filings.toolsItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
126K characters. Original on sec.gov · Markdown
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “Phillips 66” are used in this report to refer to the businesses of Phillips 66 and its consolidated subsidiaries.
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. The terms “pre-tax income” or “pre-tax loss” as used in Management’s Discussion and Analysis refer to income (loss) before income taxes.
EXECUTIVE OVERVIEW AND BUSINESS ENVIRONMENT
Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and specialties businesses. At December 31, 2018, we had total assets of $54.3 billion.
Executive Overview
In 2018, we reported earnings of $5.6 billion, generated $7.6 billion in cash from operating activities and raised net proceeds of $1.5 billion from the issuance of senior notes. We used available cash primarily for repurchases of our common stock of $4.6 billion, capital expenditures and investments of $2.6 billion, dividend payments on our common stock of $1.4 billion and the early repayment of $550 million of debt. We ended 2018 with $3.0 billion of cash and cash equivalents and approximately $5.6 billion of total committed capacity available under our credit facilities.
We continue to focus on the following strategic priorities:
| • | 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. 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. Senior management actively monitors these costs. 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 2018, our worldwide refining crude oil capacity utilization rate was 95 percent. |
| • | Growth. We have budgeted $3.2 billion in capital expenditures and investments in 2019, including $0.9 billion for Phillips 66 Partners LP (Phillips 66 Partners). The Phillips 66 Partners’ capital budget includes $0.3 billion of capital expected to be cash funded by noncontrolling interests. Additionally, our share of expected self-funded capital spending by joint ventures DCP Midstream, LLC (DCP Midstream), Chevron Phillips Chemical Company LLC (CPChem) and WRB Refining LP (WRB) in 2019 is $1.2 billion. In Midstream, we will continue building out our integrated logistics infrastructure network, including pipelines, storage, export and fractionation facilities. In Chemicals, CPChem’s growth capital will fund continuing development of a second U.S. Gulf Coast petrochemicals project and debottlenecking opportunities on existing assets. Growth capital in Refining will be directed toward high-return projects to enhance the yield of higher-value products, as well as other low-capital, quick-payout projects, while in Marketing and Specialties (M&S) it will be to further grow and enhance retail sites in Europe. |
| • | 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 we focus investments in projects that generate competitive returns throughout the business cycle. In 2018, our Midstream segment benefited from higher equity earnings and cash distributions from our investments in joint venture pipelines. Our Refining segment maintained a strong clean product yield and a high advantaged crude oil throughput rate at our U.S. refineries. Additionally, our M&S segment continued to enhance our network and brand by re-imaging sites in the United States. |
| • | Distributions. We believe shareholder value is enhanced through, among other things, consistent growth of regular dividends, complemented by share repurchases. We increased our quarterly dividend rate by 14 percent during 2018, and have increased it every year since the company’s inception in 2012. 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 2018, we repurchased $4.6 billion, or approximately 48 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. |
| • | 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
The price of U.S. benchmark crude oil, West Texas Intermediate (WTI) at Cushing, Oklahoma, increased to an average of $64.92 per barrel during 2018, compared with an average of $50.90 per barrel in 2017. The WTI discount versus the international benchmark Dated Brent widened in 2018, compared with 2017, due to growing U.S. crude production. A widening differential generally benefits our results. Over the course of 2018, commodity prices had both favorable and unfavorable impacts on our businesses that vary by segment.
The Midstream segment, which includes our 50 percent equity investment in DCP Midstream, contains fee-based operations that are not directly exposed to commodity price risk, as well as operations that are directly linked to natural gas liquids (NGL) prices, natural gas prices and crude oil prices. Natural gas prices were relatively flat in 2018, compared with 2017, while NGL prices were higher in 2018 due to higher global crude oil prices and increased domestic demand for ethane.
The Chemicals segment consists of our 50 percent equity investment in CPChem. 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. During 2018, the high-density polyethylene chain margin contracted mainly due to rapidly expanding North American supply. In addition, lower naptha-based feedstock costs internationally narrowed the difference between naptha-based and ethane-based margins. However, North American ethane-based crackers integrated through ethylene derivatives continue to benefit from a feedstock price advantage associated with abundant domestic supply and continue to capture a higher polyethylene chain margin than crackers in most other regions of the world.
Our Refining segment results are driven by several factors, including refining margins, cost control, refinery throughput, feedstock costs, product yields and turnaround activity. Industry crack spread indicators, the difference between market prices for refined petroleum products and crude oil, are used to estimate refining margins. During 2018, the U.S. 3:2:1 crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) decreased compared with 2017, primarily due to lower gasoline crack spreads caused by higher refinery utilization. The average Northwest Europe crack spread increased slightly in 2018, compared with 2017, due to higher distillate prices.
Results for our M&S segment depend largely on marketing fuel margins, lubricant margins, and other specialty product margins. While M&S margins are primarily driven by market factors, largely determined by the relationship between supply and demand, marketing fuel margins, in particular, are influenced by the trend in spot prices for refined petroleum 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
Basis of Presentation
During the fourth quarter of 2018, the segment performance measure used by our chief executive officer to assess performance and allocate resources was changed from “net income” to “income before income taxes.” Prior-period segment information has been recast to conform to the current presentation.
Consolidated Results
A summary of income (loss) before income taxes by business segment with a reconciliation to net income attributable to Phillips 66 follows:
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Midstream | $ | 1,181 | 638 | 403 | |||||
| Chemicals | 1,025 | 716 | 839 | ||||||
| Refining | 4,535 | 2,076 | 435 | ||||||
| Marketing and Specialties | 1,557 | 1,020 | 1,261 | ||||||
| Corporate and Other | (853 | ) | (895 | ) | (747 | ) | |||
| Income before income taxes | 7,445 | 3,555 | 2,191 | ||||||
| Income tax expense (benefit) | 1,572 | (1,693 | ) | 547 | |||||
| Net income | 5,873 | 5,248 | 1,644 | ||||||
| Less: net income attributable to noncontrolling interests | 278 | 142 | 89 | ||||||
| Net income attributable to Phillips 66 | $ | 5,595 | 5,106 | 1,555 |
2018 vs. 2017
Our earnings increased $489 million, or 10 percent, in 2018, mainly reflecting:
| • | Higher realized refining and marketing margins. |
| • | Higher earnings from equity affiliates in our Midstream and Chemicals segments. |
| • | A lower U.S. federal corporate income tax rate beginning January 1, 2018, as a result of the U.S. Tax Cuts and Jobs Act (the Tax Act) enacted in December 2017. |
These increases were partially offset by:
| • | A $2,735 million provisional income tax benefit from the enactment of the Tax Act recognized in December 2017, primarily due to the revaluation of deferred income taxes. |
| • | A $261 million noncash, after-tax gain from the consolidation of Merey Sweeny, L.P., predecessor to Merey Sweeny LLC (both referred to herein as Merey Sweeny), in 2017. |
| • | Higher net income attributable to noncontrolling interests primarily due to the contribution of assets to Phillips 66 Partners in the fourth quarter of 2017. |
| • | Higher interest and debt expense. |
2017 vs. 2016
Our earnings increased $3,551 million, or 228 percent, in 2017, primarily resulting from:
| • | Recognition of the $2,735 million provisional income tax benefit from the enactment of the Tax Act in December 2017. |
| • | Higher realized refining margins. |
| • | Recognition of the $261 million after-tax gain from the consolidation of Merey Sweeny. |
| • | Improved equity earnings from affiliates in our Midstream segment. |
These increases were partially offset by:
| • | Increased costs due to Hurricane Harvey, primarily impacting CPChem in our Chemicals segment. |
| • | Lower realized marketing margins. |
| • | Higher interest and debt expense. |
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
2018 vs. 2017
Sales and other operating revenues and purchased crude oil and products increased 9 percent and 23 percent, respectively, in 2018. The increases were mainly due to higher prices for refined petroleum products, crude oil and NGL. The increase in sales and other operating revenues was partially offset by a change in the presentation of excise taxes on sales of refined petroleum products resulting from our adoption of Financial Accounting Standard Board (FASB) Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” on January 1, 2018. As part of our adoption of this ASU, prospectively from January 1, 2018, our presentation of excise taxes on sales of refined petroleum products changed to a net basis from a gross basis. As a result, the “Sales and other operating revenues” and “Taxes other than income taxes” lines on our consolidated statement of income for the year ended December 31, 2018, are not presented on a comparable basis to the years ended December 31, 2017 and 2016. See Note 1—Summary of Significant Accounting Policies and Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for further information on our presentation of excise taxes on sales of refined petroleum products and our adoption of this ASU, respectively.
Equity in earnings of affiliates increased 55 percent in 2018, primarily resulting from higher equity in earnings from WRB, CPChem and affiliates in our Midstream segment.
| • | Equity in earnings of WRB increased $483 million, primarily due to higher realized margins driven by improved feedstock advantage. |
| • | Equity in earnings of CPChem increased $312 million, primarily due to commencement of full operations at CPChem’s new U.S. Gulf Coast petrochemicals assets and lower hurricane-related costs and downtime in 2018. |
| • | Equity in earnings for our Midstream segment increased $222 million, primarily due to higher volumes on affiliate pipelines, including the Bakken Pipeline, which operated for a full year in 2018. |
Other income decreased $460 million in 2018. We recognized a noncash, pre-tax gain of $423 million in February 2017 related to the consolidation of Merey Sweeny. See Note 5—Business Combinations, in the Notes to Consolidated Financial Statements, for additional information.
Taxes other than income taxes decreased 97 percent in 2018. The decrease was primarily attributable to the change in our presentation of excise taxes on sales of refined petroleum products resulting from our adoption of ASU No. 2014-09 on January 1, 2018. See the “Sales and other operating revenues” section above for further discussion.
Interest and debt expense increased 15 percent in 2018. The increase was due to higher average debt principal balances resulting from our issuance of senior notes totaling $1,500 million in March 2018 and Phillips 66 Partners’ issuance of senior notes totaling $650 million in October 2017.
Income tax expense (benefit) was an expense in 2018, compared with a benefit in 2017. The benefit in 2017 was due to the recognition of a provisional income tax benefit of $2,735 million from the enactment of the Tax Act in December 2017. The benefit from the Tax Act was primarily due to the revaluation of deferred income taxes. Excluding this benefit, income tax expense increased in 2018 due to higher income before income taxes, partially offset by the reduction of the U.S. federal corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, as a result of the Tax Act. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for more information regarding our income taxes.
Net income attributable to noncontrolling interests increased $136 million in 2018, primarily due to the contribution of assets to Phillips 66 Partners in the fourth quarter of 2017. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for more information.
2017 vs. 2016
Sales and other operating revenues and purchased crude oil and products increased 21 percent and 27 percent, respectively, in 2017. The increases were primarily due to higher prices for refined petroleum products, crude oil and NGL.
Equity in earnings of affiliates increased 22 percent in 2017, primarily resulting from higher equity in earnings from DCP Midstream and other affiliates in our Midstream segment, as well as WRB, partially offset by lower results from CPChem.
| • | Equity in earnings from our Midstream segment increased $270 million due to improved results from DCP Midstream, primarily driven by improved margins, as well as higher equity in earnings from our pipeline affiliates, including our joint ventures that own the Bakken Pipeline, which started commercial operations in June 2017. |
| • | Equity in earnings of WRB increased $207 million, primarily due to higher market crack spreads, partially offset by lower feedstock advantage. |
| • | Equity in earnings of CPChem decreased $120 million, primarily due to hurricane-related costs and downtime. |
Other income increased $447 million in 2017. We recognized a noncash, pre-tax gain of $423 million in February 2017 related to the consolidation of Merey Sweeny. See Note 5—Business Combinations, in the Notes to Consolidated Financial Statements, for additional information.
Operating expenses increased 10 percent in 2017. This increase was mainly due to the consolidation of a transportation joint venture in December 2016, as well as higher refining turnaround expenses and utility costs, pension settlement expense, and costs associated with a full year of operations at the Freeport LPG Export Terminal. These increases were partially offset by lower costs due to the sale of the Whitegate Refinery in 2016.
Depreciation and amortization increased 13 percent in 2017 due to the Freeport LPG Export Terminal beginning operations in late 2016, as well as other assets placed in service in 2017.
Interest and debt expense increased 30 percent in 2017. This increase was primarily driven by lower capitalized interest due to the completion of major projects, including completion of the Freeport LPG Export Terminal project in late 2016, as well as higher average debt principal balances.
Income tax expense (benefit) was a benefit in 2017, compared with expense in 2016, primarily due to the $2,735 million provisional income tax benefit from the enactment of the Tax Act in December 2017. The benefit from the Tax Act was primarily due to the revaluation of deferred income taxes. This benefit was partially offset by higher income tax expense from increased income before income taxes. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for more information regarding our income taxes.
Net income attributable to noncontrolling interests increased $53 million in 2017, primarily due to the contributions of assets to Phillips 66 Partners during 2017 and late 2016. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for more information.
Segment Results
Midstream
| Year Ended December 31 | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Millions of Dollars | |||||||||
| Income (Loss) Before Income Taxes | |||||||||
| Transportation | $ | 770 | 530 | 442 | |||||
| NGL and Other | 305 | 32 | (5 | ) | |||||
| DCP Midstream | 106 | 76 | (34 | ) | |||||
| Total Midstream | $ | 1,181 | 638 | 403 |
| Thousands of Barrels Daily | ||||||||
| Transportation Volumes | ||||||||
| Pipelines* | 3,441 | 3,320 | 3,321 | |||||
| Terminals | 3,153 | 2,665 | 2,422 | |||||
| Operating Statistics | ||||||||
| NGL fractionated** | 216 | 186 | 170 | |||||
| NGL extracted*** | 413 | 374 | 393 |
- Pipelines represent the sum of volumes transported through each separately tariffed consolidated pipeline segment. Prior year volumes have been recast to exclude our share of equity volumes from Yellowstone Pipe Line Company and Lake Charles Pipe Line Company.
** Excludes DCP Midstream.
*** Represents 100 percent of DCP Midstream’s volumes.
| Dollars Per Gallon | |||||||||
| Weighted-Average NGL Price* | |||||||||
| DCP Midstream | $ | 0.75 | 0.62 | 0.46 |
- Based on index prices from the Mont Belvieu market hub, which are weighted by NGL component.
The Midstream segment provides crude oil and refined petroleum product transportation, terminaling and processing services, as well as natural gas and NGL transportation, storage, processing and marketing services, mainly in the United States. This segment includes our master limited partnership (MLP), Phillips 66 Partners, as well as our 50 percent equity investment in DCP Midstream, which includes the operations of its MLP, DCP Midstream, LP (DCP Partners).
2018 vs. 2017
Pre-tax income from the Midstream segment increased $543 million in 2018, compared with 2017, due to improved results across all business lines.
Pre-tax income from our Transportation business increased $240 million in 2018, compared with 2017. The increase was mainly driven by higher volumes, tariffs and storage rates from our portfolio of consolidated and joint venture assets. These increases were partially offset by a decrease in equity earnings from Rockies Express Pipeline LLC (REX) due to a favorable settlement recorded in 2017.
Pre-tax income from our NGL and Other business increased $273 million in 2018, compared with 2017. The increase was primarily due to the contribution of Merey Sweeny to Phillips 66 Partners in October 2017, inventory impacts, improved cargo margins and volumes, and higher equity earnings from pipeline affiliates due to increased volumes.
Pre-tax income from our investment in DCP Midstream increased $30 million in 2018, compared with 2017. The increase was primarily due to higher equity earnings from affiliates as a result of increased volumes, timing of incentive distribution income allocations from DCP Partners, and favorable hedging results. These increases were partially offset by higher asset impairments and operating costs in 2018.
See the “Executive Overview and Business Environment” section for information on market factors impacting 2018 results.
2017 vs. 2016
Pre-tax income from the Midstream segment increased $235 million in 2017, compared with 2016, due to improved results across all business lines.
Pre-tax income from our Transportation business increased $88 million in 2017, compared with 2016. The improvement was mainly driven by increased equity earnings from affiliates, including our joint ventures that own the Bakken Pipeline, which started commercial operations in June 2017, as well as REX due to our share of a favorable breach of contract settlement claim. These increases were partially offset by higher operating costs.
Pre-tax income from our NGL and Other business increased $37 million in 2017, compared with 2016. The increase reflected a full year of operations at the Freeport LPG Export Terminal, the contribution of Merey Sweeny to Phillips 66 Partners in October 2017, and higher equity earnings from DCP Sand Hills Pipeline, LLC (Sand Hills), partially offset by lower realized margins.
Pre-tax income from our investment in DCP Midstream increased $110 million in 2017, compared with 2016. The increase was primarily due to improved margins driven by higher average NGL and natural gas prices, and improved hedging results.
Chemicals
| Year Ended December 31 | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Millions of Dollars | |||||||||
| Income Before Income Taxes | $ | 1,025 | 716 | 839 | |||||
| Millions of Pounds | |||||||||
| CPChem Externally Marketed Sales Volumes* | |||||||||
| Olefins and Polyolefins | 18,435 | 15,870 | 16,011 | ||||||
| Specialties, Aromatics and Styrenics | 4,931 | 4,618 | 4,911 | ||||||
| 23,366 | 20,488 | 20,922 | |||||||
| * Represents 100 percent of CPChem’s outside sales of produced petrochemical products, as well as commission sales from equity affiliates. | |||||||||
| Olefins and Polyolefins Capacity Utilization (percent) | 94 | % | 87 | 91 |
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 lines: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business line 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 line manufactures and markets aromatics and styrenics products, such as benzene, cyclohexane, styrene and polystyrene. 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.
2018 vs. 2017
Pre-tax income from the Chemicals segment increased $309 million in 2018, compared with 2017. The increased results reflected the commencement of full operations at CPChem’s new U.S. Gulf Coast petrochemicals assets in the second quarter of 2018, which resulted in higher production and sales of polyethylene and ethylene, partially offset by lower capitalized interest. Additionally, lower hurricane-related costs and downtime, as well as lower impairment charges, contributed to the increased results in 2018.
See the “Executive Overview and Business Environment” section for information on market factors impacting CPChem’s 2018 results.
2017 vs. 2016
Pre-tax income from the Chemicals segment decreased $123 million in 2017, compared with 2016. The decrease was primarily driven by higher costs and lower volumes due to Hurricane Harvey, as well as lower margins. These items were partially offset by lower impairment charges, higher equity in earnings from an O&P affiliate due to lower turnaround costs and a gain on the sale of CPChem’s K-Resin® styrene-butadiene copolymers business. CPChem recognized impairment charges of $127 million and $177 million in 2017 and 2016, respectively, due to lower demand and margin factors. As a result of these impairments, pre-tax income from the Chemicals segment was reduced by $64 million and $89 million in 2017 and 2016, respectively.
As a result of Hurricane Harvey, CPChem’s Cedar Bayou facility in Baytown, Texas, experienced severe flooding, which caused it to shut down operations in the third quarter of 2017. This facility restarted in phases during the fourth quarter of 2017. Startup of CPChem’s U.S. Gulf Coast Petrochemicals Project was delayed by the flooding.
Refining
| Year Ended December 31 | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Millions of Dollars | |||||||||
| Income (Loss) Before Income Taxes | |||||||||
| Atlantic Basin/Europe | $ | 567 | 448 | 187 | |||||
| Gulf Coast | 1,040 | 809 | 69 | ||||||
| Central Corridor | 2,817 | 755 | 367 | ||||||
| West Coast | 111 | 64 | (188 | ) | |||||
| Worldwide | $ | 4,535 | 2,076 | 435 | |||||
| Dollars Per Barrel | |||||||||
| Income (Loss) Before Income Taxes | |||||||||
| Atlantic Basin/Europe | $ | 3.05 | 2.25 | 0.85 | |||||
| Gulf Coast | 3.55 | 2.83 | 0.24 | ||||||
| Central Corridor | 26.50 | 8.19 | 3.74 | ||||||
| West Coast | 0.81 | 0.48 | (1.49 | ) | |||||
| Worldwide | 6.29 | 2.92 | 0.60 | ||||||
| Realized Refining Margins* | |||||||||
| Atlantic Basin/Europe | $ | 10.32 | 8.25 | 6.26 | |||||
| Gulf Coast | 9.48 | 7.07 | 5.49 | ||||||
| Central Corridor | 22.22 | 12.44 | 8.70 | ||||||
| West Coast | 11.20 | 10.49 | 9.15 | ||||||
| Worldwide | 12.99 | 9.13 | 6.99 |
- See the “Non-GAAP Reconciliations” section for a reconciliation of this non-GAAP measure to the most directly comparable GAAP measure, income (loss) before income taxes per barrel.
| Thousands of Barrels Daily | ||||||||
| Year Ended December 31 | ||||||||
| 2018 | 2017 | 2016 | ||||||
| Operating Statistics | ||||||||
| Refining operations* | ||||||||
| Atlantic Basin/Europe | ||||||||
| Crude oil capacity | 537 | 520 | 566 | |||||
| Crude oil processed | 477 | 494 | 568 | |||||
| Capacity utilization (percent) | 89 | % | 95 | 100 | ||||
| Refinery production | 514 | 553 | 607 | |||||
| Gulf Coast | ||||||||
| Crude oil capacity | 752 | 743 | 743 | |||||
| Crude oil processed | 717 | 709 | 704 | |||||
| Capacity utilization (percent) | 95 | % | 95 | 95 | ||||
| Refinery production | 808 | 789 | 783 | |||||
| Central Corridor | ||||||||
| Crude oil capacity | 493 | 493 | 493 | |||||
| Crude oil processed | 507 | 467 | 485 | |||||
| Capacity utilization (percent) | 103 | % | 95 | 98 | ||||
| Refinery production | 530 | 489 | 506 | |||||
| West Coast | ||||||||
| Crude oil capacity | 364 | 360 | 360 | |||||
| Crude oil processed | 343 | 342 | 318 | |||||
| Capacity utilization (percent) | 94 | % | 95 | 88 | ||||
| Refinery production | 373 | 368 | 345 | |||||
| Worldwide | ||||||||
| Crude oil capacity | 2,146 | 2,116 | 2,162 | |||||
| Crude oil processed | 2,044 | 2,012 | 2,075 | |||||
| Capacity utilization (percent) | 95 | % | 95 | 96 | ||||
| Refinery production | 2,225 | 2,199 | 2,241 | |||||
| * Includes our share of equity affiliates. |
The Refining segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels) at 13 refineries in the United States and Europe.
2018 vs. 2017
Pre-tax income for the Refining segment increased $2,459 million in 2018, compared with 2017. The increase was primarily due to higher realized refining margins, partially offset by a noncash gain of $423 million recognized on the consolidation of Merey Sweeny in February 2017.
The increased realized refining margins were primarily driven by higher feedstock advantage, improved premium coke margins, and increased optimization benefits from using our integrated logistics network to capture market opportunities related to widening Bakken, Canadian and other inland crude differentials. Improved clean product differentials and lower renewable identification number (RIN) costs also benefited margins. These items were partially offset by a decline in market crack spreads.
See the “Executive Overview and Business Environment” 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 95 percent in both 2018 and 2017.
2017 vs. 2016
Pre-tax income for the Refining segment increased $1,641 million in 2017, compared with 2016. The increase was primarily due to higher realized refining margins and West Coast volumes, as well as a noncash gain of $423 million recognized on the consolidation of Merey Sweeny, partially offset by higher turnaround expenses, utilities costs and pension settlement expense. The higher realized refining margins primarily resulted from improved market crack spreads and secondary product margins, partially offset by lower feedstock advantage.
See Note 5—Business Combinations, in the Notes to Consolidated Financial Statements, for additional information on the consolidation of Merey Sweeny in February 2017 and the subsequent contribution of our ownership interest in Merey Sweeny to Phillips 66 Partners in October 2017.
Our worldwide refining crude oil capacity utilization rate was 95 percent in 2017, compared with 96 percent in 2016. The decrease was primarily attributable to higher turnaround activities and unplanned downtime, partially offset by improved market conditions.
Marketing and Specialties
| Year Ended December 31 | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Millions of Dollars | |||||||||
| Income Before Income Taxes | |||||||||
| Marketing and Other | $ | 1,306 | 808 | 1,044 | |||||
| Specialties | 251 | 212 | 217 | ||||||
| Total Marketing and Specialties | $ | 1,557 | 1,020 | 1,261 | |||||
| Dollars Per Barrel | |||||||||
| Income Before Income Taxes | |||||||||
| U.S. | $ | 1.21 | 0.89 | 1.15 | |||||
| International | 5.00 | 2.23 | 2.36 | ||||||
| Realized Marketing Fuel Margins* | |||||||||
| U.S. | $ | 1.62 | 1.48 | 1.64 | |||||
| International | 6.87 | 4.21 | 4.05 | ||||||
| * See the “Non-GAAP Reconciliations” section for a reconciliation of this non-GAAP measure to the most directly comparable GAAP measure, income before income taxes per barrel. | |||||||||
| Dollars Per Gallon | |||||||||
| U.S. Average Wholesale Prices* | |||||||||
| Gasoline | $ | 2.20 | 1.87 | 1.62 | |||||
| Distillates | 2.29 | 1.85 | 1.48 | ||||||
| * On third-party branded refined petroleum product sales, excluding excise taxes. | |||||||||
| Thousands of Barrels Daily | |||||||||
| Marketing Refined Petroleum Product Sales | |||||||||
| Gasoline | 1,195 | 1,246 | 1,238 | ||||||
| Distillates | 975 | 931 | 947 | ||||||
| Other | 18 | 18 | 16 | ||||||
| 2,188 | 2,195 | 2,201 |
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.
2018 vs. 2017
Pre-tax income from the M&S segment increased $537 million in 2018, compared with 2017. The increase was primarily due to higher realized marketing fuel margins, mainly driven by international marketing, benefits from the retroactive extension of the 2017 U.S. biodiesel blender’s tax incentive in early 2018, as well as improved specialty product service margins.
See the “Executive Overview and Business Environment” section for information on marketing fuel margins and other market factors impacting 2018 results.
2017 vs. 2016
Pre-tax income from the M&S segment decreased $241 million in 2017, compared with 2016. The decrease was primarily due to lower realized marketing margins, as well as the absence of U.S. biofuel tax credits recognized in 2016.
Corporate and Other
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Income (Loss) Before Income Taxes | |||||||||
| Net interest expense | $ | (459 | ) | (408 | ) | (322 | ) | ||
| Corporate general and administrative expenses | (257 | ) | (268 | ) | (246 | ) | |||
| Technology | (88 | ) | (94 | ) | (91 | ) | |||
| Other | (49 | ) | (125 | ) | (88 | ) | |||
| Total Corporate and Other | $ | (853 | ) | (895 | ) | (747 | ) |
2018 vs. 2017
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $51 million in 2018, compared with 2017, mainly due to higher average debt principal balances from our issuance of senior notes totaling $1,500 million in March 2018 and Phillips 66 Partners’ issuance of senior notes totaling $650 million in October 2017. This increase was partially offset by higher interest income.
The category “Other” includes 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 $76 million decrease in other costs in 2018, compared with 2017, was primarily attributable to lower environmental-related expenses and higher equity earnings from our share of income tax benefits recorded by equity affiliates due to the enactment of the Tax Act in December 2017.
2017 vs. 2016
Net interest expense increased $86 million in 2017, compared with 2016, primarily driven by lower capitalized interest due to the completion of major projects, including completion of the Freeport LPG Export Terminal project in late 2016, and higher interest expense driven by higher average debt principal balances due to Phillips 66 Partners’ debt issuances in October 2017 and 2016.
Corporate general and administrative expenses increased $22 million in 2017, compared with 2016, due to higher employee-related costs.
Other costs increased $37 million in 2017, compared with 2016, mainly due to higher environmental-related expenses.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
| Millions of Dollars, Except as Indicated | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Cash and cash equivalents | $ | 3,019 | 3,119 | 2,711 | |||||
| Net cash provided by operating activities | 7,573 | 3,648 | 2,963 | ||||||
| Short-term debt | 67 | 41 | 550 | ||||||
| Total debt | 11,160 | 10,110 | 10,138 | ||||||
| Total equity | 27,153 | 27,428 | 23,725 | ||||||
| Percent of total debt to capital* | 29 | % | 27 | 30 | |||||
| Percent of floating-rate debt to total debt | 11 | % | 11 | 3 | |||||
| * Capital includes total debt and total equity. |
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources but rely primarily on cash generated from operating activities. Additionally, Phillips 66 Partners has raised funds for its growth activities through debt and equity financings. During 2018, we generated $7.6 billion in cash from operations and raised net proceeds of $1.5 billion from the issuance of senior notes. We used this available cash primarily for repurchases of our common stock of $4.6 billion; capital expenditures and investments of $2.6 billion; dividend payments on our common stock of $1.4 billion; and the early repayment of $550 million of debt. During 2018, cash and cash equivalents decreased by $100 million, to $3.0 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 debt securities 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 2018, cash of $7,573 million was provided by operating activities, a 108 percent increase compared with 2017. The increase was primarily attributable to higher realized refining and marketing margins, increased distributions from our equity affiliates and lower employee benefit plan contributions. These increases were partially offset by unfavorable working capital impacts primarily driven by the effects of changes in commodity prices and the timing of payments and collections.
During 2017, cash of $3,648 million was provided by operating activities, a 23 percent increase compared with 2016. The increase was primarily attributable to improved operating results due to higher realized refining margins and increased distributions from our equity affiliates. These increases were partially offset by working capital changes, reflecting the negative impact of building inventory at higher commodity prices and timing of refining payables payments, as well as lower marketing margins.
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 95 percent in both 2018 and 2017.
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, 2018, we received aggregate distributions from our equity affiliates of $4,712 million, including $201 million from DCP Midstream, $1,603 million from CPChem and $1,124 million from WRB. CPChem resumed distributions to us in the first quarter of 2018 following the return to full operations of its Cedar Bayou facility post-Hurricane Harvey and the start-up of its new U.S. Gulf Coast petrochemicals assets. 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.
Phillips 66 Partners
In 2013, we formed Phillips 66 Partners, a publicly traded MLP, to own, operate, develop and acquire primarily fee-based midstream assets.
Ownership
At December 31, 2018, we owned a 54 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while the public owned a 44 percent limited partner interest and 13.8 million perpetual convertible preferred units. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on why we consolidate the partnership. As a result of this consolidation, the public common and preferred unitholders’ interests in Phillips 66 Partners are reflected as noncontrolling interests of $2,469 million in our consolidated balance sheet at December 31, 2018.
Debt and Equity Financings
During the three years ended December 31, 2018, Phillips 66 Partners raised net proceeds of approximately $4.1 billion from the following third-party debt and equity offerings:
| • | In June 2018, Phillips 66 Partners completed its initial $250 million continuous offering of common units, or at-the-market (ATM) program, and commenced issuing common units under its second $250 million ATM program. Since inception in June 2016 through December 31, 2018, net proceeds of $320 million have been received under these programs. |
| • | In October 2017, Phillips 66 Partners received net proceeds of $643 million from the issuance of $500 million of 3.750% Senior Notes due March 2028 and $150 million of 4.680% Senior Notes due February 2045. |
| • | In October 2017, Phillips 66 Partners received net proceeds of $737 million from a private placement of 13,819,791 perpetual convertible preferred units, at a price of $54.27 per unit. |
| • | In October 2017, Phillips 66 Partners received net proceeds of $295 million from a private placement of 6,304,204 common units, at a price of $47.59 per unit. |
| • | In October 2016, Phillips 66 Partners received net proceeds of $1,111 million from the issuance of $500 million of 3.550% Senior Notes due October 2026 and $625 million of 4.900% Senior Notes due October 2046. |
| • | In August 2016, Phillips 66 Partners received net proceeds of $299 million from a public offering of 6,000,000 common units, at a price of $50.22 per unit. |
| • | In May 2016, Phillips 66 Partners received net proceeds of $656 million from a public offering of 12,650,000 common units, at a price of $52.40 per unit. |
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66 and for capital spending and investments. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on Phillips 66 Partners.
Credit Facilities and Commercial Paper
Phillips 66 has a $5 billion revolving credit facility that extends until 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 are 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 Financial Services LLC (S&P) and Moody’s Investors Service, Inc. (Moody’s). The facility also provides for customary fees, including administrative agent fees and commitment fees. At December 31, 2018, no amount had been drawn under this revolving credit agreement.
Phillips 66 has a $5 billion commercial paper program for short-term working capital needs that is supported by its revolving credit facility. Commercial paper maturities are generally limited to 90 days. At December 31, 2018, no borrowings were outstanding under the commercial paper program.
Phillips 66 Partners has a $750 million revolving credit facility that extends until October 2021. The Phillips 66 Partners facility is with a broad syndicate of financial institutions and contains covenants that are usual and customary for an agreement of this type for comparable commercial borrowers. At Phillips 66 Partners’ option, outstanding borrowings under this facility bear interest at either i) the Eurodollar rate plus a margin based on its credit rating; or ii) the base rate (as described in the facility agreement) plus a margin based on its credit rating. Eurodollar rate borrowings are due on the facility’s termination date, while base rate borrowings are due the earlier of the facility’s termination date or the fourteenth business day after such borrowings were made. At December 31, 2018, Phillips 66 Partners had borrowings of $125 million outstanding under this facility.
Other Debt Issuances and Financings
On March 1, 2018, Phillips 66 closed on a public offering of $1,500 million aggregate principal amount of unsecured notes consisting of:
| • | $500 million of floating-rate Senior Notes due February 2021. Interest on these notes is equal to the three-month LIBOR plus 0.60% per annum and is payable quarterly in arrears on February 26, May 26, August 26 and November 26, beginning on May 29, 2018. |
| • | $800 million of 3.900% Senior Notes due March 2028. Interest on these notes is payable semiannually on March 15 and September 15 of each year, beginning on September 15, 2018. |
| • | An additional $200 million of our 4.875% Senior Notes due November 2044. Interest on these notes is payable semiannually on May 15 and November 15 of each year, beginning on May 15, 2018. |
Phillips 66 used the net proceeds from the issuance of these notes and cash on hand to repay commercial paper borrowings during the first quarter of 2018, and for general corporate purposes. The commercial paper borrowings during the first quarter of 2018, were primarily used to repurchase shares of our common stock. See Note 17—Equity, in the Notes to Consolidated Financial Statements, for additional information.
In addition, 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 fifteen years. The present value of our minimum capital lease payments for these obligations as of December 31, 2018, was $184 million.
Availability of Debt and Equity Financing
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.
Off-Balance Sheet Arrangements
Under the operating lease agreement on our headquarters facility in Houston, Texas, we have a residual value guarantee with a maximum future exposure of $554 million at December 31, 2018. The operating lease term ends in June 2021 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 also have residual value guarantees associated with railcar and airplane leases with maximum future exposures totaling $300 million at December 31, 2018, which have remaining terms of up to five years.
In addition, we have guarantees outstanding related to certain joint venture debt and purchase obligations, which have remaining terms of up to seven years. The maximum potential amount of future payments to third parties under these guarantees was approximately $304 million at December 31, 2018.
See Note 13—Guarantees, in the Notes to Consolidated Financial Statements, for additional information on our guarantees.
Capital Requirements
Capital Expenditures and Investments
For information about our capital expenditures and investments, see the “Capital Spending” section below.
Debt Financing
Our debt balance at December 31, 2018, was $11.2 billion and our total debt-to-capital ratio was 29 percent.
In 2018, Phillips 66 made early debt repayments totaling $550 million, comprised of $300 million floating-rate notes due April 2019 and $250 million of the $450 million outstanding under its three-year term loan facility due April 2020.
See Note 12—Debt, in the Notes to Consolidated Financial Statements, for our annual debt maturities over the next five years and more information on debt repayments.
Dividends
On February 6, 2019, our Board of Directors declared a quarterly cash dividend of $0.80 per common share, payable March 1, 2019, to holders of record at the close of business on February 19, 2019. We are forecasting a double-digit percentage increase in our quarterly dividend rate in 2019.
Share Repurchases
Since July 2012, our Board of Directors has, at various times, authorized repurchases of our outstanding common stock under our share repurchase program, which aggregate to a total authorization of up to $12 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. Since the inception of our share repurchase program in 2012 through December 31, 2018, we have repurchased approximately 137 million shares at an aggregate cost of $10.4 billion. Shares of stock repurchased are held as treasury shares.
In February 2018, we entered into a Stock Purchase and Sale Agreement (Purchase Agreement) with Berkshire Hathaway Inc. and National Indemnity Company, a wholly owned subsidiary of Berkshire Hathaway, to repurchase 35 million shares of Phillips 66 common stock for an aggregate purchase price of $3.3 billion. Pursuant to the Purchase Agreement, the purchase price per share of $93.725 was based on the volume-weighted-average price of our common stock on the New York Stock Exchange on February 13, 2018. The transaction closed in February 2018. We funded the repurchase with cash of $1.9 billion and borrowings of $1.4 billion under our commercial paper program. These borrowings were subsequently refinanced through a public offering of senior notes. This specific share repurchase transaction was separately authorized by our Board of Directors and therefore did not impact previously announced authorizations under our share repurchase program, which are discussed above.
Employee Benefit Plan Contributions
For the year ended December 31, 2018, we contributed $150 million to our U.S. employee benefit plans and $34 million to our international employee benefit plans. In 2019, we expect to contribute approximately $90 million to those plans.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2018:
| Millions of Dollars | |||||||||||||||
| Payments Due by Period | |||||||||||||||
| Total | Up to 1 Year | Years 2-3 | Years 4-5 | After 5 Years | |||||||||||
| Debt obligations (a) | $ | 11,076 | 50 | 1,450 | 2,000 | 7,576 | |||||||||
| Capital lease obligations | 184 | 17 | 26 | 22 | 119 | ||||||||||
| Total debt | 11,260 | 67 | 1,476 | 2,022 | 7,695 | ||||||||||
| Interest on debt | 7,284 | 477 | 905 | 743 | 5,159 | ||||||||||
| Operating lease obligations | 1,581 | 509 | 573 | 207 | 292 | ||||||||||
| Purchase obligations (b) | 71,834 | 31,361 | 8,547 | 5,317 | 26,609 | ||||||||||
| Other long-term liabilities (c) | |||||||||||||||
| Asset retirement obligations | 261 | 7 | 44 | 20 | 190 | ||||||||||
| Accrued environmental costs | 447 | 76 | 132 | 89 | 150 | ||||||||||
| Repatriation income tax liability (d) | 181 | 14 | 32 | 46 | 89 | ||||||||||
| Total | $ | 92,848 | 32,511 | 11,709 | 8,444 | 40,184 |
| (a) | For additional information, see Note 12—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 with 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 raw NGL. The products are used to supply our refineries and fractionators and optimize our supply chain. Product purchase commitments with third parties totaled $31,242 million. In addition, $20,642 million are product purchases from CPChem, mostly for fuel gas and natural gasoline over the remaining contractual term of 81 years, and product purchases of $4,797 million from DCP Midstream entities for NGL over the remaining contractual term of ten years. |
Purchase obligations of $4,832 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 and unrecognized income tax benefits. From 2019 through 2023, we expect to contribute an average of $120 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $25 million per year to our non-U.S. plans. The U.S. five-year average consists of approximately $60 million for 2019 and $135 million per year for the remaining four years. Our minimum funding in 2019 is expected to be $60 million in the United States and $30 million outside the United States. Unrecognized income tax benefits of $23 million were also excluded because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable. |
| (d) | We elected to pay the one-time deemed repatriation income tax on foreign-sourced earnings, recognized as a result of the Tax Act enacted in December 2017, in installments over eight years beginning in 2018. The amount represents the remaining income tax liability. |
Capital Spending
| Millions of Dollars | ||||||||||||
| 2019 Budget | 2018 | 2017 | 2016 | |||||||||
| Capital Expenditures and Investments | ||||||||||||
| Midstream* | $ | 1,936 | 1,548 | 771 | 1,453 | |||||||
| Chemicals | — | — | — | — | ||||||||
| Refining | 923 | 826 | 853 | 1,149 | ||||||||
| Marketing and Specialties | 161 | 125 | 108 | 98 | ||||||||
| Corporate and Other | 177 | 140 | 100 | 144 | ||||||||
| $ | 3,197 | 2,639 | 1,832 | 2,844 | ||||||||
| Selected Equity Affiliates** | ||||||||||||
| DCP Midstream | $ | 505 | 484 | 268 | 99 | |||||||
| CPChem | 572 | 339 | 776 | 987 | ||||||||
| WRB | 165 | 156 | 126 | 164 | ||||||||
| $ | 1,242 | 979 | 1,170 | 1,250 |
- 2019 budget includes $303 million of capital expected to be cash funded by noncontrolling interests.
** Our share of joint venture’s self-funded capital spending.
Midstream
Capital spending in our Midstream segment during the three-year period ended December 31, 2018, included:
| • | Construction activities related to additional Gulf Coast fractionation capacity and Freeport LPG Export Terminal projects. |
| • | Construction activities related to increasing storage capacity at our crude oil and refined petroleum products terminal located near Beaumont, Texas. |
| • | Development of the Gray Oak Pipeline system, which will provide crude oil transportation from the Permian Basin and Eagle Ford to destinations in the Corpus Christi and Sweeny/Freeport markets on the Texas Gulf Coast. At December 31, 2018, Phillips 66 Partners had a 48.75 percent effective ownership interest in this pipeline system. In February 2019, another party exercised its option to acquire an interest in the pipeline system that reduced Phillips 66 Partners’ effective ownership interest to 42.25 percent. |
| • | Development of the Bayou Bridge Pipeline by Phillips 66 Partners’ 40-percent-owned joint venture. |
| • | 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. |
| • | Development of the Bakken Pipeline system project, in which Phillips 66 Partners owns a 25 percent interest. |
| • | Expansion activities on the Phillips 66 Partners’ 33-percent-owned Sand Hills Pipeline including investment in the transportation of NGL from the Permian Basin to the Texas Gulf Coast. |
| • | Construction activities related to Phillips 66 Partners’ new isomerization unit at the Lake Charles Refinery. |
| • | Expansion activities on the Phillips 66 Partners’ 50-percent owned STACK Pipeline joint venture. |
| • | Construction activities by joint ventures of Phillips 66 Partners in the Bakken production area of North Dakota, including the Palermo Rail Terminal, Sacagawea Crude Pipeline, the New Town injection point, Keene CDP Terminal and Sacagawea Gas Pipeline. |
| • | Spending associated with other return, reliability and maintenance projects in our Transportation and NGL business. |
During the three-year period ended December 31, 2018, DCP Midstream’s self-funded capital expenditures and investments were $1.7 billion on a 100 percent basis. Capital spending during this period was primarily for expansion of owned and joint venture natural gas processing and pipeline capacity.
In 2018, REX repaid $550 million of its debt, reducing its total debt to approximately $2 billion. REX funded the repayment through member cash contributions, of which our 25 percent share was approximately $138 million.
Chemicals
During the three-year period ended December 31, 2018, 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 $4.2 billion. Capital spending during this period was primarily for the U.S. Gulf Coast Petrochemicals Project.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2018, was $2.8 billion, primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to increase processing of advantaged crudes and improve product yields, improvements to the operating integrity of key processing units, and safety-related projects. Generally, our equity affiliates in the Refining segment are expected to have self-funding capital programs. During this three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $892 million.
Key projects completed during the three-year period included:
| • | Installation of facilities to improve clean product yield at the Sweeny, Lake Charles, Ponca City, and Bayway refineries, as well as the jointly owned Wood River Refinery. |
| • | Installation of facilities to improve processing of advantaged crudes at the Billings and Lake Charles refineries, as well as the jointly owned Wood River Refinery. |
| • | Installation of facilities to comply with U.S. Environmental Protection Agency (EPA) Tier 3 gasoline regulations at the Alliance, Lake Charles, Bayway and Sweeny refineries, as well as the jointly owned Wood River Refinery. |
| • | Installation of a crude tank to increase accessibility of waterborne crude at the Los Angeles Refinery. |
Major construction activities in progress include:
| • | Installation of facilities to comply with EPA Tier 3 gasoline regulations at the Ferndale Refinery. |
| • | Installation of facilities to improve product value at the Sweeny and Lake Charles refineries, as well as the jointly owned Borger Refinery. |
| • | Installation of facilities for U.K. biofuels compliance at the Humber Refinery. |
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2018, was primarily for the acquisition and further development of new international retail sites. In addition, capital was used for reliability and maintenance projects at our lubricants and power generation facilities.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2018, was primarily for information technology and facilities.
2019 Budget
Our 2019 capital budget is $3.2 billion including Phillips 66 Partners’ expected capital spending of $0.9 billion. This excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $1.2 billion, all of which is expected to be self-funded. Phillips 66 Partners’ expected capital spending includes $0.3 billion of capital expected to be cash funded by noncontrolling interests.
The Midstream capital budget of $1.9 billion includes 300,000 barrels per day of additional fractionation capacity at the Sweeny Hub, as well as ongoing expansion of the Beaumont Terminal and pipeline investments providing integration across our value chain. The Midstream capital budget also includes growth capital at Phillips 66 Partners to support organic projects, including the Gray Oak Pipeline, South Texas Gateway Terminal, Clemens Caverns expansion, an isomerization unit at the Phillips 66 Lake Charles Refinery, and the Sweeny to Pasadena Pipeline. Refining’s capital budget of $0.9 billion is primarily directed toward reliability, safety and environmental projects, as well as high-return projects to enhance the yield of higher-value products, including an upgrade of the fluid catalytic cracking unit at the Sweeny Refinery, and other low-capital, quick-payout projects. In M&S, we plan to invest approximately $0.2 billion of growth and sustaining capital; the investment will further grow and enhance retail sites in Europe. In Corporate and Other, we plan to fund approximately $0.2 billion in projects primarily related to information technology projects, including implementation of a new enterprise resource planning system.
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:
| • | U.S. Federal Clean Air Act, which governs air emissions. |
| • | U.S. Federal Clean Water Act, which governs discharges into water bodies. |
| • | European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH), which governs the manufacture, placing on the market or use of chemicals. |
| • | 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. |
| • | U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste. |
| • | 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. |
| • | 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. |
| • | 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 (GHG) 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. 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 and transporting products across state and international borders. For example, in California the South Coast Air Quality Management District (SCAQMD) 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 affect refineries in the Los Angeles metropolitan area. In 2017, SCAQMD required additional nitrogen dioxide emissions reductions through 2025 and is now promulgating new regulations to replace the RECLAIM program with a traditional command and controls regulatory regime.
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 Independence and Security Act of 2007 (EISA). It 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 2019 compliance year, the EPA has set volumes of advanced and total renewable fuel at higher levels than in previous years (the 2019 compliance year volumes are approximately 3 percent higher than those required for the 2018 and 2017 compliance years); it is uncertain if these increased obligations will be achievable by fuel producers and shippers without
drawing on the RIN bank. EISA requires EPA to reset the statutory volumes if EPA waives the volumes by 20 percent or more for two consecutive years. The 2019 rulemaking triggered this requirement and EPA is currently working on rulemaking that will set volumes for 2020 through 2022. 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 through 2018 compliance years are subject to legal challenge, further creating uncertainty regarding renewable fuel volume requirements and obligations. Additionally, 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 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, 2017, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 31 sites within the United States. During 2018, we were notified of one new site, one previously resolved site that was returned to active status, four sites that were deemed resolved and closed, and two sites that were deemed resolved but not closed, leaving 27 unresolved sites with potential liability at December 31, 2018.
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 $690 million in 2018 and are expected to be approximately $740 million and $700 million in 2019 and 2020, respectively. Capitalized environmental costs were $149 million in 2018 and are expected to be approximately $115 million and $125 million, in 2019 and 2020, 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 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 certain of 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 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 reviews, or reducing demand for certain hydrocarbon products. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
| • | EU ETS, which is part of the European Union’s policy to combat climate change and is a key tool for reducing industrial GHG emissions. EU ETS impacts factories, power stations and other installations across all EU member states. |
| • | 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 SB32, which requires further reduction of California's GHG emissions to 40 percent below the 1990 emission level by 2030, and AB398, which extends the California GHG emission cap-and-trade program through 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. |
| • | 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. |
| • | 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. |
| • | 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, which remains the subject of litigation and administrative review. |
| • | Carbon taxes in certain jurisdictions. |
| • | 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 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 2017, the President of the United States announced his intention to withdraw the United States from the Paris Agreement.
In the United States, some additional form of regulation is likely to be forthcoming in the future at the state or federal 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 was 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:
| • | Whether and to what extent legislation or regulation is enacted. |
| • | The nature of the legislation or regulation (such as a cap and trade system or a tax on emissions). |
| • | The GHG reductions required. |
| • | The price and availability of offsets. |
| • | The demand for, and amount and allocation of allowances. |
| • | Technological and scientific developments leading to new products or services. |
| • | Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature). |
| • | 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 GHG emissions. Data on our 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 in the United States (GAAP) 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. Some 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 expected cash flows. If the sum of the undiscounted expected future 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 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. Different 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 cost of future asset removals 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, 2018, we had $753 million of intangible assets that we have determined to have indefinite useful lives, and therefore are not amortized. The judgmental determination that an intangible asset has an indefinite useful life is continuously evaluated. 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 determined to have indefinite lives, they will be subject to at least annual impairment tests that require management’s judgment of their estimated fair value.
At December 31, 2018, 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 tests for impairment at a reporting unit level. A reporting unit is an operating segment or a component that is one level below an operating segment and they are determined primarily based on the manner in which the business is managed.
We perform our annual goodwill impairment test using either a qualitative assessment or a quantitative assessment. As part of our qualitative assessment, we evaluate relevant events and circumstances that could affect the fair value of our reporting units, including macroeconomic conditions, overall industry and market considerations and regulatory changes, as well as company-specific market metrics, performance and events. The evaluation of company-specific events and circumstances includes evaluating changes in our stock price and cost of capital, actual and forecasted financial performance, as well as the effect of significant asset dispositions. If our qualitative assessment indicates it is likely the fair value of a reporting unit has declined below its carrying value (including goodwill), or if we elect not to perform a qualitative assessment, a quantitative assessment is performed.
When a quantitative assessment is performed, management applies judgment in determining the estimated fair values of the reporting units because quoted market prices for our reporting units are not available. Management uses available information to make this fair value determination, including estimated cash flows, cost of capital, observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization.
We completed our annual impairment test as of October 1, 2018, and concluded that the fair values of our reporting units continued to exceed their respective carrying values (including goodwill) by significant percentages. A decline in the estimated fair value of one or more of our reporting units in the future could result in an impairment. As such, we continue to monitor for indicators of impairment until our next annual impairment test is performed.
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 expense (benefit), 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 income tax liabilities that cannot be predicted at this time.
Projected Benefit Obligations
Calculation 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 calculation 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. We engage outside actuarial firms to assist in the calculation of these projected benefit obligations and company contribution requirements due to the specialized nature of these calculations. 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 used for the plan obligation would increase annual benefit expense by an estimated $50 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 2018 and 2017, the expected weighted-average long-term rate of return for worldwide pension plan assets was approximately 6 percent, while the actual weighted-average rate of return was a negative 4 percent in 2018 and a positive 15 percent in 2017. For the past ten years, our actual weighted-average rate of return for worldwide pension plan assets was 9 percent.
NEW ACCOUNTING STANDARDS
In February 2018, the FASB issued ASU No. 2018-02, “Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU allows for the deferred income tax effects stranded in accumulated other comprehensive income (AOCI) resulting from the Tax Act enacted in December 2017 to be reclassed from AOCI to retained earnings. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Upon adoption on January 1, 2019, we increased retained earnings by approximately $90 million with the offset to accumulated other comprehensive loss on our consolidated balance sheet.
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 may result in earlier 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 evaluating the provisions of ASU No. 2016-13, and currently do not expect our adoption to have a material impact on our consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The new standard establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will continue to be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. Similarly, lessors will be required to classify leases as sales-type, finance or operating, with classification affecting the pattern of income recognition. Classification for both lessees and lessors will be based on an assessment of whether risks and rewards, as well as substantive control have been transferred through a lease contract. The ASU also requires additional disclosures. 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 will adopt ASU No. 2016-02 by recognizing a cumulative-effect adjustment to our opening consolidated balance sheet as of our January 1, 2019, adoption date. As of the adoption date, we expect to recognize ROU assets and operating lease liabilities on our consolidated balance sheet of approximately $1.4 billion. The adoption of this ASU is not expected to have a material impact on our consolidated statements of income and cash flows.
NON-GAAP RECONCILIATIONS
Refining
Our realized refining margins measure the difference between a) sales and other operating revenues derived from the sale of petroleum products manufactured at our refineries and b) purchase costs of feedstocks, primarily crude oil, used to produce the petroleum products. The realized refining margins are adjusted to include our proportional share of our joint venture refineries’ realized margins, as well as to exclude those items that are not representative of the underlying operating performance of a period, which we call “special items.” The realized refining margins are converted to a per-barrel basis by dividing them by total refinery processed inputs (primarily crude oil) measured on a barrel basis, including our share of inputs processed by our joint venture refineries. Our realized refining margin per barrel is intended to be comparable with industry refining margins, which are known as “crack spreads.” As discussed in “Business Environment,” industry crack spreads measure the difference between market prices for refined petroleum products and crude oil. We believe realized refining margin per barrel calculated on a similar basis as industry crack spreads provides a useful measure of how well we performed relative to benchmark industry margins.
The GAAP performance measure most directly comparable to realized refining margin per barrel is the Refining segment’s “income before income taxes per barrel.” Realized refining margin per barrel excludes items that are typically included in a manufacturer’s gross margin, such as depreciation and operating expenses, and other items used to determine income before income taxes, such as general and administrative expenses. It also includes our proportional share of joint venture refineries’ realized refining margins and excludes special items. Because realized refining margin per barrel is calculated in this manner, and because realized refining margin per barrel may be defined differently by other companies in our industry, it has limitations as an analytical tool. Following are reconciliations of income before income taxes to realized refining margins:
| Millions of Dollars, Except as Indicated | |||||||||||
| Realized Refining Margins | Atlantic Basin/Europe | Gulf Coast | Central Corridor | West Coast | Worldwide | ||||||
| Year Ended December 31, 2018 | |||||||||||
| Income before income taxes | $ | 567 | 1,040 | 2,817 | 111 | 4,535 | |||||
| Plus: | |||||||||||
| Taxes other than income taxes | 56 | 88 | 43 | 100 | 287 | ||||||
| Depreciation, amortization and impairments | 201 | 268 | 135 | 237 | 841 | ||||||
| Selling, general and administrative expenses | 63 | 57 | 34 | 50 | 204 | ||||||
| Operating expenses | 950 | 1,312 | 488 | 1,040 | 3,790 | ||||||
| Equity in (earnings) losses of affiliates | 10 | 6 | (812 | ) | — | (796 | ) | ||||
| Other segment (income) expense, net | (11 | ) | 3 | (13 | ) | (9 | ) | (30 | ) | ||
| Proportional share of refining gross margins contributed by equity affiliates | 87 | — | 1,565 | — | 1,652 | ||||||
| Special items: | |||||||||||
| Certain tax impacts | (5 | ) | — | — | — | (5 | ) | ||||
| Realized refining margins | $ | 1,918 | 2,774 | 4,257 | 1,529 | 10,478 | |||||
| Total processed inputs (thousands of barrels) | 186,042 | 292,665 | 106,299 | 136,332 | 721,338 | ||||||
| Adjusted total processed inputs (thousands of barrels)* | 186,042 | 292,665 | 191,561 | 136,332 | 806,600 | ||||||
| Income before income taxes per barrel (dollars per barrel)** | $ | 3.05 | 3.55 | 26.50 | 0.81 | 6.29 | |||||
| Realized refining margins (dollars per barrel)*** | 10.32 | 9.48 | 22.22 | 11.20 | 12.99 | ||||||
| Year Ended December 31, 2017 | |||||||||||
| Income before income taxes | $ | 448 | 809 | 755 | 64 | 2,076 | |||||
| Plus: | |||||||||||
| Taxes other than income taxes | 56 | 97 | 46 | 64 | 263 | ||||||
| Depreciation, amortization and impairments | 192 | 273 | 129 | 244 | 838 | ||||||
| Selling, general and administrative expenses | 61 | 55 | 34 | 48 | 198 | ||||||
| Operating expenses | 847 | 1,212 | 593 | 982 | 3,634 | ||||||
| Equity in (earnings) losses of affiliates | 11 | (4 | ) | (329 | ) | — | (322 | ) | |||
| Other segment (income) expense, net | (10 | ) | (421 | ) | 13 | 5 | (413 | ) | |||
| Proportional share of refining gross margins contributed by equity affiliates | 59 | 1 | 959 | — | 1,019 | ||||||
| Special items: | |||||||||||
| Certain tax impacts | (23 | ) | — | — | — | (23 | ) | ||||
| Realized refining margins | $ | 1,641 | 2,022 | 2,200 | 1,407 | 7,270 | |||||
| Total processed inputs (thousands of barrels) | 199,068 | 285,951 | 92,146 | 134,089 | 711,254 | ||||||
| Adjusted total processed inputs (thousands of barrels)* | 199,068 | 285,951 | 176,823 | 134,089 | 795,931 | ||||||
| Income before income taxes per barrel (dollars per barrel)** | $ | 2.25 | 2.83 | 8.19 | 0.48 | 2.92 | |||||
| Realized refining margins (dollars per barrel)*** | 8.25 | 7.07 | 12.44 | 10.49 | 9.13 | ||||||
| * Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate. | |||||||||||
| ** Income before income taxes divided by total processed inputs. | |||||||||||
| *** Realized refining margins per barrel, as presented, are calculated using the underlying realized refining margin amounts, in dollars, divided by adjusted total processed inputs, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per barrel amounts due to rounding. |
| Millions of Dollars, Except as Indicated | |||||||||||
| Realized Refining Margins | Atlantic Basin/Europe | Gulf Coast | Central Corridor | West Coast | Worldwide | ||||||
| Year Ended December 31, 2016 | |||||||||||
| Income (loss) before income taxes | $ | 187 | 69 | 367 | (188 | ) | 435 | ||||
| Plus: | |||||||||||
| Taxes other than income taxes | 58 | 73 | 42 | 80 | 253 | ||||||
| Depreciation, amortization and impairments | 200 | 234 | 106 | 230 | 770 | ||||||
| Selling, general and administrative expenses | 64 | 51 | 31 | 49 | 195 | ||||||
| Operating expenses | 817 | 1,234 | 465 | 979 | 3,495 | ||||||
| Equity in (earnings) losses of affiliates | 8 | (50 | ) | (122 | ) | — | (164 | ) | |||
| Other segment (income) expense, net | (11 | ) | 3 | (6 | ) | (2 | ) | (16 | ) | ||
| Proportional share of refining gross margins contributed by equity affiliates | 55 | (4 | ) | 705 | — | 756 | |||||
| Special items: | |||||||||||
| Pending claims and settlements | — | (70 | ) | — | — | (70 | ) | ||||
| Certain tax impacts | (32 | ) | — | — | — | (32 | ) | ||||
| Railcar lease residual value deficiencies and related costs | 5 | 16 | 11 | 8 | 40 | ||||||
| Recognition of deferred logistics commitments | 30 | — | — | — | 30 | ||||||
| Realized refining margins | $ | 1,381 | 1,556 | 1,599 | 1,156 | 5,692 | |||||
| Total processed inputs (thousands of barrels) | 220,519 | 283,574 | 98,217 | 126,329 | 728,639 | ||||||
| Adjusted total processed inputs (thousands of barrels)* | 220,519 | 283,574 | 183,691 | 126,329 | 814,113 | ||||||
| Income (loss) before income taxes per barrel (dollars per barrel)** | $ | 0.85 | 0.24 | 3.74 | (1.49 | ) | 0.60 | ||||
| Realized refining margins (dollars per barrel)*** | 6.26 | 5.49 | 8.70 | 9.15 | 6.99 | ||||||
| * Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate. | |||||||||||
| ** Income (loss) before income taxes divided by total processed inputs. | |||||||||||
| *** Realized refining margins per barrel, as presented, are calculated using the underlying realized refining margin amounts, in dollars, divided by adjusted total processed inputs, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per barrel amounts due to rounding. |
Marketing
Our realized marketing fuel margins measure the difference between a) sales and other operating revenues derived from the sale of fuels in our M&S segment and b) purchase costs of those fuels. The realized marketing fuel margins are adjusted to exclude those items that are not representative of the underlying operating performance of a period, which we call “special items.” The realized marketing fuel margins are converted to a per-barrel basis by dividing them by sales volumes measured on a barrel basis. We believe realized marketing fuel margin per barrel demonstrates the value uplift our marketing operations provide by optimizing the placement and ultimate sale of our refineries’ fuel production.
Within the M&S segment, the GAAP performance measure most directly comparable to realized marketing fuel margin per barrel is the marketing business’ “income before income taxes per barrel.” Realized marketing fuel margin per barrel excludes items that are typically included in gross margin, such as depreciation and operating expenses, and other items used to determine income before income taxes, such as general and administrative expenses. Because realized marketing fuel margin per barrel excludes these items, and because realized marketing fuel margin per barrel may be defined differently by other companies in our industry, it has limitations as an analytical tool. Following are reconciliations of income before income taxes to realized marketing fuel margins:
| Millions of Dollars, Except as Indicated | ||||||||||||||
| U.S. | International | |||||||||||||
| 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||
| Realized Marketing Fuel Margins | ||||||||||||||
| Income before income taxes | $ | 843 | 628 | 804 | 505 | 217 | 252 | |||||||
| Plus: | ||||||||||||||
| Taxes other than income taxes* | (2 | ) | 5,481 | 5,187 | 2 | 7,579 | 8,132 | |||||||
| Depreciation, amortization and impairment | 13 | 14 | 12 | 71 | 67 | 63 | ||||||||
| Selling, general and administrative expenses | 763 | 751 | 708 | 280 | 264 | 259 | ||||||||
| Equity in earnings of affiliates | (8 | ) | (5 | ) | (4 | ) | (91 | ) | (83 | ) | (75 | ) | ||
| Other operating revenues* | (379 | ) | (5,815 | ) | (5,558 | ) | (32 | ) | (7,594 | ) | (8,157 | ) | ||
| Other segment (income) expense, net | — | (15 | ) | — | 2 | 2 | 3 | |||||||
| Special items: | ||||||||||||||
| Certain tax impacts | (100 | ) | — | — | — | — | — | |||||||
| Marketing margins | 1,130 | 1,039 | 1,149 | 737 | 452 | 477 | ||||||||
| Less: margin for non-fuel related sales | — | — | — | 44 | 42 | 45 | ||||||||
| Realized marketing fuel margins | $ | 1,130 | 1,039 | 1,149 | 693 | 410 | 432 | |||||||
| Total fuel sales volumes (thousands of barrels) | 697,696 | 703,928 | 699,111 | 100,949 | 97,346 | 106,574 | ||||||||
| Income before income taxes per barrel (dollars per barrel) | $ | 1.21 | 0.89 | 1.15 | 5.00 | 2.23 | 2.36 | |||||||
| Realized marketing fuel margins (dollars per barrel)** | 1.62 | 1.48 | 1.64 | 6.87 | 4.21 | 4.05 | ||||||||
| * Includes excise taxes on sales of refined petroleum products for periods prior to our adoption of ASU No. 2014-09 on January 1, 2018. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for further information on our adoption of this ASU. Other operating revenues also includes other non-fuel revenues. | ||||||||||||||
| ** Realized marketing fuel margins per barrel, as presented, are calculated using the underlying realized marketing fuel margin amounts, in dollars, divided by sales volumes, in barrels. As such, recalculated per barrel amounts using the rounded margins and barrels presented may differ from the presented per barrel amounts due to rounding. |
Previous: Item 6. SELECTED FINANCIAL DATA · Next: Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK