MARATHON OIL CORP
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the foregoing pages under “Disclosures Regarding Forward-Looking Statements” and other information included and incorporated by reference into this Annual Report on Form 10-K.
A substantial decline in crude oil and condensate, NGLs and natural gas prices would reduce our operating results and cash flows and could adversely impact our future rate of growth and the carrying value of our assets.
The markets for crude oil and condensate, NGLs and natural gas have been volatile and are 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 and natural gas. Many of the factors influencing prices of crude oil and condensate, NGLs and natural gas are beyond our control. These factors include:
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worldwide and domestic supplies of and demand for crude oil and condensate, NGLs and natural gas;
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the cost of exploring for, developing and producing crude oil and condensate, NGLs and natural gas;
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the ability of the members of OPEC and certain non-OPEC members, such as Russia, to agree to and maintain production controls;
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the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
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the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
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political instability or armed conflict in oil and natural gas producing regions;
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changes in weather patterns and climate;
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natural disasters such as hurricanes and tornadoes;
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the price and availability of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;
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the effect of conservation efforts;
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epidemics or pandemics;
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technological advances affecting energy consumption and energy supply;
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domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and
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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 are uncertain. Historical declines in commodity prices have adversely affected our business by:
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reducing the amount of crude oil and condensate, NGLs and natural gas that we can produce economically;
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reducing our revenues, operating income and cash flows;
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causing us to reduce our capital expenditures, and delay or postpone some of our capital projects;
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requiring us to impair the carrying value of our assets;
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reducing the standardized measure of discounted future net cash flows relating to crude oil and condensate, NGLs and natural gas; and
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increasing the costs of obtaining capital, such as equity and short- and long-term debt.
Estimates of crude oil and condensate, NGLs and natural gas 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 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 and third-party consultants. Reserves were valued based on SEC pricing for the periods ended December 31, 2019, 2018 and 2017, as well as other conditions in existence at those dates. The table below provides the 2019 SEC pricing for certain benchmark prices:
If crude oil prices in 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.
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 that cannot be directly measured. Estimates of economically producible reserves and of future net cash flows depend on a number of variable factors and assumptions, including:
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location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;
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historical production from the area, compared with production from other analogous producing areas;
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the assumed impacts of regulation by governmental agencies;
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assumptions concerning future operating costs, taxes, development costs and workover and repair costs; and
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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:
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the amount and timing of production;
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the revenues and costs associated with that production; and
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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 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 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 may decline materially as crude oil and condensate, NGLs and natural gas are produced. Accordingly, to the extent we are not successful in replacing the crude oil and condensate, NGLs and natural gas we produce, our future revenues may decline. Creating and maintaining an inventory of prospects for future production depends on many factors, including:
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obtaining rights to explore for, develop and produce crude oil and condensate, NGLs and natural gas in promising areas;
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drilling success;
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the ability to complete projects timely and cost effectively;
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the ability to find or acquire additional proved reserves at acceptable costs; and
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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:
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in formations;
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equipment failures or accidents;
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inflation in exploration and drilling costs;
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fires, explosions, blowouts or surface cratering;
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lack of, or disruption in, access to pipelines or other transportation methods; and
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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:
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denial of or delay in receiving requisite regulatory approvals and/or permits;
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unplanned increases in the cost of construction materials or labor;
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disruptions in transportation of components or construction materials;
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increased costs or operational delays resulting from shortages of water;
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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;
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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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market-related increases in a project’s debt or equity financing costs; and
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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.
We may incur substantial capital expenditures and operating costs as a result of compliance with and changes in environmental, health, safety and security law, 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 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 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 could 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 the U.S. 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. 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 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. Various 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 BLM issued a rule governing certain hydraulic fracturing practices on lands within their jurisdiction; however, this rule was rescinded in December 2017. This rescission is being judicially challenged before the 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 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. 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 uses 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 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.
Our offshore operations involve special risks that could negatively impact us.
Offshore operations present technological challenges and operating risks because of the 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 substantial liabilities.
Our business could be negatively impacted by cyberattacks targeting our computer and telecommunications systems and infrastructure, or targeting those of our third-party service providers.
Our 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 process information. Such technologies are integrated into our business operations and used as a part of our production and distribution systems in the U.S. and abroad, 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 may 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 information security breaches and significant disruption to our business. Our information systems and related infrastructure have experienced attempted and actual minor breaches of our cybersecurity in the past, but we have not suffered any losses or breaches which had a material effect on our business, operations or reputation relating to such attacks; however, there is no assurance that we will not suffer such losses or breaches in the future.
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 be subject to regulatory investigations or litigation relating from cybersecurity issues.
Our level of indebtedness may limit our liquidity and financial flexibility.
As of December 31, 2019, our total debt was $5.5 billion, and our next debt maturity is our $1.0 billion 2.8% senior unsecured notes due in 2022. Our indebtedness could have important consequences to our business, including, but not limited to, the following:
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we may be more vulnerable to general adverse economic and industry conditions;
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a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
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our flexibility in planning for, or reacting to, changes in our industry may be limited;
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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;
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we may be at a competitive disadvantage as compared to similar companies that have less debt; and
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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 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.
Difficulty in accessing capital or a significant increase in our costs of accessing capital could adversely affect our business.
We receive debt ratings from the major credit rating agencies in the United States. Due to the volatility in crude oil and U.S. natural gas prices in recent years, credit rating agencies review companies in the energy industry periodically, including us. At December 31, 2019, our corporate credit ratings were: Standard & Poor’s Global Ratings Services BBB (stable); Fitch Ratings BBB (stable); and Moody’s Investor Services, Inc. Baa3 (stable). The credit rating process is contingent upon a number of factors, many of which are beyond our control. A 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 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.
Political 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 within 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 property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens.
Changes in the U.S. or global political and economic 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 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 and natural gas. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate. These risks could also cause damage to, or the inability to access, production facilities or other operating assets and could 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. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries and will continue to do so in the future. Changes in U.S. or foreign laws could also adversely affect our results, including new regulations resulting in higher costs to transport our production by pipeline, rail car, truck or vessel or the adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information or that could cause us to violate the non-disclosure laws of other countries.
Our 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, 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 production 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 natural gas properties and 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 natural gas (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 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 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 with other 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 United States and International 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. 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 including 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.
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.
For instance, government entities and other groups 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 a 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. The ultimate outcome and impact to us
cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future.
Item 1B. Unresolved Staff Comments
None.
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, 2019, under federal and state environmental laws.
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 a 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 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.
As of December 31, 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”), and is traded under the trading symbol ‘MRO’. As of January 31, 2020, there were 28,346 registered holders of Marathon Oil common stock.
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 certificate of incorporation 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, 2019, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:
(a)
57,993 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 billion share repurchase program. Our Board of Directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2 billion in July 2007, by $1.2 billion in December 2013 and by $950 million in July 2019 for a total authorized amount of $7.2 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, 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
(a)
December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million.
(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 2 and Note 13 to the consolidated financial statements for further information.
Supplemental information affecting comparability of selected financial data is shown below.
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 Regarding Forward-Looking Statements” (immediately prior to Part I) and Item 1A. Risk Factors.
Each of our two reportable operating segments are organized by geographic location and managed according to the nature of the products and services offered.
•
United States - explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States;
•
International - explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
Executive Overview
We 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 capital investment in the lower cost, higher margin U.S. resource plays (the Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico). We will continue to be guided by maintaining a strong balance sheet, prioritizing sustainable cash flow over a wide range of commodity prices and returning capital to shareholders.
Key 2019 highlights include:
Simplifying and concentrating our portfolio
•
In the first quarter of 2019, we closed the sale of our working interest in the Droshky field (Gulf of Mexico) for a pre-tax gain of $42 million.
•
In the second quarter of 2019, 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.
•
In July 2019, we closed on the sale of our U.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% non-operated working interest partner in our Louisiana Austin Chalk acreage.
•
During the fourth quarter of 2019, we acquired approximately 18,000 net acres in the Eagle Ford for $191 million and approximately 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 three leverage neutral finance transactions that extend maturities, generate annual cash cost savings, and reflect our commitment to maintaining a strong balance sheet and investment grade credit ratings at all primary rating agencies.
Financial and operational results
•
Total net sales volumes for the year were 414 mboed, including 323 mboed in the U.S. Our U.S. net sales volumes increased 8% and our wells to sales increased 11% compared to 2018.
•
Added proved reserves of 110 mmboe for a reserve replacement ratio of 74%.
•
Our net income per share from continuing operations was $0.59 in 2019 as compared to a net income per share of $1.30 last year. Included in 2019 net income are:
◦
A decrease in revenues of approximately 14% compared to 2018, as a result 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 disposal of assets decreased $269 million in 2019 primarily due to the sale of our Libya subsidiary for a pre-tax gain of $255 million in 2018.
◦
Exploration and impairment expenses decreased by $191 million to $173 million, year over year, primarily a result of non-cash impairment charges on proved and unproved properties in the prior year. See Item 8. Financial Statements and Supplementary Data - Note 11 to the consolidated financial statements for 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.
Outlook
Capital Budget
On February 12, 2020, we announced our total 2020 Capital Budget of $2.4 billion, which includes $2.2 billion 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 Eagle Ford and Bakken and the remaining allocated between the Northern Delaware and Oklahoma.
Our 2020 Capital Budget is broken down by reportable segment in the table below:
(a)
Includes approximately $200 million of spend to fund REx.
(b)
International and corporate other includes our International segment and other corporate items.
Operations
Net 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 in 2019 as a result of dispositions and natural decline in E.G. The following table presents a summary of our sales volumes for each of our segments (refer to the Results of Operations section for a price-volume analysis for each of the segments).
(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 in the segment were higher during the year ended December 31, 2019 primarily as a result of new wells to sales in our U.S. resource plays. The following tables provide additional details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
•
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.
•
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 sales 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 78 mboed including oil sales volumes of 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.
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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
Net sales volumes in the segment were lower during the year ended December 31, 2019 primarily due to E.G. planned maintenance activities and natural field decline, coupled with the dispositions of our U.K. business and our non-operated interest in the Atrush block in Kurdistan. The following table provides details regarding net sales volumes for our significant operations within this segment:
(a) Includes natural gas acquired for injection and subsequent resale.
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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.
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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.
Market Conditions
Crude oil and condensate and NGLs benchmarks decreased in 2019 as compared to the same period in 2018. As a result, we experienced decreased price realizations associated with those benchmarks. We continue to expect crude oil and condensate, NGLs and natural gas benchmark prices to remain volatile based on global supply and demand, 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 declines in these commodity prices could impact us.
United States
The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for 2019, 2018 and 2017.
(a)
Excludes gains or losses on commodity derivative instruments.
(b)
Inclusion of realized gains (losses) on crude oil derivative instruments would have impacted average price realizations by $0.67 per bbl, $(4.60) per bbl, and $0.75 per bbl for 2019, 2018, and 2017.
(c)
Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal 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 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline.
Crude oil and condensate - Price realizations may differ from benchmarks due to the quality and location of the product.
Natural gas liquids - The majority of our sales volumes are at reference to Mont Belvieu prices.
Natural gas - A significant portion of volumes are sold at bid-week prices, or first-of-month indices relative to our producing areas.
International
The following table presents our average price realizations and the related benchmark for crude oil for 2019, 2018 and 2017.
(a)
Average of monthly prices obtained from the United States Energy Information Agency website.
United Kingdom
Crude oil and condensate - Generally sold in relation to the Brent crude benchmark. We closed on the sale of our U.K. business 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. Alba Plant LLC processes the rich hydrocarbon gas which is supplied by the Alba Field under a
fixed-price long term contract. Alba Plant LLC extracts NGLs and secondary condensate which is then sold by Alba Plant LLC at market prices, with our share of the revenue reflected in income from equity method investments on the consolidated statements of income. Alba Plant LLC delivers the processed dry natural gas to the Alba Field for distribution and sale to AMPCO and EG LNG.
Natural gas liquids - Wet gas is sold to Alba Plant LLC at a fixed-price term contract resulting in realized prices not tracking market price. Alba Plant LLC extracts and keeps NGLs, which are sold at market price, with our share of income from Alba Plant LLC being reflected in the income from equity method investments on the consolidated statements of income.
Natural gas - Dry natural gas, processed by Alba Plant LLC on behalf of the Alba Field, 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 LNG on a market-based long term contract and AMPCO markets methanol at market prices.
Consolidated Results of Operations: 2019 compared to 2018
Revenues from contracts with customers are presented by segment in the table below:
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.
Net loss on commodity derivatives increased $58 million in 2019 from 2018. 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 respective index pricing and forward curves change each period. See Note 15 to the consolidated financial statements for further information.
Income from equity method investments decreased $138 million as a result of lower price realizations and lower net sales volumes due to the 2019 triennial turnaround in E.G. and natural decline of the Alba field which resulted in lower net sales volumes for equity method investments.
Net gain on disposal of assets decreased $269 million in 2019 from 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 5 to the consolidated financial statements for information about these dispositions.
Other income decreased $88 million in 2019 from 2018 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 dispositions, which included the sale of our U.K. business on July 1, 2019. Our United States segment decreased $37 million primarily due to reduced water hauling costs with more water on pipe in the Northern Delaware and non-core asset dispositions in 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 production expense rate (per boe) declined during 2019 in the 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:
Shipping, handling and other operating expenses increased $30 million in 2019 from 2018 primarily as a result of increased sales volumes in our United States segment, partially offset by the sale of our U.K. business in the International segment.
Exploration expenses decreased $140 million during 2019 versus the comparable 2018. Decreases in unproved property impairments were driven by changes in impairment assumptions based on actual development experience. Also in 2018, there was $32 million of dry well costs and $16 million in unproved property impairments related to the Rodo well in Alba Block Sub Area B, offshore E.G. See Item 8. Financial Statements and Supplementary Data - Note 11 to the consolidated financial statements for details of these items.
The following table summarizes the components of exploration expenses:
Depreciation, depletion and amortization decreased $44 million in 2019 from 2018 primarily as a result of dispositions which included the sale of our U.K. business and the sale of certain non-core asset dispositions in our United States segment. Adding to the decrease were lower 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 (per boe), which is impacted by field-level changes in reserves, capitalized costs and sales volumes, can also impact 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 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:
Impairments decreased $51 million in 2019 from 2018 as a result of lower anticipated sales of certain non-core proved properties in our International and United States segments in the current period. See Item 8. Financial Statements and Supplementary Data - Note 11 to the consolidated financial statement for detail of proved property impairments each year.
General and administrative expenses decreased $38 million in 2019 compared to 2018. This was primarily the result of decreased compensation costs.
Provision (benefit) for income taxes reflects an effective tax benefit rate of 22% for 2019, as compared to an effective income tax expense rate of 23% for 2018. See Item 8. Financial Statements and Supplementary Data - Note 8 to the consolidated financial statements for a discussion of the effective income tax rate.
Segment Results: 2019 compared to 2018
Segment Income
Segment income represents income which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations 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, 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:
(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.
United States segment income increased $67 million after-tax in 2019 compared to 2018 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 income decreased $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 sales volumes and price realizations, offset by lower costs and taxes due 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 decrease was also attributed to dispositions of our U.K. business and our non-operated interest in the Atrush block in Kurdistan.
Consolidated Results of Operations: 2018 compared to 2017
A detailed discussion of the year-over-year changes from the year ended December 31, 2018 to December 31, 2017 can be found in the Management’s Discussion and Analysis section of our Annual Report on Form 10-K for the year ended December 31, 2018.
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 2019, we experienced a decrease in operating 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 dividend payments.
•
Asset acquisitions during the year of $293 million were paid with cash on hand.
•
Cash and cash equivalents decreased $604 million to $858 million at December 31, 2019.
•
During the fourth quarter, we completed three leverage neutral finance transactions which extend maturities and generate annual cash savings.
At December 31, 2019, we had approximately $3.9 billion of liquidity consisting of $858 million in cash and cash equivalents and $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 $2.4 billion Capital Budget for 2020. We believe our current liquidity level, cash flow from operations and ability to access the capital markets provides us with the flexibility to fund our business across a wide range of commodity price environments.
Cash Flows
The following table presents sources and uses of cash and cash equivalents for 2019 and 2018:
Cash flows generated from operating activities in 2019 were 15% lower as commodity price realizations decreased 13% along with lower net sales volumes in our International segment as a result of E.G. planned maintenance and natural field decline, coupled with dispositions.
Disposals of assets in 2019 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 a 25% non-operated working interest in the Louisiana Austin Chalk as well as the sale of our non-operated interest in the Atrush block in Kurdistan. Proceeds from the disposals of assets for 2018 are primarily related to our non-operated interest in Libya, as well as the remaining proceeds from the sale of our Canadian business. Disposition transactions are discussed in further detail in Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements.
Additions to property, plant and equipment in 2019 totaled $2.6 billion, consistent with expectations (last year, we communicated our $2.6 billion Capital Budget consisted of $2.4 billion in development capital and $200 million to fund resource play exploration.
The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:
(a)
The change in capital expenditure accrual includes activity for assets classified as held for sale for the years presented.
Additions to other assets relates to deposits on our resource play exploration program.
In the fourth quarter 2019, we acquired approximately 18,000 net acres in the Eagle Ford for $191 million and approximately 40,000 acres in a Texas 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 $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 17 to the consolidated financial statements for details of these items
During 2019 and 2018, the Board of Directors approved a $0.05 per share quarterly dividend. See Capital Requirements below for additional information about the fourth quarter 2019 dividend.
Available Liquidity
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.
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 revolving Credit Facility. At December 31, 2019, we had approximately $3.9 billion of liquidity consisting of $858 million in cash and cash equivalents and $3.0 billion available under our revolving 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 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 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.
General economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to access the capital markets. Our corporate credit ratings as of December 31, 2019 are: Standard & Poor’s Ratings Services BBB (stable); Fitch Ratings BBB (stable); and Moody’s Investor Services, Inc. Baa3 (stable). We are rated investment grade at all three primary credit rating agencies. In addition, we also have the ability to borrow 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 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.
Capital Resources
Credit Arrangements and Borrowings
At December 31, 2019, we had no borrowings against our Credit Facility or under our U.S. commercial paper program that is backed by the Credit Facility.
At December 31, 2019, we had $5.5 billion in long-term debt 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 seasoned 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
In the third quarter of 2019, we closed on the sale of our U.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 the pension obligations.
In the second quarter of 2019, 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 5 to the consolidated financial statements.
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 debt-to-capital ratio was 31% at both December 31, 2019 and 2018.
Capital Requirements
Capital Spending
Our approved Capital Budget for 2020 is $2.4 billion. Additional details were previously discussed in Outlook.
Share Repurchase Program
In 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, 2019 of $1.4 billion.
Other Expected Cash Outflows
On January 29, 2020, our Board of Directors approved a dividend of $0.05 per share for the fourth quarter of 2019. The dividend is payable on March 10, 2020 to shareholders of record on February 19, 2020.
We plan to make contributions of up to $28 million to our funded pension plans during 2020. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $6 million and $18 million in 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, 2019.
(a)
Includes anticipated cash payments for interest of $252 million for 2020, $503 million for 2021-2022, $415 million for 2023-2024 and $1.6 billion for the remaining years for a total of $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.
(d)
Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
(e)
Includes any drilling rigs and fracturing crews that are not considered lease obligations.
(f)
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2027. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.
(g)
This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $254 million. See Item 8. Financial Statements and Supplementary Data - Note 12 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, 2019, 2018 and 2017 aggregated $14 million, $52 million and $89 million. Most of the letters of credit are in support of obligations recorded in the consolidated balance sheet. In 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 support firm transportation agreements and future abandonment 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 will continue to incur 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 offset 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. 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.
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 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.
For more information on environmental regulations that impact us, or could impact us, see Item 1. Business - Environmental, Health and Safety Matters, Item 1A. Risk Factors and Item 3. Legal Proceedings.
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 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, 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 2019 SEC pricing for certain benchmark prices:
When determining the December 31, 2019 proved reserves for each property, the benchmark prices listed above were adjusted using price differentials that account for property-specific quality and location differences.
If crude oil prices in 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). For further discussion of risks associated with our estimation of proved reserves, see Part I. Item 1A. Risk Factors.
Depreciation and depletion of crude oil and condensate, NGLs and natural gas 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’s units-of-production DD&A per boe and pretax income to a hypothetical 10% change in 2019 proved reserves based on 2019 production.
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:
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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.
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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.
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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 16 to the consolidated financial statements for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
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assets and liabilities acquired in a business combination;
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assets acquired in an asset acquisition;
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impairment assessments of long-lived assets;
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impairment assessments of goodwill;
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recorded value of derivative instruments; and
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recorded value of 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, sustained declines in our common stock, reductions to our Capital 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 2019, proved property impairments were 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. We estimated the fair values using a market approach, based upon anticipated sales proceeds less costs to sell, and recognized impairments.
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:
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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.
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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.
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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.
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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.
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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 is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value 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 includes goodwill. As of December 31, 2019, our consolidated balance sheet included goodwill of $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 references 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 utilizes discounted cash flows, which are 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 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 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
We are exposed to market risks related to the volatility of crude oil and condensate, NGLs, and natural gas 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. 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
Index
Page
Management’s Responsibilities for Financial Statements
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Audited Consolidated Financial Statements
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
Select Quarterly Financial Data (Unaudited)
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Management’s Responsibilities for Financial Statements
To the Stockholders of Marathon Oil Corporation:
The accompanying consolidated financial statements of Marathon Oil Corporation and its consolidated subsidiaries (“Marathon Oil”) are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.
Marathon Oil seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organization arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.
The Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit and Finance Committee. This Committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.
/s/ Lee M. Tillman
/s/ Dane E. Whitehead
Chairman, President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
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, 2019.
The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 2019 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/ Dane E. Whitehead
Chairman, President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Marathon Oil Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Marathon Oil Corporation and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 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, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the 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’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our 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 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 regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial 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 20, 2020
We have served as the Company’s auditor since 1982.
MARATHON OIL CORPORATION
Consolidated Statements of Income
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Balance Sheet
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ Equity
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 an 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.
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 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 revenues 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 may have occurred. When a loss is deemed to have occurred and is 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.
Discontinued operations - As a result of the sale of our 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. See Note 5 for discussion of the divestiture in 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 associated with the sales 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 segment, liquid hydrocarbon production may be stored as inventory and sold at a later time.
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.
Accounts receivable - The majority of our receivables are from purchasers of commodities or joint interest owners in properties we operate, 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. We routinely assess the collectability of receivable balances to determine if the amount of the reserve in allowance for doubtful accounts is sufficient.
Inventories - Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net 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.
We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.
Derivative instruments - We may use derivatives to manage a portion of our exposure to commodity price risk, commodity locational risk and interest 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, 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. 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 changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until the hedged transaction affects earnings and are then reclassified into net income. Beginning in 2019, ineffective portions of a cash flow hedge are 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 cash flow hedge is no longer expected to be highly effective, subsequent changes in fair 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 and locational risks on the forecasted sale of crude oil, NGLs, and natural gas 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.
Property, plant and equipment - We use the successful efforts method of accounting for oil and gas producing activities.
Property acquisition costs - Costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells in progress and those that find proved reserves, and to drill development wells 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 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 depreciated on a straight-line basis over the estimated useful lives of the assets as summarized below.
Impairments - We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, 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.
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. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures and restoration costs of land, including those leased. Estimates of these costs are developed for each property based on the type of production facilities and equipment, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals.
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, while accretion of 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 Director restricted stock units is determined based on the market value of our common stock on the date of grant. Restricted Stock Awards, restricted stock units, and Director restricted stock units are 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
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” model as opposed to the current “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. The adoption of this standard did not result in a material impact on our consolidated results of operations, financial position and cash flows.
Recently Adopted
Lease accounting standard
In February 2016, the FASB issued a 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 13 for 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 amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard was effective for us in the first quarter of 2019. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
3. Income (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 periods, provided the effect is not antidilutive. The per share calculations below exclude $6 million, $6 million and 11 million stock options in 2019, 2018 and 2017 that were antidilutive.
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.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
2017 - United States Segment
In the fourth quarter of 2017, we closed on our acquisition of additional acreage in the Northern Delaware basin of New Mexico from a private seller for $63 million in cash and 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 two acquisitions which included approximately 91,000 net acres in the Permian basin of New Mexico. The first acquisition with BC 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.
5. Dispositions
United States Segment
In the third quarter of 2018, we closed on the sale of non-core, non-operated conventional properties, primarily in the Gulf of Mexico, for combined net proceeds of $16 million, before closing adjustments. A pre-tax gain of $32 million was recognized in the third quarter of 2018.
International Segment
On July 1, 2019, we closed on the sale of our U.K. business (Marathon Oil U.K. LLC and 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 capital and cash equivalent balances of approximately $345 million on December 31, 2018. 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 we continued to hold that guaranteed decommissioning liabilities of Marathon Oil U.K. LLC. In November 2019, RockRose posted replacement security and accordingly, 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 U.K. ARO and the defined benefit pension plan as it relates to this disposition.
In the second quarter of 2019, 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. This property was classified as held for sale in the consolidated balance sheet at December 31, 2018, with total assets of $58 million and total liabilities of $17 million.
In the first quarter of 2018, we closed on the sale of our subsidiary, 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 approximately $450 million, excluding closing adjustments, and recognized a pre-tax gain of $255 million.
Canadian Business - Discontinued Operations
On May 31, 2017 we closed on the sale 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 2018. In the first quarter of 2017, we recorded a non-cash impairment charge of $6.6 billion (after-tax of $4.96 billion) primarily related to the 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 held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a level 2 classification. As the effective date of the transaction was January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to results of operations from our Canadian business that were transferred to the buyer upon closing.
Our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. The following table contains select amounts reported in our historical consolidated statements of income and consolidated statements of cash flows as discontinued operations:
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
International
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.
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.
(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 two reportable operating segments. Both of these segments are organized and managed based upon geographic location and the nature of the products and services offered.
•
United States (“U.S.”) - explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States
•
International (“Int’l”) - explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States as well as produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
Segment income represents income which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations 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, 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.
As discussed in Note 5, the sale of our Canadian business in 2017 is reflected as discontinued operations and is excluded from segment information in all periods presented.
(a)
Includes accruals and excludes acquisitions.
(b)
Unrealized loss on commodity derivative instruments (see Note 15).
(c)
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 a result of anticipated sales of non-core proved properties in our International and United States segments (see Note 11).
(e)
Includes pension settlement loss of $12 million (see Note 19).
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(a)
Includes accruals and excludes acquisitions.
(b)
Unrealized gain on commodity derivative instruments (see Note 15).
(c)
Primarily related to the gain on sale of our Libya subsidiary (see Note 5).
(d)
Primarily a reduction of asset retirement obligations in our International segment (see Note 12).
(e)
Primarily related to dry well expense and unproved property impairments associated with the Rodo well in Alba Block Sub Area B, offshore E.G. (see Note 10).
(f)
Due to the anticipated sales of certain non-core proved properties in our International and United States segments (see Note 11).
(g)
Includes pension settlement loss of $21 million (see Note 19).
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(a)
Includes accruals and excludes acquisitions.
(b)
Unrealized loss on commodity derivative instruments (see Note 15).
(c)
Primarily related to the sale of 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 (see Note 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).
The following summarizes property, plant and equipment and equity method investments.
(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).
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
8. Income Taxes
Income (loss) from continuing operations before income taxes were:
Income tax provisions (benefits) for continuing operations were:
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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:
(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 is reported in the “Not Allocated to Segments” column of the tables in Note 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 2018 and 2017 due to the mix of pre-tax income between high and low tax jurisdictions, including Libya where the tax rate was 93.5%. Excluding Libya, the effective tax rates on continuing operations would be an expense of 14% in 2018 and 5% in 2017. As a result of the sale of our Libya subsidiary in the first quarter of 2018, we do not expect to incur further tax expense related to Libya.
Change in tax law - On 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 the corporate alternative minimum tax (“AMT”), and a one-time deemed repatriation of accumulated foreign earnings. In the fourth quarter of 2017, we remeasured our deferred taxes at 21%, in accordance with U.S. GAAP. The impact of the 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 tax position in the fourth quarter of 2018 with no material changes made to positions considered provisional as of December 31, 2017.
Other federal tax effects - The decrease in other federal tax effects is primarily related to the settlement of the 2010-2011 U.S. Federal Tax Audit (“IRS Audit”) in the first quarter of 2019. The release of the accrued tax positions resulted in a $126 million tax benefit, primarily related to AMT credits, see Note 25 for further detail.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Deferred tax assets and liabilities resulted from the following:
Operating loss carryforwards - At December 31, 2019, our operating loss carryforwards, relating to tax years beginning prior to January 1, 2018, before valuation allowance, include $655 million from the U.S. that expire in 2035 - 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 $20 million that begin to expire in 2020. State operating loss carryforwards of $181 million expire in 2020 through 2038.
Foreign tax credits - At December 31, 2019, we reflect foreign tax credits of $611 million, which will expire in years 2022 through 2026.
Valuation allowances - At December 31, 2019, we reflect a valuation allowance in our consolidated balance sheet of $699 million against our net deferred tax assets in 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 sale of our U.K. business and corresponding reduction in the asset retirement obligations and current year activity in the U.S.
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
We are routinely undergoing examinations in the jurisdictions in which we operate. As of December 31, 2019, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:
(a)
Includes federal and state jurisdictions.
The following table summarizes the activity in unrecognized tax benefits:
If the unrecognized tax benefits as of December 31, 2019 were recognized, $13 million would affect our effective income tax rate. As of December 31, 2019, there are $5 million uncertain tax positions for which it is reasonably possible that the amount could significantly change 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 $6 million, $2 million and $27 million related to unrecognized tax benefits in 2019, 2018 and 2017. As of December 31, 2019 and 2018, $3 million and $27 million of interest and penalties were accrued related to income taxes.
9. Inventories
Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net 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.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
10. Property, Plant and Equipment
(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 2017 we had total deferred exploratory well costs as follows:
(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 no exploratory well costs capitalized greater than one year as of December 31, 2019 and December 31, 2018.
11. Impairments
The following table summarizes impairment charges of proved 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 - 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
•
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 location differentials and forecasted operating expenses for the remaining estimated life of the reservoir which resulted in a Level 3 classification.
See Note 5 for discussion of the divestitures in further detail and Note 7 for relevant detail regarding segment presentation.
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 the periods ended December 31 were as follows:
(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.
•
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.
•
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.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
13. Leases
Supplemental balance sheet information related to leases was as follows:
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 fracturing equipment, compressors, buildings, aircraft, vessels, vehicles and miscellaneous field equipment. We primarily act as a lessee in these transactions and all of our existing leases are classified as either short-term or long-term operating leases.
The majority of the drilling 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 use 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 election not to separate the lease and nonlease components, fixed payments related to equipment, crew and other nonlease components are included in the 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
Our 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 signatory 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 leased assets for joint operations, we have the contractual right to recover the other working interest owners’ share of lease costs. As a result, our 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 variable lease costs are capitalized into property, plant and equipment.
(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 periodic incremental borrowing rate to discount future contractual payments to their present values. The weighted average lease term and the 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.
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:
* Future minimum commitments for capital lease obligations were nil 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 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 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 new Houston office is ready for occupancy. At the end of the initial lease term, we can negotiate to extend the lease term 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.
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, or between annual tests when events or changes in circumstances indicate the fair value 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 includes goodwill. We 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 references 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 utilizes discounted cash flows, which are based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons 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. This quantitative goodwill test would represent Level 3 fair value measurements.
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 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.
As of December 31, 2019 and 2018 our International segment is the only reporting segment which includes goodwill. The table below displays the allocated beginning goodwill balance of our International segment along with changes in the carrying amount of goodwill for 2019 and 2018:
(a)
Primarily related to the sale of our Libya subsidiary (see Note 5).
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 1 for 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.
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 17 for 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).
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:
(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.
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 13 for 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.
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 Values - Recurring
The following tables’ present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2019 and 2018 by hierarchy level.
(a)
Derivative instruments are recorded on a net basis in our consolidated balance sheet (see Note 15).
Commodity derivatives include three-way collars and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For 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, 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.
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 15 for details on the forward starting interest swaps.
Fair Values - Goodwill
See Note 14 for detail information relating to goodwill.
Fair Values - Nonrecurring
See Note 5 and Note 11 for detail on our fair values for nonrecurring items, such as impairments.
Fair Values - Financial Instruments
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 values by individual balance sheet line item at December 31, 2019 and 2018.
(a)
Excludes debt issuance 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.
All of our long-term debt instruments are publicly traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of our debt.
17. Debt
Revolving Credit Facility
In September 2019, we entered into a fourth amendment to our unsecured revolving credit facility (the “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 of December 31, 2019, we had no borrowings against our $3.0 billion Credit Facility or under our U.S. commercial paper program that is backed by the Credit 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, 2019, we were in compliance with this covenant with a debt-to-capitalization ratio of 31%.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Long-term debt
The following table details our long-term debt:
(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, 2019 may be declared immediately due and payable.
(c)
Mandatory purchase dates for these bonds: April 1, 2023 for the 2.00% bonds; July 1, 2024 for the 2.10% bonds; and July 1, 2026 for 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:
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, 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 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 no 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 zero 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
Total 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 no tax benefits realized for deductions for stock awards settled during 2019, 2018 and 2017.
Stock option awards - During 2019, 2018 and 2017 we granted stock option awards to officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:
The following is a summary of stock option award activity in 2019.
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.
Restricted stock awards and restricted stock units - The following is a summary of restricted stock and restricted stock unit award activity in 2019.
The vesting date fair value of restricted stock awards which vested during 2019, 2018 and 2017 was $48 million, $48 million and $39 million. The weighted average grant date fair value of restricted stock awards was $15.88, $14.04 and $14.24 for awards unvested at December 31, 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
The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units granted in 2019, 2018 and 2017 were:
(a)
Represents key assumptions at grant date, as 2019 performance unit awards are settled in 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.
19. Defined Benefit Postretirement Plans and Defined Contribution Plan
We have noncontributory defined benefit pension plans covering substantially all domestic employees. Benefits under these plans are based on plan provisions specific to each plan.
We also had a noncontributory defined benefit pension plan covering eligible U.K. employees that was transferred to the buyer in connection with the sale of our U.K. business during 2019. See Note 5 for further information on this disposition. During the year ended December 31, 2019, we reclassified $20 million from accumulated other comprehensive income to pension assets upon remeasurement of the plan.
We also have 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.
(a)
Refer to Note 5 for further information on the sale of our U.K. 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.
(a)
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan’s total service and interest costs for that year.
(b)
Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
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 2020 are $9 million and $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 2020 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 2019, 2018 and 2017.
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
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 (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’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’s assets are managed by a third-party investment manager.
International plan - As mentioned above, the plan covering eligible U.K. employees that was transferred to the buyer in connection with the sale of 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, 2019 and 2018.
Cash and cash equivalents - Cash and cash equivalents are valued using a market approach and are considered Level 1.
Equity securities - Investments in common stock 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, 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 pooled funds are valued using a market approach, these various funds consist of equity with underlying investments held in U.S. and non-U.S. securities. The pooled funds are benchmarked against a relative public index 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”) are valued at the closing price reported in an active market and are considered Level 1. Corporate bonds, private placements, and GNMA/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 fixed 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
approach, and primarily have investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds and are considered Level 2.
Other - Other investments are comprised of an unallocated annuity contract, two limited liability companies, and real estate. 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’s assets, by level within the fair value hierarchy, as of December 31, 2019 and 2018.
(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.
The activity during the year ended December 31, 2019 and 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, 2019 and reflect expected future services, as appropriate, are to be paid in the years indicated.
Contributions to defined benefit plans - We expect to make contributions to the funded pension plan of up to $28 million in 2020. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $6 million and $18 million in 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 in 2019, 2018 and 2017.
20. Reclassifications Out of Accumulated Other Comprehensive Income (Loss)
The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss):
(a)
See Note 19 for detail on the U.K. pension plan.
(b)
See Note 5 for detail on the U.K. disposition.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
21. Supplemental Cash Flow Information
(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
Foreign currency - Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
23. Equity Method Investments
During 2019, 2018 and 2017 our equity method investees were considered 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:
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:
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 no 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 repurchase program, which increased the remaining share repurchase authorization to $1.5 billion. During 2019, we acquired approximately 24 million of common shares at a cost of $345 million, which were held as treasury stock. During 2018, we acquired 36 million of common shares at a cost of $700 million under the same program. As of December 31, 2019 the total remaining share repurchase authorization was $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. 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.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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 5 for 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 have incurred and will continue to incur 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 offset by the 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, 2019 and 2018, accrued liabilities for remediation were not 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 - Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Contract commitments - At December 31, 2019 and 2018, contractual commitments to acquire property, plant and equipment totaled $41 million and $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 were $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)
(a)
The first and fourth quarter of 2019 includes mark-to-market loss on commodity derivatives of $113 million and $55 million.
(b)
The fourth quarter of 2018 includes a mark-to-market gain on commodity derivatives of $336 million and unproved property impairments and exploratory dry well costs of $49 million in the fourth quarter of 2018. (See Item 8. Financial Statements and Supplementary Data - Note 11 to the consolidated financial statements). Additionally, the first quarter of 2018 includes a gain on sale of our Libya subsidiary of $255 million. (See Item 8. Financial Statements and Supplementary Data - Note 5 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.; E.G.; Libya; and Other International (“Other 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 have established a robust series of internal controls, policies and processes intended to ensure the quality and accuracy of our internal 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)
Estimated Quantities of Proved Oil and Gas Reserves
The estimation of net recoverable quantities of crude oil and condensate, NGLs, natural gas and our historical 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 Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates, commodity prices are volatile which can have an impact on proved reserves. If crude oil prices in 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:
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
(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)
2019 proved reserves decreased by 76 mmboe primarily due to the following:
•
Revisions of previous estimates: Increased by 1 mmboe as referenced below:
Increases:
•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 to technical revisions in E.G.
Decreases:
•24 mmboe due 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 expansion of proved 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. assets
•5 mmboe associated with the sale of the Atrush block in Kurdistan
2018 proved reserves decreased by 168 mmboe primarily due to the following:
•
Revisions of previous estimates: Increased by 84 mmboe as referenced below:
Increases:
•
108 mmboe 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
•33 mmboe associated with wells to sales from unproved categories
•
Production: Decreased by 153 mmboe.
•
Sales of reserves in place: Decreased by 201 mmboe as referenced below:
Decreases:
•196 mmboe associated with the sale of our subsidiary in Libya
•4 mmboe associated with divestitures of certain conventional assets in New Mexico and Michigan
•1 mmboe associated with the sale of the Sarsang block in Kurdistan
2017 proved reserves decreased by 647 mmboe primarily due to the following:
•
Revisions of previous estimates: Increased by 49 mmboe as referenced below:
Increases:
•44 mmboe due to the acceleration of higher economic wells in the 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:
Increases:
•685 mmboe associated with the sale of our 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
The following table shows changes in proved undeveloped reserves for 2019:
Revisions of prior estimates: Increased by 18 mmboe as referenced below:
Increases:
•16 mmboe associated with in-year drill schedule changes
•11 mmboe associated with planned compression in E.G.
Decreases:
•5 mmboe due to changes in the 5-year plan 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 the U.S. resource plays as referenced below:
Increases:
•28 mmboe in Oklahoma
•25 mmboe in Permian
•15 mmboe in Bakken
Transfers to proved developed: 139 mmboe of PUD reserves were converted to proved developed status during 2019, primarily from assets in our U.S. resource plays. This 2019 transfer equates to a 26% PUD conversion rate and a 5-year average annual PUD conversion rate during the 2015-2019 period of 20%. All proved undeveloped reserve drilling locations are scheduled to be producing within five years of the initial booking date.
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Costs Incurred & Future Costs to Develop
Costs incurred in 2019, 2018 and 2017 relating to the development of proved undeveloped reserves were $1,261 million, $1,082 million and $842 million.
The following table shows future development costs estimated to be required for the development of proved undeveloped reserves for future years.
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization
(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)
(a)
Includes costs incurred whether capitalized or expensed.
(b)
Includes revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of abandonment activities.
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
(a)
Includes net gain (loss) on dispositions (see Note 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, and other.
(c)
Includes long-lived asset impairments (see Note 11).
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:
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 liquids, and natural gas reserves.
(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
(a)
Includes amounts resulting from changes in the timing of production.
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, 2019.
Management’s Annual Report on Internal Control Over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” under Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” under Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
During the fourth quarter of 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 1: Election of Directors,” “Corporate Governance-Committees of the Board” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 2020 Annual Meeting of Stockholders, to be filed with the SEC within 120 days of December 31, 2019 (the “2020 Proxy Statement”).
See “Executive Officers of the Registrant” under Item 1 of this Form 10-K for information about our executive officers.
Our Code of Ethics for Senior Financial Officers, which 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 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 Governance-Compensation Committee Interlocks and Insider Participation,” “Compensation Committee Report,” “Director Compensation,” “Compensation Discussion and Analysis” and “Executive Compensation” in the 2020 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 Ownership of Certain Beneficial Owners and Management” in the 2020 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2019 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”)
•
Marathon Oil Corporation 2012 Incentive Compensation Plan (the “2012 Plan”) - No additional awards will be granted under this plan.
•
Marathon Oil Corporation 2007 Incentive Compensation Plan (the “2007 Plan”) - No additional awards will be granted under this plan.
(a)
Includes the following:
•
No 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; 989,835 stock options outstanding under the 2007 Plan;
•
181,982 common stock units that have been credited to non-employee directors pursuant to the annual director stock award program established under the 2019 Plan, 2016 Plan, 2012 Plan and 2007 Plan. Common stock units credited under the 2019 Plan, 2016 Plan, 2012 Plan and 2007 Plan were nil 153,119, nil, and 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, 6,060,945 and 276,719 shares of restricted stock were issued and outstanding as of December 31, 2019, but subject to forfeiture restrictions under the 2016 Plan and 2019 Plan, respectively.
(b)
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.
(c)
Reflects the shares available for issuance under the 2019 Plan. No more than 30,775,974 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.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item is incorporated by reference to “Transactions with Related Persons,” and “Proposal 1: Election of Directors-Director Independence” in the 2020 Proxy Statement.
Item 14. Principal Accountant Fees and Services
Information required by this item is incorporated by reference to “Proposal 2: Ratification of Independent Auditor for 2020“ in the 2020 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 - The 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 20, 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, 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 20, 2020 on behalf of the registrant and in the capacities indicated.
Signature
Title
/s/ LEE M. TILLMAN
Chairman, President and Chief Executive Officer
Lee M. Tillman
/s/ DANE E. WHITEHEAD
Executive Vice President and Chief Financial Officer
Dane E. Whitehead
/s/ GARY E. WILSON
Vice President, Controller and Chief Accounting Officer
Gary E. Wilson
/s/ GREGORY H. BOYCE
Director
Gregory H. Boyce
/s/ CHADWICK C. DEATON
Director
Chadwick C. Deaton
/s/ MARCELA E. DONADIO
Director
Marcela E. Donadio
/s/ JASON B. FEW
Director
Jason B. Few
/s/ DOUGLAS L. FOSHEE
Director
Douglas L. Foshee
/s/ M.ELISE HYLAND
Director
M. Elise Hyland
/s/ J.KENT WELLS
Director
J. Kent Wells
Exhibit Index