Phillips 66
Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as affect the value of an investment in our common stock.
Our operating results and future rate of growth are exposed to the effects of changing commodity prices and refining, marketing and petrochemical margins.
Our revenues, operating results and future rate of growth are highly dependent on a number of factors, including fixed and variable expenses (including the cost of crude oil, NGL, and other refining and petrochemical feedstocks) and the margin we can derive from selling refined and Chemicals segment products. The prices of feedstocks and our products fluctuate substantially. These prices depend on numerous factors beyond our control, including the global supply and demand for feedstocks and our products, which are subject to, among other things:
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Changes in the global economy and the level of foreign and domestic production of crude oil, natural gas and NGL and refined, petrochemical and plastics products.
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Availability of feedstocks and refined products and the infrastructure to transport feedstocks and refined products.
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Local factors, including market conditions, the level of operations of other facilities in our markets, and the volume of products imported and exported.
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Threatened or actual terrorist incidents, acts of war and other global political conditions.
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Government regulations.
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Weather conditions, hurricanes or other natural disasters.
The price of crude oil influences prices for refined products. We do not produce crude oil and must purchase all of the crude oil we process. Many crude oils available on the world market will not meet the quality restrictions for use in our refineries. Others are not economical to use due to excessive transportation costs or for other reasons. The prices for crude oil and refined products can fluctuate differently based on global, regional and local market conditions. In addition, the timing of the relative movement of the prices (both among different classes of refined products and among various global markets for similar refined products), as well as the overall change in refined product prices, can reduce refining margins and could have a significant impact on our refining, wholesale marketing and retail operations, revenues, operating income and cash flows. Also, crude oil supply contracts generally have market-responsive pricing provisions. We normally purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Changes in prices that occur between when we purchase feedstocks and when we sell the refined products produced from these feedstocks could have a significant effect on our financial results. We also purchase refined products produced by others for sale to our customers. Price changes that occur between when we purchase and sell these refined products also could have a material adverse effect on our business, financial condition and results of operations.
The price of feedstocks also influences prices for petrochemical and plastics products. Although our Chemicals segment gathers, transports, and fractionates feedstocks to meet a portion of their demand and has certain long-term feedstock supply contracts with others, it is still subject to volatile feedstock prices. In addition, the petrochemicals industry is both cyclical and volatile. Cyclicality occurs when periods of tight supply, resulting in increased prices and profit margins, are followed by periods of capacity expansion, resulting in oversupply and declining prices and profit margins. Volatility occurs as a result of changes in supply and demand for products, changes in energy prices, and changes in various other economic conditions around the world.
Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on acceptable terms and can adversely affect the financial strength of our business partners.
Our ability to obtain credit and capital depends in large measure on the state of the credit and capital markets, which is beyond our control. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, access to those markets, which could constrain our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, preventing them from meeting their obligations to us.
From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are unable to obtain necessary funds from financing activities. From time to time, we may need to supplement cash generated from operations with proceeds from financing activities. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions to fund their commitments to us under our liquidity facilities. Accordingly, we may not be able to obtain the full amount of the funds available under our liquidity facilities to satisfy our cash requirements, and our failure to do so could have a material adverse effect on our operations and financial position.
Deterioration in our credit profile could increase our costs of borrowing money and limit our access to the capital markets and commercial credit, and could trigger co-venturer rights under joint venture arrangements.
Our or Phillips 66 Partners’ credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our or Phillips 66 Partners’ borrowing costs would increase, and our funding sources could decrease. In addition, a failure by us to maintain an investment grade rating could affect our business relationships with suppliers and operating partners. For example, our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if we experience a change in control or if both S&P and Moody’s lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks. As a result of these factors, a downgrade of credit ratings could have a materially adverse impact on our future operations and financial position.
We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.
Our business is subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:
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The discharge of pollutants into the environment.
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Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).
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The quantity of renewable fuels that must be blended into motor fuels.
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The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes.
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The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.
The U.S. Environmental Protection Agency (EPA) has implemented a Renewable Fuel Standard (RFS) pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. The RFS program sets annual quotas for the quantity of renewable fuels (such as ethanol) that must be blended into motor fuels consumed in the United States. To provide certain flexibility in compliance options available to the industry, a Renewable Identification Number (RIN) is assigned to each gallon of renewable fuel produced in, or imported into, the United States. As a producer of petroleum-based motor fuels, we are obligated to blend renewable fuels into the products we produce at a rate that is at least commensurate to the EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program. To the extent the EPA mandates a quantity of renewable fuel that exceeds the amount that is commercially feasible to blend into motor fuel (a situation commonly referred to as “the blend wall”), our operations could be materially adversely impacted, up to and including a reduction in produced motor fuel.
The adoption of climate change legislation or regulation could result in increased operating costs and reduced demand for the refined products we produce.
The U.S. government, including the EPA, as well as several state and international governments, have either considered or adopted legislation or regulations in an effort to reduce greenhouse gas (GHG) emissions. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. In addition, various groups suggest that additional laws may be needed in an effort to address climate change, as illustrated by the Paris Agreement negotiated at the 2015 United Nations Conference on Climate Change, referred to as COP 21, which entered into force on November 4, 2016. We cannot predict the extent to which any such legislation or regulation will be enacted and, if so, what its provisions would be. To the extent we incur additional costs required to comply with the adoption of new laws and regulations that are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected. In addition, demand for the refined products we produce could be adversely affected.
Climate change may adversely affect our facilities and our ongoing operations.
The potential physical effects of climate change on our operations are highly uncertain and depend upon the unique geographic and environmental factors present. Examples of such effects include rising sea levels at our coastal facilities, changing storm patterns and intensities, and changing temperature levels. As many of our facilities are located near coastal areas, rising sea levels may disrupt our ability to operate those facilities or transport crude oil and refined petroleum products. Extended periods of such disruption could have an adverse effect on our results of operation. We could also incur substantial costs to protect or repair these facilities.
Domestic and worldwide political and economic developments could affect our operations and materially reduce our profitability and cash flows.
Actions of the U.S., state, local and international governments through tax and other legislation or regulation, executive order, permit or other review of infrastructure or facility development, and commercial restrictions could delay projects, increase costs, limit development, or otherwise reduce our operating profitability both in the United States and abroad. Any such actions may affect many aspects of our operations, including requiring permits or other approvals that may impose unforeseen or unduly burdensome conditions or potentially cause delays in our operations; further limiting or prohibiting construction or other activities in environmentally sensitive or other areas; requiring increased capital costs to construct, maintain or upgrade equipment or facilities; or restricting the locations where we may construct facilities or requiring the relocation of facilities. In addition, the U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments could limit our ability to operate in, or gain access to, opportunities in various countries, as well as limit our ability to obtain the optimum slate of crude oil and other refinery feedstocks. Our foreign operations and those of our joint ventures are further subject to risks of loss of revenue, equipment and property as a result of expropriation, acts of terrorism, war, civil unrest and other political risks; unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities; and difficulties enforcing rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Our foreign operations and those of our joint ventures are also subject to fluctuations in currency exchange rates. Actions by both the United States and host governments may affect our operations significantly in the future.
Renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for refined products. Tax incentives and other subsidies can make renewable fuels and alternative energy more competitive with refined products than they otherwise might be, which may reduce refined product margins and hinder the ability of refined products to compete with renewable fuels.
Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.
We will not approve a large-scale capital project unless we expect it will deliver an acceptable level of return on the capital invested in the project. We base these forecasted project economics on our best estimate of future market conditions. Most large-scale projects take several years to complete. During this multi-year period, market conditions can change from those we forecast, and these changes could be significant. Accordingly, we may not be able to realize
our expected returns from a large investment in a capital project, and this could negatively impact our results of operations, cash flows and our return on capital employed.
Our investments in joint ventures decrease our ability to manage risk.
We conduct some of our operations, including parts of our Midstream, Refining and M&S segments, and our entire Chemicals segment, through joint ventures in which we share control with our joint venture participants. Our joint venture participants may have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or our joint venture participants may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint-venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.
Activities in our Chemicals and Midstream segments involve numerous risks that may result in accidents or otherwise affect the ability of our equity affiliates to make distributions to us.
There are a variety of hazards and operating risks inherent in the manufacturing of petrochemicals and the gathering, processing, transmission, storage, and distribution of natural gas and NGL, such as spills, leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of human life, damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Should any of these risks materialize, it could have a material adverse effect on the business and financial condition of our equity affiliates in these segments and negatively impact their ability to make future distributions to us.
Our operations present hazards and risks, which may not be fully covered by insurance, if insured. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.
The scope and nature of our operations present a variety of operational hazards and risks, including explosions, fires, toxic emissions, maritime hazards and natural catastrophes, that must be managed through continual oversight and control. For example, the operation of refineries, power plants, fractionators, pipelines, terminals and vessels is inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or refined products terminals, or in connection with any facilities that receive our wastes or by-products for treatment or disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with their remediation under federal, state, local and international environmental laws or common law, and could be liable for property damage to third parties caused by contamination from releases and spills. These and other risks are present throughout our operations. As protection against these hazards and risks, we maintain insurance against many, but not all, potential losses or liabilities arising from such operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil, NGL and refined products.
We often utilize the services of third parties to transport crude oil, NGL and refined products to and from our facilities. In addition to our own operational risks discussed above, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of a pipeline or vessel to transport crude oil, NGL or refined products to or from one or more of our refineries or other facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Increased regulation of hydraulic fracturing could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely impact our results of operations.
An increasing percentage of crude oil supplied to our refineries and the crude oil and gas production of our Midstream segment’s customers is being produced from unconventional sources. These reservoirs require hydraulic fracturing completion processes to release the hydrocarbons from the rock so they can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate hydrocarbon production. The U.S. Environmental Protection Agency, as well as several state agencies, have commenced studies and/or convened hearings regarding the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed to provide for such regulation. In addition, some communities have adopted measures to ban hydraulic fracturing in their communities. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be. Any additional levels of regulation and permits required with the adoption of new laws and regulations at the federal or state level could result in our having to rely on higher priced crude oil for our refineries. This could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through DCP Midstream’s gathering systems and could reduce supplies and increase costs of NGL feedstocks to CPChem ethylene facilities. This could materially adversely affect our results of operations and the ability of DCP Midstream and CPChem to make cash distributions to us.
DCP Midstream’s success depends on its ability to obtain new sources of natural gas and NGL. Any decrease in the volumes of natural gas DCP Midstream gathers could adversely affect its business and operating results.
DCP Midstream’s gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas wells, which will naturally decline over time. As a result, its cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on its gathering and transportation pipeline systems and NGL pipelines and the asset utilization rates at its natural gas processing plants, DCP Midstream must continually obtain new supplies. The primary factors affecting DCP Midstream’s ability to obtain new supplies of natural gas and NGL, and to attract new customers to its assets, include the level of successful drilling activity near these assets, prices of, and the demand for, natural gas and crude oil, producers’ desire and ability to obtain necessary permits in an efficient manner, natural gas field characteristics and production performance, surface access and infrastructure issues, and its ability to compete for volumes from successful new wells. If DCP Midstream is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells or because of competition, throughput on its pipelines and the utilization rates of its treating and processing facilities would decline. This could have a material adverse effect on its business, results of operations, financial position and cash flows, and its ability to make cash distributions to us.
Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.
The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We do not produce any of our crude oil feedstocks. Some of our competitors, however, obtain a portion of their feedstocks from their own production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.
Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our business. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers.
We may incur losses as a result of our forward-contract activities and derivative transactions.
We currently use commodity derivative instruments, and we expect to use them in the future. If the instruments we utilize to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions involve the risk that counterparties may be unable to satisfy their obligations to us. The risk of counterparty default is heightened in a poor economic environment.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Phillips 66 Partners LP, which may involve a greater exposure to legal liability than our historic business operations.
One of our subsidiaries acts as the general partner of Phillips 66 Partners LP, a publicly traded master limited partnership. Our control of the general partner of Phillips 66 Partners may increase the possibility that we could be subject to claims of breach of fiduciary duties, including claims of conflicts of interest, related to Phillips 66 Partners. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
A significant interruption in one or more of our facilities could adversely affect our business.
Our operations could be subject to significant interruption if one or more of our facilities were to experience a major accident, mechanical failure, or power outage, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any facility were to experience an interruption in operations, earnings from the facility could be materially adversely affected (to the extent not recoverable through insurance, if insured) because of lost production and repair costs. A significant interruption in one or more of our facilities could also lead to increased volatility in prices for feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.
Our performance depends on the uninterrupted operation of our facilities, which are becoming increasingly dependent on our information technology systems.
Our performance depends on the efficient and uninterrupted operation of the manufacturing equipment in our production facilities. The inability to operate one or more of our facilities due to a natural disaster; power outage; labor dispute; or failure of one or more of our information technology, telecommunications, or other systems could significantly impair our ability to manufacture our products. Our manufacturing equipment is becoming increasingly dependent on our information technology systems. A disruption in our information technology systems due to a catastrophic event or security breach could interrupt or damage our operations.
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect sensitive data, including personally identifiable information of our customers using credit cards at our branded retail outlets. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches has had a material effect on our business, operations or reputation (or compromised any customer data). Any such breaches could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of customer information, disrupt the services we provide to customers, and damage our reputation, any of which could adversely affect our business.
The level of returns on pension and postretirement plan assets and the actuarial assumptions used for valuation purposes could affect our earnings and cash flows in future periods.
Assumptions used in determining projected benefit obligations and the expected return on plan assets for our pension plan and other postretirement benefit plans are evaluated by us based on a variety of independent market information and in consultation with outside actuaries. If we determine that changes are warranted in the assumptions used, such as the discount rate, expected long-term rate of return, or health care cost trend rate, our future pension and postretirement benefit expenses and funding requirements could increase. In addition, several factors could cause actual results to differ significantly from the actuarial assumptions that we use. Funding obligations are determined based on the value of assets and liabilities on a specific date as required under relevant regulations. Future pension funding requirements, and the timing of funding payments, could be affected by legislation enacted by governmental authorities.
In connection with the Separation, ConocoPhillips has agreed to indemnify us for certain liabilities and we have agreed to indemnify ConocoPhillips for certain liabilities. If we are required to act on these indemnities to ConocoPhillips, we may need to divert cash to meet those obligations and our financial results could be negatively impacted. The ConocoPhillips indemnity may not be sufficient to insure us against the full amount of liabilities for which it has been allocated responsibility, and ConocoPhillips may not be able to satisfy its indemnification obligations in the future.
Pursuant to the Indemnification and Release Agreement and certain other agreements with ConocoPhillips entered into in connection with the Separation, ConocoPhillips agreed to indemnify us for certain liabilities, and we agreed to indemnify ConocoPhillips for certain liabilities. Indemnities that we may be required to provide ConocoPhillips are not subject to any cap, may be significant and could negatively impact our business, particularly indemnities relating to our actions that could impact the tax-free nature of the distribution of Phillips 66 stock. Third parties could also seek to hold us responsible for any of the liabilities that ConocoPhillips has agreed to retain. Further, the indemnity from ConocoPhillips may not be sufficient to protect us against the full amount of such liabilities, and ConocoPhillips may not be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from ConocoPhillips any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks could negatively affect our business, results of operations and financial condition.
We are subject to continuing contingent liabilities of ConocoPhillips following the Separation.
Notwithstanding the Separation, there are several significant areas where the liabilities of ConocoPhillips may become our obligations. For example, under the Internal Revenue Code and the related rules and regulations, each corporation that was a member of the ConocoPhillips consolidated U.S. federal income tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the Separation is jointly and severally liable for the U.S. federal income tax liability of the entire ConocoPhillips consolidated tax reporting group for that taxable period. In connection with the Separation, we entered into the Tax Sharing Agreement with ConocoPhillips that allocates the responsibility for prior period taxes of the ConocoPhillips consolidated tax reporting group between us and ConocoPhillips. ConocoPhillips may be unable to pay any prior period taxes for which it is responsible, and we could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.
If the distribution in connection with the Separation, together with certain related transactions, does not qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, our stockholders and ConocoPhillips could be subject to significant tax liability and, in certain circumstances, we could be required to indemnify ConocoPhillips for material taxes pursuant to indemnification obligations under the Tax Sharing Agreement.
ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) substantially to the effect that, among other things, the distribution, together with certain related transactions, qualified as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The private letter ruling and the tax opinion that ConocoPhillips received relied on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the private letter ruling nor the opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the private letter ruling does not address all the issues that are relevant to determining whether the distribution qualified for tax-free treatment. Notwithstanding the private letter ruling and the tax opinion, the IRS could determine the distribution should be treated
as a taxable transaction for U.S. federal income tax purposes if it determines any of the representations, assumptions or undertakings that were included in the request for the private letter ruling are false or have been violated or if it disagrees with the conclusions in the opinion that are not covered by the IRS ruling.
If the IRS were to determine that the distribution failed to qualify for tax-free treatment, in general, ConocoPhillips would be subject to tax as if it had sold the Phillips 66 common stock in a taxable sale for its fair market value, and ConocoPhillips stockholders who received shares of Phillips 66 common stock in the distribution would be subject to tax as if they had received a taxable distribution equal to the fair market value of such shares.
Under the Tax Sharing Agreement, we would generally be required to indemnify ConocoPhillips against any tax resulting from the distribution to the extent that such tax resulted from (i) any of our representations or undertakings being incorrect or violated, or (ii) other actions or failures to act by us. Our indemnification obligations to ConocoPhillips and its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify ConocoPhillips or such other persons under the circumstances set forth in the Tax Sharing Agreement, we may be subject to substantial liabilities.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to Phillips 66, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to SEC regulations.
Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.
New Matters
The California Air Resources Board (CARB) issued four separate Notices of Violation (NOV) to the company alleging violations of fuel specification requirements at our Los Angeles Refinery and Torrance Tank Farm. During a meeting with the CARB in January 2017, it proposed to have these four NOVs resolved with a total penalty payment of $190,000. We are working with the CARB to resolve these NOVs.
In October 2016, after receiving a Notice of Intent to Sue from the Sierra Club, we entered into a voluntary settlement with the Illinois Environmental Protection Agency for alleged violations of wastewater requirements at the Wood River Refinery. The settlement involves certain capital projects and payment of $125,000. The settlement has been filed with the Court for final approval and the Sierra Club has sought to intervene in the case to oppose the settlement. A court hearing is scheduled for March 2017.
Matters Previously Reported (unresolved or resolved since the quarterly report on Form 10-Q for the quarterly period ended September 30, 2016)
In October 2007, we received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at the Bayway Refinery and proposing a penalty of $156,000. We resolved this matter with the EPA in December 2016 with a settlement payment of $35,500.
In May 2012, the Illinois Attorney General’s office filed and notified us of a complaint with respect to operations at the Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit. The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures; additional spill reporting; and yet-to-be specified amounts for fines and penalties. We are working with the Illinois Environmental Protection Agency and Attorney General’s office to resolve these allegations.
In July 2014, Phillips 66 received an NOV from the EPA alleging various flaring-related violations between 2009 and 2013 at the Wood River Refinery. We are working with the EPA to resolve this NOV.
In September 2014, the EPA issued an NOV alleging a violation of hazardous air pollution regulations at the Wood River Refinery during 2014. We are working with the EPA to resolve this NOV.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Position Held
Age*
Greg C. Garland
Chairman and Chief Executive Officer
Tim G. Taylor
President
Robert A. Herman
Executive Vice President, Midstream
Paula A. Johnson
Executive Vice President, Legal and Government Affairs, General Counsel and Corporate Secretary
Kevin J. Mitchell
Executive Vice President, Finance and Chief Financial Officer
Lawrence M. Ziemba
Executive Vice President, Refining
Chukwuemeka A. Oyolu
Vice President and Controller
*On February 10, 2017.
There are no family relationships among any of the officers named above. The Board of Directors annually elects the officers to serve until a successor is elected and qualified or as otherwise provided in our By-Laws. Set forth below is information about the executive officers identified above.
Greg C. Garland is the Chairman and Chief Executive Officer of Phillips 66, after serving as Phillips 66’s Chairman, President and Chief Executive Officer from April 2012 to June 2014. Mr. Garland previously served as ConocoPhillips’ Senior Vice President, Exploration and Production-Americas from October 2010 to April 2012, and as President and Chief Executive Officer of CPChem from 2008 to 2010.
Tim G. Taylor is the President of Phillips 66, after serving as Executive Vice President, Commercial, Marketing, Transportation and Business Development from April 2012 to June 2014. Mr. Taylor retired as Chief Operating Officer of CPChem in 2011.
Robert A. Herman is Executive Vice President, Midstream for Phillips 66, a position he has held since June 2014. Previously, Mr. Herman served Phillips 66 as Senior Vice President, HSE, Projects and Procurement from February 2014 to June 2014, and Senior Vice President, Health, Safety, and Environment from April 2012 to February 2014. Mr. Herman was Vice President, Health, Safety, and Environment for ConocoPhillips from 2010 to 2012.
Paula A. Johnson is Executive Vice President, Legal and Government Affairs, General Counsel and Corporate Secretary of Phillips 66, a position she has held since October 2016. Previously, Ms. Johnson served as Executive Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66 from May 2013 to October 2016, and Senior Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66 from April 2012 to May 2013. Ms. Johnson served as Deputy General Counsel of ConocoPhillips from 2009 to 2012.
Kevin J. Mitchell is Executive Vice President, Finance and Chief Financial Officer of Phillips 66, a position he has held since January 2016. Previously, Mr. Mitchell served as Phillips 66’s Vice President, Investor Relations since joining the company in September 2014. Prior to joining the company, he served as the General Auditor of ConocoPhillips from May 2010 until September 2014.
Lawrence M. Ziemba is Executive Vice President, Refining of Phillips 66, a position he has held since February 2014. Prior to this, Mr. Ziemba served Phillips 66 as Executive Vice President, Refining, Projects and Procurement since April 2012. Mr. Ziemba served as President, Global Refining, at ConocoPhillips from 2010 to 2012.
Chukwuemeka A. Oyolu is Vice President and Controller of Phillips 66, a position he has held since December 2014. Mr. Oyolu was Phillips 66’s General Manager, Finance for Refining, Marketing and Transportation from May 2012 until February 2014 when he became General Manager, Planning and Optimization. Prior to this, Mr. Oyolu worked for ConocoPhillips as Manager, Downstream Finance, from 2009 to 2012.
PART II
Item 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Common Stock Prices and Cash Dividends Per Share
Phillips 66’s common stock is traded on the New York Stock Exchange (NYSE) under the symbol “PSX.” The following table reflects intraday high and low sales prices of, and dividends declared on, our common stock for each quarter presented:
Issuer Purchases of Equity Securities
*Includes repurchase of shares of common stock from company employees in connection with the company’s broad-based employee incentive plans, when applicable.
**Our Board of Directors has authorized repurchases totaling up to $9 billion of our outstanding common stock. The current authorization was announced in July 2014, in the amount of $2 billion, and increased to $4 billion as announced in October 2015. The authorization does not have an expiration date. The share repurchases are expected to be funded primarily through available cash. The shares under these authorizations will be repurchased from time to time in the open market at the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Shares of stock repurchased are held as treasury shares.
Item 6. SELECTED FINANCIAL DATA
For periods prior to the Separation, the following selected financial data consisted of the combined operations of the downstream businesses of ConocoPhillips. All financial information presented for periods after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66. Accordingly, the selected income statement data for the year ended December 31, 2012, consists of the consolidated results of Phillips 66 for the eight months ended December 31, 2012, and the combined results of the downstream businesses of ConocoPhillips for the four months ended April 30, 2012.
To ensure full understanding, you should read the selected financial data presented above in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and accompanying notes included elsewhere in this Annual Report on Form 10-K.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the company’s analysis of its financial performance, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to Phillips 66.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and specialties businesses. At December 31, 2016, we had total assets of $51.7 billion.
Executive Overview
We reported earnings of $1.6 billion in 2016 and generated $3.0 billion in cash from operating activities. Phillips 66 Partners LP issued debt and common units to the public for net proceeds totaling $2.1 billion. We used this available cash primarily to fund capital expenditures and investments of $2.8 billion, pay dividends of $1.3 billion and repurchase $1.0 billion of our common stock. We ended 2016 with $2.7 billion of cash and cash equivalents and approximately $5.5 billion of total capacity under both our and Phillips 66 Partners’ available liquidity facilities.
Our financial performance in 2016 demonstrated the benefit of a diversified portfolio of businesses in a low commodity price environment. We continue to focus on the following strategic priorities:
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Operating Excellence. Our commitment to operating excellence guides everything we do. We are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. Continuous improvement in safety, environmental stewardship, reliability and cost efficiency is a fundamental requirement for our company and employees. We employ rigorous training and audit programs to drive ongoing improvement in both personal and process safety as we strive for zero incidents. 2016 was our safest year since the company’s inception. Since we cannot control commodity prices, controlling operating expenses and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. We actively monitor and report these costs to senior management. Our operating and selling, general and administrative expenses were $5.9 billion in 2016, $6.0 billion in 2015 and $6.1 billion in 2014. We are committed to protecting the environment and strive to reduce our environmental footprint throughout our operations. Optimizing utilization rates at our refineries through reliable and safe operations enables us to capture the value available in the market in terms of prices and margins. During 2016, our worldwide refining crude oil capacity utilization rate was 96 percent, 5 percent higher than during 2015.
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Growth. We have budgeted $2.7 billion in capital expenditures and investments in 2017, including $0.4 billion for Phillips 66 Partners. Including our share of expected capital spending by joint ventures DCP Midstream, LLC (DCP Midstream), Chevron Phillips Chemical Company LLC (CPChem) and WRB Refining LP (WRB), our total 2017 capital program is expected to be $3.8 billion. After completing our U.S. Gulf Coast NGL market hub in 2016, we will focus Midstream development in 2017 around our existing infrastructure’s footprint. In Chemicals, CPChem progressed towards completion of its U.S. Gulf Coast ethane cracker and polyethylene facilities project during 2016. The polyethylene units are expected to be complete by mid-2017 and the ethane
cracker is expected to be complete in the fourth quarter of 2017. Growth capital in Refining will be directed toward small, high-return, quick-payout projects, while Marketing and Specialties will continue to expand and enhance its fuels marketing business.
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Returns. We plan to improve refining returns by increasing throughput of advantaged feedstocks, disciplined capital allocation and portfolio optimization. A disciplined capital allocation process ensures that we focus investments in projects that generate competitive returns throughout the business cycle. During 2016, we sold the Whitegate Refinery in Ireland as part of our ongoing portfolio optimization process. We improved clean product yield in 2016, and continued efforts to enhance the value of our marketing brands.
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Distributions. We believe shareholder value is enhanced through, among other things, consistent growth of regular dividends, supplemented by share repurchases. We increased our quarterly dividend rate by 13 percent during 2016, and have increased it 215 percent since our separation from ConocoPhillips in 2012 (the Separation). Regular dividends demonstrate the confidence our Board of Directors and management have in our capital structure and operations’ capability to generate free cash flow throughout the business cycle. In 2016, we repurchased $1.0 billion, or approximately 12.9 million shares, of our common stock. At the discretion of our Board of Directors, we plan to increase dividends annually and fund our share repurchase program while continuing to invest in the growth of our business.
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High-Performing Organization. We strive to attract, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and culture. Throughout the company, we focus on getting results in the right way and believe success is both what we do and how we do it. We encourage collaboration throughout our company, while valuing differences, respecting diversity, and creating a great place to work. We foster an environment of learning and development through structured programs focused on enhancing functional and technical skills where employees are engaged in our business and committed to their own, as well as the company’s, success.
Business Environment
Commodity prices remained compressed during 2016. The discount for U.S. benchmark West Texas Intermediate (WTI) versus the international benchmark Brent narrowed over much of 2016 as the reemergence of floating storage pressured prompt waterborne markets. Over the course of 2016, commodity prices had a variety of impacts, both favorable and unfavorable, on our businesses that vary by segment.
Earnings in the Midstream segment, which includes our 50 percent equity investment in DCP Midstream, are closely linked to NGL prices, natural gas prices and crude oil prices. Average natural gas prices in 2016 were slightly lower than 2015 due to warmer-than-normal temperatures and high storage. In the fourth quarter of 2016, natural gas prices gained momentum with colder temperatures and increased residential and commercial heating demand. Total U.S. dry natural gas production also increased through the fourth quarter of 2016, largely from the Marcellus play, where new pipeline takeaway capacity came online in December 2016. NGL prices improved slightly throughout 2016 due to an increase in export capacity in the United States.
During 2016, our Chemicals segment, which consists of our 50 percent equity investment in CPChem, continued to benefit from feedstock cost advantages associated with manufacturing ethylene in regions of the world with significant NGL production. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on supply and demand, as well as cost factors. The petrochemicals industry continues to experience lower ethylene cash costs in regions of the world where ethylene manufacturing is based upon NGL rather than crude oil-derived feedstocks. In particular, companies with North American light NGL-based crackers have benefited from lower-priced feedstocks. The ethylene-to-polyethylene chain margins remained positive, but they compressed in 2016 because of the significant decline in crude oil prices that began in 2014.
Our Refining segment results are driven by several factors including refining margins, cost control, refinery throughput and product yields. Refinery margins, often referred to as crack spreads, are measured as the difference between market prices for refined petroleum products and crude oil. During 2016, the U.S. 3:2:1 crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) weakened across all quarters compared with 2015, largely attributable to higher product inventories resulting from historically high refining throughput (especially in the Gulf Coast and Midcontinent regions). Northwest European crack spreads on average decreased in 2016 compared to 2015, also because of high product inventories resulting from high refinery utilization.
Results for our Marketing and Specialties (M&S) segment depend largely on marketing fuel margins, lubricant margins and other specialty product margins. While M&S margins are primarily based on market factors, largely determined by the relationship between supply and demand, marketing fuel margins, in particular, are influenced by the trend of spot prices for refined products. Generally speaking, a downward trend of spot prices has a favorable impact on marketing fuel margins, while an upward trend of spot prices has an unfavorable impact on marketing fuel margins.
RESULTS OF OPERATIONS
Consolidated Results
A summary of net income (loss) attributable to Phillips 66 by business segment follows:
2016 vs. 2015
Our earnings from continuing operations decreased $2,672 million, or 63 percent, in 2016, mainly reflecting:
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Lower realized refining margins.
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Lower olefins and polyolefins margins.
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Recognition in 2015 of $242 million of the deferred gain related to the sale in 2013 of the Immingham Combined Heat and Power Plant (ICHP).
These decreases were partially offset by:
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Lower equity losses from DCP Midstream, primarily as a result of goodwill and other asset impairments recorded in 2015.
2015 vs. 2014
Our earnings from continuing operations increased $171 million, or 4 percent, in 2015, primarily resulting from:
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Improved realized refining margins.
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Recognition of $242 million in 2015, compared with $126 million in 2014, of the deferred gain related to the sale in 2013 of ICHP.
These increases were partially offset by:
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Goodwill and other asset impairments recorded by DCP Midstream in 2015.
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Lower ethylene margins.
Discontinued operations in 2014 included the recognition of a noncash $696 million gain related to the Phillips Specialty Products Inc. (PSPI) disposition through a share exchange.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
2016 vs. 2015
Sales and other operating revenues and purchased crude oil and products both decreased 15 percent in 2016. The decreases were primarily due to lower average prices for petroleum products and crude oil, while average NGL prices were slightly improved during 2016.
Equity in earnings of affiliates decreased 10 percent in 2016, primarily resulting from decreased earnings from CPChem and WRB, partially offset by improved results from DCP Midstream.
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Equity in earnings of CPChem decreased 37 percent, primarily due to lower realized olefins and polyolefins margins.
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Equity in earnings of WRB decreased $186 million, mainly resulting from lower market crack spreads, partially offset by higher feedstock advantage.
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Equity in earnings of DCP Midstream improved $426 million in 2016, primarily driven by goodwill and other asset impairments recorded by DCP Midstream in 2015.
Net gain on dispositions decreased $273 million in 2016. In 2015, we recognized a $242 million deferred gain related to the sale of ICHP. See Note 6-Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information.
See Note 21-Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.
2015 vs. 2014
Sales and other operating revenues decreased 39 percent in 2015, while purchased crude oil and products decreased 46 percent. The decreases were primarily due to lower average prices for petroleum products, crude oil and NGL.
Equity in earnings of affiliates decreased 36 percent in 2015, primarily resulting from decreased earnings from DCP Midstream, CPChem and WRB.
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Equity in earnings of DCP Midstream decreased $676 million in 2015. The decrease was primarily due to lower NGL, crude oil and natural gas prices. In addition, DCP Midstream recorded goodwill and other asset impairments in 2015.
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Equity in earnings of CPChem decreased 19 percent, primarily due to lower ethylene margins and lower equity earnings from CPChem’s equity affiliates, partially offset by lower utility costs.
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Equity in earnings of WRB decreased 13 percent, primarily driven by lower realized refining margins resulting from lower feedstock advantage, partially offset by higher secondary product margins.
Impairments in 2015 were $7 million, compared with $150 million in 2014. There was a $131 million impairment of the Whitegate Refinery recorded in 2014. For additional information, see Note 10-Impairments, in the Notes to Consolidated Financial Statements.
Interest and debt expense increased 16 percent in 2015. The increase was mainly due to a higher average debt principal balance in 2015, partially offset by increased capitalized interest.
See Note 21-Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.
Segment Results
Midstream
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by NGL component and location mix.
*Pipelines represent the sum of volumes transported through each separately tariffed pipeline segment, including our share of equity volumes from Yellowstone Pipe Line Company and Lake Charles Pipe Line Company.
**Represents 100 percent of DCP Midstream’s volumes.
***Excludes DCP Midstream.
The Midstream segment gathers, processes, transports and markets natural gas; and transports, stores, fractionates and markets NGL in the United States. In addition, this segment transports crude oil and other feedstocks to our refineries and other locations, delivers refined and specialty products to market, and provides terminaling and storage services for crude oil and petroleum products. The segment also stores, refrigerates, and exports liquefied petroleum gas (LPG) primarily to Asia and Europe. The Midstream segment includes our master limited partnership (MLP), Phillips 66 Partners LP, as well as our 50 percent equity investment in DCP Midstream, LLC, which includes the operations of its MLP, DCP Midstream, LP (formerly named DCP Midstream Partners, LP and referred to herein as DCP Partners).
2016 vs. 2015
Earnings from the Midstream segment increased $165 million in 2016, compared with 2015. The increase was primarily due to improved results from DCP Midstream, partially offset by lower earnings from our Transportation and NGL businesses.
Transportation earnings decreased $42 million in 2016, compared with 2015. Lower earnings primarily resulted from higher operating costs, and increased depreciation expense due to growth projects, as well as increased income attributable to noncontrolling interests, reflecting the contribution of assets to Phillips 66 Partners. These items were partially offset by higher revenues from increased throughput volumes and higher tariffs.
Results from our investment in DCP Midstream improved $291 million in 2016, compared with 2015. In 2015, DCP Midstream recorded goodwill and other asset impairments, which reduced our earnings from DCP Midstream by $232 million, after-tax. In addition, favorable contract restructuring efforts, improved asset performance, higher earnings from DCP Midstream’s equity affiliates, lower operating costs and higher NGL prices contributed to better results in 2016. These improvements were partially offset by lower natural gas and crude oil prices.
Results from our NGL business decreased $84 million in 2016, compared with 2015. The decrease was primarily driven by lower realized margins, as well as increased depreciation and operating expenses associated with the Sweeny Fractionator and, late in the year, the Freeport LPG Export Terminal. These items were partially offset by higher fractionated volumes, reflecting the operation of the Sweeny Fractionator for a full year in 2016, and the benefit of the first liquefied petroleum gas cargos exported from the Freeport LPG Export Terminal in late 2016.
See the “Business Environment and Executive Overview” section for information on market factors impacting 2016 results.
2015 vs. 2014
Earnings from the Midstream segment decreased $494 million in 2015, compared with 2014. The decrease was primarily due to lower earnings from DCP Midstream and our NGL business, partially offset by higher earnings from our Transportation business.
Transportation earnings increased $55 million in 2015, compared with 2014. This increase reflects the startup of our Bayway and Ferndale crude oil rail unloading facilities in the second half of 2014, as well as a full year of operations from the Beaumont Terminal acquired in 2014. Increased railcar fleet activities, higher terminal revenues, and improved earnings from equity affiliates also benefited earnings in 2015. These benefits were partially offset by higher earnings attributable to noncontrolling interests.
Earnings associated with our investment in DCP Midstream decreased $459 million in 2015, compared with 2014. The decrease in 2015 mainly resulted from lower NGL, crude oil, and natural gas prices, partially offset by increased volumes due to asset growth and lower operating costs as a result of cost saving initiatives. In addition, goodwill and other asset impairments recorded by DCP Midstream in 2015 contributed to the loss recognized from our investment in DCP Midstream. DCP Midstream performed a goodwill impairment assessment and other asset impairment assessments based on internal discounted cash flow models taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rates. The impairment tests resulted in DCP Midstream’s recognition of a $460 million goodwill impairment and $342 million in other asset impairments, net of tax impacts. Together, these impairments reduced our equity earnings from DCP Midstream by $232 million after-tax.
DCP Partners periodically issues limited partner units to the public. These issuances benefited our equity in earnings from DCP Midstream, on an after-tax basis, by approximately $1 million in 2015, compared with approximately $45 million in 2014.
The earnings from our NGL business decreased $90 million in 2015, compared with 2014. The decrease was primarily driven by lower realized margins and higher earnings attributable to noncontrolling interests. We also incurred higher tax expense in 2015, driven by a lower manufacturing deduction resulting from bonus depreciation associated with the start-up of the Sweeny Fractionator. These decreases were partially offset by higher earnings from equity affiliates.
Chemicals
The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method. CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used as feedstocks to produce plastics and other chemicals. We structure our reporting of CPChem’s operations around two primary business segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business segment produces and markets ethylene and other olefin products; ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S business segment manufactures and markets aromatics and styrenics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene and styrene-butadiene copolymers. SA&S also manufactures and/or markets a variety of specialty chemical products. Unless otherwise noted, amounts referenced below reflect our net 50 percent interest in CPChem.
2016 vs. 2015
Earnings from the Chemicals segment decreased $379 million, or 39 percent, in 2016, compared with 2015. The decrease in earnings was primarily due to lower realized margins from the O&P business, driven by a decline in sales prices for polyethylene and normal alpha olefins (NAO) and higher feedstock costs, as well as impacts from increased turnaround activity. Lower equity earnings from CPChem’s equity affiliates and lower SA&S volumes further reduced earnings in 2016.
In addition, CPChem recognized a $177 million impairment in 2016 due to lower demand and margin factors affecting an equity affiliate, which resulted in an $89 million after-tax reduction in our equity earnings from CPChem. Our equity earnings from CPChem were reduced by $24 million in 2015 as a result of an impairment CPChem recognized on an equity affiliate. These items were partially offset by higher NAO and polyethylene sales volumes and improved SA&S margins.
See the “Business Environment and Executive Overview” section for information on market factors impacting CPChem’s results.
2015 vs. 2014
Earnings from the Chemicals segment decreased $175 million, or 15 percent, in 2015, compared with 2014. The decrease in earnings was primarily due to lower margins resulting from lower sales prices, lower earnings from CPChem’s O&P equity affiliates, and higher turnaround and maintenance activities.
These decreases were partially offset by higher ethylene and polyethylene sales volumes, as well as lower repair costs due to the impact on 2014 costs of a fire at CPChem’s Port Arthur, Texas facility. Lower feedstock costs, lower utility costs due to falling natural gas prices, and lower impairment charges also benefited the 2015 operating results.
In July 2014, a localized fire occurred in the olefins unit at CPChem’s Port Arthur, Texas facility, shutting down ethylene production. The Port Arthur ethylene unit restarted in November 2014. CPChem incurred, on a 100 percent basis, $85 million of associated repair and rebuild costs. Because the Port Arthur ethylene unit was down due to the fire, CPChem experienced a significant reduction in production and sales in several of its product lines stemming from the lack of the Port Arthur ethylene supply in 2014. CPChem recorded earnings, on a 100 percent basis, of $88 million and $120 million for business interruption and property damage insurance proceeds in 2015 and 2014, respectively.
Refining
The Refining segment buys, sells and refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels) at 13 refineries, mainly in the United States and Europe.
2016 vs. 2015
Earnings for the Refining segment decreased $2,181 million, compared with 2015. Lower earnings in 2016 reflected lower realized refining margins resulting from decreased market crack spreads, higher costs associated with renewable fuels blending activities, lower clean product differentials and lower feedstock advantage. These items were partially offset by higher volumes due to lower turnaround activities and less unplanned downtime.
See the “Business Environment and Executive Overview” section for information on industry crack spreads and other market factors impacting this year’s results.
Our worldwide refining crude oil capacity utilization rate was 96 percent in 2016, compared to 91 percent in 2015. The increase was primarily attributable to lower turnaround activities and less unplanned downtime.
Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. As more fully discussed in Note 5-Business Combinations, in the Notes to Consolidated Financial Statements, in February 2017, the time expired for all legal challenges related to the exercise in 2009 of a call right to acquire Petróleos de Venezuela S.A.’s (PDVSA) 50 percent share of MSLP, and we began accounting for MSLP as a wholly owned consolidated subsidiary. Based on a preliminary appraisal, the acquisition of PDVSA’s 50 percent interest is expected to result in our recording a noncash, pre-tax gain of approximately $420 million in the first quarter of 2017.
2015 vs. 2014
Earnings for the Refining segment increased $784 million, or 44 percent, compared with 2014. The increase in earnings in 2015 primarily resulted from higher realized refining margins due to higher gasoline crack spreads and improved secondary product margins, as well as lower utility costs. These increases were partially offset by lower feedstock advantage, lower distillate crack spreads, lower clean product differentials, and lower refining volumes as a result of higher unplanned downtime and turnaround activities.
Our worldwide refining crude oil capacity utilization rate was 91 percent in 2015, compared to 94 percent in 2014. The decrease reflects higher unplanned downtime and turnaround activities.
Marketing and Specialties
The M&S segment purchases for resale and markets refined petroleum products (such as gasoline, distillates and aviation fuels), mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products (such as base oils and lubricants), as well as power generation operations.
2016 vs. 2015
Earnings from the M&S segment decreased $296 million, or 25 percent, in 2016, compared with 2015. The decrease was mainly attributable to the $242 million deferred gain recognized in 2015 related to the 2013 ICHP sale. See Note 6-Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information.
Also contributing to the lower earnings in 2016 were lower realized marketing margins driven by an upward trend of spot prices during most of 2016, and lower margins and volumes in lubricants. These decreases were partially offset by favorable tax adjustments and higher marketing volumes.
See the “Business Environment and Executive Overview” section for information on marketing fuel margins and other market factors impacting 2016 results.
2015 vs. 2014
Earnings from the M&S segment increased $153 million, or 15 percent, in 2015, compared with 2014. In July 2013, we completed the sale of ICHP, and deferred the gain from the sale due to an indemnity provided to the buyer. We recognized $242 million after-tax and $126 million after-tax of the deferred gain in 2015 and 2014, respectively.
Earnings from the M&S segment also benefited from higher domestic marketing activities, higher domestic marketing and lubricants volumes, and increased tax credits from biodiesel blending activities. These benefits were partially offset by lower international marketing margins and lubricants margins.
Corporate and Other
2016 vs. 2015
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $24 million in 2016, compared with 2015, mainly due to lower capitalized interest.
The category “Other” includes certain income tax expenses, environmental costs associated with sites no longer in operation, foreign currency transaction gains and losses and other costs not directly associated with an operating segment. The decrease in other costs in 2016 was primarily attributable to favorable tax impacts, the write-off of certain fixed assets during 2015 and the impact of an increase in noncontrolling interests on interest expense incurred by Phillips 66 Partners, partially offset by higher environmental accruals.
2015 vs. 2014
Net interest expense increased $26 million in 2015, compared with 2014, primarily due to a higher average debt principal balance as a result of the issuance of debt in the fourth quarter of 2014 and Phillips 66 Partners’ debt issuance in the first quarter of 2015. The increase was partially offset by higher capitalized interest. For additional information, see Note 13-Debt, in the Notes to Consolidated Financial Statements.
The increase in other costs in 2015 was primarily due to foreign tax credit carryforwards that were utilized in 2014 and other tax adjustments made in 2015.
Discontinued Operations
In December 2013, we entered into an agreement to exchange the stock of PSPI, a flow improver business that was included in our M&S segment, for shares of Phillips 66 common stock owned by the other party to the transaction. In February 2014, we completed the PSPI share exchange, resulting in the receipt of approximately 17.4 million shares of Phillips 66 common stock and the recognition of a before-tax noncash gain of $696 million. See Note 6-Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information on this transaction.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities and Phillips 66 Partners’ debt and equity financings. During 2016, we generated $3.0 billion in cash from operations. Phillips 66 Partners issued debt and common units to the public for net proceeds totaling $2.1 billion. We used this available cash primarily for capital expenditures and investments ($2.8 billion); repurchases of our common stock ($1.0 billion); and dividend payments on our common stock ($1.3 billion). During 2016, cash and cash equivalents decreased by $0.4 billion, to $2.7 billion.
In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs, asset sales and our ability to issue securities using our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to external sources of funds as described below under “Significant Sources of Capital,” will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, debt repayment and share repurchases.
Significant Sources of Capital
Operating Activities
During 2016, cash of $2,963 million was provided by operating activities, a 48 percent decrease compared with 2015. The decrease was primarily attributable to lower realized refining margins, as well as a reduction in distributions from our equity affiliates. This decrease was partially offset by positive working capital of $501 million in 2016 compared to a negative working capital impact of $221 million in 2015. The positive working capital impact in 2016 was primarily driven by increased refining payables, due to an increase in feedstock costs at the end of 2016 as compared with 2015, and the timing of tax payments and refunds, partially offset by an increase in receivables, resulting from higher commodity prices. See the following paragraph for a discussion of 2015 working capital effects.
During 2015, cash of $5,713 million was provided by operating activities, a 62 percent increase from cash from operations of $3,529 million in 2014. Net income in 2015 was lower than 2014; however, in both years large noncash items affected earnings, including the gain on the PSPI exchange in 2014, recognition in 2015 and 2014 of a deferred gain from a 2013 asset disposition, and goodwill and other asset impairments by DCP Midstream in 2015. Excluding these items, underlying earnings in 2015 were slightly improved compared with 2014, primarily reflecting increased refining margins and increased domestic marketing volumes, partially offset by lower midstream prices. Negative working capital impacted operating cash flow by $221 million and $1,020 million in 2015 and 2014, respectively. The lower negative working capital impact in 2015 was driven by decreased refining payables due to lower feedstock costs in 2015 as compared with 2014, partially offset by a reduction in receivables due to reduced commodity prices.
Our short- and long-term operating cash flows are highly dependent upon refining and marketing margins, NGL prices and chemicals margins. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have little or no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level and quality of output from our refineries also impacts our cash flows. Factors such as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions can affect output. We actively manage the operations of our refineries, and any variability in their operations typically has not been as significant to cash flows as that caused by margins and prices. Our worldwide refining crude oil capacity utilization was 96 percent in 2016, compared with 91 percent in 2015.
Equity Affiliates
Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including DCP Midstream, CPChem and WRB. Over the three years ended December 31, 2016, we received distributions of $237 million from DCP Midstream, $2,241 million from CPChem and $1,568 million from WRB. We cannot control the amount or timing of future distributions from equity affiliates; therefore, future distributions by these and other equity affiliates are not assured.
Effective January 1, 2017, DCP Midstream, LLC and DCP Partners closed a transaction in which DCP Midstream, LLC contributed subsidiaries owning all of its operating assets, $424 million of cash and $3.15 billion of debt to DCP Partners, in exchange for DCP Partners units which had an estimated fair value of $1.125 billion at the time of the transaction. We and our co-venturer retained our 50/50 investment in DCP Midstream, LLC, and DCP Midstream, LLC retained its incentive distribution rights in DCP Partners through its ownership of the general partner of DCP Partners. After the transaction, DCP Midstream, LLC held a 38 percent interest in DCP Partners. DCP Midstream, LLC, through its ownership of the general partner, has agreed, if required, to forgo receipt of incentive distribution rights up to $100 million annually (100 percent basis) through 2019, to support a minimum distribution coverage ratio for DCP Partners. In connection with the transaction, DCP Midstream, LLC terminated its revolving credit agreement, which had previously served to limit distributions to its owners while amounts had been borrowed under the facility. As a result, we expect distributions to the owners of DCP Midstream, LLC to resume in 2017 as it receives distributions from DCP Partners.
In 2015, CPChem made a special distribution to its owners, with our share totaling $696 million. CPChem funded the distribution by issuing $1.4 billion of senior notes with maturities ranging from three to five years, with a combination of fixed and variable interest rates. This cash inflow from CPChem was included in operating cash flows, as we had cumulative undistributed equity earnings attributable to CPChem in excess of the amount distributed. CPChem’s U.S. Gulf Coast project is expected to be completed and begin commercial operations during 2017. As a result, we expect distributions from CPChem to increase starting in 2017, as capital spending by CPChem on this project ends.
WRB is a 50-percent-owned business venture with Cenovus Energy Inc. (Cenovus). Cenovus was obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007. In 2014, Cenovus prepaid its remaining balance under this obligation. As a result, WRB declared a special dividend, which was distributed to the co-venturers in 2014. Of the $1,232 million that we received, $760 million was considered a return on our investment in WRB (an operating cash inflow), and $472 million was considered a return of our investment in WRB (an investing cash inflow). The return-of-investment portion of the dividend was included in the “Proceeds from asset dispositions” line in our consolidated statement of cash flows. A further $129 million of distributions from WRB during 2014 was considered a return of investment.
Asset Sales
Net proceeds from asset sales in 2016 were $156 million compared with $70 million in 2015 and $1,244 million in 2014. The 2016 net proceeds were primarily attributed to the sale of the Whitegate Refinery in Ireland. The 2015 net proceeds were attributed to the sale of the Bantry Bay terminal in Ireland and the sale of certain retail sites in Kansas and Missouri, and were partially offset by a working capital true-up related to the 2014 sale of our interest in the Malaysia Refining Company Sdn. Bdh. (MRC). The 2014 proceeds included a portion of the WRB special dividend as discussed above, as well as the sale of our interest in MRC.
Foreign Cash Holdings
At December 31, 2016, approximately 53 percent of our consolidated cash and cash equivalents balance was available to fund domestic opportunities without incurring material U.S. income taxes in excess of the amounts already accrued in the financial statements. We believe the remaining amount, primarily attributable to cash we hold in foreign locations where we have asserted our intention to indefinitely reinvest earnings, does not materially affect our consolidated liquidity due to the following factors:
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A substantial portion of our foreign cash supports the liquidity needs and regulatory requirements of our foreign operations.
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We have the ability to fund a significant portion of our domestic capital requirements with cash provided by domestic operating activities.
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We have access to U.S. capital markets through our $5 billion committed revolving credit facility, commercial paper program, and universal shelf registration statement.
See Note 21-Income Taxes, in the Notes to Consolidated Financial Statements, for additional information on income taxes associated with foreign earnings.
Phillips 66 Partners LP
In 2013 we formed Phillips 66 Partners LP, a publicly traded master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product, and NGL pipelines and terminals, as well as other Midstream assets.
Ownership
At December 31, 2016, we owned a 59 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while its public unitholders owned a 39 percent limited partner interest. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3-Variable Interest Entities, in the Notes to Consolidated Financial Statements, for additional information on why we consolidate the partnership. As a result of this consolidation, the public unitholders’ ownership interest in Phillips 66 Partners is reflected as a $1,306 million noncontrolling interest in our consolidated balance sheet at December 31, 2016. Generally, drop down transactions to Phillips 66 Partners will eliminate in consolidation, except for third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. Through the public offerings of common units and senior notes discussed below, our consolidated cash increased by $2.1 billion, consolidated debt increased by $1.1 billion and consolidated equity increased by $791 million.
Debt and Equity Financings
During the three years ended December 31, 2016, Phillips 66 Partners closed on the following public securities offerings in which it raised net proceeds of approximately $3.6 billion:
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In October 2016, Phillips 66 Partners received net proceeds of $1,111 million from the issuance of $500 million of 3.55% Senior Notes due 2026 and $625 million of 4.90% Senior Notes due 2046.
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In August 2016, Phillips 66 Partners received net proceeds of $299 million from a public offering of 6 million common units, at a price of $50.22 per unit.
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In June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which allows for the offering of up to $250 million of common units. Through December 31, 2016, net proceeds of $19 million had been received under this program.
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In May 2016, Phillips 66 Partners received net proceeds of $656 million from a public offering of 12.65 million common units, at a price of $52.40 per unit.
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In February 2015, Phillips 66 Partners received net proceeds of $1,092 million from the issuance of $300 million of 2.646% Senior Notes due 2020, $500 million of 3.605% Senior Notes due 2025, and $300 million of 4.680% Senior Notes due 2045.
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In February 2015, Phillips 66 Partners received net proceeds of $384 million from a public offering of 5.25 million common units, at a price of $75.50 per unit.
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66. See Note 27-Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on Phillips 66 Partners and additional details on assets contributed to the partnership by us during 2016.
Credit Facilities and Commercial Paper
In October 2016, we amended our Phillips 66 revolving credit facility, primarily to extend the term from December 2019 to October 2021. Borrowing capacity under the Phillips 66 facility remained at $5 billion. The facility may be used for direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowings under the facility will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor’s Ratings Services (S&P) and Moody’s Investors Service (Moody’s). The facility also provides for customary fees, including administrative agent fees and commitment fees. As of December 31, 2016, no amount had been directly drawn under our $5 billion credit facility; however, $51 million in letters of credit had been issued that were supported by this facility.
We have a $5 billion commercial paper program for short-term working capital needs that is supported by our revolving credit facility. Commercial paper maturities are generally limited to 90 days. As of December 31, 2016, we had no borrowings under our commercial paper program.
Phillips 66 Partners also amended its revolving credit facility in October 2016, primarily to increase its borrowing capacity to $750 million and to extend the term from November 2019 to October 2021. The Phillips 66 Partners facility is with a broad syndicate of financial institutions. As of December 31, 2016, $210 million was outstanding under the partnership’s facility.
Debt Financing
Our $7.5 billion of outstanding Senior Notes issued by Phillips 66 are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Our senior unsecured long-term debt has been rated investment grade by S&P (BBB+) and Moody’s (A3). We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating deteriorated to a level prohibiting us from accessing the commercial paper market, we would expect to be able to access funds under our liquidity facilities mentioned above.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Other Financing
We have capital lease obligations related to equipment and transportation assets, and the use of an oil terminal in the United Kingdom. These leases mature within the next seventeen years. The present value of our minimum capital lease payments for these obligations as of December 31, 2016, was $188 million.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations, we enter into agreements with other parties to pursue business opportunities, with costs and risks apportioned among the parties as provided by the agreements. In April 2012, in connection with the Separation, we entered into an agreement to guarantee 100 percent of certain outstanding debt obligations of MSLP. At December 31, 2016, the aggregate principal amount of MSLP debt guaranteed by us was $123 million.
In June 2016, the operating lease commenced on our new headquarters facility in Houston, Texas, after construction was deemed substantially complete. Under the lease agreement, we have a residual value guarantee with a maximum future exposure of $554 million. The operating lease has a term of five years and provides us the option, at the end of the lease term, to request to renew the lease, purchase the facility, or assist the lessor in marketing it for resale.
We have residual value guarantees associated with railcar and airplane leases with maximum future potential payments of $363 million. For information on our need to perform under the railcar lease guarantee, see the Capital Requirements section to follow, as well as Note 14-Guarantees, in the Notes to Consolidated Financial Statements. Also see Note 14 for additional information on our guarantees.
Capital Requirements
For information about our capital expenditures and investments, see “Capital Spending” below.
Our debt balance at December 31, 2016, was $10.1 billion and our debt-to-capital ratio was 30 percent. Our target debt-to-capital ratio is between 20 and 30 percent.
On February 8, 2017, our Board of Directors declared a quarterly cash dividend of $0.63 per common share, payable March 1, 2017, to holders of record at the close of business on February 21, 2017.
Our Board of Directors at various times has authorized repurchases of our outstanding common stock which aggregate to a total authorization of up to $9 billion. The share repurchases are expected to be funded primarily through available cash. The shares will be repurchased from time to time in the open market at our discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012 through December 31, 2016, we have repurchased a total of 105,404,649 shares at a cost of $7.4 billion. Shares of stock repurchased are held as treasury shares.
We own a 25 percent interest in the Dakota Access, LLC (DAPL) and Energy Transfer Crude Oil Company, LLC (ETCOP) joint ventures, which have been constructing pipelines to deliver crude oil produced in the Bakken area of North Dakota to market centers in the Midwest and the Gulf Coast. In May 2016, we and our co-venturer executed agreements under which we and our co-venturer would loan DAPL and ETCOP up to a maximum of $2,256 million and $227 million, respectively, with the amounts loaned by us and our co-venturer being proportionate to our ownership interests (Sponsor Loans). In August 2016, DAPL and ETCOP secured a $2.5 billion facility (Facility) with a syndicate of financial institutions on a limited recourse basis with certain guaranties, and the outstanding Sponsor Loans were repaid. Allowable draws under the Facility were initially reduced and finally suspended in September 2016 pending resolution of permitting delays. As a result, DAPL and ETCOP resumed making draws under the Sponsor Loans. The maximum amounts that could be loaned under the Sponsor Loans were reduced on September 22, 2016, to $1,411 million for DAPL and $76 million for ETCOP. As of December 31, 2016, DAPL and ETCOP had $976 million and $22 million, respectively, outstanding under the Sponsor Loans. Our 25 percent share of those loans was $244 million and $6 million, respectively. DAPL was granted the lone outstanding easement to complete work beneath the Missouri River on February 8, 2017. As a result, construction of its pipeline resumed and draws under the Facility were reinitiated to repay the outstanding Sponsor Loans and to continue funding of construction. The DAPL pipeline is expected to be completed and operational by mid-2017. The book values of our investments in DAPL and ETCOP at December 31, 2016, were $403 million and $129 million, respectively.
In the first quarter of 2016, we and our co-venturer in WRB each made a $75 million partner loan to provide for WRB’s operating needs.
On May 1, 2015, the U.S. Department of Transportation issued a final rule focused on the safe transportation of flammable liquids by rail. The final rule, which is being challenged, subjects new and existing railcars transporting crude oil in high volumes to heightened design standards, including thicker tank walls and heat shields, improved pressure relief valves and enhanced braking systems. We are currently evaluating the impact of the new regulations on our crude oil railcar fleet, which is mostly held under operating leases. The regulations become effective subsequent to the expiration dates of our leases. Although we have no direct contractual obligation to retrofit these leased railcars, certain leases are subject to residual value guarantees. Under the lease terms, we have the option either to purchase the railcars
or to return them to the lessors. If railcars are returned to the lessors, we may be required to make the lessors whole under the residual value guarantees, which are subject to a cap. The current market demand for crude oil railcars is low, which has resulted in a decline in crude oil railcar prices. At year-end 2016, based on an outside appraisal of the railcars’ fair value at the end of their lease terms, we estimated a total residual value deficiency of $94 million that would be payable at the end of the lease terms, with approximately one-half due in late 2017 and the other half due in 2019. Due to current market uncertainties, changes in the estimated fair values of railcars could occur, which could increase or decrease our currently estimated residual value deficiency. As of December 31, 2016, our maximum future exposure under the residual value guarantees was approximately $320 million. See Note 14-Guarantees, in the Notes to Consolidated Financial Statements, for information on charges recorded in 2016 associated with the residual value deficiencies and related cease-use costs for railcars permanently taken out of service.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2016:
(a)
For additional information, see Note 13-Debt, in the Notes to Consolidated Financial Statements.
(b)
Represents any agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms. We expect these purchase obligations will be fulfilled by operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $123,715 million. In addition, $18,438 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 83 years, and $4,732 million from Excel Paralubes, for base oil over the remaining contractual term of 8 years.
Purchase obligations of $5,435 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and product terminals, to transport, process, treat, and store products. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned facilities where we are the operator.
(c)
Excludes pensions. For the 2017 through 2021 time period, we expect to contribute an average of $110 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $33 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $130 million for 2017 and then approximately $105 million per year for the remaining four years. Our minimum funding in 2017 is expected to be $55 million in the United States and $35 million outside the United States.
(d)
Excludes unrecognized tax benefits of $35 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential refunds. Also excludes interest and penalties of $12 million. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.
Capital Spending
*Our share of capital spending.
Midstream
Capital spending in our Midstream segment during the three-year period ended December 31, 2016, included:
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Construction activities related to the Sweeny Fractionator and Freeport LPG Export Terminal projects.
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Pipeline projects being developed by two of our joint ventures, DAPL and ETCOP. We own a 25 percent interest in each of these joint ventures.
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Acquisition of and projects to increase storage capacity at our crude oil and petroleum products terminal located near Beaumont, Texas.
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Acquisition by Phillips 66 Partners of certain southeast Louisiana NGL logistics assets comprising approximately 500 miles of pipelines and a storage cavern connecting multiple fractionation facilities, refineries and a petrochemical facility.
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Construction of rail racks to accept advantaged crude deliveries at our Bayway and Ferndale refineries.
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Formation of the STACK JV.
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Spending associated with return, reliability and maintenance projects in our Transportation and NGL businesses.
During the three-year period ended December 31, 2016, DCP Midstream’s capital expenditures and investments were $2.6 billion on a 100 percent basis. In 2015, we contributed $1.5 billion of cash to DCP Midstream, LLC and our co-venturer contributed its interests in certain operating assets of equal value, that are held as equity investments. Upon completion of this transaction, our interest in DCP Midstream, LLC remained at 50 percent.
In 2015, Rockies Express Pipeline LLC (REX) repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we contributed to REX in 2015.
Chemicals
During the three-year period ended December 31, 2016, CPChem had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer. During this period, on a 100 percent basis, CPChem’s capital expenditures and investments were $6.4 billion. In addition, CPChem’s advances to equity affiliates, primarily used for project construction and start-up activities, were $206 million and its repayments received from equity affiliates were $81 million.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2016, was $3.3 billion, primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to increase accessibility of advantaged crudes and improve product yields, improvements to the operating integrity of key processing units, and safety-related projects.
Key projects completed during the three-year period included:
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Installation of facilities to reduce nitrous oxide emissions from the fluid catalytic cracker at the Alliance Refinery.
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Installation of a tail gas treating unit at the Humber Refinery to reduce emissions from the sulfur recovery units.
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Installation of facilities to improve clean product yields at the Sweeny and Lake Charles refineries.
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Installation of facilities to improve processing of advantaged crudes at the Alliance and Ponca City refineries.
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Installation of facilities to comply with U.S. Environmental Protection Agency (EPA) Tier 3 gasoline regulations at the Alliance and Lake Charles refineries.
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Installation of a crude tank to increase accessibility of waterborne crude at the Los Angeles Refinery.
Major construction activities in progress include:
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Installation of facilities to comply with EPA Tier 3 gasoline regulations at the Sweeny and Bayway refineries.
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Installation of facilities to improve processing of advantaged crudes at the Billings Refinery.
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Installation of facilities to improve clean product yield at the Bayway and Ponca City refineries.
Generally, our equity affiliates in the Refining segment are intended to have self-funding capital programs. During this three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $958 million. We expect WRB’s 2017 capital program to be self-funding.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2016, was primarily for the acquisition of, and investments in, a limited number of retail sites in the Western and Midwestern portions of the United States, which have subsequently been disposed of; the acquisition of Spectrum Corporation, a private label specialty lubricants business headquartered in Memphis, Tennessee; the acquisition of the remaining interest that we did not already own in an entity that operates a power and steam generation plant; reliability and maintenance projects; and projects targeted at developing our new international sites.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2016, was primarily for projects related to information technology and facilities.
2017 Budget
Our 2017 capital budget is $2.7 billion including Phillips 66 Partners’ capital budget of $0.4 billion. This excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $1.1 billion, all of which is expected to be self-funded.
The Midstream capital budget of $1.5 billion is focused on development around its existing infrastructure’s footprint, including continued expansion of the Beaumont Terminal and investment in pipelines and other terminals. Refining’s capital budget of $0.9 billion is directed toward reliability, safety and environmental projects, as well as projects designed to improve clean product yields and lower feedstock costs. In M&S, we plan to invest approximately $0.1 billion to expand and enhance our fuel marketing business. In Corporate and Other, we plan to fund approximately $0.1 billion in projects primarily related to information technology and facilities.
Contingencies
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Legal and Tax Matters
Our legal and tax matters are handled by our legal and tax organizations. These organizations apply their knowledge, experience and professional judgment to the specific characteristics of our cases and uncertain tax positions. We employ a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. In the case of income-tax-related contingencies, we monitor tax legislation and court decisions, the status of tax audits and the statute of limitations within which a taxing authority can assert a liability. See Note 21-Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.
Environmental
Like other companies in our industry, we are subject to numerous international, federal, state and local environmental laws and regulations. Among the most significant of these international and federal environmental laws and regulations are the:
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U.S. Federal Clean Air Act, which governs air emissions.
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U.S. Federal Clean Water Act, which governs discharges into water bodies.
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European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH), which governs the manufacture, placing on the market or use of chemicals.
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U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.
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U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.
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U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories to local emergency planning committees and response departments.
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U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines as well as owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.
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European Union Trading Directive resulting in the European Union Emissions Trading Scheme (EU ETS), which uses a market-based mechanism to incentivize the reduction of greenhouse gas emissions.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. For example, in California the South Coast Air Quality Management District approved amendments to the Regional Clean Air Incentives Market (RECLAIM) that became effective in 2016, which require a phased reduction of nitrogen oxide emissions through 2022 and potentially affect refineries in the Los Angeles metropolitan area. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of developing infrastructure and marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
An example of this in the fuels area is the Energy Policy Act of 2005, which imposed obligations to provide increasing volumes of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence and Security Act of 2007 (EISA). EISA requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels and stipulates a mix of various types to be included through 2022. We have met the increasingly stringent requirements to date while establishing implementation, operating and capital strategies, along with advanced technology development, to address projected future requirements. It is uncertain how various future requirements contained in EISA, and the regulations promulgated thereunder, may be implemented and what their full impact may be on our operations. For the 2017 compliance year, the U.S. Environmental Protection Agency (EPA) has set volumes of advanced and total renewable fuel at higher levels than mandated in previous years; it is uncertain if these increased obligations will be achievable by fuel producers and shippers without drawing on the Renewable Identification Number (RIN) bank. For compliance years after 2017, we do not know whether the EPA will utilize its authority to reduce statutory volumes. Additionally, we may experience a decrease in demand for refined petroleum products due to the regulatory program as currently promulgated. This program continues to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s regulations pertaining to the 2014, 2015, and 2016 compliance years are subject to legal challenge, further creating uncertainty regarding renewable fuel volume requirements and obligations.
The EPA’s Renewable Fuel Standard (RFS) program was also implemented in accordance with the Energy Policy Act of 2005 and EISA. The RFS program sets annual quotas for the percentage of biofuels (such as ethanol) that must be blended into motor fuels consumed in the United States. A RIN represents a serial number assigned to each gallon of biofuel produced or imported into the United States. As a producer of petroleum-based motor fuels, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program. The market for RINs has been the subject of fraudulent third-party activity, and it is reasonably possible that some RINs that we have purchased may be determined to be invalid. Should that occur, we could incur costs to replace those fraudulent RINs. Although the
cost for replacing any fraudulently marketed RINs is not reasonably estimable at this time, we would not expect to incur the full financial impact of fraudulent RINs replacement costs in any single interim or annual period, and would not expect such costs to have a material impact on our results of operations or financial condition.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous previously and currently owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater.
At RCRA-permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2015, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 36 sites within the United States. During 2016, there was one new site for which we received notification of potential liability, three sites were resolved but not closed, and three sites were deemed resolved and closed, leaving 31 unresolved sites with potential liability at December 31, 2016.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites for which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval of a remediation plan. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.
Expensed environmental costs were $648 million in 2016 and are expected to be a similar amount in 2017 and in 2018. Capitalized environmental costs were $224 million in 2016 and are expected to be approximately $170 million and $220 million, in 2017 and 2018, respectively. This amount does not include capital expenditures made for another purpose that have an indirect benefit on environmental compliance.
Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where our generated waste was disposed. We also have accrued for a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Remediation activities vary substantially in duration and cost from site to site,
depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect on our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) emissions reduction, including various regulations proposed or issued by the EPA. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. Laws regulating GHG emissions continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws potentially could have a material impact on our results of operations and financial condition as a result of increasing costs of compliance, lengthening project implementation and agency review items, or reducing demand for certain hydrocarbon products. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
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EU ETS, which is part of the European Union’s policy to combat climate change and is a key tool for reducing industrial greenhouse gas emissions. EU ETS impacts factories, power stations and other installations across all EU member states.
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California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by 2020 (as well as the recently enacted SB32, which requires further reduction of California's GHG emissions to 40 percent below the 1990 emission level by 2030). Other GHG emissions programs in the western U.S. states have been enacted or are under consideration or development, including amendments to California's Low Carbon Fuel Standard, Oregon's Low Carbon Fuel Standard, and Washington's carbon reduction programs.
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The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S. Ct. 1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.
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The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act. These collectively may lead to more climate-based claims for damages, and may result in longer agency review time for development projects to determine the extent of potential climate change.
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EPA's 2015 Final Rule regulating GHG emissions from existing fossil fuel-fired electrical generating units under the Federal Clean Air Act, commonly referred to as the Clean Power Plan.
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Carbon taxes in certain jurisdictions.
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GHG emission cap and trade programs in certain jurisdictions.
In the EU, the first phase of the EU ETS completed at the end of 2007 and Phase II was undertaken from 2008 through to 2012. The current phase (Phase III) runs from 2013 through to 2020, with the main changes being reduced allocation of free allowances and increased auctioning of new allowances. Phillips 66 has assets that are subject to the EU ETS, and the company is actively engaged in minimizing any financial impact from the EU ETS.
From November 30 to December 12, 2015, more than 190 countries, including the United States, participated in the United Nations Climate Change Conference in Paris, France. The conference culminated in what is known as the “Paris Agreement,” which, upon certain conditions being met, entered into force on November 4, 2016. The Paris Agreement establishes a commitment by signatory parties to pursue domestic GHG emission reductions.
In the United States, some additional form of regulation is likely to be forthcoming in the future at the federal or state levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws
and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.
Compliance with changes in laws and regulations that create a GHG emission trading program, GHG reduction requirements or carbon taxes could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources.
An example of one such program is California’s cap and trade program, which was promulgated pursuant to the State’s Global Warming Solutions Act. The program had been limited to certain stationary sources, which include our refineries in California, but beginning in January 2015 expanded to include emissions from transportation fuels distributed in California. Inclusion of transportation fuels in California’s cap and trade program as currently promulgated has increased our cap and trade program compliance costs. The ultimate impact on our financial performance, either positive or negative, from this and similar programs, will depend on a number of factors, including, but not limited to:
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Whether and to what extent legislation or regulation is enacted.
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The nature of the legislation or regulation (such as a cap and trade system or a tax on emissions).
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The GHG reductions required.
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The price and availability of offsets.
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The amount and allocation of allowances.
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Technological and scientific developments leading to new products or services.
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Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).
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Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.
We consider and take into account anticipated future GHG emissions in designing and developing major facilities and projects, and implement energy efficiency initiatives to reduce such emissions. GHG emissions, legal requirements regulating such emissions, and the possible physical effects of climate change on our coastal assets are incorporated into our planning, investment, and risk management decision-making.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1-Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussion of critical accounting estimates, along with the discussion of contingencies in this report, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected. If the sum of the undiscounted pre-tax cash flows of an asset group is less than the carrying value, including applicable liabilities, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets (for example, at a refinery complex level). Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of similar assets, adjusted using principal market participant assumptions when necessary. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future volumes, commodity prices, operating costs, margins, discount rates and capital project decisions, considering all available information at the date of review.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment when there are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the investment’s carrying amount. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value.
When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that allows for recovery. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.
Asset Retirement Obligations
Under various contracts, permits and regulations, we have legal obligations to remove tangible equipment and restore the land at the end of operations at certain operational sites. Our largest asset removal obligations involve asbestos abatement at refineries. Estimating the timing and amount of payments for future asset removal costs is difficult. Most of these removal obligations are many years, or decades, in the future, and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
Environmental Costs
In addition to asset retirement obligations discussed above, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries, underground storage sites and non-operated sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, timing and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
Intangible Assets and Goodwill
At December 31, 2016, we had $764 million of intangible assets that we have determined to have indefinite useful lives, and are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have finite useful lives, amortization will commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to annual impairment tests that require management’s judgment of the estimated fair value of these intangible assets.
At December 31, 2016, we had $3.3 billion of goodwill recorded in conjunction with past business combinations. Goodwill is not amortized. Instead, goodwill is subject to at least annual reviews for impairment at a reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment.
Because quoted market prices for our reporting units are not available, management applies judgment in determining the estimated fair values of the reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make this fair value determination, including observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization. Sales or dispositions of significant assets within a reporting unit are allocated a portion of that reporting unit’s goodwill, based on relative fair values, which impacts the amount of gain or loss on the sale or disposition.
We completed our annual impairment test, as of October 1, 2016, and concluded that the fair value of each of our reporting units exceeded their respective recorded net book values (including goodwill), by over 25 percent for our Refining reporting unit and by over 100 percent for our Transportation and M&S reporting units. A decline in the estimated fair value of one or more of our reporting units in the future could result in an impairment. For example, a prolonged or significant decline in our stock price or a significant decline in actual or forecasted earnings could provide evidence of a significant decline in fair value and a need to record a material impairment of goodwill for one or more of our reporting units. After we have completed our annual test, we continue to monitor for impairment indicators, which can lead to further goodwill impairment testing.
Tax Assets and Liabilities
Our operations are subject to various taxes, including federal, state and foreign income taxes, property taxes, and transactional taxes such as excise, sales/use and payroll taxes. We record tax liabilities based on our assessment of existing tax laws and regulations. The recording of tax liabilities requires significant judgment and estimates. We recognize the financial statement effects of an income tax position when it is more likely than not that the position will be sustained upon examination by a taxing authority. A contingent liability related to a transactional tax claim is recorded if the loss is both probable and estimable. Actual incurred tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.
In determining our income tax provision, we assess the likelihood our deferred tax assets will be recovered through future taxable income. Valuation allowances reduce deferred tax assets to an amount that will, more likely than not, be realized. Judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against our deferred tax assets. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, we expect the net deferred tax assets will more likely than not be realized as offsets to reversing deferred tax liabilities and as reductions to future taxable income. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised.
New tax laws and regulations, as well as changes to existing tax laws and regulations, are continuously being proposed or promulgated. The implementation of future legislative and regulatory tax initiatives could result in increased tax liabilities that cannot be predicted at this time.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans impacts the obligations on the balance sheet and the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future interest rates, future health care cost-trend rates, and rates of utilization of health care services by
retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A one percentage-point decrease in the discount rate assumption would increase annual benefit expense by an estimated $60 million, while a one percentage-point decrease in the return on plan assets assumption would increase annual benefit expense by an estimated $30 million. In determining the discount rate, we use yields on high-quality fixed income investments with payments matched to the estimated distributions of benefits from our plans.
In 2016 and 2015, we used expected long-term rates of return of 6.75 percent and 7 percent, respectively, for the U.S. pension plan assets, which account for 74 percent of our overall pension plan assets. The actual U.S. pension plan asset returns were a gain of 7 percent in 2016 and a loss of less than 1 percent in 2015. For the past ten years, actual returns averaged 6 percent for the U.S. pension plan assets.
NEW ACCOUNTING STANDARDS
In January 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-04, “Intangibles-Goodwill and Other-Simplifying the Test for Goodwill Impairment,” which eliminates Step 2 from the goodwill impairment test. Under the revised test, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Public business entities should apply the guidance in ASU No. 2017-04 for its annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2017-04.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations: Clarifying the Definition of a Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen for determining when a transaction involves the acquisition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then the transaction does not involve the acquisition of a business. If the screen is not met, then the amendment requires that to be considered a business, the operation must include at a minimum an input and a substantive process that together significantly contribute to the ability to create an output. The guidance may reduce the number of transactions accounted for as business acquisitions. Public business entities should apply the guidance in ASU No. 2017-01 to annual periods beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The amendments should be applied prospectively, and no disclosures are required at the effective date. We are currently evaluating the provisions of ASU No. 2017-01.
In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash,” which clarifies the classification and presentation of changes in restricted cash. The amendment requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. Public business entities should apply the guidance in ASU No. 2016-18 on a retrospective basis for annual periods beginning after December 15, 2017, including interim periods within those annual periods, with early adoption permitted. We do not expect the adoption of this ASU to have a material impact on our financial statements.
In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which clarifies the treatment of several cash flow categories. In addition, ASU No. 2016-15 clarifies that when cash receipts and cash payments have aspects of more than one class of cash flows and cannot be separated, classification will depend on the predominant source or use. Public business entities should apply
the guidance in ASU No. 2016-15 on a retrospective basis for annual periods beginning after December 15, 2017, including interim periods within those annual periods, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2016-15 and assessing the impact on our financial statements.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The new standard amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. Public business entities should apply the guidance in ASU No. 2016-13 for annual periods beginning after December 15, 2019, including interim periods within those annual periods. Early adoption will be permitted for annual periods beginning after December 15, 2018. We are currently evaluating the provisions of ASU No. 2016-13 and assessing the impact on our financial statements.
In March 2016, the FASB issued ASU No. 2016-09, “Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment award transactions including accounting for income taxes and classification of excess tax benefits on the statement of cash flows, forfeitures and minimum statutory tax withholding requirements. Public business entities should apply the guidance in ASU No. 2016-09 for annual periods beginning after December 15, 2016, including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the provisions of ASU No. 2016-09 and assessing the impact on our financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” In the new standard, the FASB modified its determination of whether a contract is a lease rather than whether a lease is a capital or operating lease under the previous accounting principles generally accepted in the United States (GAAP). A contract represents a lease if a transfer of control occurs over an identified property, plant and equipment for a period of time in exchange for consideration. Control over the use of the identified asset includes the right to obtain substantially all of the economic benefits from the use of the asset and the right to direct its use. The FASB continued to maintain two classifications of leases - financing and operating - which are substantially similar to capital and operating leases in the previous lease guidance. Under the new standard, recognition of assets and liabilities arising from operating leases will require recognition on the balance sheet. The effect of all leases in the statement of comprehensive income and the statement of cash flows will be largely unchanged. Lessor accounting will also be largely unchanged. Additional disclosures will be required for financing and operating leases for both lessors and lessees. Public business entities should apply the guidance in ASU No. 2016-02 for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the provisions of ASU No. 2016-02 and assessing its impact on our financial statements.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to be carried at fair value upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU No. 2016-01 for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a limited impact on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under GAAP and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets and expand disclosure requirements. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier adoption is permitted only as of annual reporting
periods beginning after December 31, 2016, including interim reporting periods within that reporting period. Retrospective or modified retrospective application of the accounting standard is required. ASU No. 2014-09 was further amended in March 2016 by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASU No. 2016-20, “Technical Corrections to Topic 606, Revenue from Contracts with Customers.” As part of our assessment work-to-date, we have formed an implementation work team, completed training on the new ASU’s revenue recognition model and are continuing our contract review and documentation. Our expectation is to adopt the standard on January 1, 2018, using the modified retrospective application. In addition, we expect to present revenue net of sales-based taxes collected from our customers resulting in no impact to earnings. Sales-based taxes include excise taxes on petroleum product sales as noted on our consolidated statement of income. Our evaluation of the new ASU is ongoing, which includes understanding the impact of adoption on earnings from equity method investments. Based upon our analysis to-date, we have not identified any other material impact on our financial statements other than disclosures.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial- and commodity-based derivative contracts to manage the risks produced by changes in the prices of crude oil and related products, natural gas, NGL, and electric power; fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient market liquidity for comparable valuations. The Authority Limitations document also establishes Value at Risk (VaR) limits, and compliance with these limits is monitored daily. Our Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates. Our President monitors commodity price risk. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors related risks of our businesses.
Commodity Price Risk
We sell into or receive supply from the worldwide crude oil, refined products, natural gas, NGL, and electric power markets, exposing our revenues, purchases, cost of operating activities, and cash flows to fluctuations in the prices for these commodities. Generally, our policy is to remain exposed to the market prices of commodities. Consistent with this policy, our Commercial organization uses derivative contracts to effectively convert our exposure from fixed-price sales contracts, often requested by refined product customers, back to fluctuating market prices. Conversely, our Commercial organization also uses futures, forwards, swaps and options in various markets to accomplish the following objectives to optimize the value of our supply chain, and this may reduce our exposure to fluctuations in market prices:
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In addition to cash settlement prior to contract expiration, exchange-traded futures contracts may be settled by physical delivery of the commodity. This provides another source of supply to balance physical systems or to meet our refinery requirements and marketing demand.
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Manage the risk to our cash flows from price exposures on specific crude oil, refined product, natural gas, NGL, and electric power transactions.
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Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be utilized to optimize these activities.
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2016, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2016 and 2015, was immaterial to our cash flows and net income. The VaR for instruments held for purposes other than trading at December 31, 2016 and 2015, was also immaterial to our cash flows and net income.
Interest Rate Risk
Our use of fixed- or variable-rate debt directly exposes us to interest rate risk. Fixed-rate debt, such as our senior notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed-rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates, or that we may be obligated to pay rates higher than the current market. Variable-rate debt, such as borrowings under our revolving credit facility, exposes us to short-term changes in market rates that impact our interest expense. The following tables provide information about our debt instruments that are sensitive to changes in U.S. interest rates. These tables present principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.
For additional information about our use of derivative instruments, see Note 16-Derivatives and Financial Instruments, in the Notes to Consolidated Financial Statements.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:
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Fluctuations in NGL, crude oil, petroleum products and natural gas prices and refining, marketing and petrochemical margins.
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Failure of new products and services to achieve market acceptance.
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Unexpected changes in costs or technical requirements for constructing, modifying or operating our facilities or transporting our products.
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Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemicals products.
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Lack of, or disruptions in, adequate and reliable transportation for our NGL, crude oil, natural gas and refined products.
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The level and success of drilling and quality of production volumes around DCP Midstream’s assets and its ability to connect supplies to its gathering and processing systems, residue gas and NGL infrastructure.
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Inability to timely obtain or maintain permits, including those necessary for capital projects; comply with government regulations; or make capital expenditures required to maintain compliance.
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Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future capital projects.
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Potential disruption or interruption of our operations due to accidents, weather events, civil unrest, political events, terrorism or cyber attacks.
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International monetary conditions and exchange controls.
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Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.
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Liability resulting from litigation or for remedial actions, including removal and reclamation obligations under environmental regulations.
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General domestic and international economic and political developments including: armed hostilities; expropriation of assets; changes in governmental policies relating to NGL, crude oil, natural gas or refined product pricing, regulation or taxation; and other political, economic or diplomatic developments.
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Changes in tax, environmental and other laws and regulations (including alternative energy mandates) applicable to our business.
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Limited access to capital or significantly higher cost of capital related to changes to our credit profile or illiquidity or uncertainty in the domestic or international financial markets.
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The operation, financing and distribution decisions of our joint ventures.
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Domestic and foreign supplies of crude oil and other feedstocks.
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Domestic and foreign supplies of petrochemicals and refined products, such as gasoline, diesel, aviation fuel and home heating oil.
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Governmental policies relating to exports of crude oil and natural gas.
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Overcapacity or undercapacity in the midstream, chemicals and refining industries.
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Fluctuations in consumer demand for refined products.
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The factors generally described in Item 1A.-Risk Factors in this report.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS 66
Page
Report of Management
Reports of Independent Registered Public Accounting Firm
Consolidated Financial Statements of Phillips 66:
Consolidated Statement of Income for the years ended December 31, 2016, 2015 and 2014
Consolidated Statement of Comprehensive Income for the years ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheet at December 31, 2016 and 2015
Consolidated Statement of Cash Flows for the years ended December 31, 2016, 2015 and 2014
Consolidated Statement of Changes in Equity for the years ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
Supplementary Information
Selected Quarterly Financial Data (Unaudited)
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Phillips 66’s internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2016. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded the company’s internal control over financial reporting was effective as of December 31, 2016.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2016, and their report is included herein.
/s/ Greg C. Garland
/s/ Kevin J. Mitchell
Greg C. Garland
Kevin J. Mitchell
Chairman and
Executive Vice President, Finance and
Chief Executive Officer
Chief Financial Officer
February 17, 2017
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Phillips 66
We have audited the accompanying consolidated balance sheet of Phillips 66 as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Phillips 66 at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Phillips 66’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 17, 2017, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 17, 2017
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Phillips 66
We have audited Phillips 66’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Phillips 66’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such-other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
In our opinion, Phillips 66 maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2016 consolidated financial statements of Phillips 66 and our report dated February 17, 2017, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 17, 2017
Consolidated Statement of Income
Phillips 66
Notes to Consolidated Financial Statements
Phillips 66
Note 1-Summary of Significant Accounting Policies
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Consolidation Principles and Investments-Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method if fair value is not readily determinable. Undivided interests in pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.
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Foreign Currency Translation-Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income/loss in stockholders’ equity. Foreign currency transaction gains and losses result from remeasuring monetary assets and liabilities denominated in a foreign currency into the functional currency of our subsidiary holding the asset or liability. We include these transaction gains and losses in current earnings. Most of our foreign operations use their local currency as the functional currency.
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Use of Estimates-The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.
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Revenue Recognition-Revenues associated with sales of crude oil, natural gas liquids (NGL), petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into in contemplation of one another, are combined and reported net (i.e., on the same income statement line) in the “Purchased crude oil and products” line of our consolidated statement of income.
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Cash Equivalents-Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and will mature within 90 days or less from the date of acquisition. We carry these at cost plus accrued interest, which approximates fair value.
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Shipping and Handling Costs-We record shipping and handling costs in the “Purchased crude oil and products” line of our consolidated statement of income. Freight costs billed to customers are recorded in “Sales and other operating revenues.”
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Inventories-We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil and petroleum products inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual or nonrecurring costs or research and development costs. Materials and supplies inventories are valued using the weighted-average-cost method.
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Fair Value Measurements-We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs which are observable,
other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.
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Derivative Instruments-Derivative instruments are recorded on the balance sheet at fair value. We have elected to net derivative assets and liabilities with the same counterparty on the balance sheet if the right of offset exists and certain other criteria are met. We also net collateral payables or receivables against derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not designated as cash-flow hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in other comprehensive income/loss and appear on the balance sheet in accumulated other comprehensive income/loss until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses are recognized immediately in earnings.
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Capitalized Interest-A portion of interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset’s properties, plants and equipment and is amortized over the useful life of the asset.
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Intangible Assets Other Than Goodwill-Intangible assets with finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets with indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. These indefinite-lived intangibles are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, the fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.
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Goodwill-Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. It is not amortized, but is tested annually for impairment, and when events or changes in circumstance indicate that the fair value of a reporting unit with goodwill is below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, the implied fair value of goodwill is calculated. The excess, if any, of the book value over the implied fair value of the goodwill is charged to net income. For purposes of testing goodwill for impairment, we have three reporting units with goodwill balances: Transportation, Refining and Marketing and Specialties (M&S).
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Depreciation and Amortization-Depreciation and amortization of properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).
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Impairment of Properties, Plants and Equipment-Properties, plants and equipment (PP&E) used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If indicators of potential impairment exist, an undiscounted cash flow test is performed. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, including applicable liabilities, the carrying value of the PP&E included in the asset group is written down to estimated fair value through additional amortization or
depreciation provisions and reported in the “Impairments” line of our consolidated statement of income in the period in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets (for example, at a refinery complex level). Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of similar assets, adjusted using principal market participant assumptions when necessary. Long-lived assets held for sale are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.
The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future volumes, prices, costs, margins and capital project decisions, considering all available evidence at the date of review.
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Impairment of Investments in Nonconsolidated Entities-Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When indicators exist, the fair value is estimated and compared to the investment carrying value. If any impairment is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate.
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Maintenance and Repairs-Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Major refinery maintenance turnarounds are expensed as incurred.
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Property Dispositions-When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Net gain on dispositions” line of our consolidated statement of income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
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Asset Retirement Obligations and Environmental Costs-The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred. When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related PP&E. Over time, the liability is increased for the change in its present value, and the capitalized cost in PP&E is depreciated over the useful life of the related asset. Our estimate of the liability may change after initial recognition, in which case we record an adjustment to the liability and PP&E.
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.
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Guarantees-The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability has essentially been relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and
circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.
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Stock-Based Compensation-We recognize stock-based compensation expense over the shorter of: (1) the service period (i.e., the time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, which is the minimum time required for an award not to be subject to forfeiture. We have elected to recognize expense on a straight-line basis over the service period for the entire award, irrespective of whether the award was granted with ratable or cliff vesting.
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Income Taxes-Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Interest related to unrecognized tax benefits is reflected in interest expense, and penalties in operating expenses.
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Taxes Collected from Customers and Remitted to Governmental Authorities-Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes.
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Treasury Stock-We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in stockholders’ equity in the consolidated balance sheet.
Note 2-Changes in Accounting Principles
Effective January 1, 2016, we early adopted the Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” This ASU simplified the presentation of deferred income taxes and required deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. The classification is made at the taxpaying component level of an entity, after reflecting any offset of deferred tax liabilities, deferred tax assets and any related valuation allowances. We applied this ASU prospectively to all deferred tax liabilities and assets.
In June 2014, the FASB issued ASU No. 2014-10, “Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation.” This ASU removed the definition of a development stage entity from the Master Glossary of the Accounting Standard Codification (ASC) and the related financial reporting requirements specific to development stage entities. ASU 2014-10 is intended to reduce cost and complexity of financial reporting for entities that have not commenced planned principal operations. For financial reporting requirements other than the variable interest entity (VIE) guidance in ASC Topic 810, ASU No. 2014-10 was effective for annual and quarterly reporting periods of public entities beginning after December 15, 2014. For the financial reporting requirements related to VIEs in ASC Topic 810, ASU No. 2014-10 was effective for annual and quarterly reporting periods of public entities beginning after December 15, 2015. We adopted the provisions of this ASU related to the financial reporting requirements other than the VIE guidance effective January 1, 2015. We adopted the remaining provisions effective January 1, 2016, and updated our disclosures about the risks and uncertainties related to our joint venture entities that have not commenced their principal operations.
Note 3-Variable Interest Entities
Consolidated VIEs
In 2013, we formed Phillips 66 Partners LP, a master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other midstream assets. We consolidate Phillips 66 Partners as we determined that Phillips 66 Partners is a VIE and we are the primary beneficiary. As general partner of Phillips 66 Partners, we have the ability to control its financial interests, as well as the ability to direct the activities of Phillips 66 Partners that most significantly impact its economic performance. See Note 27-Phillips 66 Partners LP, for additional information.
The most significant assets of Phillips 66 Partners that are available to settle only its obligations at December 31 were:
* Included in “Investments and long-term receivables” on the Phillips 66 consolidated balance sheet.
The most significant liability of Phillips 66 Partners for which creditors do not have recourse to the general credit of its primary beneficiary was long-term debt, which was $2,396 million and $1,091 million at December 31, 2016 and 2015, respectively.
Non-consolidated VIEs
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant non-consolidated VIEs follows.
Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a delayed coker and related facilities at the Sweeny Refinery. Under the agreements that governed the relationships between the co-venturers in MSLP, certain defaults by Petróleos de Venezuela S.A. (PDVSA) with respect to supply of crude oil to the Sweeny Refinery triggered the right to acquire PDVSA’s 50 percent ownership interest in MSLP. The call right was exercised in August 2009. The exercise of the call right was challenged, and the dispute was arbitrated in our favor and subsequently litigated. Through December 31, 2016, we continued to use the equity method of accounting for MSLP because the call right exercise remained subject to legal challenge. MSLP was a VIE because, in securing lender consents in connection with our separation from ConocoPhillips in 2012 (the Separation), we provided a 100 percent debt guarantee to the lender of MSLP’s 8.85% senior notes (MSLP Senior Notes). PDVSA did not participate in the debt guarantee. In our VIE assessment, this disproportionate debt guarantee, plus other liquidity support provided jointly by us and PDVSA independently of equity ownership, resulted in MSLP not being exposed to all potential losses. We determined we were not the primary beneficiary while the call exercise was subject to legal challenge, because under the partnership agreement, the co-venturers jointly directed the activities of MSLP that most significantly impacted economic performance. At December 31, 2016, our maximum exposure to loss was $326 million, which represented the outstanding principal balance of the MSLP Senior Notes of $123 million and our investment in MSLP of $203 million. As discussed more fully in Note 5-Business Combinations, the exercise of the call right ceased to be subject to legal challenge in February 2017. At that point, we began consolidating MSLP as a wholly owned subsidiary and MSLP was no longer considered a VIE.
We have a 25 percent ownership interest in Dakota Access, LLC (DAPL) and Energy Transfer Crude Oil Company, LLC (ETCOP), whose planned principal operations have not commenced. Until planned principal operations have commenced, these entities do not have sufficient equity at risk to fully fund the construction of all assets required for principal operations, and thus represent VIEs. We have determined we are not the primary beneficiary because we and our co-venturer jointly direct the activities of DAPL and ETCOP that most significantly impact economic performance. We use the equity method of accounting for these investments. At December 31, 2016, our maximum exposure to loss was $1,057 million, which represents the aggregate book value of our equity investments of $532 million, our loans to DAPL and ETCOP for an aggregated balance of $250 million and our share of borrowings under the project financing facility of $275 million.
Note 4-Inventories
Inventories at December 31 consisted of the following:
Inventories valued on the LIFO basis totaled $2,772 million and $3,085 million at December 31, 2016 and 2015, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $3.3 billion and $1.3 billion at December 31, 2016 and 2015, respectively.
Excluding the disposition of the Whitegate Refinery, which occurred in September 2016, certain planned reductions in inventory caused liquidations of LIFO inventory values during each of the three years ended December 31, 2016. These liquidations decreased net income by approximately $68 million, $37 million and $8 million in 2016, 2015 and 2014, respectively.
In conjunction with the Whitegate Refinery disposition, the refinery’s LIFO inventory values were liquidated causing a
decrease in net income of $62 million during the year ended December 31, 2016. This LIFO liquidation impact was included in the net gain recognized on the disposition.
Note 5-Business Combinations
In November 2016, Phillips 66 Partners acquired NGL logistics assets located in southeast Louisiana, consisting of approximately 500 miles of pipelines and storage caverns connecting multiple fractionation facilities, refineries and a petrochemical facility. The acquisition provided an opportunity for fee-based growth in the Louisiana market within our Midstream segment. The acquisition was included in the “Capital expenditures and investments” line of our consolidated statement of cash flows. As of December 31, 2016, we provisionally recorded $183 million of PP&E in connection with the acquisition.
While we had no acquisitions in 2015, we completed the following acquisitions in 2014:
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In August 2014, we acquired a 7.1 million-barrel-storage-capacity crude oil and petroleum products terminal located near Beaumont, Texas, to promote growth plans in our Midstream segment.
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In July 2014, we acquired Spectrum Corporation, a private label and specialty lubricants business headquartered in Memphis, Tennessee. The acquisition supported our plans to selectively grow stable-return businesses in our M&S segment.
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In March 2014, we acquired our co-venturer’s interest in an entity that operates a power and steam generation plant located in Texas that is included in our M&S segment. This acquisition provided us with full operational control over a key facility supplying utilities and other services to one of our refineries.
We funded each of these 2014 acquisitions with cash on hand. Total cash consideration paid in 2014 was $741 million, net of cash acquired. Cash consideration paid for acquisitions is included in the “Capital expenditures and investments” line of our consolidated statement of cash flows. Our acquisition accounting for these transactions was finalized in 2015.
MSLP owns a delayed coker and related facilities at the Sweeny Refinery, and its results are included in our Refining segment. MSLP processes long residue, which is produced from heavy sour crude oil, for a fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50
by ConocoPhillips and PDVSA. Under the agreements that governed the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery triggered the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which was exercised in August 2009. The exercise was challenged, and the dispute was arbitrated in our favor and subsequently litigated. While the dispute was being arbitrated and litigated, we continued to use the equity method of accounting for our 50 percent interest in MSLP. When the exercise of the call right ceased to be subject to legal challenge on February 7, 2017, we deemed that we had acquired PDVSA’s 50 percent share of MSLP and began accounting for MSLP as a wholly owned consolidated subsidiary.
Based on a preliminary third-party appraisal of the fair value of MSLP’s net assets, utilizing discounted cash flows and replacement costs, the acquisition of PDVSA’s 50 percent interest is expected to result in our recording a noncash, pre-tax gain of approximately $420 million in the first quarter of 2017. The preliminary fair value of our original equity interest in MSLP is approximately $190 million.
Note 6-Assets Held for Sale or Sold
In September 2016, we completed the sale of the Whitegate Refinery and related marketing assets, which were included primarily in our Refining segment. The net carrying value of the assets at the time of their disposition was $135 million, which consisted of $127 million of inventory, other working capital, and PP&E; and $8 million of allocated goodwill. An immaterial gain was recognized in 2016 on the disposition.
In December 2014, we completed the sale of our ownership interests in the Malaysia Refining Company Sdn. Bdh. (MRC), which was included in our Refining segment. At the time of the disposition, the total carrying value of our investment in MRC was $334 million, including $76 million of allocated goodwill and currency translation adjustments. A before-tax gain of $145 million was recognized in 2014 from this disposition.
In July 2014, we entered into an agreement to sell the Bantry Bay terminal in Ireland, which was included in our Refining segment. Accordingly, the net assets of the terminal were classified as held for sale at that time, which resulted in a before-tax impairment in 2014 of $12 million from the reduction of the carrying value of the long-lived assets to estimated fair value less costs to sell. In February 2015, we completed the sale of the terminal. At the time of the disposition, the terminal had a net carrying value of $68 million, which primarily related to net PP&E. An immaterial gain was recognized in 2015 on this disposition.
In February 2014, we exchanged the stock of Phillips Specialty Products Inc. (PSPI), a flow improver business, which was included in our M&S segment, for shares of Phillips 66 common stock owned by another party. The PSPI share exchange resulted in the receipt of approximately 17.4 million shares of Phillips 66 common stock, which are held as treasury shares, and the recognition in 2014 of a before-tax gain of $696 million. At the time of the disposition, PSPI had a net carrying value of $685 million, which primarily included $481 million of cash and cash equivalents, $60 million of net PP&E and $117 million of allocated goodwill. Cash and cash equivalents of $450 million included in PSPI’s net carrying value is reflected as a financing cash outflow in the “Share exchange-PSPI transaction” line of our consolidated statement of cash flows. Revenues, income before tax and net income from discontinued operations, excluding the recognized before-tax gain of $696 million, were not material for the year ended December 31, 2014.
In July 2013, we completed the sale of the Immingham Combined Heat and Power Plant (ICHP), which was included in our M&S segment. A gain on this disposal was deferred at the time of the sale due to an indemnity provided to the buyer. We recognized the deferred gain in earnings as our exposure under the indemnity declined, beginning in the third quarter of 2014 and ending in the second quarter of 2015 when the indemnity expired. We recognized $242 million and $126 million of the deferred gain during the years ended December 31, 2015 and 2014, respectively.
Note 7-Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2016, included:
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WRB Refining LP (WRB)-50 percent owned business venture with Cenovus Energy Inc. (Cenovus)-owns the Wood River and Borger refineries.
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DCP Midstream, LLC (DCP Midstream)-50 percent owned joint venture with Spectra Energy Corp-owns and operates gas plants, gathering systems, storage facilities and fractionation plants, including through its investment in DCP Midstream, LP (formerly named DCP Midstream Partners, LP).
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Chevron Phillips Chemical Company LLC (CPChem)-50 percent owned joint venture with Chevron U.S.A. Inc., an indirect wholly owned subsidiary of Chevron Corporation-manufactures and markets petrochemicals and plastics.
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Rockies Express Pipeline LLC (REX)-25 percent owned joint venture with Tallgrass Energy Partners L.P.-owns and operates a natural gas pipeline system from Meeker, Colorado to Clarington, Ohio.
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DCP Sand Hills Pipeline, LLC (Sand Hills)-Phillips 66 Partners’ 33 percent owned joint venture with DCP Partners-owns and operates NGL pipeline systems from the Permian and Eagle Ford basins to Mont Belvieu, Texas.
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DCP Southern Hills Pipeline, LLC (Southern Hills)-Phillips 66 Partners’ 33 percent owned joint venture with DCP Partners-owns and operates NGL pipeline systems from the Midcontinent region to Mont Belvieu, Texas.
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DAPL/ETCOP-two 25 percent owned joint ventures with Energy Transfer Equity L.P. and Energy Transfer Partners L.P. (collectively “Energy Transfer”). DAPL is constructing a crude oil pipeline system from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois, and ETCOP completed a connecting crude oil pipeline system from Patoka to Nederland, Texas.
Summarized 100 percent financial information for all equity method investments in affiliated companies, combined, was as follows:
Our share of income taxes incurred directly by the equity companies is included in equity in earnings of affiliates, and as such is not included in the provision for income taxes in our consolidated financial statements.
At December 31, 2016, retained earnings included $1,945 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $616 million, $1,769 million, and $3,305 million in 2016, 2015 and 2014, respectively.
WRB
WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively, for which we are the operator and managing partner. As a result of our contribution of these two assets to WRB, a basis difference was created because the fair value of the contributed assets recorded by WRB exceeded their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years, which was the estimated remaining useful life of the refineries’ PP&E at the closing date. At December 31, 2016, the book value of our investment in WRB was $2,088 million, and the basis difference was $2,970 million. Equity earnings in 2016, 2015 and 2014 were increased by $185 million, $218 million and $184 million, respectively, due to amortization of the basis difference. Cenovus was obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007. In the first quarter of 2014, Cenovus prepaid its remaining balance under this obligation. As a result, WRB declared a special dividend, which was distributed to the co-venturers in March 2014. Of the $1,232 million that we received, $760 million was considered a return on our investment in WRB (an operating cash inflow), and $472 million was considered a return of our investment in WRB (an investing cash inflow). The return of investment portion of the dividend was included in the “Proceeds from asset dispositions” line in our consolidated statement of cash flows.
DCP Midstream
DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants, including through its investment in DCP Partners. DCP Midstream markets a portion of its NGL to us and CPChem under supply agreements, the primary production commitment of which began a ratable wind-down period in December 2014 and expires in January 2019. This purchase commitment is on an “if-produced, will-purchase” basis. NGL is purchased under this agreement at various published market index prices, less transportation and fractionation fees.
In 2015, we contributed $1.5 billion in cash to DCP Midstream as a capital contribution. Our co-venturer contributed its interests in Sand Hills and Southern Hills as a capital contribution equal in value to ours. Our ownership percentage in DCP Midstream remained unchanged.
At December 31, 2016, the book value of our investment in DCP Midstream was $2,258 million, and the basis difference was $55 million.
CPChem
CPChem manufactures and markets petrochemicals and plastics. At December 31, 2016, the book value of our equity method investment in CPChem was $5,773 million. We have multiple supply and purchase agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and NGL feedstocks, as well as fuel oils and gases. All products are purchased and sold under specified pricing formulas based on various published pricing indices.
REX
REX owns a natural gas pipeline that runs from Meeker, Colorado to Clarington, Ohio. In 2015, REX repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we contributed to REX in 2015. At December 31, 2016, the book value of our equity method investment in REX was $455 million.
Sand Hills
The Sand Hills pipeline is a fee-based pipeline that transports NGL from the Permian Basin and Eagle Ford Shale to facilities along the Texas Gulf Coast and the Mont Belvieu market hub. This investment was contributed to Phillips 66 Partners LP in March 2015 as discussed further in Note 27-Phillips 66 Partners LP. At December 31, 2016, the book value of our equity investment in Sand Hills was $445 million.
Southern Hills
The Southern Hills pipeline is a fee-based pipeline that transports NGL from the Midcontinent to facilities along the Texas Gulf Coast and the Mont Belvieu market hub. This investment was contributed to Phillips 66 Partners LP in March 2015 as discussed further in Note 27-Phillips 66 Partners LP. At December 31, 2016, the book value of our investment in Southern Hills was $212 million, and the basis difference was $96 million.
DAPL/ETCOP
We own a 25 percent interest in the DAPL and ETCOP joint ventures, which were formed to construct pipelines to deliver crude oil produced in the Bakken/Three Forks production area of North Dakota to market centers in the Midwest and the Gulf Coast. In May 2016, we and our co-venturer executed agreements under which we and our co-venturer would loan DAPL and ETCOP up to a maximum of $2,256 million and $227 million, respectively, with the amounts loaned by us and our co-venturer being proportionate to our ownership interests (Sponsor Loans). In August 2016, DAPL and ETCOP secured a $2.5 billion facility (Facility) with a syndicate of financial institutions on a limited recourse basis with certain guarantees, and the outstanding Sponsor Loans were repaid. Allowable draws under the Facility were initially reduced and finally suspended in September 2016 pending resolution of permitting delays. As a result, DAPL and ETCOP resumed making draws under the Sponsor Loans. The maximum amounts that could be loaned under the Sponsor Loans were reduced in September 2016, to $1,411 million for DAPL and $76 million for ETCOP. At December 31, 2016, DAPL and ETCOP had $976 million and $22 million, respectively, outstanding under the Sponsor Loans. Our 25 percent share of those loans was $244 million and $6 million, respectively. The Sponsor Loans were repaid in their entirety in February 2017 when draws resumed under the Facility. At December 31, 2016, the book values of our investments in DAPL and ETCOP were $403 million and $129 million, respectively.
Loans and Long-term Receivables
We enter into agreements with other parties to pursue business opportunities, which may require us to provide loans or advances to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.
Note 8-Properties, Plants and Equipment
Our investment in PP&E is recorded at cost. Investments in refining manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life, pipeline assets over a 45-year life and terminal assets over a 33-year life. The company’s investment in PP&E, with the associated accumulated depreciation and amortization (Accum. D&A), at December 31 was:
Note 9-Goodwill and Intangibles
Goodwill
The carrying amount of goodwill was as follows:
Intangible Assets
Information relating to the carrying value of intangible assets at December 31 follows:
At year-end 2016, the net book value of our amortized intangible assets was $124 million, which included accumulated amortization of $152 million. At year-end 2015, the net book value of our amortized intangible assets was $136 million, which included accumulated amortization of $135 million. Amortization expense was not material for 2016 and 2015, and is not expected to be material in future years.
Note 10-Impairments
During 2016, 2015 and 2014, we recognized the following before-tax impairment charges:
In 2014, we recorded a $131 million held-for-use impairment in our Refining segment related to the Whitegate Refinery in Ireland, due to the then current and forecasted negative market conditions in that region. In addition, we also recorded a $12 million held-for-sale impairment in our Refining segment related to the Bantry Bay terminal. See Note 6-Assets Held for Sale or Sold for additional information.
Note 11-Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
*Classified as a current liability on the consolidated balance sheet, under the caption “Other accruals.”
Asset Retirement Obligations
We have asset retirement obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until many years in the future and are expected to be funded from general company resources at the time of removal. Our largest individual obligations involve asbestos abatement at refineries.
During 2016 and 2015, our overall asset retirement obligation changed as follows:
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2016 and 2015, were $496 million and $485 million, respectively. The 2016 increase in total accrued environmental costs is due to new accruals, accrual adjustments and accretion exceeding payments and settlements during the year.
We had accrued environmental costs at December 31, 2016 and 2015 of $268 million and $270 million, respectively, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations; $178 million and $168 million, respectively, associated with nonoperator sites; and $50 million and $47 million, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities will be paid over periods extending up to 30 years. Because a large portion of the accrued environmental costs were acquired in various business combinations, the obligations are recorded at a discount. Expected expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $248 million at December 31, 2016. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $25 million in 2017, $26 million in 2018, $22 million in 2019, $16 million in 2020, $15 million in 2021, and $212 million for all future years after 2021.
Note 12-Earnings Per Share
The numerator of basic earnings per share (EPS) is net income attributable to Phillips 66, reduced by noncancelable dividends paid on unvested share-based employee awards during the vesting period (participating securities). The denominator of basic EPS is the sum of the daily weighted-average number of common shares outstanding during the periods presented and fully vested stock and unit awards that have not yet been issued as common stock. The numerator of diluted EPS is also based on net income attributable to Phillips 66, which is reduced only by dividend equivalents paid on participating securities for which the dividends are more dilutive than the participation of the awards in the earnings of the periods presented. To the extent unvested stock, unit or option awards and vested unexercised stock options are dilutive, they are included with the weighted-average common shares outstanding in the denominator. Treasury stock is excluded from the denominator in both basic and diluted EPS.
Note 13-Debt
Long-term debt at December 31 was:
Maturities of borrowings outstanding at December 31, 2016, inclusive of net unamortized discounts and debt issuance costs, for each of the years from 2017 through 2021 are $1,550 million, $43 million, $31 million, $335 million and $231 million, respectively. At December 31, 2016, we classified $1 billion of debt maturing in 2017 as long-term debt on our consolidated balance sheet, based on our ability and intent to refinance the obligation on a long-term basis, with such ability demonstrated by our revolving credit facility.
Debt Issuances
In October 2016, Phillips 66 Partners closed on a public offering of $1.125 billion aggregate principal amount of unsecured senior notes, consisting of:
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$500 million of 3.55% Senior Notes due 2026.
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$625 million of 4.90% Senior Notes due 2046.
In February 2015, Phillips 66 Partners closed on a public offering of $1.1 billion aggregate principal amount of unsecured
senior notes, consisting of:
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$300 million of 2.646% Senior Notes due 2020.
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$500 million of 3.605% Senior Notes due 2025.
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$300 million of 4.680% Senior Notes due 2045.
Credit Facilities and Commercial Paper
In October 2016, Phillips 66 amended its $5 billion revolving credit facility, primarily to extend the term from December 2019 to October 2021. This facility may be used for direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowings under the facility will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor’s Ratings Services and Moody’s Investors Service. The facility also provides for customary fees, including administrative agent fees and commitment fees. As of December 31, 2016, no amount had been directly drawn under this revolving credit agreement, while $51 million in letters of credit had been issued that were supported by it.
We have a $5 billion commercial paper program for short-term working capital needs that is supported by our revolving credit facility. Commercial paper maturities are generally limited to 90 days. As of December 31, 2016, we had no borrowings under our commercial paper program.
Phillips 66 Partners also amended its $500 million revolving credit facility in October 2016, primarily to increase borrowing capacity to $750 million and to extend the term from November 2019 to October 2021. The Phillips 66 Partners facility is with a broad syndicate of financial institutions. As of December 31, 2016, Phillips 66 Partners had $210 million outstanding under this facility.
Note 14-Guarantees
At December 31, 2016, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.
Guarantees of Joint Venture Debt
In 2012, in connection with the Separation, we issued a guarantee for 100 percent of MSLP Senior Notes issued in July 1999. At December 31, 2016, the maximum potential amount of future payments to third parties under the guarantee was estimated to be $123 million, which could become payable if MSLP fails to meet its obligations under the senior notes agreement. The MSLP Senior Notes mature in 2019.
In December 2016, as part of the restructuring within DCP Midstream which occurred effective January 1, 2017, we issued a guarantee in support of DCP Midstream, LLC’s newly issued debt. At December 31, 2016, the maximum potential amount of future payments to third parties under the guarantee is estimated to be $212 million. Payment would be required if DCP Midstream, LLC defaults on this debt obligation. DCP Midstream, LLC’s debt matures in 2019.
Other Guarantees
In the second quarter of 2016, the operating lease commenced on our new headquarters facility in Houston, Texas, after construction was deemed substantially complete. Under this lease agreement, we have a residual value guarantee with a maximum future exposure of $554 million. The operating lease has a term of five years and provides us the option, at the end of the lease term, to request to renew the lease, purchase the facility, or assist the lessor in marketing it for resale.
We have residual value guarantees associated with railcar and airplane leases with maximum future potential payments of $363 million. We estimated a $94 million residual value guarantee obligation for our railcars in the fourth quarter of 2016. This residual value guarantee reflects the negative impact of new safety regulations issued by the U.S. Department of Transportation on the fair value of crude-oil railcars. The amount was based on an outside appraisal of the estimated fair value of the railcars at their lease termination dates. Of the total $94 million residual value guarantee obligation, $28
million was recognized as expense in 2016, with $20 million of that amount related to railcars permanently taken out of service. The remaining $66 million estimated obligation at year-end 2016 will be recognized on a straight-line basis through the applicable lease termination dates in either late-2017 or 2019. For railcars taken out of service in 2016, we also recognized remaining executory lease costs of $12 million.
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, litigation, environmental liabilities, permits and licenses, and employee claims; and real estate indemnity against tenant defaults. The provisions of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues with generally indefinite terms, and the maximum amount of future payments is generally unlimited. The carrying amount recorded for indemnifications at December 31, 2016, was $193 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were $102 million of environmental accruals for known contamination that were primarily included in “Asset retirement obligations and accrued environmental costs” at December 31, 2016. For additional information about environmental liabilities, see Note 15-Contingencies and Commitments.
Indemnification and Release Agreement
In 2012, we entered into the Indemnification and Release Agreement with ConocoPhillips. This agreement governs the treatment between ConocoPhillips and us of matters relating to indemnification, insurance, litigation responsibility and management, and litigation document sharing and cooperation arising in connection with the Separation. Generally, the agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of ConocoPhillips’ business with ConocoPhillips. The agreement also establishes procedures for handling claims subject to indemnification and related matters.
Note 15-Contingencies and Commitments
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 21-Income Taxes, for additional information about income-tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies alleged to have liability at a particular site. Due to such joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those pertaining to sites acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 11-Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized.
At December 31, 2016, we had performance obligations secured by letters of credit and bank guarantees of $541 million (of which $51 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit and bank guarantees) related to various purchase and other commitments incident to the ordinary conduct of business.
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of third-party financing arrangements. The agreements typically provide for crude oil transportation to be used in the ordinary course of our business. The aggregate amounts of estimated payments under these various agreements are $319 million annually for each of the years
from 2017 through 2021 and $2,902 million in the aggregate for years 2022 and thereafter. Total payments under the agreements were $325 million in 2016, $328 million in 2015 and $331 million in 2014.
Note 16-Derivatives and Financial Instruments
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in interest rates, foreign currency exchange rates and commodity prices or to capture market opportunities. Because we have not used cash-flow hedge accounting for commodity derivative contracts, all gains and losses, realized or unrealized, from commodity derivative contracts have been recognized in the consolidated statement of income. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in “Other income” on our consolidated statement of income. Cash flows from all our derivative activity for the periods presented appear in the operating section of the consolidated statement of cash flows.
Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily convertible to cash (e.g., crude oil and gasoline) are recorded on the balance sheet as derivatives unless the contracts are eligible for, and we elect, the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). We generally apply this normal purchases and normal sales exception to eligible crude oil, refined product, NGL, natural gas and power commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value). Our derivative instruments are held at fair value on our consolidated balance sheet. For further information on the fair value of derivatives, see Note 17-Fair Value Measurements.
Commodity Derivative Contracts-We sell into or receive supply from the worldwide crude oil, refined products, natural gas, NGL, and electric power markets, exposing our revenues, purchases, cost of operating activities, and cash flows to fluctuations in the prices for these commodities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business, all of which may reduce our exposure to fluctuations in market prices. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades.
The following table indicates the balance sheet line items that include the fair values of commodity derivative assets and liabilities. The balances in the following table are presented on a gross basis, before the effects of counterparty and collateral netting. However, we have elected to present our commodity derivative assets and liabilities with the same counterparty on a net basis on the balance sheet when the right of setoff exists. For information on the impact of counterparty netting and collateral netting, and reconciliation of the balances presented below to the balance sheet, see Note 17-Fair Value Measurements.
Hedge accounting has not been used for any item in the table.
The gains (losses) incurred from commodity derivatives, and the line items where they appear on our consolidated statement of income, were:
Hedge accounting has not been used for any item in the table.
The following table summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivative positions such as inventory volumes. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts. The percentage of our derivative contract volumes expiring within the next 12 months was at least 98 percent at December 31, 2016 and 2015.
Interest-Rate Derivative Contracts-During the first quarter of 2016, we entered into interest-rate swaps to hedge the variability of anticipated lease payments on our new headquarters. These monthly lease payments will vary based on monthly changes in the one-month LIBOR and changes, if any, in the Company’s credit rating over the five-year term of the lease. The pay-fixed, receive-floating interest rate swaps have an aggregate notional value of $650 million and end on April 25, 2021. They qualify for and are designated as cash-flow hedges.
At December 31, 2016, the aggregate net fair value of these swaps, which is included in the “Other accruals” and “Other assets” lines of our consolidated balance sheet, amounted to $8 million.
We report the effective portion of the mark-to-market gain or loss on our interest rate swaps designated and qualifying as a cash flow hedging instrument as a component of other comprehensive income/loss and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness are recognized in general and administrative expenses. During the year ended December 31, 2016, we did not recognize any material hedge ineffectiveness gain or loss in the consolidated income statement. Net realized loss from settlements of the swaps during the year ended December 31, 2016, was immaterial.
We estimate that pre-tax losses of $3 million will be reclassified from accumulated other comprehensive income/loss into general and administrative expenses during the next twelve months as the hedged transaction settles; however, the actual amounts that will be reclassified will vary based on changes in interest rates throughout the year 2017.
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of over-the-counter (OTC) derivative contracts and trade receivables.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps
and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from the sale of products from, or related to, our refinery operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less. We continually monitor this exposure and the creditworthiness of the counterparties and recognize bad debt expense based on historical write-off experience or specific counterparty collectability. Generally, we do not require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if our credit ratings fall below investment grade. Cash is the primary collateral in all contracts; however, many contracts also permit us to post letters of credit as collateral.
The aggregate fair values of all derivative instruments with such credit-risk-related contingent features that were in a liability position were not material at December 31, 2016 or 2015.
Note 17-Fair Value Measurements
Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
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Cash and cash equivalents: The carrying amount reported on the consolidated balance sheet approximates fair value.
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Accounts and notes receivable: The carrying amount reported on the consolidated balance sheet approximates fair value.
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Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of our fixed-rate debt is estimated based on quoted market prices.
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Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, we estimate fair value using the forward price of a similar commodity, adjusted for the difference in quality or location.
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Interest-rate swaps: We determine fair value based upon observed market valuations for interest-rate swaps that have notionals, durations, and pay and reset frequencies similar to ours.
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Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the Intercontinental Exchange, or other traded exchanges.
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Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect at the end of the reporting period, which approximates the exit price at that date.
We carry certain assets and liabilities at fair value, which we measure at the reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability), and disclose the quality of these fair values based on the valuation inputs used in these measurements under the following hierarchy:
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Level 1: Fair value measured with unadjusted quoted prices from an active market for identical assets or liabilities.
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Level 2: Fair value measured either with: (1) adjusted quoted prices from an active market for similar assets or liabilities; or (2) other valuation inputs that are directly or indirectly observable.
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Level 3: Fair value measured with unobservable inputs that are significant to the measurement.
We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement; however, the fair value of an asset or liability initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement or corroborating market data becomes available. Conversely, an asset or liability initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable. For the year ended December 31, 2016, derivative assets with an aggregate value of $201 million and derivative liabilities with an aggregate value of $156 million were transferred into Level 1, as measured from the beginning of the reporting period. The measurements were reclassified within the fair value hierarchy due to the availability of unadjusted quoted prices from an active market.
Recurring Fair Value Measurements
Financial assets and liabilities recorded at fair value on a recurring basis consist primarily of investments to support nonqualified deferred compensation plans and derivative instruments. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. We value our exchange-traded commodity derivatives using closing prices provided by the exchange as of the balance sheet date, and these are also classified as Level 1 in the fair value hierarchy. When exchange-cleared contracts lack sufficient liquidity or are valued using either adjusted exchange-provided prices or non-exchange quotes, we classify those contracts as Level 2. OTC financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotes provided by brokers and price index developers such as Platts and Oil Price Information Service. We corroborate these quotes with market data and classify the resulting fair values as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. We classify these contracts as Level 3. Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3. We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.
The following tables display the fair value hierarchy for our material financial assets and liabilities either accounted for or disclosed at fair value on a recurring basis. These values are determined by treating each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are shown gross (i.e., without the effect of netting where the legal right of setoff exists) in the hierarchy sections of these tables. These tables also show that our Level 3 activity was not material.
We have master netting agreements for all of our exchange-cleared derivative instruments, the majority of our OTC derivative instruments, and certain physical commodity forward contracts (primarily pipeline crude oil deliveries). The following tables show the fair value of these contracts on a net basis in the column “Effect of Counterparty Netting,” which is how these also appear on the consolidated balance sheet.
The carrying values and fair values by hierarchy of our material financial instruments and commodity forward contracts, either carried or disclosed at fair value, including any effects of netting derivative assets with liabilities and netting collateral due to right of setoff or master netting agreements, were:
*Physical forward contracts may have a larger value on the balance sheet than disclosed in the fair value hierarchy when the remaining contract term at the reporting date is greater than 12 months and the short-term portion is an asset while the long-term portion is a liability, or vice versa.
**We carry fixed-rate debt on the balance sheet at amortized cost.
*Physical forward contracts may have a larger value on the balance sheet than disclosed in the fair value hierarchy when the remaining contract term at the reporting date is greater than 12 months and the short-term portion is an asset while the long-term portion is a liability, or vice versa.
**We carry fixed-rate debt on the balance sheet at amortized cost.
At December 31, 2016 and 2015, there were no material cash collateral received or paid that were not offset on the balance sheet.
The rabbi trust assets appear on our consolidated balance sheet in the “Investments and long-term receivables” line, while the floating-rate and fixed-rate debt appear in the “Short-term debt” and “Long-term debt” lines. For information regarding where our commodity derivative assets and liabilities appear on the balance sheet, see the first table in Note 16-Derivatives and Financial Instruments.
Nonrecurring Fair Value Remeasurements
During the years ended December 31, 2016 and 2015, there were no material nonrecurring fair value remeasurements of assets subsequent to their initial recognition.
Note 18-Equity
Preferred Stock
We have 500 million shares of preferred stock authorized, with a par value of $0.01 per share. No shares of preferred stock were outstanding as of December 31, 2016 or 2015.
Treasury Stock
Since July 2012, our Board of Directors has, at various times, authorized repurchases of our outstanding common stock which aggregate to a total authorization of up to $9 billion. The share repurchases are expected to be funded primarily through available cash. The shares will be repurchased from time to time in the open market at the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012, through December 31, 2016, we have repurchased a total of 105,404,649 shares at a cost of $7.4 billion. Shares of stock repurchased are held as treasury shares.
In 2014 we completed the exchange of our flow improvers business for shares of Phillips 66 common stock owned by the other party to the transaction. We received 17,422,615 shares of our common stock with a fair value at the time of the exchange of $1.35 billion.
Common Stock Dividends
On February 8, 2017, our Board of Directors declared a quarterly cash dividend of $0.63 per common share, payable March 1, 2017, to holders of record at the close of business on February 21, 2017.
Noncontrolling Interests
See Note 27-Phillips 66 Partners LP for information on Phillips 66 Partners issuances of common units to the public during 2016.
Note 19-Leases
We lease ocean transport vessels, tugboats, barges, pipelines, railcars, service station sites, computers, office buildings, corporate aircraft, land and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property. There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or borrowing ability. Our capital lease obligations relate primarily to the lease of an oil terminal in the United Kingdom. The lease obligation is subject to foreign currency translation adjustments each reporting period. The total net PP&E recorded for capital leases was $208 million and $231 million at December 31, 2016 and 2015, respectively.
Future minimum lease payments as of December 31, 2016, for operating and capital lease obligations were:
Operating lease rental expense for the years ended December 31 was:
Note 20-Employee Benefit Plans
Pension and Postretirement Plans
The following table provides a reconciliation of the projected benefit obligations and plan assets for our pension plans and accumulated benefit obligations for our other postretirement benefit plans:
Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at December 31, 2016 and 2015, include:
Included in accumulated other comprehensive income/loss at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:
The accumulated benefit obligations for all U.S. and international pensions plans were $2,601 million and $880 million, respectively at December 31, 2016, and $2,485 million and $712 million, respectively, at December 31, 2015.
Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31 were:
Components of net periodic benefit cost for all defined benefit plans are presented in the table below:
In determining net periodic benefit cost, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year. The amount subject to amortization is determined on a plan-by-plan basis. Amounts included in accumulated other comprehensive income at December 31, 2016, that are expected to be amortized into net periodic benefit cost during 2017 are provided below:
The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:
For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.
Our other postretirement benefit plans for health insurance are contributory. Effective December 31, 2012, we terminated the subsidy for retiree medical plans. Since January 1, 2013, eligible employees have been able to utilize notional amounts credited to an account during their period of service with the company to pay all, or a portion, of their cost to participate in postretirement health insurance through the company. In general, employees hired after December 31, 2012, will not receive credits to an account, but will have unsubsidized access to health insurance through the plan. The cost of health insurance will be adjusted annually by the company’s actuary to reflect actual experience and expected health care cost trends. The measurement of the accumulated benefit obligation assumes a health care cost trend rate of 6.50 percent in 2017 that declines to 5.00 percent by 2023. A one percentage-point change in the assumed health care cost trend rate would be immaterial to Phillips 66.
Plan Assets
The investment strategy for managing pension plan assets is to seek a reasonable rate of return relative to an appropriate level of risk and provide adequate liquidity for benefit payments and portfolio management. We follow a policy of diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include equities, fixed income, cash, real estate and insurance contracts. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are approximately 62 percent equity securities, 37 percent debt securities and 1 percent in all other types of investments. Generally, the investments in the plans are publicly traded, therefore minimizing the liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets.
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Fair values of equity securities and government debt securities are based on quoted market prices.
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Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held.
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Cash and cash equivalents are valued at cost, which approximates fair value.
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Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’ participants.
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Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.
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Fair values of investments in common/collective trusts are valued at net asset value (NAV) as determined by the issuer of each fund. Certain investments that are measured at fair value using the NAV value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.
The fair values of our pension plan assets at December 31, by asset class, were as follows:
As reflected in the table above, Level 3 activity was not material.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to international plans are subject to local laws and tax regulations. Actual contribution amounts are dependent upon plan asset returns, changes in pension obligations, regulatory environments, and other economic factors. In 2017, we expect to contribute approximately $130 million to our U.S. pension plans and other postretirement benefit plans and $35 million to our international pension plans.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by us in the years indicated:
Defined Contribution Plans
Most U.S. employees are eligible to participate in the Phillips 66 Savings Plan (Savings Plan). Employees can contribute up to 75 percent of their eligible pay, subject to certain statutory limits, in the thrift feature of the Savings Plan to a choice of investment funds. Phillips 66 provides a company match of participant thrift contributions up to 5 percent of eligible pay. In addition, participants who contribute at least 1 percent to the Savings Plan are eligible for “Success Share,” a semi-annual discretionary company contribution to the Savings Plan that can range from 0 to 6 percent of eligible pay, with a target of 2 percent. The total expense related to participants in the Savings Plan was $99 million, $134 million and $112 million in 2016, 2015 and 2014, respectively.
Share-Based Compensation Plans
In accordance with the Employee Matters Agreement related to the Separation, compensation awards based on ConocoPhillips stock and granted before April 30, 2012 (the Separation Date) were converted to compensation awards based on both ConocoPhillips and Phillips 66 stock if, on the Separation Date, the awards were: (1) options outstanding and exercisable; or (2) restricted stock or restricted stock units (RSUs) awarded for completed performance periods under the ConocoPhillips Performance Share Program. Phillips 66 restricted stock, RSUs and options issued in this conversion became subject to the “Omnibus Stock and Performance Incentive Plan of Phillips 66” (the 2012 Plan) on the Separation Date, whether held by grantees working for the company or grantees that remained employees of ConocoPhillips. Some of these awards based on Phillips 66 stock and held by employees of ConocoPhillips are still outstanding and appear in the activity tables for the Stock Option and the Performance Share Programs presented later in this footnote.
In May 2013, shareholders approved the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66 (the P66 Omnibus Plan). Subsequent to this approval, all new share-based awards are granted under the P66 Omnibus Plan, which authorizes the Human Resources and Compensation Committee of our Board of Directors (the Committee) to grant stock options, stock appreciation rights, stock awards (including restricted stock and RSU awards), cash awards, and performance awards to our employees, non-employee directors and other plan participants. The number of shares that may be issued under the P66 Omnibus Plan to settle share-based awards may not exceed 45 million.
Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time they become eligible for retirement. We recognize share-based compensation expense over the shorter of: (1) the service period (i.e., the stated period of time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months as this is the minimum period of time required for an award not to be subject to forfeiture.
Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). The company made a policy election to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.
Total share-based compensation expense recognized in income and the associated tax benefits for the years ended December 31 were as follows:
Stock Options
Stock options granted under the provisions of the P66 Omnibus Plan and earlier plans permit purchase of our common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date for the three years following the date of grant. Options awarded to employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period.
The following table summarizes our stock option activity from January 1, 2016, to December 31, 2016:
The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2016, were 5.36 years and 4.56 years, respectively. During 2016, we received $34 million in cash and realized a tax benefit of $16 million from the exercise of options. At December 31, 2016, the remaining unrecognized compensation expense from
unvested options was $5 million, which will be recognized over a weighted-average period of 21 months, the longest period being 27 months. The calculations of realized tax benefit and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.
During 2015 and 2014, we granted options with a weighted-average grant-date fair value of $18.84 and $18.95, respectively. During 2015 and 2014, employees exercised options with an aggregate intrinsic value of $60 million and $89 million, respectively.
The following table provides the significant assumptions used to calculate the grant date fair market values of options granted over the years shown below, as calculated using the Black-Scholes-Merton option-pricing model:
After the Separation and through 2015, we calculated the volatility of options granted using a formula that adjusts the pre-Separation historical volatility of ConocoPhillips by the ratio of Phillips 66 implied market volatility on the grant date divided by the pre-Separation implied market volatility of ConocoPhillips. In 2016, we started calculating the volatility using historical Phillips 66 end-of-week closing stock prices from the Separation date.
We calculate the average period of time elapsed between grant dates and exercise dates of past grants to estimate the expected life of new option grants.
Restricted Stock Unit Program
Generally, RSUs are granted annually under the provisions of the P66 Omnibus Plan and cliff vest at the end of three years. Most RSU awards granted prior to the Separation vested ratably over five years, with one-third of the units vesting in 36 months, one-third vesting in 48 months, and the final third vesting 60 months from the date of grant. In addition to the regularly scheduled annual awards, RSUs are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these RSUs vest vary by award. Upon vesting, RSUs are settled by issuing one share of Phillips 66 common stock per RSU. RSUs awarded to employees already eligible for retirement vest within six months of the grant date, but those units are not issued as shares until the end of the normal vesting period. Until issued as stock, most recipients of RSUs receive a quarterly cash payment of a dividend equivalent, and for this reason the grant date fair value of these units is deemed equal to the average Phillips 66 stock price on the date of grant. The grant date fair market value of RSUs that do not receive a dividend equivalent while unvested is deemed equal to the average Phillips 66 common stock price on the grant date, less the net present value of the dividend equivalents that will not be received.
The following table summarizes our RSU activity from January 1, 2016, to December 31, 2016:
At December 31, 2016, the remaining unrecognized compensation cost from the unvested RSU awards was $48 million, which will be recognized over a weighted-average period of 21 months, the longest period being 49 months.
During 2015 and 2014, we granted RSUs with a weighted-average grant-date fair value of $74.09 and $73.28, respectively. During 2015 and 2014, we issued shares with an aggregate fair value of $107 million and $116 million, respectively, to settle RSUs.
Performance Share Program
Under the P66 Omnibus Plan, we also annually grant to senior management restricted performance share units (PSUs) that vest: (1) with respect to awards for performance periods beginning before 2009, when the employee becomes eligible for retirement by reaching age 55 with five years of service; or (2) with respect to awards for performance periods beginning in 2009, five years after the grant date of the award (although recipients can elect to defer the lapsing of restrictions until retirement after reaching age 55 with five years of service); or (3) with respect to awards for performance periods beginning in 2013 or later, on the grant date.
For PSU awards with performance periods beginning before 2013, we recognize compensation expense beginning on the date authorized and ending on the date the PSUs are scheduled to vest; however, since these awards are authorized three years prior to the grant date, we recognize compensation expense for employees that will become eligible for retirement by or shortly after the grant date over the period beginning on the date of authorization and ending on the date of grant. Since PSU awards with performance periods beginning in 2013 or later vest on the grant date, we recognize compensation expense beginning on the date of authorization and ending on the grant date for all employees participating in the PSU grant.
We settle PSUs with performance periods beginning before 2013 by issuing one share of Phillips 66 common stock for each PSU. Recipients of these PSUs receive a quarterly cash payment of a dividend equivalent beginning on the grant date and ending on the settlement date.
We settle PSUs with performance periods beginning in 2013 or later by paying cash equal to the fair value of the PSU on the grant date, which is also the date the PSU vests. Since these PSUs vest and settle on the grant date, dividend equivalents are never paid on these awards.
The following table summarizes our PSU activity from January 1, 2016, to December 31, 2016:
At December 31, 2016, the remaining unrecognized compensation cost from unvested PSU awards held by employees of Phillips 66 was $9 million, which will be recognized over a weighted-average period of 29 months, the longest period being 10 years. The calculations of unamortized expense and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.
During 2015 and 2014, we granted PSUs with a weighted-average grant-date fair value of $74.14 and $72.26, respectively. During 2015 and 2014, we issued shares with an aggregate fair value of $37 million and $13 million, respectively, to settle PSUs. No PSUs were cash settled in 2015 or 2014.
Note 21-Income Taxes
Income taxes charged to income were:
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:
The loss and credit carryforwards deferred tax assets are primarily related to a German interest deduction carryforward of $295 million, an alternative minimum tax credit of $59 million and a foreign tax credit of $89 million. The German interest deduction carryforward and the alternative minimum tax credit may be carried forward indefinitely. The foreign tax credit expires in 2026.
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2016, valuation allowances decreased by a total of $122 million. This decrease was primarily attributable to the reversal of valuation allowances related to interest deduction carryforwards in Germany and the sale of the Whitegate Refinery. During 2016, certain German intercompany loans were refinanced at lower interest rates. As a result of reduced interest rates, as well as increased earnings (current and forecasted), the likelihood of realizing approximately $68 million in tax benefits associated with interest deduction carryforwards is now considered more likely than not. The sale of the Whitegate Refinery resulted in the elimination of a net deferred tax asset and corresponding valuation allowance of approximately $45 million. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects the remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and the tax consequences of future taxable income.
As of December 31, 2016, we had undistributed earnings related to foreign subsidiaries and foreign corporate joint ventures of approximately $3 billion for which deferred income taxes have not been provided. We plan to reinvest these earnings for the foreseeable future. If these amounts were distributed to the United States, we would be subject to additional U.S. income taxes. Determination of the amount of unrecognized deferred income tax liability is not practicable due to the number of unknown variables inherent in the calculation.
As a result of the Separation and pursuant to the Tax Sharing Agreement with ConocoPhillips, the unrecognized tax benefits related to our operations for which ConocoPhillips was the taxpayer remain the responsibility of ConocoPhillips, and we have indemnified ConocoPhillips for such amounts. Those unrecognized tax benefits are included in the following table which shows a reconciliation of the beginning and ending unrecognized tax benefits.
Included in the balance of unrecognized tax benefits for 2016, 2015 and 2014 were $13 million, $34 million and $98 million, respectively, which, if recognized, would affect our effective tax rate. With respect to various unrecognized tax benefits and the related accrued liability, approximately $32 million may be recognized or paid within the next twelve months due to completion of audits.
At December 31, 2016, 2015 and 2014, accrued liabilities for interest and penalties totaled $12 million, $19 million and $16 million, respectively, net of accrued income taxes. As a result of reversing certain of these accruals, earnings increased by $7 million and $3 million in 2016 and 2015, respectively. Neither interest nor penalties had an impact on earnings in 2014.
We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in significant jurisdictions are generally complete as follows: United Kingdom (2011), Germany (2011) and United States (2008). Certain issues remain in dispute for audited years, and unrecognized tax benefits for years still subject to or currently undergoing an audit are subject to change. As a consequence, the balance in unrecognized tax benefits can be expected to
fluctuate from period to period. Although it is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, the amount of change is not estimable.
The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:
Included in the line item “Sale of foreign subsidiaries” is a $224 million tax benefit attributable to the realization of excess tax basis during the fourth quarter of 2014 resulting from the sale of MRC and a $72 million benefit realized in 2015 attributable to the nontaxable gain from the sale of ICHP.
Income tax expenses of $150 million in 2016, and income tax benefits of $34 million and $37 million, for the years 2015 and 2014, respectively, are reflected in the “Capital in Excess of Par” column of the consolidated statement of equity.
Note 22-Accumulated Other Comprehensive Income (Loss)
Changes in the balances of each component of accumulated other comprehensive income (loss) were as follows:
*Included in the computation of net periodic benefit cost. See Note 20-Employee Benefit Plans, for additional information.
Note 23-Cash Flow Information
*2016 reflects a net cash refund position; cash payments for income taxes were $385 million.
PSPI Noncash Stock Exchange
As discussed more fully in Note 6-Assets Held for Sale or Sold, in 2014, we completed the exchange of our flow improvers business for shares of Phillips 66 common stock owned by the other party to the transaction. The noncash portion of the net assets surrendered by us in the exchange was $204 million, and we received approximately 17.4 million shares of our common stock, with a fair value at the time of the exchange of $1.35 billion.
Note 24-Other Financial Information
Note 25-Related Party Transactions
Significant transactions with related parties were:
In December 2014, we completed the sale of our interest in MRC. Accordingly, sales of crude oil to MRC and purchases of refined products from MRC are only included in the 2014 amounts in the table above.
(a)
We sold NGL and other petrochemical feedstocks, along with solvents, to CPChem, and we sold gas oil and hydrogen feedstocks to Excel Paralubes (Excel). We sold certain feedstocks and intermediate products to WRB and also acted as agent for WRB in supplying crude oil and other feedstocks for a fee. We also sold refined products to our OnCue Holdings, LLC joint venture. In addition, we charged several of our affiliates, including CPChem, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
(b)
We purchased crude oil and refined products from WRB. We also acted as agent for WRB in distributing asphalt and solvents for a fee. We purchased natural gas and NGL from DCP Midstream and CPChem, as well as other feedstocks from various affiliates, for use in our refinery and fractionation processes. We paid NGL fractionation fees to CPChem. We also paid fees to various pipeline equity companies for transporting crude oil, finished refined products and NGL. We purchased base oils and fuel products from Excel for use in our refining and specialty businesses.
(c)
We paid utility and processing fees to various affiliates.
Note 26-Segment Disclosures and Related Information
Our operating segments are:
1)
Midstream-Gathers, processes, transports and markets natural gas; and transports, stores, fractionates and markets NGL in the United States. In addition, this segment transports crude oil and other feedstocks to our refineries and other locations, delivers refined and specialty products to market, and provides terminaling and storage services for crude and petroleum products. The segment also stores, refrigerates and exports liquefied petroleum gas primarily to Asia and Europe. The Midstream segment includes our master limited partnership, Phillips 66 Partners LP, as well as our 50 percent equity investment in DCP Midstream.
2)
Chemicals-Consists of our 50 percent equity investment in CPChem, which manufactures and markets petrochemicals and plastics on a worldwide basis.
3)
Refining-Buys, sells and refines crude oil and other feedstocks at 13 refineries, mainly in the United States and Europe.
4)
Marketing and Specialties (M&S)-Purchases for resale and markets refined petroleum products (such as gasolines, distillates and aviation fuels), mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products, as well as power generation operations.
Corporate and Other includes general corporate overhead, interest expense, our investments in new technologies and various other corporate items. Corporate assets include all cash and cash equivalents.
We evaluate segment performance based on net income attributable to Phillips 66. Intersegment sales are at prices that approximate market.
Analysis of Results by Operating Segment
Geographic Information
*Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.
**Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.
Note 27-Phillips 66 Partners LP
Phillips 66 Partners is a publicly traded master limited partnership formed to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other midstream assets. Headquartered in Houston, Texas, Phillips 66 Partners’ assets currently consist of crude oil, refined petroleum products and NGL transportation, terminaling and storage systems, as well as an NGL fractionator. Phillips 66 Partners conducts its operations through both wholly owned and joint-venture operations. The majority of Phillips 66 Partners’ wholly owned assets are associated with, and integral to the operation of, nine of Phillips 66’s owned or joint-venture refineries.
2016 Activities
In March 2016, we contributed to Phillips 66 Partners a 25 percent interest in our then wholly owned subsidiary, Phillips 66 Sweeny Frac LLC, which owns the Sweeny Fractionator, an NGL fractionator located within our Sweeny Refinery complex in Old Ocean, Texas, and the Clemens Caverns, an NGL salt dome storage facility located near Brazoria, Texas. Total consideration for the transaction was $236 million, which consisted of Phillips 66 Partners’ assumption of a $212 million note payable to us and the issuance of common units and general partner units to us with an aggregate fair value of $24 million.
In May 2016, we contributed to Phillips 66 Partners the remaining 75 percent interest in Phillips 66 Sweeny Frac LLC and a 100 percent interest in our wholly owned subsidiary, Phillips 66 Plymouth LLC, which owned the Standish Pipeline, a refined petroleum product pipeline system extending from Phillips 66’s Ponca City Refinery in Ponca City, Oklahoma, and terminating at Phillips 66 Partners’ North Wichita Terminal in Wichita, Kansas. Total consideration for the transaction was $775 million, consisting of Phillips 66 Partners’ assumption of $675 million of notes payable to us and the issuance of common units and general partner units to us with an aggregate fair value of $100 million.
In May 2016, Phillips 66 Partners completed a public offering of 12,650,000 common units representing limited partner interests, at a price of $52.40 per unit. The net proceeds at closing were $656 million. Phillips 66 Partners used these net proceeds to repay a large portion of the notes assumed in the May 2016 transaction.
In June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which allows for the issuance of up to an aggregate of $250 million of Phillips 66 Partners’ common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of the offerings. We refer to this as an at-the-market, or ATM, program. Through December 31, 2016, on a settlement-date basis, Phillips 66 Partners issued an aggregate of 346,152 common units under the ATM program, generating net proceeds of approximately $19 million.
In August 2016, Phillips 66 Partners completed a public offering of 6,000,000 common units representing limited partner interests, at a price of $50.22 per unit. The net proceeds at closing were $299 million. The net proceeds from the offering were used to repay the note assumed in the March 2016 transaction discussed above, as well as short-term borrowings incurred to fund Phillips 66 Partners’ acquisition of an additional interest in Explorer Pipeline Company and its contribution to a recently formed pipeline joint venture.
In October 2016, we contributed to Phillips 66 Partners certain crude oil, refined product and NGL pipeline and terminal assets supporting four of our operated refineries. Total consideration for the transaction was $1.3 billion, consisting of $1,109 million in cash and the issuance of common and general partner units to us with a fair value of $196 million. Phillips 66 Partners funded the cash portion of the transaction with proceeds from a public debt offering of unsecured senior notes of $1,125 million in the aggregate. See Note 13-Debt for additional information on the notes offering.
In November 2016, Phillips 66 Partners acquired a third-party NGL logistics system in southeast Louisiana. Consideration was financed with cash and borrowings under Phillips 66 Partners’ revolving credit facility. The system includes approximately 500 miles of pipeline and a storage cavern connecting multiple fractionation facilities, refineries and a petrochemical facility.
Ownership
At December 31, 2016, we owned a 59 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 39 percent limited partner interest. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3-Variable Interest Entities for additional information on why we consolidate the partnership. As a result of this consolidation, the public unitholders’ ownership interest in Phillips 66 Partners is reflected as a noncontrolling interest of $1,306 million and $809 million in our consolidated balance sheet as of December 31, 2016, and 2015, respectively. Generally, drop down transactions to Phillips 66 Partners will eliminate in consolidation, except for third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. For contributions in 2016 together with the public offerings of common units and senior notes discussed above, our consolidated cash increased by $2.1 billion, consolidated debt increased by $1.1 billion and consolidated equity increased by $791 million as a result of the transactions.
Note 28-New Accounting Standards
In January 2017, the FASB issued ASU 2017-04, “Intangibles-Goodwill and Other-Simplifying the Test for Goodwill Impairment,” which eliminates Step 2 from the goodwill impairment test. Under the revised test, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Public business entities should apply the guidance in ASU No. 2017-04 for its annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2017-04.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations: Clarifying the Definition of a Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen for determining when a transaction involves an acquisition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then the transaction does not involve the acquisition of a business. If the screen is not met, then the amendment requires that to be considered a business, the operation must include at a minimum an input and a substantive process that together significantly contribute to the ability to create an output. The guidance may reduce the number of transactions accounted for as business acquisitions. Public business entities should apply the guidance in ASU No. 2017-01 to annual periods beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The amendments should be applied prospectively, and no disclosures are required at the effective date. We are currently evaluating the provisions of ASU No. 2017-01.
In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash,” which clarifies the classification and presentation of changes in restricted cash. The amendment requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. Public business entities should apply the guidance in ASU No. 2016-18 on a retrospective basis for annual periods beginning after December 15, 2017, including interim periods within those annual periods, with early adoption permitted. We do not expect the adoption of this ASU to have a material impact on our financial statements.
In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which clarifies the treatment of several cash flow categories. In addition, ASU No. 2016-15 clarifies that when cash receipts and cash payments have aspects of more than one class of cash flows and cannot be separated, classification will depend on the predominant source or use. Public business entities should apply the guidance in ASU No. 2016-15 on a retrospective basis for annual periods beginning after December 15, 2017, including interim periods within those annual periods, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2016-15 and assessing the impact on our financial statements.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The new standard amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. Public business entities should apply the guidance in ASU No. 2016-13 for annual periods beginning after December 15, 2019, including interim periods within those annual periods. Early adoption will be permitted for annual periods beginning after December 15, 2018. We are currently evaluating the provisions of ASU No. 2016-13 and assessing the impact on our financial statements.
In March 2016, the FASB issued ASU No. 2016-09, “Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment award transactions including accounting for income taxes and classification of excess tax benefits on the statement of cash flows, forfeitures and minimum statutory tax withholding requirements. Public business entities should apply the guidance in ASU No. 2016-09 for annual periods beginning after December 15, 2016, including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the provisions of ASU No. 2016-09 and assessing the impact on our financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” In the new standard, the FASB modified its determination of whether a contract is a lease rather than whether a lease is a capital or operating lease under the previous accounting principles generally accepted in the United States (GAAP). A contract represents a lease if a transfer of control occurs over an identified property, plant and equipment for a period of time in exchange for consideration. Control over the use of the identified asset includes the right to obtain substantially all of the economic benefits from the use of the asset and the right to direct its use. The FASB continued to maintain two classifications of leases - financing and operating - which are substantially similar to capital and operating leases in the previous lease guidance. Under the new standard, recognition of assets and liabilities arising from operating leases will require recognition on the balance sheet. The effect of all leases in the statement of comprehensive income and the statement of cash flows will be largely unchanged. Lessor accounting will also be largely unchanged. Additional disclosures will be required for financing and operating leases for both lessors and lessees. Public business entities should apply the guidance in ASU No. 2016-02 for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the provisions of ASU No. 2016-02 and assessing its impact on our financial statements.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to be carried at fair value upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU No. 2016-01 for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a limited impact on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under GAAP and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets and expand disclosure requirements. In August 2015, the FASB
issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier adoption is permitted only as of annual reporting periods beginning after December 31, 2016, including interim reporting periods within that reporting period. Retrospective or modified retrospective application of the accounting standard is required. ASU No. 2014-09 was further amended in March 2016 by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASU No. 2016-20, “Technical Corrections to Topic 606, Revenue from Contracts with Customers.” As part of our assessment work-to-date, we have formed an implementation work team, completed training on the new ASU’s revenue recognition model and are continuing our contract review and documentation. Our expectation is to adopt the standard on January 1, 2018, using the modified retrospective application. In addition, we expect to present revenue net of sales-based taxes collected from our customers resulting in no impact to earnings. Sales-based taxes include excise taxes on petroleum product sales as noted on our consolidated statement of income. Our evaluation of the new ASU is ongoing, which includes understanding the impact of adoption on earnings from equity method investments.
Note 29-Condensed Consolidating Financial Information
Our $7.5 billion of outstanding Senior Notes issued by Phillips 66 are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Phillips 66 Company has fully and unconditionally guaranteed the payment obligations of Phillips 66 with respect to these debt securities. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
•
Phillips 66 and Phillips 66 Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
•
All other nonguarantor subsidiaries.
•
The consolidating adjustments necessary to present Phillips 66’s results on a consolidated basis.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
Selected Quarterly Financial Data (Unaudited)
*Includes excise taxes on petroleum products sales.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of December 31, 2016, with the participation of management, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2016.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the quarterly period ended December 31, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
This report is included in Item 8 and is incorporated herein by reference.
Item 9B. OTHER INFORMATION
None.
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report.
The remaining information required by Item 10 of Part III is incorporated herein by reference from our 2017 Definitive Proxy Statement.*
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Part III is incorporated herein by reference from our 2017 Definitive Proxy Statement.*
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by Item 12 of Part III is incorporated herein by reference from our 2017 Definitive Proxy Statement.*
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 of Part III is incorporated herein by reference from our 2017 Definitive Proxy Statement.*
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Part III is incorporated herein by reference from our 2017 Definitive Proxy Statement.*
_________________________
*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2017 Definitive Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report.
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1.
Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 66, are filed as part of this Annual Report on Form 10-K.
2.
Financial Statement Schedules
All financial statement schedules are omitted because they are not required, not significant, not applicable, or the information is shown in the financial statements or notes thereto.
3.
Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages 135 to 138, are filed as part of this Annual Report on Form 10-K.
(c)
Pursuant to Rule 3-09 of Regulation S-X, the financial statements of Chevron Phillips Chemical Company LLC as of December 31, 2016 and 2015, and for the three years ended December 31, 2016, are included as an exhibit to this Annual Report on Form 10-K.
PHILLIPS 66
INDEX TO EXHIBITS
Incorporated by Reference
Exhibit
Number
Exhibit Description
Form
Exhibit
Number
Filing
Date
SEC
File No.
2.1
Separation and Distribution Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.
8-K
2.1
05/01/12
001-35349
3.1
Amended and Restated Certificate of Incorporation of Phillips 66.
8-K
3.1
05/01/12
001-35349
3.2
Amended and Restated By-Laws of Phillips 66.
8-K
3.1
02/09/17
001-35349
4.1
Indenture, dated as of March 12, 2012, among Phillips 66, as issuer, Phillips 66 Company, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee, in respect of senior debt securities of Phillips 66.
4.3
04/05/12
001-35349
4.2
Form of the terms of the 2.950% Senior Notes due 2017, the 4.300% Senior Notes due 2022 and the 5.875% Senior Notes due 2042, including the form of the 2.950% Senior Notes due 2017, the 4.300% Senior Notes due 2022 and the 5.875% Senior Notes due 2042.
10-K
4.2
02/22/13
001-35349
4.3
Form of the terms of the 4.650% Senior Notes due 2034 and the 4.875% Senior Notes due 2044.
8-K
4.2
11/17/14
001-35349
10.1
Credit Agreement among Phillips 66, Phillips 66 Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders named therein, dated as of February 22, 2012.
4.1
03/01/12
001-35349
10.2
First Amendment to Credit Agreement among Phillips 66, Phillips 66 Company, JPMorgan Chase Bank, N.A., and lenders named therein, dated as of June 10, 2013.
10-Q
10.1
05/01/14
001-35349
10.3
Second Amendment to Credit Agreement among Phillips 66, Phillips 66 Company, JPMorgan Chase Bank, N.A., and lenders named therein, dated as of December 10, 2014.
10-K
10.3
02/20/15
001-35349
10.4*
Third Amendment to Credit Agreement among Phillips 66, Phillips 66 Company, JPMorgan Chase Bank, N.A., and lenders named therein, dated as of October 3, 2016.
10.5
Third Amended and Restated Limited Liability Company Agreement of Chevron Phillips Chemical Company LLC, effective as of May 1, 2012.
10-Q
10.14
08/03/12
001-35349
10.6
Second Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC, dated July 5, 2005, by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation.
10.12
03/01/12
001-35349
10.7
First Amendment to Second Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC, dated August 11, 2006, by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation.
10.13
03/01/12
001-35349
Incorporated by Reference
Exhibit
Number
Exhibit Description
Form
Exhibit
Number
Filing
Date
SEC
File No.
10.8
Second Amendment to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC), dated February 1, 2007, by and between ConocoPhillips Gas Company, Spectra Energy DEFS Holding, LLC, and Spectra Energy DEFS Holding Corp.
10.14
03/01/12
001-35349
10.9
Third Amendment to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC), dated April 30, 2009, by and between ConocoPhillips Gas Company, Spectra Energy DEFS Holding, LLC, and Spectra Energy DEFS Holding Corp.
10.15
03/01/12
001-35349
10.10
Fourth Amendment to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC), dated November 9, 2010, by and between ConocoPhillips Gas Company, Spectra Energy DEFS Holding, LLC, and Spectra Energy DEFS Holding Corp.
10.16
03/01/12
001-35349
10.11
Fifth Amendment to July 5, 2005 Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC) dated September 9, 2014, by and between Phillips Gas Company (formerly ConocoPhillips Gas Company), Spectra Energy DEFS Holding, LLC, and Spectra Energy DEFS Holding II, LLC.
10-Q
10.1
10/30/14
001-35349
10.12
Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.
8-K
10.1
05/01/12
001-35349
10.13
Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.
8-K
10.2
05/01/12
001-35349
10.14
Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.
8-K
10.3
05/01/12
001-35349
10.15
Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.
8-K
10.4
05/01/12
001-35349
10.16
Amendment to the Employee Matters Agreement by and between ConocoPhillips and Phillips 66, dated April 26, 2012.
10-Q
10.1
05/02/13
001-35349
10.17
Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.
8-K
10.5
05/01/12
001-35349
10.18
2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**
DEF14A
App. A
03/27/13
001-35349
10.19
Phillips 66 Key Employee Supplemental Retirement Plan.**
10-Q
10.15
08/03/12
001-35349
10.20
First Amendment to the Phillips 66 Key Employee Supplemental Retirement Plan.**
10-K
10.18
02/22/13
001-35349
10.21
Phillips 66 Amended and Restated Executive Severance Plan.**
10-Q
10.1
07/29/16
001-35349
10.22
Phillips 66 Deferred Compensation Plan for Non-Employee Directors.**
10-Q
10.17
08/03/12
001-35349
Incorporated by Reference
Exhibit
Number
Exhibit Description
Form
Exhibit
Number
Filing
Date
SEC
File No.
10.23
Phillips 66 Key Employee Deferred Compensation Plan-Title I.**
10-Q
10.18
08/03/12
001-35349
10.24
Phillips 66 Key Employee Deferred Compensation Plan-Title II.**
10-Q
10.19
08/03/12
001-35349
10.25
First Amendment to the Phillips 66 Key Employee Deferred Compensation Plan Title II.**
10-K
10.24
02/22/13
001-35349
10.26
Phillips 66 Defined Contribution Make-Up Plan Title I.**
10-Q
10.20
08/03/12
001-35349
10.27
Phillips 66 Defined Contribution Make-Up Plan Title II.**
10-K
10.26
02/22/13
001-35349
10.28
Phillips 66 Key Employee Change in Control Severance Plan.**
10-K
10.27
02/22/13
001-35349
10.29
First Amendment to Phillips 66 Key Employee Change in Control Severance Plan, Effective October 2, 2015.**
8-K
10.1
11/08/13
001-35349
10.30
Annex to the Phillips 66 Nonqualified Deferred Compensation Arrangements.**
10-Q
10.23
08/03/12
001-35349
10.31
Form of Stock Option Award Agreement under the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**
10-K
10.29
02/22/13
001-35349
10.32
Form of Restricted Stock or Restricted Stock Unit Award Agreement under the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**
10-K
10.30
02/22/13
001-35349
10.33
Form of Performance Share Unit Award Agreement under the 2013 Omnibus Stock and Performance Incentive Plan of Phillips 66.**
10-K
10.31
02/22/13
001-35349
12*
Computation of Ratio of Earnings to Fixed Charges.
21*
List of Subsidiaries of Phillips 66.
23.1*
Consent of Ernst & Young LLP, independent registered public accounting firm.
23.2*
Consent of Ernst & Young LLP, independent auditors for Chevron Phillips Chemicals Company LLC.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32*
Certifications pursuant to 18 U.S.C. Section 1350.
99.1*
The financial statements of Chevron Phillips Chemical Company, LLC, pursuant to Rule 3-09 of Regulation S-X.
Incorporated by Reference
Exhibit
Number
Exhibit Description
Form
Exhibit
Number
Filing
Date
SEC
File No.
101.INS*
XBRL Instance Document.
101.SCH*
XBRL Schema Document.
101.CAL*
XBRL Calculation Linkbase Document.
101.LAB*
XBRL Labels Linkbase Document.
101.PRE*
XBRL Presentation Linkbase Document.
101.DEF*
XBRL Definition Linkbase Document.
*Filed herewith.
**Management contracts and compensatory plans or arrangements.
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.
PHILLIPS 66
February 17, 2017
/s/ Greg C. Garland
Greg C. Garland
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 17, 2017, on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors.
Signature
Title
/s/ Greg C. Garland
Chairman of the Board of Directors
Greg C. Garland
and Chief Executive Officer
(Principal executive officer)
/s/ Kevin J. Mitchell
Executive Vice President, Finance
Kevin J. Mitchell
and Chief Financial Officer
(Principal financial officer)
/s/ Chukwuemeka A. Oyolu
Vice President and Controller
Chukwuemeka A. Oyolu
(Principal accounting officer)
/s/ Gary K. Adams
Director
Gary K. Adams
/s/ J. Brian Ferguson
Director
J. Brian Ferguson
/s/ William R. Loomis Jr.
Director
William R. Loomis Jr.
/s/ John E. Lowe
Director
John E. Lowe
/s/ Harold W. McGraw III
Director
Harold W. McGraw III
/s/ Denise L. Ramos
Director
Denise L. Ramos
/s/ Glenn F. Tilton
Director
Glenn F. Tilton
/s/ Victoria J. Tschinkel
Director
Victoria J. Tschinkel
/s/ Marna C. Whittington
Director
Marna C. Whittington