filings.toolsItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
135K characters. Original on sec.gov · Markdown
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the company’s analysis of its financial performance, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to Phillips 66.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and specialties businesses. At December 31, 2017, we had total assets of $54.4 billion.
Executive Overview
We reported earnings of $5.1 billion and generated $3.6 billion in cash from operating activities in 2017. Our reported earnings included a $2.7 billion provisional income tax benefit from the U.S. Tax Cuts and Jobs Act (the Tax Act) enacted on December 22, 2017. Phillips 66 Partners LP (Phillips 66 Partners) raised net proceeds totaling $1.8 billion from equity and debt offerings. We used available cash to fund capital expenditures and investments of $1.8 billion, repurchase $1.6 billion of our common stock and pay dividends of $1.4 billion. We ended 2017 with $3.1 billion of cash and cash equivalents and approximately $5.8 billion of total committed capacity available under both our and Phillips 66 Partners’ 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. We achieved a record-low combined injury rate in 2017. 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 2017, our worldwide refining crude oil capacity utilization rate was 95 percent. |
| • | Growth. We have budgeted $2.3 billion in capital expenditures and investments in 2018, including $0.6 billion for Phillips 66 Partners. Additionally, our share of expected capital spending by joint ventures DCP Midstream, LLC (DCP Midstream), Chevron Phillips Chemical Company LLC (CPChem) and WRB Refining LP (WRB) in 2018 is $0.9 billion. In Midstream, we plan to invest in our Transportation and NGL businesses, focusing on projects integrated with our existing assets and infrastructure. In Chemicals, CPChem’s capital expenditures are expected to decrease due to completion of its U.S. Gulf Coast Petrochemicals Project. The two polyethylene units started up in September 2017, while commissioning of the ethane cracker is expected to begin in the first |
quarter of 2018. Growth capital in Refining will be directed toward small, high-return, quick-payout projects primarily to increase clean product yields, while in Marketing and Specialties (M&S) it will be directed primarily towards increasing our 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 2017, we improved clean product yield in Refining, and in M&S, we continued to enhance our network and brand by re-imaging sites in the United States, while growing our number of sites in Europe. |
| • | 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 11 percent during 2017, and have increased it 250 percent 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 2017, we repurchased $1.6 billion, or approximately 18.7 million shares, of our common stock. Also, in October 2017, our Board of Directors authorized up to $3 billion of additional share repurchases. 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
Commodity prices rose significantly during 2017, compared with 2016. The discount for the U.S. crude oil benchmark West Texas Intermediate (WTI) versus the international benchmark Brent widened over much of 2017, initially related to extended production cuts by the Organization of the Petroleum Exporting Countries (OPEC) and certain non-OPEC countries, but further widened with Hurricane Harvey and logistical issues at the Cushing, Oklahoma, trading hub. Over the course of 2017, commodity prices had both favorable and unfavorable impacts on our businesses that vary by segment.
Net income in the Midstream segment, which includes our 50 percent equity investment in DCP Midstream, is closely linked to natural gas liquids (NGL) prices, natural gas prices and crude oil prices. Average natural gas prices increased in 2017, compared with 2016, due to higher demand and low production in early 2017. In the fourth quarter of 2017, natural gas prices gained momentum with colder temperatures and increased residential and commercial heating demand. Total U.S. natural gas production also increased through the fourth quarter of 2017, largely from dry gas in the Marcellus play and associated gas from the Permian Basin. NGL prices improved throughout 2017 due to international demand.
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 2017, the chemicals and plastics industry continued to benefit from feedstock cost advantages associated with manufacturing ethylene in regions of the world with significant NGL production. The price of crude oil is rising faster than NGL prices and thus the petrochemicals industry continues to experience lower ethylene cash costs in regions of the world where ethylene manufacturing is based upon NGL rather than crude oil-derived feedstocks. In particular, companies with North American ethane-based crackers have benefited and have captured a somewhat higher polyethylene chain margin. The ethylene-to-polyethylene chain margins expanded in 2017 because of the crude oil price recovery after the significant decline in oil prices that began in 2014.
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 products and crude oil, are used to estimate refining margins. During 2017, the U.S. 3:2:1 crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) strengthened across all quarters, compared with 2016, largely attributable to higher product demand and lower product inventories in the last half of 2017 due to Hurricane Harvey. Northwest European crack spreads on average increased in 2017, compared with 2016, also due to higher demand.
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 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. Spot prices moved upward in 2017, following the increase in crude oil prices.
RESULTS OF OPERATIONS
Basis of Presentation
During the fourth quarter of 2017, the segment performance measure used by our chief executive officer to assess performance and allocate resources was changed from “net income attributable to Phillips 66” to “net income.” This change reflects the recognition that management does not differentiate between those earnings attributable to Phillips 66 and those attributable to noncontrolling interests when making operating and resource allocation decisions impacting segment performance. Prior period segment information has been recast to conform to the current presentation.
Consolidated Results
A summary of net income (loss) by business segment with a reconciliation to net income attributable to Phillips 66 follows:
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Midstream | $ | 464 | 280 | 74 | |||||
| Chemicals | 525 | 583 | 962 | ||||||
| Refining | 1,404 | 374 | 2,555 | ||||||
| Marketing and Specialties | 686 | 891 | 1,187 | ||||||
| Corporate and Other | 2,169 | (484 | ) | (498 | ) | ||||
| Net income | 5,248 | 1,644 | 4,280 | ||||||
| Less: net income attributable to noncontrolling interests | 142 | 89 | 53 | ||||||
| Net income attributable to Phillips 66 | $ | 5,106 | 1,555 | 4,227 |
2017 vs. 2016
Our earnings increased $3,551 million, or 228 percent, in 2017, mainly reflecting:
| • | Recognition of a $2,735 million provisional income tax benefit from the enactment of the Tax Act in December 2017. |
| • | Higher realized refining margins. |
| • | Recognition of a $261 million after-tax gain from the consolidation of Merey Sweeny, L.P. (MSLP). |
| • | 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. |
2016 vs. 2015
Our earnings decreased $2,672 million, or 63 percent, in 2016, primarily resulting from:
| • | Lower realized refining margins. |
| • | Lower olefins and polyolefins margins. |
| • | Recognition in 2015 of $242 million of the deferred gain related to the sale in 2013 of the Immingham Combined Heat and Power Plant (ICHP). |
These decreases were partially offset by:
| • | Improved results from DCP Midstream, primarily as a result of goodwill and other asset impairments recorded in 2015. |
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
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 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 Transportation 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 MSLP. 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 due to lower capitalized interest from the completion of major projects, including the startup of the Freeport LPG Export Terminal 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. 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 interest increased $53 million in 2017, reflecting the contribution 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.
2016 vs. 2015
Sales and other operating revenues and purchased crude oil and products both decreased 15 percent in 2016. The decreases were primarily due to lower average prices for petroleum products and crude oil, while average NGL prices were slightly improved during 2016.
Equity in earnings of affiliates decreased 10 percent in 2016, primarily resulting from decreased earnings from CPChem and WRB, partially offset by improved results from DCP Midstream.
| • | Equity in earnings of CPChem decreased 37 percent, primarily due to lower realized olefins and polyolefins margins. |
| • | Equity in earnings of WRB decreased $186 million, mainly resulting from lower market crack spreads, partially offset by higher feedstock advantage. |
| • | Equity in earnings of DCP Midstream improved $426 million in 2016, primarily driven by goodwill and other asset impairments recorded by DCP Midstream in 2015. |
Net gain on dispositions decreased $273 million in 2016. In 2015, we recognized a $242 million deferred gain related to the sale of ICHP. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information.
See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax expense and effective tax rates.
Segment Results
Midstream
| Year Ended December 31 | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Millions of Dollars | |||||||||
| Net Income (Loss) | |||||||||
| Transportation | $ | 376 | 311 | 335 | |||||
| NGL and Other | 43 | 2 | 63 | ||||||
| DCP Midstream | 45 | (33 | ) | (324 | ) | ||||
| Total Midstream | $ | 464 | 280 | 74 |
| Thousands of Barrels Daily | ||||||||
| Transportation Volumes | ||||||||
| Pipelines* | 3,501 | 3,511 | 3,264 | |||||
| Terminals | 2,665 | 2,422 | 1,981 | |||||
| Operating Statistics | ||||||||
| NGL fractionated** | 186 | 170 | 112 | |||||
| NGL extracted*** | 374 | 393 | 410 |
- Pipelines represent the sum of volumes transported through each separately tariffed pipeline segment, including our share of equity volumes from Yellowstone Pipe Line Company and Lake Charles Pipe Line Company.
** Excludes DCP Midstream.
*** Represents 100 percent of DCP Midstream’s volumes.
| Dollars Per Gallon | |||||||||
| Weighted-Average NGL Price* | |||||||||
| DCP Midstream | $ | 0.62 | 0.46 | 0.45 |
- Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by NGL component and location mix.
The Midstream segment provides crude oil and refined products transportation, terminaling and processing services, as well as natural gas, NGL and liquefied petroleum gas (LPG) 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).
2017 vs. 2016
Net income from the Midstream segment increased $184 million in 2017, compared with 2016, due to improved results across all business lines.
Transportation net income increased $65 million in 2017, compared with 2016. The improvement was mainly driven by increased equity in earnings from affiliates, including our joint ventures that own the Bakken Pipeline, which started commercial operations in June 2017, as well as Rockies Express Pipeline LLC (REX) due to our share of a favorable breach of contract settlement claim. These increases were partially offset by higher operating costs.
Net income from our NGL and Other business increased $41 million in 2017, compared with 2016. The increase reflects a full year of operations at the Freeport LPG Export Terminal, the contribution of MSLP 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.
Net income from our investment in DCP Midstream improved $78 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 results from DCP Midstream’s hedging program.
See the “Business Environment and Executive Overview” section for information on market factors impacting 2017 results.
2016 vs. 2015
Net income from the Midstream segment increased $206 million in 2016, compared with 2015. The increase was primarily due to improved results from DCP Midstream, partially offset by lower net income from our Transportation and NGL and Other businesses.
Transportation net income decreased $24 million in 2016, compared with 2015. Lower net income primarily resulted from higher operating costs and increased depreciation expense due to growth projects. These items were partially offset by higher revenues from increased throughput volumes and higher tariffs.
Net income from our NGL and Other business decreased $61 million in 2016, compared with 2015. The decrease was primarily driven by lower realized margins, as well as increased depreciation and operating expenses associated with the Sweeny Fractionator and, late in the year, the Freeport LPG Export Terminal. These items were partially offset by higher fractionated volumes, reflecting the operation of the Sweeny Fractionator for a full year in 2016, and the benefit of the first liquefied petroleum gas cargos exported from the Freeport LPG Export Terminal in late 2016.
Improved results from our investment in DCP Midstream increased our net income by $291 million in 2016, compared with 2015. In 2015, DCP Midstream recorded goodwill and other asset impairments, which reduced our net income by $232 million. In addition, favorable contract restructuring efforts, improved asset performance, higher equity in earnings from DCP Midstream’s equity affiliates, lower operating costs and higher NGL prices contributed to better results in 2016. These improvements were partially offset by lower natural gas and crude oil prices.
Chemicals
| Year Ended December 31 | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Millions of Dollars | |||||||||
| Net Income | $ | 525 | 583 | 962 | |||||
| Millions of Pounds | |||||||||
| CPChem Externally Marketed Sales Volumes* | |||||||||
| Olefins and Polyolefins | 15,870 | 16,011 | 16,916 | ||||||
| Specialties, Aromatics and Styrenics | 4,618 | 4,911 | 5,301 | ||||||
| 20,488 | 20,922 | 22,217 | |||||||
| * 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)* | 87 | % | 91 | 92 |
The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method. CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used as feedstocks to produce plastics and other chemicals. We structure our reporting of CPChem’s operations around two primary business segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business segment produces and markets ethylene and other olefin products. Ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S business segment manufactures and markets aromatics and styrenics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene. 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.
2017 vs. 2016
Net income from the Chemicals segment decreased $58 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, net income of the Chemicals segment was reduced by $39 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. CPChem’s U.S. Gulf Coast Petrochemicals Project, which consists of an ethane cracker at Cedar Bayou and two polyethylene units at Old Ocean, Texas, was also impacted by the flooding. CPChem achieved mechanical completion of its ethane cracker at the Cedar Bayou facility in December 2017, and is expected to complete commissioning of the ethane cracker in the first quarter of 2018, with a transition to full production in the second quarter of 2018.
See the “Business Environment and Executive Overview” section for information on market factors impacting CPChem’s results.
2016 vs. 2015
Net income from the Chemicals segment decreased $379 million in 2016, compared with 2015. The decrease in net income was primarily due to lower realized margins from the O&P business, driven by a decline in sales prices for polyethylene and normal alpha olefins (NAO) and higher feedstock costs, as well as impacts from increased turnaround activity. Lower equity earnings from CPChem’s equity affiliates and lower SA&S volumes further reduced net income in 2016.
In addition, CPChem recognized a $177 million impairment in 2016 due to lower demand and margin factors affecting an equity affiliate, which resulted in an $89 million after-tax reduction in our equity earnings from CPChem. Our equity in earnings from CPChem were reduced by $24 million in 2015 as a result of an impairment CPChem recognized on an equity affiliate. These items were partially offset by higher NAO and polyethylene sales volumes and improved SA&S margins.
Refining
| Year Ended December 31 | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Millions of Dollars | |||||||||
| Net Income (Loss) | |||||||||
| Atlantic Basin/Europe | $ | 370 | 204 | 569 | |||||
| Gulf Coast | 512 | 52 | 551 | ||||||
| Central Corridor | 477 | 234 | 857 | ||||||
| West Coast | 45 | (116 | ) | 578 | |||||
| Worldwide | $ | 1,404 | 374 | 2,555 | |||||
| Dollars Per Barrel | |||||||||
| Net Income (Loss) | |||||||||
| Atlantic Basin/Europe | $ | 1.86 | 0.93 | 2.68 | |||||
| Gulf Coast | 1.79 | 0.18 | 2.08 | ||||||
| Central Corridor | 5.18 | 2.38 | 8.96 | ||||||
| West Coast | 0.34 | (0.92 | ) | 4.42 | |||||
| Worldwide | 1.97 | 0.51 | 3.63 | ||||||
| Realized Refining Margins | |||||||||
| Atlantic Basin/Europe | $ | 8.25 | 6.26 | 9.39 | |||||
| Gulf Coast | 7.07 | 5.49 | 9.29 | ||||||
| Central Corridor | 12.44 | 8.70 | 14.88 | ||||||
| West Coast | 10.49 | 9.15 | 16.86 | ||||||
| Worldwide | 9.13 | 6.99 | 11.84 |
| Thousands of Barrels Daily | ||||||||
| Year Ended December 31 | ||||||||
| 2017 | 2016 | 2015 | ||||||
| Operating Statistics | ||||||||
| Refining operations* | ||||||||
| Atlantic Basin/Europe | ||||||||
| Crude oil capacity | 520 | 566 | 588 | |||||
| Crude oil processed | 494 | 568 | 539 | |||||
| Capacity utilization (percent) | 95 | % | 100 | 92 | ||||
| Refinery production | 553 | 607 | 587 | |||||
| Gulf Coast | ||||||||
| Crude oil capacity | 743 | 743 | 738 | |||||
| Crude oil processed | 709 | 704 | 654 | |||||
| Capacity utilization (percent) | 95 | % | 95 | 89 | ||||
| Refinery production | 789 | 783 | 733 | |||||
| Central Corridor | ||||||||
| Crude oil capacity | 493 | 493 | 492 | |||||
| Crude oil processed | 467 | 485 | 465 | |||||
| Capacity utilization (percent) | 95 | % | 98 | 95 | ||||
| Refinery production | 489 | 506 | 486 | |||||
| West Coast | ||||||||
| Crude oil capacity | 360 | 360 | 360 | |||||
| Crude oil processed | 342 | 318 | 330 | |||||
| Capacity utilization (percent) | 95 | % | 88 | 92 | ||||
| Refinery production | 368 | 345 | 359 | |||||
| Worldwide | ||||||||
| Crude oil capacity | 2,116 | 2,162 | 2,178 | |||||
| Crude oil processed | 2,012 | 2,075 | 1,988 | |||||
| Capacity utilization (percent) | 95 | % | 96 | 91 | ||||
| Refinery production | 2,199 | 2,241 | 2,165 | |||||
| * 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.
2017 vs. 2016
Net income for the Refining segment increased $1,030 million in 2017, compared with 2016. The increase was primarily due to higher realized refining margins and West Coast volumes, as well as an after-tax gain of $261 million recognized on the consolidation of MSLP, 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 the “Business Environment and Executive Overview” section for information on industry crack spreads and other market factors impacting this year’s results. In addition, see Note 5—Business Combinations and Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on the consolidation of MSLP in February 2017 and the subsequent contribution of our ownership interest in MSLP to Phillips 66 Partners in October 2017, respectively.
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.
2016 vs. 2015
Net income for the Refining segment decreased $2,181 million in 2016, compared with 2015. Lower net income in 2016 reflected lower realized refining margins resulting from decreased market crack spreads, higher costs associated with renewable fuels blending activities, lower clean product differentials and lower feedstock advantage. These items were partially offset by higher volumes due to lower turnaround activities and less unplanned downtime.
Our worldwide refining crude oil capacity utilization rate was 96 percent in 2016, compared with 91 percent in 2015. The increase was primarily attributable to lower turnaround activities and less unplanned downtime.
Non-GAAP Reconciliations
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 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. 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.
Under generally accepted accounting principles in the United States (GAAP), the performance measure most directly comparable to refining margin per barrel is the Refining segment’s “net income per barrel.” 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 net income, such as general and administrative expenses and income taxes. It also includes our proportional share of joint-venture refineries’ realized margins and excludes special items. Because refining margin per barrel is calculated in this manner, and because 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 net income 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, 2017 | |||||||||||
| Net income | $ | 370 | 512 | 477 | 45 | 1,404 | |||||
| Plus: | |||||||||||
| Income tax expense | 78 | 297 | 278 | 19 | 672 | ||||||
| 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 | ||||||
| Net income per barrel (dollars per barrel)** | $ | 1.86 | 1.79 | 5.18 | 0.34 | 1.97 | |||||
| Realized refining margins (dollars per barrel)*** | 8.25 | 7.07 | 12.44 | 10.49 | 9.13 | ||||||
| Year Ended December 31, 2016 | |||||||||||
| Net income (loss) | $ | 204 | 52 | 234 | (116 | ) | 374 | ||||
| Plus: | |||||||||||
| Income tax expense (benefit) | (17 | ) | 17 | 133 | (72 | ) | 61 | ||||
| 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 | ||||||
| Net income (loss) per barrel (dollars per barrel)** | $ | 0.93 | 0.18 | 2.38 | (0.92 | ) | 0.51 | ||||
| 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. | |||||||||||
| ** Net income (loss) 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, 2015 | |||||||||||
| Net income | $ | 569 | 551 | 857 | 578 | 2,555 | |||||
| Plus: | |||||||||||
| Income tax expense (benefit) | (15 | ) | 338 | 469 | 312 | 1,104 | |||||
| Taxes other than income taxes | 57 | 76 | 42 | 84 | 259 | ||||||
| Depreciation, amortization and impairments | 197 | 226 | 102 | 216 | 741 | ||||||
| Selling, general and administrative expenses | 67 | 60 | 35 | 59 | 221 | ||||||
| Operating expenses | 995 | 1,241 | 447 | 961 | 3,644 | ||||||
| Equity in (earnings) losses of affiliates | 8 | (25 | ) | (308 | ) | — | (325 | ) | |||
| Other segment (income) expense, net | 30 | 2 | 8 | (5 | ) | 35 | |||||
| Proportional share of refining gross margins contributed by equity affiliates | 89 | (9 | ) | 977 | — | 1,057 | |||||
| Realized refining margins | $ | 1,997 | 2,460 | 2,629 | 2,205 | 9,291 | |||||
| Total processed inputs (thousands of barrels) | 212,627 | 264,874 | 95,682 | 130,799 | 703,982 | ||||||
| Adjusted total processed inputs (thousands of barrels)* | 212,627 | 264,874 | 176,641 | 130,799 | 784,941 | ||||||
| Net income per barrel (dollars per barrel)** | $ | 2.68 | 2.08 | 8.96 | 4.42 | 3.63 | |||||
| Realized refining margins (dollars per barrel)*** | 9.39 | 9.29 | 14.88 | 16.86 | 11.84 | ||||||
| * Adjusted total processed inputs include our proportional share of processed inputs of an equity affiliate. | |||||||||||
| ** Net income 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 and Specialties
| Year Ended December 31 | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Millions of Dollars | |||||||||
| Net Income | |||||||||
| Marketing and Other | $ | 551 | 747 | 1,004 | |||||
| Specialties | 135 | 144 | 183 | ||||||
| Total Marketing and Specialties | $ | 686 | 891 | 1,187 | |||||
| Dollars Per Barrel | |||||||||
| Net Income | |||||||||
| U.S. | $ | 0.56 | 0.74 | 0.76 | |||||
| International | 1.81 | 2.21 | 1.98 | ||||||
| Realized Marketing Fuel Margins | |||||||||
| U.S. | $ | 1.48 | 1.64 | 1.65 | |||||
| International | 4.21 | 4.05 | 4.40 | ||||||
| Dollars Per Gallon | |||||||||
| U.S. Average Wholesale Prices* | |||||||||
| Gasoline | $ | 1.87 | 1.62 | 1.92 | |||||
| Distillates | 1.85 | 1.48 | 1.77 | ||||||
| * On third-party branded petroleum products sales, excluding excise taxes. | |||||||||
| Thousands of Barrels Daily | |||||||||
| Marketing Petroleum Products Sales | |||||||||
| Gasoline | 1,246 | 1,238 | 1,205 | ||||||
| Distillates | 931 | 947 | 953 | ||||||
| Other | 18 | 16 | 16 | ||||||
| 2,195 | 2,201 | 2,174 |
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.
2017 vs. 2016
Net income from the M&S segment decreased $205 million in 2017, compared with 2016. The decrease was primarily due to lower realized marketing margins, as well as the absence of biofuel tax credits and a favorable income tax adjustment recognized in 2016.
See the “Business Environment and Executive Overview” section for information on marketing fuel margins and other market factors impacting 2016 results.
2016 vs. 2015
Net income from the M&S segment decreased $296 million in 2016, compared with 2015. The decrease was mainly attributable to the $242 million deferred gain recognized in 2015 related to the 2013 ICHP sale. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information.
Also contributing to the lower net income in 2016 were lower realized marketing margins driven by an upward trend of spot prices during most of 2016, and lower margins and volumes in lubricants. These decreases were partially offset by favorable tax adjustments and higher marketing volumes.
Non-GAAP Reconciliations
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. These margins are converted to a per-barrel basis by dividing them by sales volumes measured on a barrel basis. 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 marketing fuel margin per barrel is the marketing business’ “net income per barrel.” 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 net income, such as general and administrative expenses and income taxes. Because marketing fuel margin per barrel excludes these items, and because 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 net income to realized marketing fuel margins:
| Millions of Dollars, Except as Indicated | ||||||||||||||
| U.S. | International | |||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||
| Realized Marketing Fuel Margins | ||||||||||||||
| Net income | $ | 395 | 519 | 518 | 176 | 235 | 217 | |||||||
| Plus: | ||||||||||||||
| Income tax expense | 233 | 285 | 292 | 41 | 17 | 57 | ||||||||
| Taxes other than income taxes | 5,481 | 5,187 | 5,208 | 7,579 | 8,132 | 8,499 | ||||||||
| Depreciation, amortization and impairment | 14 | 12 | 9 | 67 | 63 | 62 | ||||||||
| Selling, general and administrative expenses | 751 | 708 | 732 | 264 | 259 | 269 | ||||||||
| Equity in earnings of affiliates | (5 | ) | (4 | ) | (4 | ) | (83 | ) | (75 | ) | (78 | ) | ||
| Other operating revenues* | (5,815 | ) | (5,558 | ) | (5,614 | ) | (7,594 | ) | (8,157 | ) | (8,507 | ) | ||
| Other segment (income) expense, net | (15 | ) | — | (15 | ) | 2 | 3 | 6 | ||||||
| Marketing margins | 1,039 | 1,149 | 1,126 | 452 | 477 | 525 | ||||||||
| Less: margin for non-fuel related sales | — | — | — | 42 | 45 | 44 | ||||||||
| Realized marketing fuel margins | $ | 1,039 | 1,149 | 1,126 | 410 | 432 | 481 | |||||||
| Total fuel sales volumes (thousands of barrels) | 703,928 | 699,111 | 684,045 | 97,346 | 106,574 | 109,332 | ||||||||
| Net income per barrel (dollars per barrel) | $ | 0.56 | 0.74 | 0.76 | 1.81 | 2.21 | 1.98 | |||||||
| Realized marketing fuel margins (dollars per barrel)** | 1.48 | 1.64 | 1.65 | 4.21 | 4.05 | 4.40 | ||||||||
| * Primarily excise taxes and 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. |
Corporate and Other
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Net Income (Loss) | |||||||||
| Net interest expense | $ | (266 | ) | (210 | ) | (186 | ) | ||
| Corporate general and administrative expenses | (175 | ) | (161 | ) | (157 | ) | |||
| Technology | (62 | ) | (58 | ) | (60 | ) | |||
| U.S. tax reform | 2,735 | — | — | ||||||
| Other | (63 | ) | (55 | ) | (95 | ) | |||
| Total Corporate and Other | $ | 2,169 | (484 | ) | (498 | ) |
2017 vs. 2016
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $56 million in 2017, compared with 2016, primarily due to lower capitalized interest as a result of the Freeport LPG Export Terminal beginning operations in late 2016, and higher interest expense driven by higher average debt principal balances, reflecting Phillips 66 Partners’ debt issuances in October 2017 and 2016.
The Tax Act was enacted on December 22, 2017. The material provisions of the Tax Act i) reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, ii) imposed a one-time deemed repatriation tax on foreign-sourced earnings that were previously tax deferred, and iii) created a new tax regime on post-2017 foreign-sourced earnings. We have not yet completed our accounting for the income tax effects of the Tax Act as of December 31, 2017, but have made reasonable estimates of those effects on our existing deferred income tax balances and the one-time deemed repatriation tax. We recognized a provisional income tax benefit of $2,735 million, which is included in the “Income tax expense (benefit)” line on our consolidated statement of income. We have included these one-time impacts of the Tax Act in Corporate and Other. Of the provisional income tax benefit recognized, $2,870 million was associated with the revaluation of our existing deferred tax assets and liabilities, and $14 million reflected higher manufacturing deductions, which was an indirect benefit of the Tax Act. These benefits were partially offset by the one-time deemed repatriation tax estimate of $149 million. We expect the Tax Act to significantly lower our effective tax rates in 2018 and future years for both our consolidated operations and each of our operating segments. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for more information.
2016 vs. 2015
Net interest expense increased $24 million in 2016, compared with 2015, mainly due to lower capitalized interest.
The category “Other” includes certain income tax expenses, environmental costs associated with sites no longer in operation, foreign currency transaction gains and losses and other costs not directly associated with an operating segment. The decrease in other costs in 2016 was primarily attributable to favorable tax impacts and the write-off of certain fixed assets during 2015, partially offset by higher environmental accruals.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
| Millions of Dollars, Except as Indicated | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Cash and cash equivalents | $ | 3,119 | 2,711 | 3,074 | |||||
| Net cash provided by operating activities | 3,648 | 2,963 | 5,713 | ||||||
| Short-term debt | 41 | 550 | 44 | ||||||
| Total debt | 10,110 | 10,138 | 8,887 | ||||||
| Total equity | 27,428 | 23,725 | 23,938 | ||||||
| Percent of total debt to capital* | 27 | % | 30 | 27 | |||||
| Percent of floating-rate debt to total debt | 11 | % | 3 | 1 | |||||
| * 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 raises funds for its growth activities through debt and equity financings. During 2017, we generated $3.6 billion in cash from operations. Phillips 66 Partners completed the private placement of perpetual convertible preferred units and common units and the public offering of senior notes and common units for net proceeds totaling $1.8 billion. We used this available cash primarily for capital expenditures and investments of $1.8 billion; repurchases of our common stock of $1.6 billion; and dividend payments on our common stock of $1.4 billion. During 2017, cash and cash equivalents increased by $0.4 billion, to $3.1 billion.
In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs, asset sales and our ability to issue securities using our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to external sources of funds as described below under “Significant Sources of Capital,” will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, debt repayment and share repurchases.
Significant Sources of Capital
Operating Activities
During 2017, cash of $3,648 million was provided by operating activities, a 23 percent increase compared with 2016. The increase was primarily attributable to increased operating results due to higher realized refining margins and distributions from our equity affiliates. This increase was 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.
During 2016, cash of $2,963 million was provided by operating activities, a 48 percent decrease compared with 2015. The decrease was primarily attributable to lower realized refining margins, as well as a reduction in distributions from our equity affiliates. This decrease was partially offset by positive working capital of $501 million in 2016 compared to a negative working capital impact of $221 million in 2015. The positive working capital impact in 2016 was primarily driven by increased refining payables, due to an increase in feedstock costs at the end of 2016 as compared with 2015, and the timing of tax payments and refunds, partially offset by an increase in receivables, resulting from higher commodity prices.
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 2017, compared with 96 percent in 2016.
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, 2017, we received distributions of $107 million from DCP Midstream, $1,854 million from CPChem and $300 million from WRB. We cannot control the amount or timing of future distributions from equity affiliates; therefore, future distributions by these and other equity affiliates are not assured.
Effective January 1, 2017, DCP Midstream and DCP Partners closed a transaction in which DCP Midstream contributed subsidiaries owning all of its operating assets, $424 million of cash and $3.15 billion of debt to DCP Partners, in exchange for DCP Partners units which had an estimated fair value of $1.125 billion at the time of the transaction. We and our co-venturer retained our 50/50 investment in DCP Midstream, and DCP Midstream retained its incentive distribution rights (IDRs) in DCP Partners through its ownership of the general partner of DCP Partners. After the transaction, DCP Midstream held a 36 percent limited partner interest and a 2 percent general partner interest in DCP Partners. DCP Midstream, through its ownership of the general partner, has agreed, if required, to forgo receipt of IDRs up to $100 million annually (100 percent basis) through 2019, to support a minimum distribution coverage ratio for DCP Partners. In connection with the transaction, DCP Midstream terminated its revolving credit agreement, which had previously served to limit distributions to its owners while amounts had been borrowed under the facility. As a result, distributions to the owners of DCP Midstream resumed in 2017.
In 2015, CPChem made a special distribution to its owners, with our share totaling $696 million. CPChem funded the distribution by issuing $1.4 billion of senior notes with maturities ranging from three to five years, with a combination of fixed and floating interest rates. This cash inflow from CPChem was included in operating cash flows, as we had cumulative undistributed equity earnings attributable to CPChem in excess of the amount distributed. We did not receive any distributions from CPChem in the second half of 2017 due to the impacts of Hurricane Harvey on its Gulf Coast operations and its U.S. Gulf Coast Petrochemicals Project. We expect distributions from CPChem to resume in 2018.
Foreign Cash Holdings
With the passage of the Tax Act in December 2017, we are subject to a one-time deemed repatriation tax on foreign-sourced earnings. For a portion of those foreign earnings, we had previously deferred any associated U.S. income taxes. As a result of the Tax Act, we now have the ability to utilize a greater percentage of our worldwide cash and cash equivalents for domestic purposes without incurring additional material U.S. income taxes beyond those imposed by the one-time deemed repatriation tax, thereby improving the flexibility of our worldwide cash management system. We expect a portion of our foreign cash holdings will be reserved exclusively for foreign use in support of those operations and local statutory and regulatory requirements; however, that amount is not expected to materially impact our liquidity. Additionally, we do not expect the payment of the one-time deemed repatriation tax to materially impact our liquidity.
Phillips 66 Partners
In 2013, we formed Phillips 66 Partners, a publicly traded MLP, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum products, and NGL pipelines and terminals, as well as other Midstream assets.
Ownership
At December 31, 2017, we owned a 55 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while its public unitholders owned a 43 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 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements, for additional information on why we consolidate the partnership. As a result of this consolidation, the public common and preferred unitholders’ interests in Phillips 66 Partners are reflected as noncontrolling interests in our consolidated balance sheet, and totaled $2,314 million at December 31, 2017. Generally, drop down transactions to Phillips 66 Partners will eliminate in consolidation, except for third-party debt or third-party equity offerings made by Phillips 66 Partners to finance such transactions. As a result of Phillips 66 Partners’ third-party debt and equity offerings in 2017, primarily
related to the contribution of assets in October 2017, our consolidated cash increased by $1,848 million and consolidated debt increased by $643 million.
Debt and Equity Financings
During the three years ended December 31, 2017, Phillips 66 Partners raised net proceeds of approximately $5.4 billion from the following third-party debt and equity offerings:
| • | In October 2017, Phillips 66 Partners received net proceeds of $643 million from the issuance of $500 million of 3.750% Senior Notes due 2028 and $150 million of 4.680% Senior Notes due 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 2026 and $625 million of 4.900% Senior Notes due 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 June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which allows for the offering of up to $250 million of common units. Through December 31, 2017, net proceeds of $192 million had been received under this program. |
| • | 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. |
| • | In February 2015, Phillips 66 Partners received net proceeds of $1,092 million from the issuance of $300 million of 2.646% Senior Notes due 2020, $500 million of 3.605% Senior Notes due 2025, and $300 million of 4.680% Senior Notes due 2045. |
| • | In February 2015, Phillips 66 Partners received net proceeds of $384 million from a public offering of 5,250,000 million common units, at a price of $75.50 per unit. |
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on Phillips 66 Partners and additional details on assets contributed to the partnership by us during 2017.
Phillips 66 Partners filed a new shelf registration statement for a second continuous offering program that became effective with the Securities and Exchange Commission (SEC) on January 23, 2018, related to the continuous offering of up to an aggregate of $250 million of common units, in amounts, at prices and on terms to be determined by the market conditions and other factors at the time of the offerings.
Credit Facilities and Commercial Paper
Phillips 66 has a $5.0 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 we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowings under the facility will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor’s (S&P) Ratings
Services and Moody’s Investors Service. The facility also provides for customary fees, including administrative agent fees and commitment fees. At December 31, 2017, no amount had been drawn under this revolving credit agreement.
We have a $5.0 billion commercial paper program for short-term working capital needs that is supported by our revolving credit facility. Commercial paper maturities are generally limited to 90 days. At December 31, 2017, we had no borrowings under our 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. At December 31, 2017, Phillips 66 Partners had no borrowings outstanding under this facility.
Other Debt Issuances and Financings
In April 2017, Phillips 66 completed a private offering of $600 million aggregate principal amount of unsecured notes, consisting of $300 million of Notes due 2019 and $300 million of Notes due 2020. Interest on the notes is a floating rate equal to three-month LIBOR plus 0.65% per annum for the 2019 Notes and three-month LIBOR plus 0.75% per annum for the 2020 Notes. Interest on both series of notes is payable quarterly in arrears on January 15, April 15, July 15 and October 15, commencing in July 2017. The 2019 Notes mature on April 15, 2019, and the 2020 Notes mature on April 15, 2020.
Also in April 2017, Phillips 66 entered into term loan facilities with an aggregate borrowing amount of $900 million, consisting of a $450 million 364-day facility and a $450 million three-year facility. Interest on the term loans is a floating rate based on either the Eurodollar rate or the reference rate, plus a margin determined by our long-term credit ratings.
Phillips 66 used the net proceeds from the issuance of the notes, together with the proceeds from the term loans, and cash on-hand to repay its outstanding 2.950% Senior Notes upon maturity in May 2017.
In October 2017, as part of the contribution of assets to Phillips 66 Partners, discussed above, Phillips 66 Partners assumed the $450 million term loan outstanding under the 364-day facility originally issued in April 2017, and subsequently repaid the loan.
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 sixteen years. The present value of our minimum capital lease payments for these obligations as of December 31, 2017, was $192 million.
Availability of Debt and Equity Financing
The $6.0 billion of outstanding Senior Notes and $600 million of floating-rate notes issued by Phillips 66 are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Our senior unsecured long-term debt has been rated investment grade by S&P (BBB+) and Moody’s (A3). We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating deteriorated to a level prohibiting us from accessing the commercial paper market, we would expect to be able to access funds under our liquidity facilities mentioned above.
In addition, we have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
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. The operating lease has a term of five years and provides us the option, at the end of the lease term, to request to renew the lease, purchase the facility, or assist the lessor in marketing it for resale.
We also have residual value guarantees associated with railcar and airplane leases with maximum future potential payments of $305 million. For information on our need to perform under the railcar lease guarantee, see the “Capital Requirements” section to follow.
In addition, we have guarantees outstanding related to certain joint-venture debt obligations, which have remaining terms of up to eight years. The maximum potential amount of future payments to third parties under these guarantees is approximately $308 million.
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 “Capital Spending” below.
Debt Financing
Our debt balance at December 31, 2017, was $10.1 billion and our total debt-to-capital ratio was 27 percent. See Note 12—Debt, in the Notes to Consolidated Financial Statements, for our annual debt maturities over the next five years.
Dividends
On February 7, 2018, our Board of Directors declared a quarterly cash dividend of $0.70 per common share, payable March 1, 2018, to holders of record at the close of business on February 20, 2018.
Share Repurchases
Since July 2012, our Board of Directors has, at various times, authorized repurchases of our outstanding common stock which aggregate to a total authorization of up to $12.0 billion. The share repurchases are expected to be funded primarily through available cash. The shares will be repurchased from time to time in the open market at our discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012, through December 31, 2017, we have repurchased a total of 124,142,530 shares at an aggregate cost of $9.0 billion. Shares of stock repurchased are held as treasury shares.
On February 13, 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 approximately $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 on February 14, 2018. We funded the repurchase with cash on hand of approximately $1.9 billion and borrowings of approximately $1.4 billion under our commercial paper program. This specific share repurchase transaction was separately authorized by our Board of Directors and therefore does not impact previously announced authorizations which total up to $12.0 billion.
Railcar and Airplane Leases Residual Value Guarantees
On May 1, 2015, the U.S. Department of Transportation issued a final rule focused on the safe transportation of flammable liquids by rail. The final rule, which is being challenged, subjects new and existing railcars transporting crude oil in high volumes to heightened design standards, including thicker tank walls and heat shields, improved pressure relief valves and enhanced braking systems. We are currently evaluating the impact of the new regulations on our crude oil railcar fleet, which is mostly held under operating leases. The regulations become effective subsequent to the expiration dates of a portion of our leases. Some of our leases require a portion of the leased railcars to be retrofitted. Certain leases are subject to residual value guarantees. Under the lease terms, we have the option to either purchase the railcars or return them to the lessors. If railcars are returned to the lessors, we may be required to make the lessors whole under the residual value guarantees, which are subject to a cap. The current market demand for crude oil railcars is low, which has resulted in a decline in crude oil railcar prices. Based on third-party appraisals of the railcars’ fair value at the end of their lease terms, we estimated a total residual value deficiency of $109 million that would be payable at the end of the lease terms, with approximately one-half paid in late 2017 and the other half due in 2019. During 2017 and 2016, we recognized $73 million of expense related to the residual value deficiency of our leased railcars. In October 2017, upon maturity of one of our railcar leases, $53 million of the total residual value deficiency of $109 million was settled. The residual value deficiency of $36 million remaining at December 31, 2017, will be recognized on a straight-line basis through May 2019. Due to current market uncertainties, changes in the estimated fair values of railcars could occur, which could increase or decrease our currently estimated residual value deficiency. As of December 31, 2017, our maximum future exposure for residual value guarantees associated with our railcar and airplane leases was approximately $305 million. See Note 13—Guarantees, in the Notes to Consolidated Financial Statements.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2017:
| Millions of Dollars | |||||||||||||||
| Payments Due by Period | |||||||||||||||
| Total | Up to 1 Year | Years 2-3 | Years 4-5 | After 5 Years | |||||||||||
| Debt obligations (a) | $ | 10,026 | 25 | 1,375 | 2,050 | 6,576 | |||||||||
| Capital lease obligations | 192 | 16 | 27 | 22 | 127 | ||||||||||
| Total debt | 10,218 | 41 | 1,402 | 2,072 | 6,703 | ||||||||||
| Interest on debt | 7,371 | 436 | 839 | 765 | 5,331 | ||||||||||
| Operating lease obligations | 1,826 | 533 | 726 | 241 | 326 | ||||||||||
| Purchase obligations (b) | 77,683 | 32,236 | 9,554 | 6,698 | 29,195 | ||||||||||
| Other long-term liabilities (c) | |||||||||||||||
| Asset retirement obligations | 268 | 7 | 30 | 18 | 213 | ||||||||||
| Accrued environmental costs | 458 | 78 | 117 | 72 | 191 | ||||||||||
| Unrecognized income tax benefits (d) | 1 | 1 | (d) | (d) | (d) | ||||||||||
| Total | $ | 97,825 | 33,332 | 12,668 | 9,866 | 41,959 |
| (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 by operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $35,480 million. In addition, $24,230 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 82 years, and product purchases of $1,652 million from DCP entities for NGL over the remaining contractual term of three years. |
Purchase obligations of $5,097 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. From 2018 through 2022, we expect to contribute an average of $70 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $34 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $60 million for 2018 and then approximately $75 million per year for the remaining four years. Our minimum funding in 2018 is expected to be $60 million in the United States and $35 million outside the United States. |
| (d) | Excludes unrecognized income tax benefits of $33 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential refunds. Also excludes interest and penalties of $8 million. Although unrecognized income tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity. |
Capital Spending
| Millions of Dollars | ||||||||||||
| 2018 Budget | 2017 | 2016 | 2015 | |||||||||
| Capital Expenditures and Investments | ||||||||||||
| Midstream | $ | 1,218 | 771 | 1,453 | 4,457 | |||||||
| Chemicals | — | — | — | — | ||||||||
| Refining | 827 | 853 | 1,149 | 1,069 | ||||||||
| Marketing and Specialties | 140 | 108 | 98 | 122 | ||||||||
| Corporate and Other | 116 | 100 | 144 | 116 | ||||||||
| $ | 2,301 | 1,832 | 2,844 | 5,764 | ||||||||
| Selected Equity Affiliates* | ||||||||||||
| DCP Midstream | $ | 405 | 268 | 99 | 438 | |||||||
| CPChem | 398 | 776 | 987 | 1,319 | ||||||||
| WRB | 143 | 126 | 164 | 175 | ||||||||
| $ | 946 | 1,170 | 1,250 | 1,932 |
- Our share of capital spending.
Midstream
Capital spending in our Midstream segment during the three-year period ended December 31, 2017, included:
| • | Construction activities related to the Sweeny Fractionator and Freeport LPG Export Terminal projects. |
| • | Bakken Pipeline project, developed by our 25-percent-owned joint ventures, Dakota Access, LLC and Energy Transfer Crude Oil Company. |
| • | Construction activities related to increasing storage capacity at our crude oil and petroleum products terminal located near Beaumont, Texas. |
| • | 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 Bayou Bridge Pipeline by Phillips 66 Partners’ 40-percent-owned 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. |
| • | 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. |
| • | Expansion activities on the Phillips 66 Partners’ 50-percent-owned STACK Pipeline joint venture. |
| • | Spending associated with return, reliability and maintenance projects in our Transportation and NGL and Other businesses. |
During the three-year period ended December 31, 2017, DCP Midstream’s capital expenditures and investments were $1.6 billion on a 100 percent basis. In 2015, we contributed $1.5 billion of cash to DCP Midstream and our co-venturer contributed its interests in certain operating assets of equal value, that are held as equity investments. Upon completion of this transaction, our interest in DCP Midstream remained at 50 percent.
In 2015, REX repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we contributed to REX in 2015.
Chemicals
During the three-year period ended December 31, 2017, CPChem had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer. During this period, on a 100 percent basis, CPChem’s capital expenditures and investments were $6.2 billion. In addition, CPChem’s advances to its equity affiliates, primarily used for project construction and start-up activities, were $139 million and its repayments received from equity affiliates were $140 million.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2017, was $3.1 billion, primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to increase accessibility of advantaged crudes and improve product yields, improvements to the operating integrity of key processing units, and safety-related projects.
Key projects completed during the three-year period included:
| • | Installation of a tail gas treating unit at the Humber Refinery to reduce emissions from the sulfur recovery units. |
| • | Installation of facilities to improve clean product yields at the Sweeny, Lake Charles and Ponca City refineries. |
| • | Installation of facilities to improve processing of advantaged crudes at the Billings and Ponca City 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 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 Bayway and Ferndale refineries. |
| • | Installation of facilities to improve processing of advantaged crudes at the Lake Charles Refinery. |
| • | Installation of facilities to improve clean product yield at the Bayway Refinery, as well as the jointly owned Wood River Refinery. |
Generally, our equity affiliates in the Refining segment are intended to have self-funding capital programs. During this three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $930 million. We expect WRB’s 2018 capital program to be self-funding.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2017, was primarily for the acquisition of and investments in projects targeted at developing our new international sites. In addition, capital is used for reliability and maintenance projects at our Lubricants facilities.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2017, was primarily for projects related to information technology and facilities.
2018 Budget
Our 2018 capital budget is $2.3 billion including Phillips 66 Partners’ capital budget of $0.6 billion. This excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $0.9 billion, all of which is expected to be self-funded.
The Midstream capital budget of $1.2 billion is focused on projects integrated with our existing assets and infrastructure, including continued expansion of the Beaumont Terminal, additional Gulf Coast fractionation capacity and investment in pipelines and other terminals. The Midstream capital budget also includes Phillips 66 Partners’ growth projects, including expansions of the Sand Hills and Bayou Bridge pipelines, and construction of an isomerization unit at our Lake Charles Refinery. Refining’s capital budget of $0.8 billion is primarily directed toward reliability, safety and
environmental projects, as well as small, high-return, quick payout projects, primarily to improve clean product yields. In M&S, we plan to invest approximately $0.1 billion, primarily directed towards increasing retail sites in Europe. In Corporate and Other, we plan to fund approximately $0.1 billion in projects primarily related to information technology and facilities.
Contingencies
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Legal and Tax Matters
Our legal and tax matters are handled by our legal and tax organizations. These organizations apply their knowledge, experience and professional judgment to the specific characteristics of our cases and uncertain tax positions. We employ a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. In the case of income-tax-related contingencies, we monitor tax legislation and court decisions, the status of tax audits and the statute of limitations within which a taxing authority can assert a liability. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.
Environmental
Like other companies in our industry, we are subject to numerous international, federal, state and local environmental laws and regulations. Among the most significant of these international and federal environmental laws and regulations are the:
| • | 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 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 potentially affect refineries in the Los Angeles metropolitan area. In 2017, SCAQMD required additional nitrogen dioxide emissions reductions through 2025 and began evaluating if and how 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 2018 compliance year, the EPA has set volumes of advanced and total renewable fuel at higher levels than mandated in most previous years (although the 2018 compliance year volumes are roughly equivalent to those required for the 2017 compliance year); it is uncertain if these increased obligations will be achievable by fuel producers and shippers without drawing on the Renewable Identification Number (RIN) bank. For compliance years after 2018, we do not know whether the EPA will utilize its authority to reduce statutory volumes. Additionally, we may experience a decrease in demand for refined petroleum products due to the regulatory program as currently promulgated. This program continues to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s regulations pertaining to the 2014 through 2017 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, 2016, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 31 sites within the United States. During 2017, there were three new sites for which we received notification of potential liability, and three sites were deemed resolved and closed, leaving 31 unresolved sites with potential liability at December 31, 2017.
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 2017 and are expected to be approximately $670 million and $640 million in 2018 and 2019, respectively. Capitalized environmental costs were $159 million in 2017 and are expected to be approximately $185 million and $135 million, in 2018 and 2019, 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 greenhouse gas (GHG) emissions reduction, including various regulations proposed or issued by the EPA. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. Laws regulating GHG emissions continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws potentially could have a material impact on our results of operations and financial condition as a result of increasing costs of compliance, lengthening project implementation and agency review items, or reducing demand for certain hydrocarbon products. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
| • | EU ETS, which is part of the European Union’s policy to combat climate change and is a key tool for reducing industrial greenhouse gas emissions. EU ETS impacts factories, power stations and other installations across all EU member states. |
| • | 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 the recently-enacted 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. |
| • | 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 to 2012. The current phase (Phase III) runs from 2013 through to 2020, with the main changes being reduced allocation of free allowances and increased auctioning of new allowances. Phillips 66 has assets that are subject to the EU ETS, and the company is actively engaged in minimizing any financial impact from the EU ETS.
From November 30 to December 12, 2015, more than 190 countries, including the United States, participated in the United Nations Climate Change Conference in Paris, France. The conference culminated in what is known as the “Paris Agreement,” which, upon certain conditions being met, entered into force on November 4, 2016. The Paris Agreement establishes a commitment by signatory parties to pursue domestic GHG emission reductions. In 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 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 requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussion of critical accounting estimates, along with the discussion of contingencies in this report, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected. If the sum of the undiscounted pre-tax cash flows of an asset group is less than the carrying value, including applicable liabilities, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets (for example, at a refinery complex level). Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of similar assets, adjusted using principal market participant assumptions when necessary. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future volumes, commodity prices, operating costs, margins, discount rates and capital project decisions, considering all available information at the date of review.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment when there are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the investment’s carrying amount. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value.
When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that allows for recovery. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.
Asset Retirement Obligations
Under various contracts, permits and regulations, we have legal obligations to remove tangible equipment and restore the land at the end of operations at certain operational sites. Our largest asset removal obligations involve asbestos abatement at refineries. Estimating the timing and amount of payments for future asset removal costs is difficult. Most of these removal obligations are many years, or decades, in the future, and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
Environmental Costs
In addition to asset retirement obligations discussed above, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries, underground storage sites and non-operated sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, timing and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
Intangible Assets and Goodwill
At December 31, 2017, we had $756 million of intangible assets that we have determined to have indefinite useful lives, and therefore are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have finite useful lives, amortization will commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to annual impairment tests that require management’s judgment of the estimated fair value of these intangible assets.
At December 31, 2017, we had $3.3 billion of goodwill recorded in conjunction with past business combinations. Goodwill is not amortized. Instead, goodwill is subject to at least annual reviews for impairment at a reporting unit level. The reporting units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment.
Because quoted market prices for our reporting units are not available, management applies judgment in determining the estimated fair values of the reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make this fair value determination, including observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization. Sales or dispositions of significant assets within a reporting unit are allocated a portion of that reporting unit’s goodwill, based on relative fair values, which impacts the amount of gain or loss on the sale or disposition.
We completed our annual impairment test as of October 1, 2017, and concluded that the fair value of each of our reporting units continued to exceed their respective recorded net book values by a significant percentage. A decline in the estimated fair value of one or more of our reporting units in the future could result in an impairment. For example, a prolonged or significant decline in our stock price or a significant decline in actual or forecasted earnings could provide evidence of a significant decline in fair value and a need to record a material impairment of goodwill for one or more of our reporting units. After we have completed our annual test, we continue to monitor for impairment indicators, which can lead to further goodwill impairment testing.
Tax Assets and Liabilities
Our operations are subject to various taxes, including federal, state and foreign income taxes, property taxes, and transactional taxes such as excise, sales/use and payroll taxes. We record tax liabilities based on our assessment of existing tax laws and regulations. The recording of tax liabilities requires significant judgment and estimates. We recognize the financial statement effects of an income tax position when it is more likely than not that the position will be sustained upon examination by a taxing authority. A contingent liability related to a transactional tax claim is recorded if the loss is both probable and estimable. Actual incurred tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.
In determining our income tax 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. The material provisions of the Tax Act i) reduced the U.S. federal corporate income tax rate from 35 percent to 21 percent beginning January 1, 2018, ii) imposed a one-time deemed repatriation tax on foreign-sourced earnings that were previously tax deferred, and iii) created a new tax regime on post-2017 foreign-sourced earnings. We have not yet completed our accounting for the income tax effects of the Tax Act as of December 31, 2017, but have made reasonable estimates of those effects on our existing deferred income tax balances and the one-time deemed repatriation tax. As more guidelines and interpretations of the Tax Act become available over the next year, the estimates previously made may change, which could increase or decrease our revalued deferred income tax balances and the one-time deemed repatriation tax, with an offset to earnings.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans impacts the obligations on the balance sheet and the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future interest rates, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A one percentage-point decrease in the discount rate assumption would increase annual benefit expense by an estimated $65 million, while a one percentage-point decrease in the return on plan assets assumption would increase annual benefit expense by an estimated $35 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 2017 and 2016, our expected weighted-average long-term rate of return was approximately 6 percent for our worldwide pension plan assets. The actual weighted-average rate of return was 15 percent and 10 percent in 2017 and 2016, respectively. For the past ten years, our weighted-average actual rate of return was 7 percent for worldwide pension plan assets.
NEW ACCOUNTING STANDARDS
In February 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2017-05, “Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20).” This ASU clarifies the scope and accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU will eliminate the use of carryover basis for most nonmonetary exchanges, including contributions of assets to equity method joint ventures. These amendments could result in the entity recognizing a gain or loss on the sale or transfer of nonfinancial assets. Public entities should apply the guidance in ASU No. 2017-05 to annual periods beginning after December 15, 2017, including interim periods within those periods. There was no impact on our financial statements from adopting this ASU on January 1, 2018.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen for determining when a transaction involves an acquisition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset, or a group of similar identifiable assets, then the transaction is not considered an acquisition of a business. If the screen is not met, then the amendment requires that to be considered a business, the operation must include at a minimum an input and a substantive process that together significantly contribute to the ability to create an output. The guidance may reduce the number of transactions accounted for as business acquisitions. Public business entities should apply the guidance in ASU No. 2017-01 to annual periods beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The amendments should be applied prospectively and no disclosures are required at the effective date. There was no impact on our financial statements from adopting this ASU on January 1, 2018.
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 currently evaluating the provisions of ASU No. 2016-13 and assessing the impact on our 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. 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. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. We are currently evaluating the provisions of ASU No. 2016-02 and assessing its impact on our financial statements. As part of our assessment to-date, we have formed an implementation team, commenced identification of our lease population and selected a lease software package. We expect the adoption of ASU 2016-02 will materially gross up our consolidated balance sheet with the recognition of the ROU assets and operating lease liabilities. The impact to our consolidated statements of income and cash flows is not expected to be material. The new standard will also require additional disclosures for financing and operating leases.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to be carried at fair value upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU No. 2016-01 for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a limited impact on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU and other related updates are intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets and expand disclosure requirements. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Our assessment work primarily included the formation of an implementation work team, training on the new ASU’s revenue recognition model, contract review and documentation and the monitoring of industry interpretative issues. We adopted the standard on January 1, 2018, using the modified retrospective application. Our evaluation of the new ASU is near completion, which includes understanding the impact of adoption on earnings from equity method investments. Based upon our analysis to-date, the primary impact of adoption of the new standard is the netting of sales-based taxes collected from our customers against revenue. Sales-based taxes include excise taxes on sales of petroleum products as noted on our consolidated statement of income. We have not identified any other material impact on our financial statements other than disclosures.
Previous: Item 6. SELECTED FINANCIAL DATA · Next: Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK