disc Ops | | Total |
| Natural gas liquids | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2014 | 119 |
| | — |
| | 34 |
| | — |
| | 1 |
| | 154 |
| | — |
| | 154 |
|
| Revisions of previous estimates | 4 |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 48 |
| | — |
| | — |
| | — |
| | — |
| | 48 |
| | — |
| | 48 |
|
| Production | (11 | ) | | — |
| | (4 | ) | | — |
| | — |
| | (15 | ) | | — |
| | (15 | ) |
| Sales of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2014 | 161 |
| | — |
| | 30 |
| | — |
| | 1 |
| | 192 |
| | — |
| | 192 |
|
| Revisions of previous estimates | (31 | ) | | — |
| | 2 |
| | — |
| | (1 | ) | | (30 | ) | | — |
| | (30 | ) |
| Improved recovery | — |
| | — |
| | — |
| | — |
| | | | — |
| | — |
| | — |
|
| Purchases of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 57 |
| | — |
| | — |
| | — |
| | — |
| | 57 |
| | — |
| | 57 |
|
| Production | (14 | ) | | — |
| | (4 | ) | | — |
| | — |
| | (18 | ) | | — |
| | (18 | ) |
| Sales of reserves in place | (1 | ) | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| End of year - 2015 | 172 |
| | — |
|
| 28 |
|
| — |
|
| — |
|
| 200 |
|
| — |
|
| 200 |
|
| Revisions of previous estimates | (51 | ) | | — |
| | — |
| | — |
| | — |
| | (51 | ) | | — |
| | (51 | ) |
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | 12 |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | 12 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 54 |
| | — |
| | — |
| | — |
| | — |
| | 54 |
| | — |
| | 54 |
|
| Production | (14 | ) | | — |
| | (4 | ) | | — |
| | — |
| | (18 | ) | | — |
| | (18 | ) |
| Sales of reserves in place | (3 | ) | | — |
| | — |
| | — |
| | — |
| | (3 | ) | | — |
| | (3 | ) |
| End of year - 2016 | 170 |
| | — |
| | 24 |
| | — |
| | — |
| | 194 |
| | — |
| | 194 |
|
| Proved developed reserves: | | | | | | | | | | | | | | | |
| Beginning of year - 2014 | 51 |
| | — |
| | 18 |
| | — |
| | 1 |
| | 70 |
| | — |
| | 70 |
|
| End of year - 2014 | 68 |
| | — |
| | 15 |
| | — |
| | — |
| | 83 |
| | — |
| | 83 |
|
| End of year - 2015 | 92 |
| | — |
| | 12 |
| | — |
| | — |
| | 104 |
| | — |
| | 104 |
|
| End of year - 2016 | 78 |
| | — |
| | 24 |
| | — |
| | — |
| | 102 |
| | — |
| | 102 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | | | |
| Beginning of year - 2014 | 68 |
| | — |
| | 16 |
| | — |
| | — |
| | 84 |
| | — |
| | 84 |
|
| End of year - 2014 | 93 |
| | — |
| | 15 |
| | — |
| | 1 |
| | 109 |
| | — |
| | 109 |
|
| End of year - 2015 | 80 |
| | — |
| | 16 |
| | — |
| | — |
| | 96 |
| | — |
| | 96 |
|
| End of year - 2016 | 92 |
| | — |
| | — |
| | — |
| | — |
| | 92 |
| | — |
| | 92 |
|
|
| | | | | | | | | | | | | | |
| (mmbbl) | U.S. | | E.G.(a) | | Libya(b) | | Other Int'l(c) | | Cont Ops(d) |
| Natural gas liquids | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2017 | 170 |
| | 24 |
| | — |
| | — |
| | 194 |
|
| Revisions of previous estimates | 37 |
| | 3 |
| | — |
| | — |
| | 40 |
|
| Purchases of reserves in place | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
| Extensions, discoveries and other additions | 34 |
| | 2 |
| | — |
| | — |
| | 36 |
|
| Production | (16 | ) | | (4 | ) | | — |
| | — |
| | (20 | ) |
| Sales of reserves in place | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| End of year - 2017 | 229 |
| | 25 |
| | — |
| | — |
| | 254 |
|
| Revisions of previous estimates | (9 | ) | | 1 |
| | — |
| | — |
| | (8 | ) |
| Extensions, discoveries and other additions | 25 |
| | — |
| | — |
| | — |
| | 25 |
|
| Production | (20 | ) | | (4 | ) | | — |
| | — |
| | (24 | ) |
| Sales of reserves in place | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| End of year - 2018 | 224 |
| | 22 |
| | — |
| | — |
| | 246 |
|
| Revisions of previous estimates | (21 | ) | | 2 |
| | — |
| | — |
| | (19 | ) |
| Purchases of reserves in place | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
| Extensions, discoveries and other additions | 19 |
| | — |
| | — |
| | — |
| | 19 |
|
| Production | (22 | ) | | (3 | ) | | — |
| | — |
| | (25 | ) |
| Sales of reserves in place | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| End of year - 2019 | 204 |
| | 21 |
| | — |
| | — |
| | 225 |
|
| Proved developed reserves: | | | | | | | | | |
| Beginning of year - 2017 | 78 |
| | 24 |
| | — |
| | — |
| | 102 |
|
| End of year - 2017 | 118 |
| | 25 |
| | — |
| | — |
| | 143 |
|
| End of year - 2018 | 119 |
| | 22 |
| | — |
| | — |
| | 141 |
|
| End of year - 2019 | 122 |
| | 19 |
| | — |
| | — |
| | 141 |
|
| Proved undeveloped reserves: | | | | | | | | | |
| Beginning of year - 2017 | 92 |
| | — |
| | — |
| | — |
| | 92 |
|
| End of year - 2017 | 111 |
| | — |
| | — |
| | — |
| | 111 |
|
| End of year - 2018 | 105 |
| | — |
| | — |
| | — |
| | 105 |
|
| End of year - 2019 | 82 |
| | 2 |
| | — |
| | — |
| | 84 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| (bcf) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Other Int'l | | Cont Ops | | Disc Ops | | Total |
| Natural gas | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2014 | 1,025 |
| | — |
| | 1,320 |
| | 205 |
| | 28 |
| | 2,578 |
| | 93 |
| | 2,671 |
|
| Revisions of previous estimates | (24 | ) | | — |
| | 1 |
| | 5 |
| | 2 |
| | (16 | ) | | 7 |
| | (9 | ) |
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | 5 |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 290 |
| | — |
| | 44 |
| | — |
| | — |
| | 334 |
| | 2 |
| | 336 |
|
Production(b) | (113 | ) | | — |
| | (160 | ) | | (1 | ) | | (8 | ) | | (282 | ) | | (13 | ) | | (295 | ) |
| Sales of reserves in place | (39 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) | | (89 | ) | | (128 | ) |
| End of year - 2014 | 1,144 |
| | — |
| | 1,205 |
| | 209 |
| | 22 |
| | 2,580 |
| | — |
| | 2,580 |
|
| Revisions of previous estimates | (191 | ) | | — |
| | 35 |
| | (3 | ) | | 1 |
| | (158 | ) | | — |
| | (158 | ) |
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 394 |
| | — |
| | — |
| | — |
| | — |
| | 394 |
| | — |
| | 394 |
|
Production(b) | (128 | ) | | — |
| | (150 | ) | | — |
| | (8 | ) | | (286 | ) | | — |
| | (286 | ) |
| Sales of reserves in place | (69 | ) | | — |
| | — |
| | — |
| | — |
| | (69 | ) | | — |
| | (69 | ) |
| End of year - 2015 | 1,151 |
| | — |
| | 1,090 |
| | 206 |
| | 15 |
| | 2,462 |
| | — |
| | 2,462 |
|
| Revisions of previous estimates | (146 | ) | | — |
| | 8 |
| | (1 | ) | | 3 |
| | (136 | ) | | — |
| | (136 | ) |
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | 61 |
| | — |
| | — |
| | — |
| | — |
| | 61 |
| | — |
| | 61 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 362 |
| | — |
| | — |
| | — |
| | — |
| | 362 |
| | — |
| | 362 |
|
Production(b) | (115 | ) | | — |
| | (155 | ) | | — |
| | (8 | ) | | (278 | ) | | — |
| | (278 | ) |
| Sales of reserves in place | (25 | ) | | — |
| | — |
| | — |
| | — |
| | (25 | ) | | — |
| | (25 | ) |
| End of year - 2016 | 1,288 |
| | — |
| | 943 |
| | 205 |
| | 10 |
| | 2,446 |
| | — |
| | 2,446 |
|
| Proved developed reserves: | | | | | | | | | | | | | | |
|
| Beginning of year - 2014 | 540 |
| | — |
| | 823 |
| | 95 |
| | 21 |
| | 1,479 |
| | 20 |
| | 1,499 |
|
| End of year - 2014 | 575 |
| | — |
| | 664 |
| | 94 |
| | 17 |
| | 1,350 |
| | — |
| | 1,350 |
|
| End of year - 2015 | 640 |
| | — |
| | 552 |
| | 94 |
| | 11 |
| | 1,297 |
| | — |
| | 1,297 |
|
| End of year - 2016 | 648 |
| | — |
| | 943 |
| | 95 |
| | 5 |
| | 1,691 |
| | ��� |
| | 1,691 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | | |
|
| Beginning of year - 2014 | 485 |
| | — |
| | 497 |
| | 110 |
| | 7 |
| | 1,099 |
| | 73 |
| | 1,172 |
|
| End of year - 2014 | 569 |
| | — |
| | 541 |
| | 115 |
| | 5 |
| | 1,230 |
| | — |
| | 1,230 |
|
| End of year - 2015 | 511 |
| | — |
| | 538 |
| | 112 |
| | 4 |
| | 1,165 |
| | — |
| | 1,165 |
|
| End of year - 2016 | 640 |
| | — |
| | — |
| | 110 |
| | 5 |
| | 755 |
| | — |
| | 755 |
|
|
| | | | | | | | | | | | | | |
| (bcf) | U.S. | | E.G.(a) | | Libya(b) | | Other Int'l(c) | | Cont Ops(d) |
| Natural gas | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2017 | 1,288 |
| | 943 |
| | 205 |
| | 10 |
| | 2,446 |
|
| Revisions of previous estimates | (33 | ) | | (18 | ) | | — |
| | 4 |
| | (47 | ) |
| Purchases of reserves in place | 36 |
| | — |
| | — |
| | — |
| | 36 |
|
| Extensions, discoveries and other additions | 204 |
| | 76 |
| | — |
| | — |
| | 280 |
|
Production(e) | (127 | ) | | (168 | ) | | (1 | ) | | (6 | ) | | (302 | ) |
| Sales of reserves in place | (44 | ) | | — |
| | — |
| | — |
| | (44 | ) |
| End of year - 2017 | 1,324 |
| | 833 |
| | 204 |
| | 8 |
| | 2,369 |
|
| Revisions of previous estimates | 188 |
| | 35 |
| | — |
| | 4 |
| | 227 |
|
| Extensions, discoveries and other additions | 198 |
| | — |
| | — |
| | — |
| | 198 |
|
Production(e) | (156 | ) | | (153 | ) | | (1 | ) | | (5 | ) | | (315 | ) |
| Sales of reserves in place | (1 | ) | | — |
| | (203 | ) | | — |
| | (204 | ) |
| End of year - 2018 | 1,553 |
| | 715 |
| | — |
| | 7 |
| | 2,275 |
|
| Revisions of previous estimates | (223 | ) | | 108 |
| | — |
| | — |
| | (115 | ) |
| Purchases of reserves in place | 28 |
| | — |
| | — |
| | — |
| | 28 |
|
| Extensions, discoveries and other additions | 118 |
| | — |
| | — |
| | — |
| | 118 |
|
Production(e) | (160 | ) | | (133 | ) | | — |
| | (3 | ) | | (296 | ) |
| Sales of reserves in place | (38 | ) | | — |
| | — |
| | (4 | ) | | (42 | ) |
| End of year - 2019 | 1,278 |
| | 690 |
| | — |
| | — |
| | 1,968 |
|
| Proved developed reserves: | | | | | | | | | |
| Beginning of year - 2017 | 648 |
| | 943 |
| | 95 |
| | 5 |
| | 1,691 |
|
| End of year - 2017 | 726 |
| | 833 |
| | 94 |
| | 2 |
| | 1,655 |
|
| End of year - 2018 | 869 |
| | 715 |
| | — |
| | 7 |
| | 1,591 |
|
| End of year - 2019 | 825 |
| | 649 |
| | — |
| | — |
| | 1,474 |
|
| Proved undeveloped reserves: | | | | | | | | | |
| Beginning of year - 2017 | 640 |
| | — |
| | 110 |
| | 5 |
| | 755 |
|
| End of year - 2017 | 598 |
| | — |
| | 110 |
| | 6 |
| | 714 |
|
| End of year - 2018 | 684 |
| | — |
| | — |
| | — |
| | 684 |
|
| End of year - 2019 | 453 |
| | 41 |
| | — |
| | — |
| | 494 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| (mmbbl) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Other Int'l | | Cont Ops | | Disc Ops | | Total |
| Synthetic crude oil | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2014 | — |
| | 680 |
| | — |
| | — |
| | — |
| | 680 |
| | — |
| | 680 |
|
| Revisions of previous estimates | — |
| | (55 | ) | | — |
| | — |
| | — |
| | (55 | ) | | — |
| | (55 | ) |
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | — |
| | 38 |
| | — |
| | — |
| | — |
| | 38 |
| | — |
| | 38 |
|
| Extensions, discoveries and | | | | | | | | | | | | | | | |
| other additions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Production | — |
| | (15 | ) | | — |
| | — |
| | — |
| | (15 | ) | | — |
| | (15 | ) |
| Sales of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2014 | — |
| | 648 |
| | — |
| | — |
| | — |
| | 648 |
| | — |
| | 648 |
|
| Revisions of previous estimates | — |
| | 67 |
| | — |
| | — |
| | — |
| | 67 |
| | — |
| | 67 |
|
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Extensions, discoveries and | | | | | | | | | | | | | | | |
| other additions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Production | — |
| | (17 | ) | | — |
| | — |
| | — |
| | (17 | ) | | — |
| | (17 | ) |
| Sales of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2015 | — |
| | 698 |
| | — |
| | — |
| | — |
| | 698 |
| | — |
| | 698 |
|
| Revisions of previous estimates | — |
| | 12 |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | 12 |
|
| Improved recovery | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchases of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Extensions, discoveries and | | | | | | | | | | | | | | | — |
|
| other additions | — |
| | — |
| | — |
| | — |
| | | | | | — |
| | — |
|
| Production | — |
| | (18 | ) | | — |
| | — |
| | — |
| | (18 | ) | | — |
| | (18 | ) |
| Sales of reserves in place | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2016 | — |
| | 692 |
| | — |
| | — |
| | — |
| | 692 |
| | — |
| | 692 |
|
| Proved developed reserves: | | | | | | | | | | | | | | | |
| Beginning of year - 2014 | — |
| | 674 |
| | — |
| | — |
| | — |
| | 674 |
| | — |
| | 674 |
|
| End of year - 2014 | — |
| | 644 |
| | — |
| | — |
| | — |
| | 644 |
| | — |
| | 644 |
|
| End of year - 2015 | — |
| | 698 |
| | — |
| | — |
| | — |
| | 698 |
| | — |
| | 698 |
|
| End of year - 2016 | — |
| | 692 |
| | — |
| | — |
| | — |
| | 692 |
| | — |
| | 692 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | | | |
| Beginning of year - 2014 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2014 | — |
| | 4 |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
| End of year - 2015 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| End of year - 2016 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
|
| | |
| (mmbbl) | Disc Ops |
| Synthetic crude oil | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2017 | 692 |
|
| Production | (7 | ) |
| Sales of reserves in place | (685 | ) |
| End of year - 2017 | — |
|
| Proved developed reserves: | |
| Beginning of year - 2017 | 692 |
|
| End of year - 2017 | — |
|
| Proved undeveloped reserves: | |
| Beginning of year - 2017 | — |
|
| End of year - 2017 | — |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| (mmboe) | U.S. | | Canada | | E.G.(a) | | Other Africa | | Other Int'l | | Cont Ops | | Disc Ops | | Total |
| Total Proved Reserves | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2014 | 787 |
| | 680 |
| | 318 |
| | 249 |
| | 31 |
| | 2,065 |
| | 106 |
| | 2,171 |
|
| Revisions of previous estimates | 36 |
| | (55 | ) | | — |
| | (3 | ) | | — |
| | (22 | ) | | 11 |
| | (11 | ) |
| Improved recovery | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Purchases of reserves in place | 8 |
| | 38 |
| | — |
| | — |
| | — |
| | 46 |
| | — |
| | 46 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 250 |
| | — |
| | 8 |
| | — |
| | 7 |
| | 265 |
| | 3 |
| | 268 |
|
Production(b) | (87 | ) | | (15 | ) | | (38 | ) | | (3 | ) | | (5 | ) | | (148 | ) | | (19 | ) | | (167 | ) |
| Sales of reserves in place | (10 | ) | | — |
| | — |
| | — |
| | | | (10 | ) | | (101 | ) | | (111 | ) |
| End of year - 2014 | 986 |
| | 648 |
| | 288 |
| | 243 |
| | 33 |
| | 2,198 |
| | — |
| | 2,198 |
|
| Revisions of previous estimates | (173 | ) | | 67 |
| | 8 |
| | (8 | ) | | (2 | ) | | (108 | ) | | — |
| | (108 | ) |
| Improved recovery | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Purchases of reserves in place | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | | — |
|
| other additions | 245 |
| | — |
| | 1 |
| | — |
| | — |
| | 246 |
| | — |
| | 246 |
|
Production(b) | (98 | ) | | (17 | ) | | (36 | ) | | — |
| | (6 | ) | | (157 | ) | | — |
| | (157 | ) |
| Sales of reserves in place | (18 | ) | | — |
| | — |
| | — |
| | — |
| | (18 | ) | | — |
| | (18 | ) |
| End of year - 2015 | 944 |
| | 698 |
| | 261 |
| | 235 |
| | 25 |
| | 2,163 |
| | — |
| | 2,163 |
|
| Revisions of previous estimates | (171 | ) | | 12 |
| | 2 |
| | (28 | ) | | 4 |
| | (181 | ) | | — |
| | (181 | ) |
| Improved recovery | 4 |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
| Purchases of reserves in place | 34 |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | — |
| | 34 |
|
| Extensions, discoveries and | | | | | | | | |
|
| |
|
| | | |
|
|
| other additions | 303 |
| | — |
| | — |
| | — |
| | 1 |
| | 304 |
| | — |
| | 304 |
|
Production(b) | (82 | ) | | (18 | ) | | (37 | ) | | (1 | ) | | (6 | ) | | (144 | ) | | — |
| | (144 | ) |
| Sales of reserves in place | (84 | ) | | — |
| | — |
| | — |
| | — |
| | (84 | ) | | — |
| | (84 | ) |
| End of year - 2016 | 948 |
| | 692 |
|
| 226 |
|
| 206 |
|
| 24 |
| | 2,096 |
| | — |
|
| 2,096 |
|
| Proved developed reserves: | | | | | | | | | | | | | | | |
| Beginning of year - 2014 | 382 |
| | 674 |
| | 193 |
| | 192 |
| | 23 |
| | 1,464 |
| | 80 |
| | 1,544 |
|
| End of year - 2014 | 458 |
| | 644 |
| | 155 |
| | 191 |
| | 22 |
| | 1,470 |
| | — |
| | 1,470 |
|
| End of year - 2015 | 526 |
| | 698 |
| | 129 |
| | 189 |
| | 18 |
| | 1,560 |
| | — |
| | 1,560 |
|
| End of year - 2016 | 424 |
| | 692 |
| | 226 |
| | 188 |
| | 14 |
| | 1,544 |
| | — |
| | 1,544 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | | |
|
| Beginning of year - 2014 | 405 |
| | 6 |
| | 125 |
| | 57 |
| | 8 |
| | 601 |
| | 26 |
| | 627 |
|
| End of year - 2014 | 528 |
| | 4 |
| | 133 |
| | 52 |
| | 11 |
| | 728 |
| | — |
| | 728 |
|
| End of year - 2015 | 418 |
| | — |
| | 132 |
| | 46 |
| | 7 |
| | 603 |
| | — |
| | 603 |
|
| End of year - 2016 | 524 |
| | — |
| | — |
| | 18 |
| | 10 |
| | 552 |
| | — |
| | 552 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| (mmboe) | U.S. | | E.G.(a) | | Libya(b) | | Other Int'l(c) | | Cont Ops(d) | | Disc Ops | | Total |
| Total Proved Reserves | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: |
| Beginning of year - 2017 | 948 |
| | 226 |
| | 206 |
| | 24 |
| | 1,404 |
| | 692 |
| | 2,096 |
|
| Revisions of previous estimates | 42 |
| | (1 | ) | | — |
| | 8 |
| | 49 |
| | — |
| | 49 |
|
| Purchases of reserves in place | 28 |
| | — |
| | — |
| | — |
| | 28 |
| | — |
| | 28 |
|
Extensions, discoveries and
other additions | 98 |
| | 18 |
| | — |
| | — |
| | 116 |
| | — |
| | 116 |
|
Production(e) | (86 | ) | | (40 | ) | | (7 | ) | | (5 | ) | | (138 | ) | | (7 | ) | | (145 | ) |
| Sales of reserves in place | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) | | (685 | ) | | (695 | ) |
| End of year - 2017 | 1,020 |
| | 203 |
| | 199 |
| | 27 |
| | 1,449 |
| | — |
| | 1,449 |
|
| Revisions of previous estimates | 71 |
| | 8 |
| | — |
| | 5 |
| | 84 |
| | — |
| | 84 |
|
Extensions, discoveries and
other additions | 100 |
| | — |
| | — |
| | 2 |
| | 102 |
| | — |
| | 102 |
|
Production(e) | (109 | ) | | (35 | ) | | (3 | ) | | (6 | ) | | (153 | ) | | — |
| | (153 | ) |
| Sales of reserves in place | (4 | ) | | — |
| | (196 | ) | | (1 | ) | | (201 | ) | | — |
| | (201 | ) |
| End of year - 2018 | 1,078 |
| | 176 |
| | — |
| | 27 |
| | 1,281 |
| | — |
| | 1,281 |
|
| Revisions of previous estimates | (23 | ) | | 24 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Purchases of reserves in place | 18 |
| | — |
| | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
Extensions, discoveries and
other additions | 91 |
| | — |
| | — |
| | — |
| | 91 |
| | — |
| | 91 |
|
Production(e) | (117 | ) | | (31 | ) | | — |
| | (3 | ) | | (151 | ) | | — |
| | (151 | ) |
| Sales of reserves in place | (11 | ) | | — |
| | — |
| | (24 | ) | | (35 | ) | | — |
| | (35 | ) |
| End of year - 2019 | 1,036 |
| | 169 |
| | — |
| | — |
| | 1,205 |
| | — |
| | 1,205 |
|
| Proved developed reserves: | | | | | | | | | | | | | |
| Beginning of year - 2017 | 424 |
| | 226 |
| | 188 |
| | 14 |
| | 852 |
| | 692 |
| | 1,544 |
|
| End of year - 2017 | 502 |
| | 203 |
| | 181 |
| | 17 |
| | 903 |
| | — |
| | 903 |
|
| End of year - 2018 | 552 |
| | 176 |
| | — |
| | 24 |
| | 752 |
| | — |
| | 752 |
|
| End of year - 2019 | 563 |
| | 158 |
| | — |
| | — |
| | 721 |
| | — |
| | 721 |
|
| Proved undeveloped reserves: | | | | | | | | | | | | | |
| Beginning of year - 2017 | 524 |
| | — |
| | 18 |
| | 10 |
| | 552 |
| | — |
| | 552 |
|
| End of year - 2017 | 518 |
| | — |
| | 18 |
| | 10 |
| | 546 |
| | — |
| | 546 |
|
| End of year - 2018 | 526 |
| | — |
| | — |
| | 3 |
| | 529 |
| | — |
| | 529 |
|
| End of year - 2019 | 473 |
| | 11 |
| | — |
| | — |
| | 484 |
| | — |
| | 484 |
|
| |
(a) | Consists of estimated reserves from properties governed by production sharing contracts. |
| |
(b) | In 2018, we closed on the sale of our subsidiary, Marathon Oil Libya Limited. |
| |
(c) | In 2019, we closed on the sale of our U.K. business and our non-operated interested in the Atrush block of Kurdistan. These volumes are reflected in Other Int’l in the tables above for the periods presented. |
| |
(d) | Continuing operations (“Cont Ops”) excludes the sale of our Canada business which was reflected as discontinued operations (“Disc Ops”) in 2017. Proved reserves in our Canada business consisted entirely of synthetic crude oil. |
| |
(e) | Excludes the resale of purchased natural gas used in reservoir management. |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
20162019 proved reserves decreased by 6776 mmboe primarily due to the following:
| |
| • | Revisions of previous estimates:Increased by 1 mmboe as referenced below: |
Increases:
Revisions of previous estimates: Decrease of 181•20 mmboe associated with wells to sales that were additions to the plan
•11 mmboe associated with planned compression in E.G.
•11 mmboe due primarily to 93technical revisions in E.G.
Decreases:
•24 mmboe of revisiondue to reduced commodity pricing
•12 mmboe due to technical revisions in the U.S. resource plays
•5 mmboe due to changes in the 5-year plan in the U.S. resource plays
| |
| • | Purchases of reserves in place:Increased by 18 mmboe due to the acquisition in the Eagle Ford. |
| |
| • | Extensions, discoveries, and other additions:Increased by 91 mmboe in the U.S. resource plays as referenced below: |
Increases:
•53 mmboe associated with the deferralexpansion of lower economic valueproved areas
•38 mmboe associated with wells to sales from unproved categories
| |
| • | Production: Decreased by 151 mmboe. |
| |
| • | Sales of reserves in place:Decreased by 35 mmboe as referenced below: |
Decreases:
•19 mmboe associated with the sale of assets in the U.K.
•11 mmboe associated with divestitures of certain U.S. unconventional resource plays outsideassets
•5 mmboe associated with the sale of the 5-year plan and a decrease of 64Atrush block in Kurdistan
2018 proved reserves decreased by 168 mmboe primarily due to U.S. technical reevaluations.the following:
| |
| • | Revisions of previous estimates: Increased by 84 mmboe as referenced below: |
Increases:
Extensions, discoveries, and other additions: Increased by 308108 mmboe primarily in our U.S unconventional resource plays associated with the acceleration of higher economic wells in the U.S. resource plays into the 5-year plan
•15 mmboe associated with wells to sales that were additions to the plan
Decreases:
•39 mmboe due to technical revisions across the business
| |
| • | Extensions, discoveries, and other additions: Increased by 102 mmboe primarily in the U.S. resource plays as referenced below: |
Increases:
•69 mmboe associated with the expansion of proved areas in Oklahoma, and new
•33 mmboe associated with wells to sales from unproved categories.categories
| |
| • | Production: Decreased by 153 mmboe. |
| |
| • | Sales of reserves in place:Decreased by 201 mmboe as referenced below: |
Decreases:
Purchases of reserves in place: Acquisition of STACK assets in Oklahoma.
Production: Decrease of 144 mmboe.
Sales of reserves in place: Decrease of 84•196 mmboe associated with the sale of our subsidiary in Libya
•4 mmboe associated with divestitures of our Wyomingcertain conventional assets in New Mexico and certain GulfMichigan
•1 mmboe associated with the sale of Mexico assets. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information regarding these dispositions.
Sarsang block in Kurdistan
2015 total2017 proved reserves decreased by 35647 mmboe primarily due to the following:
| |
| • | Revisions of previous estimates:Increased by 49 mmboe as referenced below: |
Revisions of previous estimates: Decrease of 173 mmboe which was largely due to reductions to our capital development program and adherence to the SEC 5-year rule and partially offset by a positive revision of 67 mmboe in OSM due to technical reevaluation and lower royalty percentages related to lower realized prices. Royalties paid in Canada are determined on a progressive scale; as the sales price of our synthetic crude oil rises, the royalty rate rises as well.
Increases:Extensions, discoveries, and other additions: Increased 245•44 mmboe as a result of drilling programs in our U.S. resource plays.
Production: Decrease of 157 mmboe.
Sales of reserves in place: U.S. conventional assets sales contributed to a decrease of 18 mmboe.
2014 total proved reserves increased by 27 mmboe primarily due to the following:
Revisionsacceleration of previous estimates: Negative revisions of 55 mmboe to OSM synthetic crude oil reserves were impacted by technical changes, calculation of estimated royalty volumes, and development plan changes in mineable areas. This downward revision was offset by positive revisions from U.S. resource play development activity.
Extensions, discoveries, and other additions: Increased 250 mmboe primarily as a result of development activityhigher economic wells in the U.S.Bakken into the 5-year plan
•The remainder being due to revisions across the business
| |
| • | Extensions, discoveries, and other additions: Increased by 116 mmboe primarily due to an increase of 97 mmboe associated with the expansion of proved areas and wells to sales from unproved categories in Oklahoma. |
| |
| • | Purchases of reserves in place: Increased by 28 mmboe from acquisitions of assets in the Northern Delaware Basin in New Mexico. |
| |
| • | Production:Decreased by 145 mmboe. |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
| |
| • | Sales of reserves in place: Decreased by 695 mmboe as referenced below: |
Production: Decrease of 167 mmboe.
Increases:Sales of reserves in place: Decrease of 101•685 mmboe primarily related toassociated with the sale of our assets in Norway and Angola (reflected in discontinued operations).Canadian business
| |
| • | 10 mmboe associated with divestitures of certain conventional assets in Oklahoma and Colorado. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information regarding these dispositions. |
Changes in Proved Undeveloped Reserves
As of December 31, 2016, 552 mmboe of proved undeveloped reserves were reported, a decrease of 51 mmboe from December 31, 2015. The following table shows changes in total proved undeveloped reserves for 2016:2019:
|
| | |
| (mmboe) | |
| Beginning of year | 603529 |
|
| Revisions of previous estimates | (14418 | ) |
Improved recovery | 4 |
|
| Purchases of reserves in place | 2013 |
|
| Extensions, discoveries, and other additions | 26468 |
|
| Dispositions | (145 | ) |
| Transfers to proved developed | (181139 | ) |
| End of year | 552484 |
|
Revisions of prior estimates. Revisions of prior estimates decreased 144estimates:Increased by 18 mmboe during 2016. Over half of this revision, 93as referenced below:
Increases:
•16 mmboe wasassociated with in-year drill schedule changes
•11 mmboe associated with planned compression in E.G.
Decreases:
•5 mmboe due to deferral of lower economic value wells beyondchanges in the 5-year window. The remaining revisions were driven by well performance dominated by lower secondary product volumes, which includes reduction in NGL reserves associated with ethane rejection, recognition of lower than expected performance from high density wells in Eagle Ford and various wells in Oklahoma and the removal of capital commitment from two long-term international projects.
Extensions, discoveries and other additions. Increased264 mmboe through higher planned activity levelsplan in the U.S. resource plays
•4 mmboe due to technical revisions
Extensions, discoveries and other additions:Increased by 68 mmboe associated with expansion of proved areas in Oklahoma, and acceleration of higher economic value wells into the 5-year plan.U.S. resource plays as referenced below:
Increases:
•28 mmboe in Oklahoma
Supplementary Information on Oil and Gas Producing Activities (Unaudited)•25 mmboe in Permian
•15 mmboe in Bakken
Transfers to proved developed. 181developed:139 mmboe of PUD reserves were converted to proved developed status during 2016, of which 134 mmboe is associated with the E.G. Alba compression project.2019, primarily from assets in our U.S. resource plays. This 20162019 transfer equates to a 30%26% PUD conversion rate. Ourrate and a 5-year average annual PUD conversion rate during 2012-2016the 2015-2019 period is 19% and would be 28% if the long-term projects in E.G. and Libya are excluded.of 20%. All proved undeveloped reserve drilling locations are scheduled to be drilled prior toproducing within five years of the end of 2021. No material volumes of proved undeveloped reserves have beeninitial booking date.
Supplementary Information on the books beyond 5 years as of year-end 2016.Oil and Gas Producing Activities (Unaudited)
Costs Incurred & Future Costs to Develop
Costs incurred in 2016, 20152019, 2018 and 20142017 relating to the development of proved undeveloped reserves were $359$1,261 million, $1,415$1,082 million and $3,149$842 million. As of December 31, 2016,
The following table shows future development costs estimated to be required for the development of proved undeveloped crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves for the years 2017 through 2021 are projected to be $784 million, $1,134 million, $1,665 million, $1,847 million and $809 million.future years. |
| | | |
| (In millions) | Future Development Costs |
| 2020 | $ | 1,464 |
|
| 2021 | 1,568 |
|
| 2022 | 1,562 |
|
| 2023 | 1,456 |
|
| 2024 | 913 |
|
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Other Int'l | | Total |
| 2016 Capitalized Costs: | | | | | | | | | | | |
| Proved properties | $ | 25,497 |
| | $ | 9,571 |
| | $ | 1,978 |
| | $ | 756 |
| | $ | 5,864 |
| | $ | 43,666 |
|
| Unproved properties | 1,473 |
| | 1,379 |
| | 119 |
| | 417 |
| | 183 |
| | 3,571 |
|
| Total | 26,970 |
| | 10,950 |
| | 2,097 |
| | 1,173 |
| | 6,047 |
| | 47,237 |
|
| Accumulated depreciation, | | | | | | | | | | | |
| depletion and amortization: | | | | | | | | | | | |
| Proved properties | 12,526 |
| | 1,649 |
| | 1,216 |
| | 269 |
| | 5,246 |
| | 20,906 |
|
Unproved properties (a) | 382 |
| | 310 |
| | 2 |
| | — |
| | 113 |
| | 807 |
|
| Total | 12,908 |
| | 1,959 |
| | 1,218 |
| | 269 |
| | 5,359 |
| | 21,713 |
|
| Net capitalized costs | $ | 14,062 |
| | $ | 8,991 |
| | $ | 879 |
| | $ | 904 |
| | $ | 688 |
| | $ | 25,524 |
|
| 2015 Capitalized Costs: | | | | | | | | | | | |
| Proved properties | $ | 27,816 |
| | $ | 9,538 |
| | $ | 1,955 |
| | $ | 828 |
| | $ | 5,741 |
| | $ | 45,878 |
|
| Unproved properties | 1,625 |
| | 1,389 |
| | 86 |
| | 465 |
| | 242 |
| | 3,807 |
|
| Total | 29,441 |
| | 10,927 |
| | 2,041 |
| | 1,293 |
| | 5,983 |
| | 49,685 |
|
| Accumulated depreciation, | | | | | | | | | | | |
| depletion and amortization: | | | | | | | | | | | |
| Proved properties | 13,656 |
| | 1,420 |
| | 1,105 |
| | 263 |
| | 5,195 |
| | 21,639 |
|
Unproved properties (a) | 675 |
| | 310 |
| | — |
| | 107 |
| | 114 |
| | 1,206 |
|
| Total | 14,331 |
| | 1,730 |
| | 1,105 |
| | 370 |
| | 5,309 |
| | 22,845 |
|
| Net capitalized costs | $ | 15,110 |
| | $ | 9,197 |
| | $ | 936 |
| | $ | 923 |
| | $ | 674 |
| | $ | 26,840 |
|
(a) Includes unproved property impairments (see Note 13). |
| | | | | | | | | | | | | | | |
| (In millions) | U.S. | | E.G. | | Other Int’l | | Total |
| Year Ended December 31, 2019 | | | | | | | |
| Capitalized Costs: | | | | | | | |
| Proved properties | $ | 29,250 |
| | $ | 2,042 |
| | $ | — |
| | $ | 31,292 |
|
| Unproved properties | 2,880 |
| | 12 |
| | — |
| | 2,892 |
|
| Total | 32,130 |
| | 2,054 |
| | — |
| | 34,184 |
|
| Accumulated depreciation, depletion and amortization: | | | | | | |
|
| Proved properties | 15,435 |
| | 1,568 |
| | — |
| | 17,003 |
|
Unproved properties(a) | 357 |
| | (7 | ) | | — |
| | 350 |
|
| Total | 15,792 |
| | 1,561 |
| | — |
| | 17,353 |
|
| Net capitalized costs | $ | 16,338 |
| | $ | 493 |
| | $ | — |
| | $ | 16,831 |
|
| Year Ended December 31, 2018 | | | | | | | |
| Capitalized Costs: | | | | | | |
|
| Proved properties | $ | 27,983 |
| | $ | 2,041 |
| | $ | 4,828 |
| | $ | 34,852 |
|
| Unproved properties | 2,977 |
| | 11 |
| | — |
| | 2,988 |
|
| Total | 30,960 |
| | 2,052 |
| | 4,828 |
| | 37,840 |
|
| Accumulated depreciation, depletion and amortization: | | | | | | |
|
| Proved properties | 14,742 |
| | 1,471 |
| | 4,706 |
| | 20,919 |
|
Unproved properties(a) | 299 |
| | (7 | ) | | — |
| | 292 |
|
| Total | 15,041 |
| | 1,464 |
| | 4,706 |
| | 21,211 |
|
| Net capitalized costs | $ | 15,919 |
| | $ | 588 |
| | $ | 122 |
| | $ | 16,629 |
|
| |
(a) | Includes unproved property impairments (see Note 11). |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Costs Incurred for Property Acquisition, Exploration and Development (a) | | | (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Other Int'l | | Cont Ops | | Disc Ops | | Total | U.S. | | E.G. | | Libya | | Other Int’l | | Cont Ops | | Disc Ops | | Total |
| December 31, 2016 | | | | | | | | | | | | | | | | |
| December 31, 2019 | | | | | | | | | | | | | | |
| Property acquisition: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved | $ | 276 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 276 |
| | $ | — |
| | $ | 276 |
| $ | 93 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 93 |
| | $ | — |
| | $ | 93 |
|
| Unproved | 642 |
| | — |
| | — |
| | 1 |
| | (11 | ) | | 632 |
| | — |
| | 632 |
| 282 |
| | — |
| | — |
| | — |
| | 282 |
| | — |
| | 282 |
|
| Exploration | 525 |
| | — |
| | 1 |
| | 10 |
| | 3 |
| | 539 |
| | — |
| | 539 |
| 862 |
| | — |
| | — |
| | — |
| | 862 |
| | — |
| | 862 |
|
| Development | 456 |
| | 31 |
| | 55 |
| | 3 |
| | 121 |
| (c) | 666 |
| | — |
| | 666 |
| 1,675 |
| | 1 |
| | — |
| | 23 |
| | 1,699 |
| | — |
| | 1,699 |
|
| Total | $ | 1,899 |
| | $ | 31 |
| | $ | 56 |
| | $ | 14 |
| | $ | 113 |
| | $ | 2,113 |
| | $ | — |
| | $ | 2,113 |
| $ | 2,912 |
| | $ | 1 |
| | $ | — |
| | $ | 23 |
| | $ | 2,936 |
| | $ | — |
| | $ | 2,936 |
|
| December 31, 2015 | | | | | | | | | | | | | | | | |
| December 31, 2018 | | | | | | | | | | | | | | |
| Property acquisition: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 4 |
| $ | 211 |
| | $ | — |
| | $ | — |
| | $ | 11 |
| | $ | 222 |
| | $ | — |
| | $ | 222 |
|
| Unproved | 61 |
| | — |
| | — |
| | 1 |
| | — |
| | 62 |
| | — |
| | 62 |
| 144 |
| | — |
| | — |
| | — |
| | 144 |
| | — |
| | 144 |
|
| Exploration | 959 |
| | 1 |
| | 60 |
| | 38 |
| | 50 |
| | 1,108 |
| | — |
| | 1,108 |
| 929 |
| | 1 |
| | — |
| | (9 | ) | | 921 |
| | — |
| | 921 |
|
| Development | 1,477 |
| | — |
| | 150 |
| | 13 |
| | 31 |
| (c) | 1,671 |
| | — |
| | 1,671 |
| 1,332 |
| | (2 | ) | | — |
| | (126 | ) | (b) | 1,204 |
| | — |
| | 1,204 |
|
| Total | $ | 2,501 |
| | $ | 1 |
| (b) | $ | 210 |
| | $ | 52 |
| | $ | 81 |
| | $ | 2,845 |
| | $ | — |
| | $ | 2,845 |
| $ | 2,616 |
| | $ | (1 | ) | | $ | — |
| | $ | (124 | ) | | $ | 2,491 |
| | $ | — |
| | $ | 2,491 |
|
| December 31, 2014 | | | | | | | | | | | | | | | | |
| December 31, 2017 | | | | | | | | | | | | | | |
| Property acquisition: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved | $ | 26 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 26 |
| $ | 191 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 192 |
| | $ | — |
| | $ | 192 |
|
| Unproved | 202 |
| | 3 |
| | — |
| | 53 |
| | 2 |
| | 260 |
| | 1 |
| | 261 |
| 1,746 |
| | — |
| | — |
| | 1 |
| | 1,747 |
| | — |
| | 1,747 |
|
| Exploration | 1,140 |
| | 4 |
| | 35 |
| | 119 |
| | 119 |
| | 1,417 |
| | 6 |
| | 1,423 |
| 882 |
| | 1 |
| | — |
| | 40 |
| | 923 |
| | — |
| | 923 |
|
| Development | 3,532 |
| | 196 |
| | 139 |
| | 16 |
| | 94 |
| | 3,977 |
| | 418 |
| | 4,395 |
| 1,122 |
| | 5 |
| | 10 |
| | (144 | ) | (b) | 993 |
| | 6 |
| | 999 |
|
| Total | $ | 4,900 |
| | $ | 203 |
| | $ | 174 |
| | $ | 188 |
| | $ | 215 |
| | $ | 5,680 |
| | $ | 425 |
| | $ | 6,105 |
| $ | 3,941 |
| | $ | 7 |
| | $ | 10 |
| | $ | (103 | ) | | $ | 3,855 |
| | $ | 6 |
| | $ | 3,861 |
|
| |
(a) | Includes costs incurred whether capitalized or expensed. |
| |
(b) | Reflects reimbursements earned from the governments of Canada and Alberta related to funds previously expended for Quest CCS capital equipment. |
| |
(c)
| Includes revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of these activities in the U.K.abandonment activities. |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
| | | | U.S. | | Canada | | E.G. | | Other Africa | | Other Int'l | | Cont Ops | | Disc Ops | | Total | U.S. | | E.G. | | Libya | | Other Int’l | | Cont Ops | | Disc Ops | | Total |
| Year Ended December 31, 2016 | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2019 | | | | | | | | | | | | | | |
| Revenues and other income: | | | | | | | | | | | | | | |
| Sales | | $ | 4,472 |
| | $ | 307 |
| | $ | — |
| | $ | 140 |
| | $ | 4,919 |
| | $ | — |
| | $ | 4,919 |
|
Other income(a) | | 46 |
| | — |
| | — |
| | 3 |
| | 49 |
| | — |
| | 49 |
|
| Total revenues and other income | | 4,518 |
| | 307 |
| | — |
| | 143 |
| | 4,968 |
| | — |
| | 4,968 |
|
| Expenses: | | | | | | | | | |
| | | | |
| Production costs | | (1,384 | ) | | (73 | ) | | — |
| | (71 | ) | | (1,528 | ) | | — |
| | (1,528 | ) |
Exploration expenses(b) | | (149 | ) | | — |
| | — |
| | — |
| | (149 | ) | | — |
| | (149 | ) |
Depreciation, depletion and amortization(c) | | (2,274 | ) | | (97 | ) | | — |
| | (23 | ) | | (2,394 | ) | | — |
| | (2,394 | ) |
| Technical support and other | | (38 | ) | | (9 | ) | | — |
| | (10 | ) | | (57 | ) | | — |
| | (57 | ) |
| Total expenses | | (3,845 | ) | | (179 | ) | | — |
| | (104 | ) | | (4,128 | ) | | — |
| | (4,128 | ) |
| Results before income taxes | | 673 |
| | 128 |
| | — |
| | 39 |
| | 840 |
| | — |
| | 840 |
|
| Income tax (provision) benefit | | (6 | ) | | (32 | ) | | — |
| | 12 |
| | (26 | ) | | — |
| | (26 | ) |
| Results of operations | | $ | 667 |
| | $ | 96 |
| | $ | — |
| | $ | 51 |
| | $ | 814 |
| | $ | — |
| | $ | 814 |
|
| Year Ended December 31, 2018 | | | | | | | | | |
| | | | |
| Revenues and other income: | | | | | | | | | |
| | | | |
| Sales | | $ | 4,842 |
| | $ | 383 |
| | $ | 196 |
| | $ | 402 |
| | $ | 5,823 |
| | $ | — |
| | $ | 5,823 |
|
Other income(a) | | 81 |
| | — |
| | 255 |
| | 104 |
| | 440 |
| | — |
| | 440 |
|
| Total revenues and other income | | 4,923 |
| | 383 |
| | 451 |
| | 506 |
| | 6,263 |
| | — |
| | 6,263 |
|
| Expenses: | | | | | | | | | |
| | | |
|
| Production costs | | (1,371 | ) | | (68 | ) | | (12 | ) | | (180 | ) | | (1,631 | ) | | — |
| | (1,631 | ) |
Exploration expenses(b) | | (245 | ) | | (51 | ) | | — |
| | 7 |
| | (289 | ) | | — |
| | (289 | ) |
Depreciation, depletion and amortization(c) | | (2,247 | ) | | (117 | ) | | (8 | ) | | (102 | ) | | (2,474 | ) | | — |
| | (2,474 | ) |
| Technical support and other | | (49 | ) | | (5 | ) | | — |
| | (6 | ) | | (60 | ) | | — |
| | (60 | ) |
| Total expenses | | (3,912 | ) | | (241 | ) | | (20 | ) | | (281 | ) | | (4,454 | ) | | — |
| | (4,454 | ) |
| Results before income taxes | | 1,011 |
| | 142 |
| | 431 |
| | 225 |
| | 1,809 |
| | — |
| | 1,809 |
|
| Income tax (provision) benefit | | 19 |
| | (38 | ) | | (163 | ) | | (124 | ) | | (306 | ) | | — |
| | (306 | ) |
| Results of operations | | $ | 1,030 |
| | $ | 104 |
| | $ | 268 |
| | $ | 101 |
| | $ | 1,503 |
| | $ | — |
| | $ | 1,503 |
|
| Year Ended December 31, 2017 | | | | | | | | | |
| | | | |
| Revenues and other income: | | | | | | | | | | | | | | | | | | | | | | | |
| | | | |
| Sales | $ | 2,249 |
| | $ | 724 |
| | $ | 42 |
| | $ | 54 |
| | $ | 237 |
| | $ | 3,306 |
| | $ | — |
| | $ | 3,306 |
| $ | 3,050 |
| | $ | 45 |
| | $ | 431 |
| | $ | 282 |
| | $ | 3,808 |
| | $ | 423 |
| | $ | 4,231 |
|
| Transfers | — |
| | — |
| | 291 |
| | — |
| | — |
| | 291 |
| | — |
| | 291 |
| — |
| | 344 |
| | — |
| | — |
| | 344 |
| | — |
| | 344 |
|
Other income(a) | 387 |
| | — |
| | — |
| | — |
| | 2 |
| | 389 |
| | — |
| | 389 |
| 74 |
| | — |
| | — |
| | 38 |
| | 112 |
| | (43 | ) | | 69 |
|
| Total revenues and other income | 2,636 |
| | 724 |
| | 333 |
| | 54 |
| | 239 |
| | 3,986 |
| | — |
| | 3,986 |
| 3,124 |
| | 389 |
| | 431 |
| | 320 |
| | 4,264 |
| | 380 |
| | 4,644 |
|
| Expenses: | | | | | | | | | | | | | | | | | | | | | | | |
| | | |
|
| Production costs | (952 | ) | | (544 | ) | | (81 | ) | | (36 | ) | | (140 | ) | | (1,753 | ) | | — |
| | (1,753 | ) | (985 | ) | | (84 | ) | | (44 | ) | | (152 | ) | | (1,265 | ) | | (272 | ) | | (1,537 | ) |
Exploration expenses(b) | (306 | ) | | (7 | ) | | (1 | ) | | (14 | ) | | (2 | ) | | (330 | ) | | — |
| | (330 | ) | (153 | ) | | — |
| | — |
| | (254 | ) | | (407 | ) | | — |
| | (407 | ) |
| Depreciation, depletion and | | | | | | | | |
|
| | | | | | | |
amortization(c) | (1,901 | ) | | (239 | ) | | (114 | ) | | (7 | ) | | (132 | ) | | (2,393 | ) | | — |
| | (2,393 | ) | |
Depreciation, depletion and amortization(c) | | (2,105 | ) | | (134 | ) | | (21 | ) | | (273 | ) | | (2,533 | ) | | (6,676 | ) | | (9,209 | ) |
| Technical support and other | (21 | ) | | (1 | ) | | (4 | ) | | (3 | ) | | (2 | ) | | (31 | ) | | — |
| | (31 | ) | (28 | ) | | (4 | ) | | (4 | ) | | (25 | ) | | (61 | ) | | — |
| | (61 | ) |
| Total expenses | (3,180 | ) | | (791 | ) | | (200 | ) | | (60 | ) | | (276 | ) | | (4,507 | ) | | — |
| | (4,507 | ) | (3,271 | ) | | (222 | ) | | (69 | ) | | (704 | ) | | (4,266 | ) | | (6,948 | ) | | (11,214 | ) |
| Results before income taxes | (544 | ) | | (67 | ) | | 133 |
| | (6 | ) | | (37 | ) | | (521 | ) | | — |
| | (521 | ) | (147 | ) | | 167 |
| | 362 |
| | (384 | ) | | (2 | ) | | (6,568 | ) | | (6,570 | ) |
| Income tax provision | 195 |
| | 15 |
| | (26 | ) | | (2 | ) | | 57 |
| | 239 |
| | — |
| | 239 |
| |
| Income tax (provision) benefit | | (1 | ) | | (50 | ) | | (333 | ) | | 13 |
| | (371 | ) | | 1,674 |
| | 1,303 |
|
| Results of operations | $ | (349 | ) | | $ | (52 | ) | | $ | 107 |
| | $ | (8 | ) | | $ | 20 |
| | $ | (282 | ) | | $ | — |
| | $ | (282 | ) | $ | (148 | ) | | $ | 117 |
| | $ | 29 |
| | $ | (371 | ) | | $ | (373 | ) | | $ | (4,894 | ) | | $ | (5,267 | ) |
| Year Ended December 31, 2015 | | | | | | | | | | | | | | | | |
| Revenues and other income: | | | | | | | | | | | | | | | | |
| Sales | $ | 3,374 |
| | $ | 700 |
| | $ | 40 |
| | $ | — |
| | $ | 329 |
| | $ | 4,443 |
| | $ | — |
| | $ | 4,443 |
| |
| Transfers | — |
| | — |
| | 296 |
| | — |
| | — |
| | 296 |
| | — |
| | 296 |
| |
Other income(a) | 230 |
| | — |
| | — |
| | (109 | ) | | 1 |
| | 122 |
| | — |
| | 122 |
| |
| Total revenues and other income | 3,604 |
| | 700 |
| | 336 |
| | (109 | ) | | 330 |
| | 4,861 |
| | — |
| | 4,861 |
| |
| Expenses: | | | | | | | | | | | | | | |
| |
| Production costs | (1,259 | ) | | (660 | ) | | (84 | ) | | (31 | ) | | (177 | ) | | (2,211 | ) | | — |
| | (2,211 | ) | |
Exploration expenses(b) | (750 | ) | | (348 | ) | | (41 | ) | | (36 | ) | | (143 | ) | | (1,318 | ) | | — |
| | (1,318 | ) | |
| Depreciation, depletion and | | | | | | | | |
|
| |
|
| | | | | |
amortization(c) | (2,758 | ) | | (266 | ) | | (92 | ) | | (5 | ) | | (163 | ) | | (3,284 | ) | | — |
| | (3,284 | ) | |
| Technical support and other | (47 | ) | | (2 | ) | | (6 | ) | | (2 | ) | | (3 | ) | | (60 | ) | | — |
| | (60 | ) | |
| Total expenses | (4,814 | ) | | (1,276 | ) | | (223 | ) | | (74 | ) | | (486 | ) | | (6,873 | ) | | — |
| | (6,873 | ) | |
| Results before income taxes | (1,210 | ) | | (576 | ) | | 113 |
| | (183 | ) | | (156 | ) | | (2,012 | ) | | — |
| | (2,012 | ) | |
Income tax provision (d) | 437 |
| | 31 |
| | (33 | ) | | 87 |
| | 86 |
| | 608 |
| | — |
| | 608 |
| |
| Results of operations | $ | (773 | ) | | $ | (545 | ) | | $ | 80 |
| | $ | (96 | ) | | $ | (70 | ) | | $ | (1,404 | ) | | $ | — |
| | $ | (1,404 | ) | |
| Year Ended December 31, 2014 | | | | | | | | | | | | | | | | |
| Revenues and other income: | | | | | | | | | | | | | | | | |
| Sales | $ | 5,754 |
| | $ | 1,316 |
| | $ | 43 |
| | $ | 244 |
| | $ | 440 |
| | $ | 7,797 |
| | $ | 189 |
| | $ | 7,986 |
| |
| Transfers | 3 |
| | — |
| | 588 |
| | — |
| | 3 |
| | 594 |
| | 1,848 |
| | 2,442 |
| |
Other income(a) | (85 | ) | | — |
| | — |
| | — |
| | — |
| | (85 | ) | | 1,832 |
| | 1,747 |
| |
| Total revenues and other income | 5,672 |
| | 1,316 |
| | 631 |
| | 244 |
| | 443 |
| | 8,306 |
| | 3,869 |
| | 12,175 |
| |
| Expenses: | | | | | | | | | | | | | | |
| |
| Production costs | (1,544 | ) | | (803 | ) | | (154 | ) | | (79 | ) | | (253 | ) | | (2,833 | ) | | (181 | ) | | (3,014 | ) | |
Exploration expenses(b) | (607 | ) | | (1 | ) | | (26 | ) | | (103 | ) | | (56 | ) | | (793 | ) | | (5 | ) | | (798 | ) | |
| Depreciation, depletion and | | | | | | | | |
|
| |
|
| | | | — |
| |
amortization(c) | (2,474 | ) | | (206 | ) | | (93 | ) | | (9 | ) | | (115 | ) | | (2,897 | ) | | (105 | ) | | (3,002 | ) | |
| Technical support and other | (193 | ) | | (15 | ) | | (31 | ) | | (21 | ) | | (14 | ) | | (274 | ) | | (7 | ) | | (281 | ) | |
| Total expenses | (4,818 | ) | | (1,025 | ) | | (304 | ) | | (212 | ) | | (438 | ) | | (6,797 | ) | | (298 | ) | | (7,095 | ) | |
| Results before income taxes | 854 |
| | 291 |
| | 327 |
| | 32 |
| | 5 |
| | 1,509 |
| | 3,571 |
| | 5,080 |
| |
| Income tax provision | (302 | ) | | (71 | ) | | (117 | ) | | (32 | ) | | (18 | ) | | (540 | ) | | (1,496 | ) | | (2,036 | ) | |
| Results of operations | $ | 552 |
| | $ | 220 |
| | $ | 210 |
| | $ | — |
| | $ | (13 | ) | | $ | 969 |
| | $ | 2,075 |
| | $ | 3,044 |
| |
| |
(a) | Includes net gain (loss) on dispositions (see Note 6)5). In 2018 and 2017 this also includes revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of abandonment activities. |
| |
(b) | Includes exploratory dry well costs, unproved property impairments, (see Note 13).and other. |
| |
(c) | Includes long-lived asset impairments (see Note 13)11). |
(d) Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note 9).
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
The following reconciles results of operations for oil and gas producing activities to segment income:
| | | | Year Ended December 31, | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Results of operations | $ | (282 | ) | | $ | (1,404 | ) | | $ | 3,044 |
| $ | 814 |
| | $ | 1,503 |
| | $ | (5,267 | ) |
| Discontinued operations | — |
| | — |
| | (2,075 | ) | — |
| | — |
| | 4,894 |
|
| Results of continuing operations | (282 | ) | | (1,404 | ) | | 969 |
| 814 |
| | 1,503 |
| | (373 | ) |
| Items not included in results of oil and gas operations, net of tax: | | | | | | | | | | |
| Marketing income and other non-oil and gas producing related activities | (43 | ) | | (75 | ) | | 73 |
| (141 | ) | | (170 | ) | | (107 | ) |
| Income from equity method investments | 142 |
| | 127 |
| | 327 |
| 87 |
| | 214 |
| | 229 |
|
| Items not allocated to segment income, net of tax: | | | | | | | | | | |
| Loss (gain) on asset dispositions | (248 | ) | | (57 | ) | | 58 |
| |
| Loss (gain) on asset dispositions and other | | — |
| | (304 | ) | | (79 | ) |
| Long-lived asset impairments | 149 |
| | 819 |
| | 69 |
| 24 |
| | 103 |
| | 475 |
|
| Unrealized loss (gain) on derivatives | 72 |
| | (32 | ) | | — |
| 124 |
| | (265 | ) | | 81 |
|
| Alberta provincial corporate tax rate increase | — |
| | 135 |
| | — |
| |
| Foreign tax valuation allowance increase | (32 | ) | | — |
| | — |
| |
| Segment income | $ | (242 | ) | | $ | (487 | ) | | $ | 1,496 |
| $ | 908 |
| | $ | 1,081 |
| | $ | 226 |
|
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
U.S. GAAP prescribes guidelines for computing the standardized measure of future net cash flows and changes therein relating to estimated proved reserves, giving very specific assumptions to be made such as the use of a 10% discount rate and an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each month as well as current costs applicable at the date of the estimate. These and other required assumptions have not always proved accurate in the past, and other valid assumptions would give rise to substantially different results. In addition, the 10% discount rate required to be used 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. This information is not the fair value nor does it represent the expected present value of future cash flows of our crude oil and condensate, natural gas liquid,liquids, and natural gas and synthetic crude oil reserves.
| | | (In millions) | U.S. | | Canada | | E.G. | | Other Africa | | Other Int'l | | Total | U.S. | | E.G. | | Libya | | Other Int’l | | Total |
| Year Ended December 31, 2016 | | | | | | | | | | | | |
| Year Ended December 31, 2019 | | | | | | | | | | |
| Future cash inflows | $ | 27,610 |
| | $ | 26,803 |
| | $ | 1,977 |
| | $ | 8,511 |
| | $ | 921 |
| | $ | 65,822 |
| $ | 40,487 |
| | $ | 1,812 |
| | $ | — |
| | $ | — |
| | $ | 42,299 |
|
| Future production and support costs | (12,758 | ) | | (20,208 | ) | | (824 | ) | | (930 | ) | | (673 | ) | | (35,393 | ) | (14,167 | ) | | (838 | ) | | — |
| | — |
| | (15,005 | ) |
| Future development costs | (7,233 | ) | | (3,209 | ) | | (13 | ) | | (296 | ) | | (1,345 | ) | | (12,096 | ) | (7,561 | ) | | (18 | ) | | — |
| | — |
| | (7,579 | ) |
| Future income tax expenses | — |
| | (446 | ) | | (251 | ) | | (6,884 | ) | | 514 |
| | (7,067 | ) | (1,085 | ) | | (280 | ) | | — |
| | — |
| | (1,365 | ) |
| Future net cash flows | $ | 7,619 |
| | $ | 2,940 |
| | $ | 889 |
| | $ | 401 |
| | $ | (583 | ) | (a) | $ | 11,266 |
| $ | 17,674 |
| | $ | 676 |
| | $ | — |
| | $ | — |
| | $ | 18,350 |
|
| 10% annual discount for timing of cash flows | (4,355 | ) | | (1,864 | ) | | (264 | ) | | (143 | ) | | 313 |
| | (6,313 | ) | (7,416 | ) | | (179 | ) | | — |
| | — |
| | (7,595 | ) |
| Standardized measure of discounted future net cash flows- | |
| -related to continuing operations | $ | 3,264 |
| | $ | 1,076 |
| | $ | 625 |
| | $ | 258 |
| | $ | (270 | ) | | $ | 4,953 |
| |
| -related to discontinued operations | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | — |
| | — |
| |
| Year Ended December 31, 2015 | | | | | | | | | | | | |
Standardized measure of discounted future net cash flows- related to continuing operations | | $ | 10,258 |
| | $ | 497 |
| | $ | — |
| | $ | — |
| | $ | 10,755 |
|
| Year Ended December 31, 2018 | | | | | | | | | | |
| Future cash inflows | $ | 31,026 |
| | $ | 31,087 |
| | $ | 2,671 |
| | $ | 12,157 |
| | $ | 1,281 |
| | $ | 78,222 |
| $ | 49,054 |
| | $ | 2,218 |
| | $ | — |
| | $ | 1,813 |
| | $ | 53,085 |
|
| Future production and support costs | (12,270 | ) | | (27,459 | ) | | (1,095 | ) | | (901 | ) | | (902 | ) | | (42,627 | ) | (15,995 | ) | | (878 | ) | | — |
| | (876 | ) | | (17,749 | ) |
| Future development costs | (6,637 | ) | | (2,929 | ) | | (94 | ) | | (689 | ) | | (1,537 | ) | | (11,886 | ) | (7,729 | ) | | (12 | ) | | — |
| | (1,072 | ) | | (8,813 | ) |
| Future income tax expenses | (778 | ) | | — |
| | (369 | ) | | (9,857 | ) | | 602 |
| | (10,402 | ) | (1,967 | ) | | (355 | ) | | — |
| | 275 |
| | (2,047 | ) |
| Future net cash flows | $ | 11,341 |
| | $ | 699 |
| | $ | 1,113 |
| | $ | 710 |
| | $ | (556 | ) | (a) | $ | 13,307 |
| $ | 23,363 |
| | $ | 973 |
| | $ | — |
| | $ | 140 |
| (a) | $ | 24,476 |
|
| 10% annual discount for timing of cash flows | (6,082 | ) | | (534 | ) | | (380 | ) | | (441 | ) | | 352 |
| | (7,085 | ) | (10,653 | ) | | (254 | ) | | — |
| | 100 |
| | (10,807 | ) |
| Standardized measure of discounted future net cash flows- | |
| -related to continuing operations | $ | 5,259 |
| | $ | 165 |
| | $ | 733 |
| | $ | 269 |
| | $ | (204 | ) | | $ | 6,222 |
| |
| -related to discontinued operations | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Year Ended December 31, 2014 | | | | | | | | | | | | |
Standardized measure of discounted future net cash flows- related to continuing operations | | $ | 12,710 |
| | $ | 719 |
| | $ | — |
| | $ | 240 |
| | $ | 13,669 |
|
| Year Ended December 31, 2017 | | | | | | | | | | |
| Future cash inflows | $ | 66,307 |
| | $ | 55,675 |
| | $ | 5,027 |
| | $ | 23,803 |
| | $ | 3,040 |
| | $ | 153,852 |
| $ | 36,480 |
| | $ | 1,966 |
| | $ | 10,303 |
| | $ | 1,403 |
| | $ | 50,152 |
|
| Future production and support costs | (19,504 | ) | | (34,838 | ) | | (1,270 | ) | | (803 | ) | | (1,452 | ) | | (57,867 | ) | (14,796 | ) | | (748 | ) | | (931 | ) | | (821 | ) | | (17,296 | ) |
| Future development costs | (14,626 | ) | | (9,754 | ) | | (259 | ) | | (680 | ) | | (1,669 | ) | | (26,988 | ) | (6,987 | ) | | (7 | ) | | (501 | ) | | (1,247 | ) | | (8,742 | ) |
| Future income tax expenses | (8,124 | ) | | (2,190 | ) | | (922 | ) | | (21,008 | ) | | (9 | ) | | (32,253 | ) | (786 | ) | | (274 | ) | | (8,387 | ) | | 496 |
| | (8,951 | ) |
| Future net cash flows | $ | 24,053 |
| | $ | 8,893 |
| | $ | 2,576 |
| | $ | 1,312 |
| | $ | (90 | ) | | $ | 36,744 |
| $ | 13,911 |
| | $ | 937 |
| | $ | 484 |
| | $ | (169 | ) | (a) | $ | 15,163 |
|
| 10% annual discount for timing of cash flows | (12,138 | ) | | (6,613 | ) | | (915 | ) | | (742 | ) | | 221 |
| | (20,187 | ) | (7,009 | ) | | (235 | ) | | (224 | ) | | 168 |
| | (7,300 | ) |
| Standardized measure of discounted future net cash flows- | |
| -related to continuing operations | $ | 11,915 |
| | $ | 2,280 |
| | $ | 1,661 |
| | $ | 570 |
| | $ | 131 |
| | $ | 16,557 |
| |
| -related to discontinued operations | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Standardized measure of discounted future net cash flows- related to continuing operations | | $ | 6,902 |
| | $ | 702 |
| | $ | 260 |
| | $ | (1 | ) | | $ | 7,863 |
|
| |
(a) | Future cash flows for Other International reflects the impact of future abandonment costs related to the U.K. |
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Changes in the Standardized Measure of Discounted Future Net Cash Flows | | | | Year Ended December 31, | Year Ended December 31, |
| (In millions) | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| Sales and transfers of oil and gas produced, net of production and support costs | $ | (1,813 | ) | | $ | (2,460 | ) | | $ | (5,284 | ) | $ | (3,345 | ) | | $ | (4,135 | ) | | $ | (2,853 | ) |
| Net changes in prices and production and support costs related to future production | (3,173 | ) | (b) | (25,239 | ) | (b) | (2,688 | ) | (3,569 | ) | | 6,342 |
| | 4,916 |
|
| Extensions, discoveries and improved recovery, less related costs | 238 |
| | 1,100 |
| | 3,539 |
| 718 |
| | 998 |
| | 661 |
|
| Development costs incurred during the period | 700 |
| | 1,694 |
| | 4,088 |
| 1,727 |
| | 1,240 |
| | 1,027 |
|
| Changes in estimated future development costs | 2,492 |
| | 9,397 |
| | (1,423 | ) | 278 |
| | (330 | ) | | 183 |
|
Revisions of previous quantity estimates(a) | (1,088 | ) | | (7,625 | ) | | (3,193 | ) | 7 |
| | (501 | ) | | 497 |
|
| Net changes in purchases and sales of minerals in place | (651 | ) | | (460 | ) | | (168 | ) | (200 | ) | | (3,035 | ) | | 102 |
|
| Accretion of discount | 1,020 |
| | 2,967 |
| | 3,132 |
| 1,315 |
| | 1,175 |
| | 698 |
|
| Net change in income taxes | 1,006 |
| | 10,291 |
| | 3,312 |
| 155 |
| | 4,052 |
| | (1,245 | ) |
| Net change for the year | (1,269 | ) | | (10,335 | ) | | 1,315 |
| (2,914 | ) | | 5,806 |
| | 3,986 |
|
| Beginning of the year related to continuing operations | 6,222 |
| | 16,557 |
| | 15,242 |
| |
| End of the year related to continuing operations | $ | 4,953 |
| | $ | 6,222 |
| | $ | 16,557 |
| |
| Net change for the year related to discontinued operations | $ | — |
| | $ | — |
| | $ | (2,530 | ) | |
| Beginning of the year | | 13,669 |
| | 7,863 |
| | 3,877 |
|
| End of the year | | $ | 10,755 |
| | $ | 13,669 |
| | $ | 7,863 |
|
| |
(a) | Includes amounts resulting from changes in the timing of production. |
| |
(b)
| Decrease primarily due to lower realized prices. |
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2016.2019.
Management'sManagement’s Annual Report on Internal Control Over Financial Reporting
See "Management’s“Management’s Report on Internal Control over Financial Reporting"Reporting” under Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See "Report“Report of Independent Registered Public Accounting Firm"Firm” under Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
During the fourth quarter of 2016,2019, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information required by this item is incorporated by reference to "Proposal“Proposal 1: Election of Directors," "Corporate” “Corporate Governance—Committees of the Board"Board” and "Section“Section 16(a) Beneficial Ownership Reporting Compliance"Compliance” in our Proxy Statement for the 20172020 Annual Meeting of Stockholders, to be filed with the SEC within 120 days of December 31, 20162019 (the "2017“2020 Proxy Statement"Statement”).
See "Executive“Executive Officers of the Registrant"Registrant” under Item 1 of this Form 10-K for information about our executive officers.
Our Code of Business Conduct and the Code of Ethics for Senior Financial Officers, arewhich applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, is available on our website at www.marathonoil.com.www.marathonoil.com under Investors—Corporate Governance. You may request a printed copy free of charge by sending a request to the Corporate Secretary. We intend to disclose any amendments and any waivers to our Code of Ethics for Senior Financial Officers on our website at www.marathonoil.com under Investors —Corporate Governance within four business days. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.
Item 11. Executive Compensation
Information required by this item is incorporated by reference to "Corporate“Corporate Governance—Compensation Committee Interlocks and Insider Participation," "Compensation” “Compensation Committee Report," "Director” “Director Compensation," "Compensation” “Compensation Discussion and Analysis"Analysis” and "Executive Compensation"“Executive Compensation” in the 20172020 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Portions of information required by this item are incorporated by reference to "Security“Security Ownership of Certain Beneficial Owners and Management"Management” in the 20172020 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 20162019 with respect to shares of Marathon Oil common stock that may be issued under our existing equity compensation plans:
Marathon Oil Corporation 2019 Incentive Compensation Plan (the “2019 Plan”)
Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 Plan"“2016 Plan”)
Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan"“2012 Plan”) – No additional awards will be granted under this plan.
Marathon Oil Corporation 2007 Incentive Compensation Plan (the "2007 Plan"“2007 Plan”) – No additional awards will be granted under this plan.
Marathon Oil Corporation 2003 Incentive Compensation Plan (the "2003 Plan") – No additional awards will be granted under this plan.
Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.
| | | Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted-average exercise price of outstanding options, warrants and rights(c) | | Number of securities remaining available for future issuance under equity compensation plans | | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted-average exercise price of outstanding options, warrants and rights(b) | | Number of securities remaining available for future issuance under equity compensation plans | |
| Equity compensation plans approved by stockholders | 13,566,560 |
| (a) | $27.31 | | 53,818,078 |
| (d) | 6,546,401 |
| (a) | $ | 23.55 |
| | 30,911,537 |
| (c) |
| Equity compensation plans not approved by stockholders | 12,291 |
| (b) | N/A | | — |
| | |
| Total | 13,578,851 |
| | N/A | | 53,818,078 |
| | |
| |
(a) | Includes the following: |
4,214,949No stock options outstanding under the 2019 Plan; 2,044,463 stock options outstanding under the 2016 Plan; 2,494,866 stock options outstanding under the 2012 Plan; 7,700,584989,835 stock options outstanding under the 2007 Plan;
353,503181,982 common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the 2019 Plan, 2016 Plan, 2012 Plan 2007 Plan and 20032007 Plan. Common stock units credited under the 20122019 Plan, 20072016 Plan, and 2003 Plan were 166,680, 152,828 and 33,995, respectively;
1,297,524 restricted stock units granted to non-officers under the 2012 Plan and 20162007 Plan were nil 153,119, nil, and outstanding as of December 31, 2016.28,863, respectively;
| |
| • | 12,263 and 647,889 outstanding restricted stock units granted to non-officers under the 2019 Plan and 2016 Plan as of December 31, 2019, respectively. Additionally, 175,103 outstanding restricted stock units granted to officers under the 2016 Plan; |
In addition to the awards reported above, 60,7166,060,945 and 429,708276,719 shares of restricted stock were issued and outstanding as of December 31, 2016,2019, but subject to forfeiture restrictions under the 2016 Plan. In addition to the awards reported above 5,206,301 shares of restricted stock were issuedPlan and outstanding as of December 31, 2016, but subject to forfeiture restrictions under the 2012 Plan.2019 Plan, respectively.
| |
(b) | Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon Oil common stock in place of the common stock units. |
| |
(c)
| The weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price. |
| |
(d)(c)
| Reflects the shares available for issuance under the 20162019 Plan. No more than 22,331,15230,775,974 of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, canceled or expire unexercised shall again immediately become available for issuance. |
The Deferred Compensation Plan for Non-Employee Directors is our only equity compensation plan that has not been approved by our stockholders. Our authority to make equity grants under this plan was terminated effective April 30, 2003. Under the Deferred Compensation Plan for Non-Employee Directors, all non-employee directors were required to defer half of their annual retainers in the form of common stock units. On the date the retainer would have otherwise been payable to the non-employee director, we credited an unfunded bookkeeping account for each non-employee director with a number of common stock units equal to half of his or her annual retainer divided by the fair market value of our common stock on that date. The ongoing value of each common stock unit equals the market price of a share of our common stock. When the non-employee director leaves the Board, he or she is issued actual shares of our common stock equal to the number of common stock units in his or her account at that time.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item is incorporated by reference to "Transactions“Transactions with Related Persons,"” and "Proposal“Proposal 1: Election of Directors—Director Independence"Independence” in the 20172020 Proxy Statement.
Item 14. Principal Accountant Fees and Services
Information required by this item is incorporated by reference to "Proposal“Proposal 2: Ratification of Independent Auditor for 2017"2020“ in the 20172020 Proxy Statement.
PART IV
Item 15. Exhibits, Financial Statement Schedules
A. Documents Filed as Part of the Report
1. Financial Statements – See Part II, Item 8. of this Annual Report on Form 10-K.
2. Financial Statement Schedules – FinancialThe audited financial statements and related footnotes of Alba Plant LLC, our equity method investment, are being filed within Exhibit 99.9 in accordance with Rule 3-09 of Regulation S-X. All other financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.
3. Exhibits – The information required by this Item 15 is incorporated by reference to the Exhibit Index accompanying this Annual Report on Form 10-K.
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | |
February 24, 201720, 2020 | | MARATHON OIL CORPORATION |
| | | |
| | | By: /s/ GARY E. WILSON |
| | | Gary E. Wilson |
| | | Vice President, Controller and Chief Accounting Officer |
POWER OF ATTORNEY
Each person whose signature appears below appoints Lee M. Tillman, Patrick J. Wagner,Dane E. Whitehead, and Gary E. Wilson, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, with full power and authority to each of said attorneys-in-fact and agents to do and perform each and every act whatsoever that is necessary, appropriate or advisable in connection with any or all of the above-described matters and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 24, 201720, 2020 on behalf of the registrant and in the capacities indicated. |
| | |
| Signature | | Title |
| | | |
/S/s/ LEE M. TILLMAN | | Chairman, President and Chief Executive Officer and Director |
| Lee M. Tillman | | |
| | | |
/S/ PATRICK J. WAGNER s/ DANE E. WHITEHEAD | | InterimExecutive Vice President and Chief Financial Officer and Vice President Corporate Development and Strategy |
Patrick J. WagnerDane E. Whitehead | | |
| | | |
| /s/ GARY E. WILSON | | Vice President, Controller and Chief Accounting Officer |
| Gary E. Wilson | | |
| | | |
/S/ DENNIS H. REILLEY
| | Chairman of the Board |
Dennis H. Reilley | | |
| | |
/s/ GAURDIE E. BANISTER, JR. | | Director |
Gaurdie E. Banister, Jr. | | |
| | |
/S/ GREGORY H. BOYCE
| | Director |
| Gregory H. Boyce | | |
| | | |
/S/s/ CHADWICK C. DEATON | | Director |
| Chadwick C. Deaton | | |
| | | |
/S/s/ MARCELA E. DONADIO | | Director |
| Marcela E. Donadio | | |
| | | |
/S/ PHILIP LADER s/ JASON B. FEW | | Director |
Philip LaderJason B. Few | | |
| | | |
/S/ MICHAEL E. J. PHELPS s/ DOUGLAS L. FOSHEE | | Director |
Michael E. Douglas L. Foshee | | |
| | |
| /s/ M.ELISE HYLAND | | Director |
| M. Elise Hyland | | |
| | |
| /s/ J.KENT WELLS | | Director |
J. PhelpsKent Wells | | |
Exhibit Index
|
| | | | | | | |
| Exhibit | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
| Number | | Exhibit Description | Form | | Exhibit | | Filing Date |
| 3 | | Articles of Incorporation and By-laws |
| 3.1 | | Restated Certificate of Incorporation of Marathon Oil Corporation | 10-Q | | 3.1 | | 8/8/2013 |
| 3.2 | | Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016) | 8-K | | 3.1 | | 3/1/2016 |
| 3.3 | | Specimen of Common Stock Certificate | 10-K | | 3.3 | | 2/28/2014 |
| 4 | | Instruments Defining the Rights of Security Holders, Including Indentures |
| 4.1 | | Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request | 10-K | | 4.2 | | 2/28/2014 |
| 10 | | Material Contracts | | | | | |
| 10.1 | | Amended and Restated Credit Agreement, dated as of May 28, 2014, among Marathon Oil Corporation, as borrower, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein | 8-K | | 4.1 | | 6/2/2014 |
| 10.2 | | First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein | 10-Q | | 10.1 | | 5/7/2015 |
| 10.3 | | Incremental Commitments Supplement, dated as of March 4, 2016, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent. | 8-K | | 99.1 | | 3/8/2016 |
10.4† | | Marathon Oil Corporation 2016 Incentive Compensation Plan | DEF 14A | | App. A | | 4/7/2016 |
| 10.5† | | Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year cliff vesting) | 8-K/A | | 10.1 | | 10/6/2016 |
10.6†* | | Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year prorata vesting) | | | | | |
| 10.7†* | | Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers | | | | | |
| 10.8†* | | Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Unit Award Agreement for Non-Employee Directors (3-year cliff vesting) | | | | | |
|
| | | | | | | | |
| Exhibit Number | | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
| | Exhibit Description | | Form | | Exhibit | | Filing Date |
| 1 | | Underwriting Agreement | | | | | | |
| 1.1 | | | | 10-K | | 1.1 | | 2/22/2018 |
| 2 | | Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession | | | | | | |
| 2.1 | | | | 10-Q | | 10.1 | | 5/5/2017 |
| 3 | | Articles of Incorporation and By-laws |
| 3.1 | | | | 8-K | | 3.1 | | 6/1/2018 |
| 3.2 | | | | 10-Q | | 3.2 | | 8/4/2016 |
| 3.3 | | | | 10-K | | 3.3 | | 2/28/2014 |
| 4 | | Instruments Defining the Rights of Security Holders, Including Indentures |
| 4.1 | | | | 10-K | | 4.2 | | 2/28/2014 |
| 4.2* | | | | | | | | |
| 10 | | Material Contracts | | | | | | |
| 10.1 | | Amended and Restated Credit Agreement, dated as of May 28, 2014, among Marathon Oil Corporation, as borrower, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein | | 8-K | | 4.1 | | 6/2/2014 |
| 10.2 | | First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein | | 10-Q | | 10.1 | | 5/7/2015 |
| 10.3 | | Incremental Commitments Supplement, dated as of March 4, 2016, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent. | | 8-K | | 99.1 | | 3/8/2016 |
|
| | | | | | | | |
| Exhibit Number | | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
| | Exhibit Description | | Form | | Exhibit | | Filing Date |
| 10.4 | | Second Amendment, dated as of June 22, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, and supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent. | | 8-K | | 99.1 | | 6/23/2017 |
| 10.5 | | Incremental Commitment Supplement, dated as of July 11, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, and amended by the Second Amendment dated as of June 22, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent. | | 10-Q | | 10.2 | | 8/3/2017 |
| 10.6 | | Third Amendment, dated as of October 18, 2018, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015 and the Second Amendment dated as of June 22, 2017 and as supplemented by the Incremental Commitments Supplement dated as of March 4, 2016 and Incremental Commitments Supplement dated as July 11, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, Mizuho Bank, Ltd, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent | | 8-K | | 99.1 | | 10/22/2018 |
| 10.7 | | Fourth Amendment, dated as of September 24, 2019, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, the Second Amendment dated as of June 22, 2017, and the Third Amendment dated as of October 18, 2018 and as supplemented by the Incremental Commitments Supplement dated as of March 4, 2016 and Incremental Commitments Supplement dated as July 11, 2017, among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein
| | 8-K | | 10.1 | | 9/24/2019 |
| 10.8† | | | | DEF 14A | | App. A | | 4/12/2019 |
| 10.9† | | | | 10-Q | | 10.1 | | 8/8/2019 |
| 10.10† | | | | 10-Q | | 10.2 | | 8/8/2019 |
| 10.11† | | | | 10-Q | | 10.3 | | 8/8/2019 |
10.12† | | | | 10-Q | | 10.4 | | 8/8/2019 |
|
| | | | | | | | |
| Exhibit Number | | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
Number | | Exhibit Description | | Form | | Exhibit | | Filing Date |
10.9†10.13†*
| | | | | | | | |
10.14† | | | | DEF 14A | | App. A | | 4/7/2016 |
| 10.15† | | | | 10-Q | | 10.1 | | 5/2/2019 |
| 10.16† | | | | 10-Q | | 10.2 | | 5/2/2019 |
| 10.17† | | | | 10-Q | | 10.3 | | 5/2/2019 |
10.18† | | | | 10-Q | | 10.4 | | 5/2/2019 |
| 10.19† | | | | 10-Q | | 10.5 | | 5/2/2019 |
| 10.20† | | | | 8-K/A | | 10.1 | | 10/6/2016 |
| 10.21† | | | | 10-K | | 10.6 | | 2/24/2017 |
| 10.22† | | | | 10-K | | 10.7 | | 2/24/2017 |
| 10.23† | | | | 10-K | | 10.8 | | 2/24/2017 |
10.24†
| | | | 10-K | | | |
10.10†10.9 | | 2/24/2017 |
10.25†
| | | | 10-K | | 10.12 | | 2/22/2018 |
10.26†
| | | | 10-K | | 10.13 | | 2/22/2018 |
10.27† | | | | DEF 14A | | App. III | | 3/8/2012 |
10.11†10.28† | | | | 8-K | | 10.1 | | 8/1/2014 |
10.12†
10.29† | | | | 10-Q | | 10.1 | | 5/7/2014 |
10.1310.30†
| | | | 10-Q | | 10.2 | | 5/7/2014 |
10.14†10.31† | | | | 10-Q | | 10.1 | | 11/6/2013 |
10.15†10.32† | | Form of Marathon Oil Corporation 2012 Incentive Compensation Plan CEO Restricted Stock Agreement (3-year prorata vesting) | 10-Q | | 10.2 | | 11/6/2013 |
10.16† | | Form of Marathon Oil Corporation 2012 Incentive Compensation Plan CEO Restricted Stock Award Agreement granted (3-year cliff vesting) | 10-Q | | 10.3 | | 11/6/2013 |
10.17† | | | | 10-K | | 10.5 | | 2/22/2013 |
10.18† | | Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers (3-year prorata vesting) | 10-K | | 10.6 | | 2/22/2013 |
10.19† | | Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year cliff vesting) | 10-K | | 10.7 | | 2/22/2013 |
10.20† | | Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Officers (3-year cliff vesting) | 10-K | | 10.8 | | 2/22/2013 |
10.21†
| | Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year prorata vesting) | 10-K | | 10.9 | | 2/22/2013 |
10.22†
| | Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Officers (3-year prorata vesting) | 10-K | | 10.10 | | 2/22/2013 |
10.23†
| | Marathon Oil Corporation 2007 Incentive Compensation Plan | 10-K | | 10.5 | | 2/29/2012 |
10.24† | | Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers | 10-K | | 10.6 | | 2/29/2012 |
10.25†
| | Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers | 10-K | | 10.5 | | 2/28/2011 |
10.26† | | Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers | 10-K | | 10.26 | | 2/26/2010 |
10.27† | | Marathon Oil Corporation 2003 Incentive Compensation Plan | 10-K | | 10.9 | | 2/26/2010 |
|
| | | | | | | |
| Exhibit | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
| Number | | Exhibit Description | Form | | Exhibit | | Filing Date |
| 10.28† | | Form of Marathon Oil Corporation 2003 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers | 10-K | | 10.22 | | 2/26/2010 |
| 10.29†* | | Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of December 20, 2016) | | | | | |
| 10.30† | | Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011 | 10-K | | 10.32 | | 2/29/2012 |
| 10.31† | | Marathon Oil Company Excess Benefit Plan Amended and Restated | 10-K | | 10.31 | | 2/29/2012 |
| 10.32† | | Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (as amended, effective November 1, 2014) | 10-K | | 10.36 | | 3/2/2015 |
10.33† | | Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts | 10-K | | 10.10 | | 2/28/2011 |
10.34† | | Marathon Oil Corporation Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009 | 10-K | | 10.32 | | 2/27/2009 |
| 10.35 | | Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC | 8-K | | 10.1 | | 5/26/2011 |
| 10.36 | | Separation Agreement with John R. Sult, dated September 23, 2016 | 8-K | | 10.1 | | 9/29/2016 |
| 10.37 | | Consulting Services Agreement with John R. Sult, dated September 23, 2016 | 8-K | | 10.2 | | 9/29/2016 |
| 10.38 | | Separation Agreement with Lance W. Robertson, dated September 23, 2016 | 8-K | | 10.3 | | 9/29/2016 |
| 12.1* | | Computation of Ratio of Earnings to Fixed Charges | | | | | |
| 21.1* | | List of Significant Subsidiaries | | | | | |
| 23.1* | | Consent of Independent Registered Public Accounting Firm | | | | | |
| 23.2* | | Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists | | | | | |
| 23.3* | | Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists | | | | | |
| 23.4* | | Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists | | | | | |
| 31.1* | | Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | |
| 31.2* | | Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 | | | | | |
| 32.1* | | Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350 | | | | | |
| 32.2* | | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 | | | | | |
| 99.1 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2015 | 10-K | | 99.1 | | 2/25/2016 |
|
| | | | | | | | |
| Exhibit Number | | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
| | Exhibit Description | | Form | | Exhibit | | Filing Date |
| 10.33† | | | | 10-K | | 10.6 | | 2/22/2013 |
10.34† | | | | 10-K | | 10.5 | | 2/29/2012 |
| 10.35† | | | | 10-K | | 10.6 | | 2/29/2012 |
10.36† | | | | 10-K | | 10.5 | | 2/28/2011 |
| 10.37† | | | | 10-K | | 10.29 | | 2/24/2017 |
| 10.38† | | | | 10-K | | 10.32 | | 2/29/2012 |
| 10.39† | | | | 10-K | | 10.31 | | 2/29/2012 |
| 10.40† | |
| | 10-Q | | 10.1 | | 11/7/2019 |
10.41† | | | | 10-K | | 10.10 | | 2/28/2011 |
10.42† | | | | 10-K | | 10.32 | | 2/27/2009 |
| 10.43 | | | | 8-K | | 10.1 | | 5/26/2011 |
| 21.1* | | | | | | | | |
| 23.1* | | | | | | | | |
| 23.2* | | | | | | | | |
| 23.3* | | | | | | | | |
| 23.4* | | | | | | | | |
| 31.1* | | | | | | | | |
| 31.2* | | | | | | | | |
| 32.1* | | | | | | | | |
| 32.2* | | | | | | | | |
| 99.1* | | | | | | | | |
| 99.2* | | | | | | | | |
| 99.3 | | | | 10-K | | 99.2 | | 2/21/2019 |
|
| | | | | | | |
| Exhibit | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
| Number | | Exhibit Description | Form | | Exhibit | | Filing Date |
| 99.2 | | Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2014 | 10-K | | 99.1 | | 3/2/2015 |
| 99.3* | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2016 | | | | | |
| 99.4* | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2015 | | | | | |
| 99.5 | | Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2014 | 10-K | | 99.7 | | 2/25/2016 |
| 99.6* | | Summary report performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2015 | | | | | |
| 99.7 | | Summary report performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2014 | 10-K | | 99.4 | | 2/25/2016 |
| 101.INS* | | XBRL Instance Document | | | | | |
| 101.SCH* | | XBRL Taxonomy Extension Schema | | | | | |
| 101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase | | | | | |
| 101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase | | | | | |
| 101.LAB* | | XBRL Taxonomy Extension Label Linkbase | | | | | |
| 101.DEF* | | XBRL Taxonomy Extension Definition Linkbase | | | | | |
| * | | Filed herewith. |
| † | | Management contract or compensatory plan or arrangement. |
|
| | | | | | | | |
| Exhibit Number | | | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
| | Exhibit Description | | Form | | Exhibit | | Filing Date |
| 99.4 | | | | 10-K | | 99.7 | | 2/22/2018 |
| 99.9* | | | | | | | | |
| 101.INS* | | XBRL Instance Document - the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | | | | | | |
| 101.SCH* | | XBRL Taxonomy Extension Schema | | | | | | |
| 101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase | | | | | | |
| 101.DEF* | | XBRL Taxonomy Extension Definition Linkbase | | | | | | |
| 101.LAB* | | XBRL Taxonomy Extension Label Linkbase | | | | | | |
| 101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase | | | | | | |
| 104* | | Cover Page Interactive Data File, formatted in iXBRL and contained in Exhibit 101 | | | | | | |
| * | | Filed herewith. |
| † | | Management contract or compensatory plan or arrangement. |
