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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the company’s analysis of its financial performance, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.”
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to Phillips 66.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
Phillips 66 is an energy manufacturing and logistics company with midstream, chemicals, refining, and marketing and specialties businesses. At December 31, 2016, we had total assets of $51.7 billion.
Executive Overview
We reported earnings of $1.6 billion in 2016 and generated $3.0 billion in cash from operating activities. Phillips 66 Partners LP issued debt and common units to the public for net proceeds totaling $2.1 billion. We used this available cash primarily to fund capital expenditures and investments of $2.8 billion, pay dividends of $1.3 billion and repurchase $1.0 billion of our common stock. We ended 2016 with $2.7 billion of cash and cash equivalents and approximately $5.5 billion of total capacity under both our and Phillips 66 Partners’ available liquidity facilities.
Our financial performance in 2016 demonstrated the benefit of a diversified portfolio of businesses in a low commodity price environment. We continue to focus on the following strategic priorities:
| • | Operating Excellence. Our commitment to operating excellence guides everything we do. We are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. Continuous improvement in safety, environmental stewardship, reliability and cost efficiency is a fundamental requirement for our company and employees. We employ rigorous training and audit programs to drive ongoing improvement in both personal and process safety as we strive for zero incidents. 2016 was our safest year since the company’s inception. Since we cannot control commodity prices, controlling operating expenses and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. We actively monitor and report these costs to senior management. Our operating and selling, general and administrative expenses were $5.9 billion in 2016, $6.0 billion in 2015 and $6.1 billion in 2014. We are committed to protecting the environment and strive to reduce our environmental footprint throughout our operations. Optimizing utilization rates at our refineries through reliable and safe operations enables us to capture the value available in the market in terms of prices and margins. During 2016, our worldwide refining crude oil capacity utilization rate was 96 percent, 5 percent higher than during 2015. |
| • | Growth. We have budgeted $2.7 billion in capital expenditures and investments in 2017, including $0.4 billion for Phillips 66 Partners. Including our share of expected capital spending by joint ventures DCP Midstream, LLC (DCP Midstream), Chevron Phillips Chemical Company LLC (CPChem) and WRB Refining LP (WRB), our total 2017 capital program is expected to be $3.8 billion. After completing our U.S. Gulf Coast NGL market hub in 2016, we will focus Midstream development in 2017 around our existing infrastructure’s footprint. In Chemicals, CPChem progressed towards completion of its U.S. Gulf Coast ethane cracker and polyethylene facilities project during 2016. The polyethylene units are expected to be complete by mid-2017 and the ethane |
cracker is expected to be complete in the fourth quarter of 2017. Growth capital in Refining will be directed toward small, high-return, quick-payout projects, while Marketing and Specialties will continue to expand and enhance its fuels marketing business.
| • | Returns. We plan to improve refining returns by increasing throughput of advantaged feedstocks, disciplined capital allocation and portfolio optimization. A disciplined capital allocation process ensures that we focus investments in projects that generate competitive returns throughout the business cycle. During 2016, we sold the Whitegate Refinery in Ireland as part of our ongoing portfolio optimization process. We improved clean product yield in 2016, and continued efforts to enhance the value of our marketing brands. |
| • | Distributions. We believe shareholder value is enhanced through, among other things, consistent growth of regular dividends, supplemented by share repurchases. We increased our quarterly dividend rate by 13 percent during 2016, and have increased it 215 percent since our separation from ConocoPhillips in 2012 (the Separation). Regular dividends demonstrate the confidence our Board of Directors and management have in our capital structure and operations’ capability to generate free cash flow throughout the business cycle. In 2016, we repurchased $1.0 billion, or approximately 12.9 million shares, of our common stock. At the discretion of our Board of Directors, we plan to increase dividends annually and fund our share repurchase program while continuing to invest in the growth of our business. |
| • | High-Performing Organization. We strive to attract, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and culture. Throughout the company, we focus on getting results in the right way and believe success is both what we do and how we do it. We encourage collaboration throughout our company, while valuing differences, respecting diversity, and creating a great place to work. We foster an environment of learning and development through structured programs focused on enhancing functional and technical skills where employees are engaged in our business and committed to their own, as well as the company’s, success. |
Business Environment
Commodity prices remained compressed during 2016. The discount for U.S. benchmark West Texas Intermediate (WTI) versus the international benchmark Brent narrowed over much of 2016 as the reemergence of floating storage pressured prompt waterborne markets. Over the course of 2016, commodity prices had a variety of impacts, both favorable and unfavorable, on our businesses that vary by segment.
Earnings in the Midstream segment, which includes our 50 percent equity investment in DCP Midstream, are closely linked to NGL prices, natural gas prices and crude oil prices. Average natural gas prices in 2016 were slightly lower than 2015 due to warmer-than-normal temperatures and high storage. In the fourth quarter of 2016, natural gas prices gained momentum with colder temperatures and increased residential and commercial heating demand. Total U.S. dry natural gas production also increased through the fourth quarter of 2016, largely from the Marcellus play, where new pipeline takeaway capacity came online in December 2016. NGL prices improved slightly throughout 2016 due to an increase in export capacity in the United States.
During 2016, our Chemicals segment, which consists of our 50 percent equity investment in CPChem, continued to benefit from feedstock cost advantages associated with manufacturing ethylene in regions of the world with significant NGL production. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on supply and demand, as well as cost factors. The petrochemicals industry continues to experience lower ethylene cash costs in regions of the world where ethylene manufacturing is based upon NGL rather than crude oil-derived feedstocks. In particular, companies with North American light NGL-based crackers have benefited from lower-priced feedstocks. The ethylene-to-polyethylene chain margins remained positive, but they compressed in 2016 because of the significant decline in crude oil prices that began in 2014.
Our Refining segment results are driven by several factors including refining margins, cost control, refinery throughput and product yields. Refinery margins, often referred to as crack spreads, are measured as the difference between market prices for refined petroleum products and crude oil. During 2016, the U.S. 3:2:1 crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) weakened across all quarters compared with 2015, largely attributable to higher product inventories resulting from historically high refining throughput (especially in the Gulf Coast and Midcontinent regions). Northwest European crack spreads on average decreased in 2016 compared to 2015, also because of high product inventories resulting from high refinery utilization.
Results for our Marketing and Specialties (M&S) segment depend largely on marketing fuel margins, lubricant margins and other specialty product margins. While M&S margins are primarily based on market factors, largely determined by the relationship between supply and demand, marketing fuel margins, in particular, are influenced by the trend of spot prices for refined products. Generally speaking, a downward trend of spot prices has a favorable impact on marketing fuel margins, while an upward trend of spot prices has an unfavorable impact on marketing fuel margins.
RESULTS OF OPERATIONS
Consolidated Results
A summary of net income (loss) attributable to Phillips 66 by business segment follows:
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2016 | 2015 | 2014 | |||||||
| Midstream | $ | 178 | 13 | 507 | |||||
| Chemicals | 583 | 962 | 1,137 | ||||||
| Refining | 374 | 2,555 | 1,771 | ||||||
| Marketing and Specialties | 891 | 1,187 | 1,034 | ||||||
| Corporate and Other | (471 | ) | (490 | ) | (393 | ) | |||
| Income from continuing operations attributable to Phillips 66 | 1,555 | 4,227 | 4,056 | ||||||
| Discontinued Operations | — | — | 706 | ||||||
| Net income attributable to Phillips 66 | $ | 1,555 | 4,227 | 4,762 |
2016 vs. 2015
Our earnings from continuing operations decreased $2,672 million, or 63 percent, in 2016, mainly reflecting:
| • | 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:
| • | Lower equity losses from DCP Midstream, primarily as a result of goodwill and other asset impairments recorded in 2015. |
2015 vs. 2014
Our earnings from continuing operations increased $171 million, or 4 percent, in 2015, primarily resulting from:
| • | Improved realized refining margins. |
| • | Recognition of $242 million in 2015, compared with $126 million in 2014, of the deferred gain related to the sale in 2013 of ICHP. |
These increases were partially offset by:
| • | Goodwill and other asset impairments recorded by DCP Midstream in 2015. |
| • | Lower ethylene margins. |
Discontinued operations in 2014 included the recognition of a noncash $696 million gain related to the Phillips Specialty Products Inc. (PSPI) disposition through a share exchange.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
2016 vs. 2015
Sales and other operating revenues and purchased crude oil and products both decreased 15 percent in 2016. The decreases were primarily due to lower average prices for petroleum products and crude oil, while average NGL prices were slightly improved during 2016.
Equity in earnings of affiliates decreased 10 percent in 2016, primarily resulting from decreased earnings from CPChem and WRB, partially offset by improved results from DCP Midstream.
| • | 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 provision for income taxes and effective tax rates.
2015 vs. 2014
Sales and other operating revenues decreased 39 percent in 2015, while purchased crude oil and products decreased 46 percent. The decreases were primarily due to lower average prices for petroleum products, crude oil and NGL.
Equity in earnings of affiliates decreased 36 percent in 2015, primarily resulting from decreased earnings from DCP Midstream, CPChem and WRB.
| • | Equity in earnings of DCP Midstream decreased $676 million in 2015. The decrease was primarily due to lower NGL, crude oil and natural gas prices. In addition, DCP Midstream recorded goodwill and other asset impairments in 2015. |
| • | Equity in earnings of CPChem decreased 19 percent, primarily due to lower ethylene margins and lower equity earnings from CPChem’s equity affiliates, partially offset by lower utility costs. |
| • | Equity in earnings of WRB decreased 13 percent, primarily driven by lower realized refining margins resulting from lower feedstock advantage, partially offset by higher secondary product margins. |
Impairments in 2015 were $7 million, compared with $150 million in 2014. There was a $131 million impairment of the Whitegate Refinery recorded in 2014. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.
Interest and debt expense increased 16 percent in 2015. The increase was mainly due to a higher average debt principal balance in 2015, partially offset by increased capitalized interest.
See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.
Segment Results
Midstream
| Year Ended December 31 | |||||||||
| 2016 | 2015 | 2014 | |||||||
| Millions of Dollars | |||||||||
| Net Income (Loss) Attributable to Phillips 66 | |||||||||
| Transportation | $ | 246 | 288 | 233 | |||||
| DCP Midstream | (33 | ) | (324 | ) | 135 | ||||
| NGL | (35 | ) | 49 | 139 | |||||
| Total Midstream | $ | 178 | 13 | 507 | |||||
| Dollars Per Unit | |||||||||
| Weighted Average NGL Price* | |||||||||
| DCP Midstream (per gallon) | $ | 0.46 | 0.45 | 0.89 |
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by NGL component and location mix.
| Thousands of Barrels Daily | ||||||||
| Transportation Volumes | ||||||||
| Pipelines* | 3,511 | 3,264 | 3,206 | |||||
| Terminals | 2,422 | 1,981 | 1,683 | |||||
| Operating Statistics | ||||||||
| NGL extracted** | 393 | 410 | 454 | |||||
| NGL fractionated*** | 170 | 112 | 109 |
*Pipelines represent the sum of volumes transported through each separately tariffed pipeline segment, including our share of equity volumes from Yellowstone Pipe Line Company and Lake Charles Pipe Line Company.
**Represents 100 percent of DCP Midstream’s volumes.
***Excludes DCP Midstream.
The Midstream segment gathers, processes, transports and markets natural gas; and transports, stores, fractionates and markets NGL in the United States. In addition, this segment transports crude oil and other feedstocks to our refineries and other locations, delivers refined and specialty products to market, and provides terminaling and storage services for crude oil and petroleum products. The segment also stores, refrigerates, and exports liquefied petroleum gas (LPG) primarily to Asia and Europe. The Midstream segment includes our master limited partnership (MLP), Phillips 66 Partners LP, as well as our 50 percent equity investment in DCP Midstream, LLC, which includes the operations of its MLP, DCP Midstream, LP (formerly named DCP Midstream Partners, LP and referred to herein as DCP Partners).
2016 vs. 2015
Earnings from the Midstream segment increased $165 million in 2016, compared with 2015. The increase was primarily due to improved results from DCP Midstream, partially offset by lower earnings from our Transportation and NGL businesses.
Transportation earnings decreased $42 million in 2016, compared with 2015. Lower earnings primarily resulted from higher operating costs, and increased depreciation expense due to growth projects, as well as increased income attributable to noncontrolling interests, reflecting the contribution of assets to Phillips 66 Partners. These items were partially offset by higher revenues from increased throughput volumes and higher tariffs.
Results from our investment in DCP Midstream improved $291 million in 2016, compared with 2015. In 2015, DCP Midstream recorded goodwill and other asset impairments, which reduced our earnings from DCP Midstream by $232 million, after-tax. In addition, favorable contract restructuring efforts, improved asset performance, higher earnings from DCP Midstream’s equity affiliates, lower operating costs and higher NGL prices contributed to better results in 2016. These improvements were partially offset by lower natural gas and crude oil prices.
Results from our NGL business decreased $84 million in 2016, compared with 2015. The decrease was primarily driven by lower realized margins, as well as increased depreciation and operating expenses associated with the Sweeny Fractionator and, late in the year, the Freeport LPG Export Terminal. These items were partially offset by higher fractionated volumes, reflecting the operation of the Sweeny Fractionator for a full year in 2016, and the benefit of the first liquefied petroleum gas cargos exported from the Freeport LPG Export Terminal in late 2016.
See the “Business Environment and Executive Overview” section for information on market factors impacting 2016 results.
2015 vs. 2014
Earnings from the Midstream segment decreased $494 million in 2015, compared with 2014. The decrease was primarily due to lower earnings from DCP Midstream and our NGL business, partially offset by higher earnings from our Transportation business.
Transportation earnings increased $55 million in 2015, compared with 2014. This increase reflects the startup of our Bayway and Ferndale crude oil rail unloading facilities in the second half of 2014, as well as a full year of operations from the Beaumont Terminal acquired in 2014. Increased railcar fleet activities, higher terminal revenues, and improved earnings from equity affiliates also benefited earnings in 2015. These benefits were partially offset by higher earnings attributable to noncontrolling interests.
Earnings associated with our investment in DCP Midstream decreased $459 million in 2015, compared with 2014. The decrease in 2015 mainly resulted from lower NGL, crude oil, and natural gas prices, partially offset by increased volumes due to asset growth and lower operating costs as a result of cost saving initiatives. In addition, goodwill and other asset impairments recorded by DCP Midstream in 2015 contributed to the loss recognized from our investment in DCP Midstream. DCP Midstream performed a goodwill impairment assessment and other asset impairment assessments based on internal discounted cash flow models taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rates. The impairment tests resulted in DCP Midstream’s recognition of a $460 million goodwill impairment and $342 million in other asset impairments, net of tax impacts. Together, these impairments reduced our equity earnings from DCP Midstream by $232 million after-tax.
DCP Partners periodically issues limited partner units to the public. These issuances benefited our equity in earnings from DCP Midstream, on an after-tax basis, by approximately $1 million in 2015, compared with approximately $45 million in 2014.
The earnings from our NGL business decreased $90 million in 2015, compared with 2014. The decrease was primarily driven by lower realized margins and higher earnings attributable to noncontrolling interests. We also incurred higher tax expense in 2015, driven by a lower manufacturing deduction resulting from bonus depreciation associated with the start-up of the Sweeny Fractionator. These decreases were partially offset by higher earnings from equity affiliates.
Chemicals
| Year Ended December 31 | |||||||||
| 2016 | 2015 | 2014 | |||||||
| Millions of Dollars | |||||||||
| Net Income Attributable to Phillips 66 | $ | 583 | 962 | 1,137 | |||||
| Millions of Pounds | |||||||||
| CPChem Externally Marketed Sales Volumes* | |||||||||
| Olefins and Polyolefins | 16,011 | 16,916 | 16,815 | ||||||
| Specialties, Aromatics and Styrenics | 4,911 | 5,301 | 6,294 | ||||||
| 20,922 | 22,217 | 23,109 | |||||||
| *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)* | 91 | % | 92 | 88 | |||||
| *Revised to exclude polyethylene pipe operations. Prior periods recast for comparability. |
The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method. CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used as feedstocks to produce plastics and other chemicals. We structure our reporting of CPChem’s operations around two primary business segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P business segment produces and markets ethylene and other olefin products; ethylene produced is primarily consumed within CPChem for the production of polyethylene, normal alpha olefins and polyethylene pipe. The SA&S business segment manufactures and markets aromatics and styrenics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene and styrene-butadiene copolymers. SA&S also manufactures and/or markets a variety of specialty chemical products. Unless otherwise noted, amounts referenced below reflect our net 50 percent interest in CPChem.
2016 vs. 2015
Earnings from the Chemicals segment decreased $379 million, or 39 percent, in 2016, compared with 2015. The decrease in earnings was primarily due to lower realized margins from the O&P business, driven by a decline in sales prices for polyethylene and normal alpha olefins (NAO) and higher feedstock costs, as well as impacts from increased turnaround activity. Lower equity earnings from CPChem’s equity affiliates and lower SA&S volumes further reduced earnings in 2016.
In addition, CPChem recognized a $177 million impairment in 2016 due to lower demand and margin factors affecting an equity affiliate, which resulted in an $89 million after-tax reduction in our equity earnings from CPChem. Our equity earnings from CPChem were reduced by $24 million in 2015 as a result of an impairment CPChem recognized on an equity affiliate. These items were partially offset by higher NAO and polyethylene sales volumes and improved SA&S margins.
See the “Business Environment and Executive Overview” section for information on market factors impacting CPChem’s results.
2015 vs. 2014
Earnings from the Chemicals segment decreased $175 million, or 15 percent, in 2015, compared with 2014. The decrease in earnings was primarily due to lower margins resulting from lower sales prices, lower earnings from CPChem’s O&P equity affiliates, and higher turnaround and maintenance activities.
These decreases were partially offset by higher ethylene and polyethylene sales volumes, as well as lower repair costs due to the impact on 2014 costs of a fire at CPChem’s Port Arthur, Texas facility. Lower feedstock costs, lower utility costs due to falling natural gas prices, and lower impairment charges also benefited the 2015 operating results.
In July 2014, a localized fire occurred in the olefins unit at CPChem’s Port Arthur, Texas facility, shutting down ethylene production. The Port Arthur ethylene unit restarted in November 2014. CPChem incurred, on a 100 percent basis, $85 million of associated repair and rebuild costs. Because the Port Arthur ethylene unit was down due to the fire, CPChem experienced a significant reduction in production and sales in several of its product lines stemming from the lack of the Port Arthur ethylene supply in 2014. CPChem recorded earnings, on a 100 percent basis, of $88 million and $120 million for business interruption and property damage insurance proceeds in 2015 and 2014, respectively.
Refining
| Year Ended December 31 | |||||||||
| 2016 | 2015 | 2014 | |||||||
| Millions of Dollars | |||||||||
| Net Income (Loss) Attributable to Phillips 66 | |||||||||
| Atlantic Basin/Europe | $ | 204 | 569 | 198 | |||||
| Gulf Coast | 52 | 551 | 252 | ||||||
| Central Corridor | 234 | 857 | 967 | ||||||
| West Coast | (116 | ) | 578 | 354 | |||||
| Worldwide | $ | 374 | 2,555 | 1,771 | |||||
| Dollars Per Barrel | |||||||||
| Refining Margins | |||||||||
| Atlantic Basin/Europe | $ | 6.26 | 9.39 | 8.94 | |||||
| Gulf Coast | 5.49 | 9.29 | 7.64 | ||||||
| Central Corridor | 8.70 | 14.88 | 15.63 | ||||||
| West Coast | 9.15 | 16.86 | 8.89 | ||||||
| Worldwide | 6.99 | 11.84 | 9.93 | ||||||
| Thousands of Barrels Daily | |||||||||
| Operating Statistics | |||||||||
| Refining operations* | |||||||||
| Atlantic Basin/Europe | |||||||||
| Crude oil capacity | 566 | 588 | 588 | ||||||
| Crude oil processed | 568 | 539 | 554 | ||||||
| Capacity utilization (percent) | 100 | % | 92 | 94 | |||||
| Refinery production | 607 | 587 | 605 | ||||||
| Gulf Coast | |||||||||
| Crude oil capacity | 743 | 738 | 733 | ||||||
| Crude oil processed | 704 | 654 | 676 | ||||||
| Capacity utilization (percent) | 95 | % | 89 | 92 | |||||
| Refinery production | 783 | 733 | 771 | ||||||
| Central Corridor | |||||||||
| Crude oil capacity | 493 | 492 | 485 | ||||||
| Crude oil processed | 485 | 465 | 475 | ||||||
| Capacity utilization (percent) | 98 | % | 95 | 98 | |||||
| Refinery production | 506 | 486 | 494 | ||||||
| West Coast | |||||||||
| Crude oil capacity | 360 | 360 | 440 | ||||||
| Crude oil processed | 318 | 330 | 403 | ||||||
| Capacity utilization (percent) | 88 | % | 92 | 92 | |||||
| Refinery production | 345 | 359 | 435 | ||||||
| Worldwide | |||||||||
| Crude oil capacity | 2,162 | 2,178 | 2,246 | ||||||
| Crude oil processed | 2,075 | 1,988 | 2,108 | ||||||
| Capacity utilization (percent) | 96 | % | 91 | 94 | |||||
| Refinery production | 2,241 | 2,165 | 2,305 | ||||||
| *Includes our share of equity affiliates. |
The Refining segment buys, sells and refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels) at 13 refineries, mainly in the United States and Europe.
2016 vs. 2015
Earnings for the Refining segment decreased $2,181 million, compared with 2015. Lower earnings in 2016 reflected lower realized refining margins resulting from decreased market crack spreads, higher costs associated with renewable fuels blending activities, lower clean product differentials and lower feedstock advantage. These items were partially offset by higher volumes due to lower turnaround activities and less unplanned downtime.
See the “Business Environment and Executive Overview” section for information on industry crack spreads and other market factors impacting this year’s results.
Our worldwide refining crude oil capacity utilization rate was 96 percent in 2016, compared to 91 percent in 2015. The increase was primarily attributable to lower turnaround activities and less unplanned downtime.
Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. As more fully discussed in Note 5—Business Combinations, in the Notes to Consolidated Financial Statements, in February 2017, the time expired for all legal challenges related to the exercise in 2009 of a call right to acquire Petróleos de Venezuela S.A.’s (PDVSA) 50 percent share of MSLP, and we began accounting for MSLP as a wholly owned consolidated subsidiary. Based on a preliminary appraisal, the acquisition of PDVSA’s 50 percent interest is expected to result in our recording a noncash, pre-tax gain of approximately $420 million in the first quarter of 2017.
2015 vs. 2014
Earnings for the Refining segment increased $784 million, or 44 percent, compared with 2014. The increase in earnings in 2015 primarily resulted from higher realized refining margins due to higher gasoline crack spreads and improved secondary product margins, as well as lower utility costs. These increases were partially offset by lower feedstock advantage, lower distillate crack spreads, lower clean product differentials, and lower refining volumes as a result of higher unplanned downtime and turnaround activities.
Our worldwide refining crude oil capacity utilization rate was 91 percent in 2015, compared to 94 percent in 2014. The decrease reflects higher unplanned downtime and turnaround activities.
Marketing and Specialties
| Year Ended December 31 | |||||||||
| 2016 | 2015 | 2014 | |||||||
| Millions of Dollars | |||||||||
| Net Income Attributable to Phillips 66 | |||||||||
| Marketing and Other | $ | 747 | 1,004 | 836 | |||||
| Specialties | 144 | 183 | 198 | ||||||
| Total Marketing and Specialties | $ | 891 | 1,187 | 1,034 | |||||
| Dollars Per Barrel | |||||||||
| Realized Marketing Fuel Margin* | |||||||||
| U.S. | $ | 1.64 | 1.65 | 1.51 | |||||
| International | 4.05 | 4.40 | 5.22 | ||||||
| *On third-party petroleum products sales. | |||||||||
| Dollars Per Gallon | |||||||||
| U.S. Average Wholesale Prices* | |||||||||
| Gasoline | $ | 1.62 | 1.92 | 2.72 | |||||
| Distillates | 1.48 | 1.77 | 2.95 | ||||||
| *Excludes excise taxes. | |||||||||
| Thousands of Barrels Daily | |||||||||
| Marketing Petroleum Products Sales | |||||||||
| Gasoline | 1,238 | 1,205 | 1,195 | ||||||
| Distillates | 947 | 953 | 979 | ||||||
| Other | 16 | 16 | 17 | ||||||
| 2,201 | 2,174 | 2,191 |
The M&S segment purchases for resale and markets refined petroleum products (such as gasoline, distillates and aviation fuels), mainly in the United States and Europe. In addition, this segment includes the manufacturing and marketing of specialty products (such as base oils and lubricants), as well as power generation operations.
2016 vs. 2015
Earnings from the M&S segment decreased $296 million, or 25 percent, in 2016, compared with 2015. The decrease was mainly attributable to the $242 million deferred gain recognized in 2015 related to the 2013 ICHP sale. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information.
Also contributing to the lower earnings in 2016 were lower realized marketing margins driven by an upward trend of spot prices during most of 2016, and lower margins and volumes in lubricants. These decreases were partially offset by favorable tax adjustments and higher marketing volumes.
See the “Business Environment and Executive Overview” section for information on marketing fuel margins and other market factors impacting 2016 results.
2015 vs. 2014
Earnings from the M&S segment increased $153 million, or 15 percent, in 2015, compared with 2014. In July 2013, we completed the sale of ICHP, and deferred the gain from the sale due to an indemnity provided to the buyer. We recognized $242 million after-tax and $126 million after-tax of the deferred gain in 2015 and 2014, respectively.
Earnings from the M&S segment also benefited from higher domestic marketing activities, higher domestic marketing and lubricants volumes, and increased tax credits from biodiesel blending activities. These benefits were partially offset by lower international marketing margins and lubricants margins.
Corporate and Other
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2016 | 2015 | 2014 | |||||||
| Net Loss Attributable to Phillips 66 | |||||||||
| Net interest expense | $ | (210 | ) | (186 | ) | (160 | ) | ||
| Corporate general and administrative expenses | (161 | ) | (157 | ) | (156 | ) | |||
| Technology | (58 | ) | (60 | ) | (58 | ) | |||
| Other | (42 | ) | (87 | ) | (19 | ) | |||
| Total Corporate and Other | $ | (471 | ) | (490 | ) | (393 | ) |
2016 vs. 2015
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $24 million in 2016, compared with 2015, mainly due to lower capitalized interest.
The category “Other” includes certain income tax expenses, environmental costs associated with sites no longer in operation, foreign currency transaction gains and losses and other costs not directly associated with an operating segment. The decrease in other costs in 2016 was primarily attributable to favorable tax impacts, the write-off of certain fixed assets during 2015 and the impact of an increase in noncontrolling interests on interest expense incurred by Phillips 66 Partners, partially offset by higher environmental accruals.
2015 vs. 2014
Net interest expense increased $26 million in 2015, compared with 2014, primarily due to a higher average debt principal balance as a result of the issuance of debt in the fourth quarter of 2014 and Phillips 66 Partners’ debt issuance in the first quarter of 2015. The increase was partially offset by higher capitalized interest. For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.
The increase in other costs in 2015 was primarily due to foreign tax credit carryforwards that were utilized in 2014 and other tax adjustments made in 2015.
Discontinued Operations
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2016 | 2015 | 2014 | |||||||
| Net Income Attributable to Phillips 66 | |||||||||
| Discontinued operations | $ | — | — | 706 |
In December 2013, we entered into an agreement to exchange the stock of PSPI, a flow improver business that was included in our M&S segment, for shares of Phillips 66 common stock owned by the other party to the transaction. In February 2014, we completed the PSPI share exchange, resulting in the receipt of approximately 17.4 million shares of Phillips 66 common stock and the recognition of a before-tax noncash gain of $696 million. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information on this transaction.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
| Millions of Dollars Except as Indicated | ||||||||||
| 2016 | 2015 | 2014 | ||||||||
| Cash and cash equivalents | $ | 2,711 | 3,074 | 5,207 | ||||||
| Net cash provided by operating activities | 2,963 | 5,713 | 3,529 | |||||||
| Short-term debt | 550 | 44 | 842 | |||||||
| Total debt | 10,138 | 8,887 | 8,635 | |||||||
| Total equity | 23,725 | 23,938 | 22,037 | |||||||
| Percent of total debt to capital* | 30 | % | 27 | 28 | ||||||
| Percent of floating-rate debt to total debt | 3 | % | 1 | 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, including cash generated from operating activities and Phillips 66 Partners’ debt and equity financings. During 2016, we generated $3.0 billion in cash from operations. Phillips 66 Partners issued debt and common units to the public for net proceeds totaling $2.1 billion. We used this available cash primarily for capital expenditures and investments ($2.8 billion); repurchases of our common stock ($1.0 billion); and dividend payments on our common stock ($1.3 billion). During 2016, cash and cash equivalents decreased by $0.4 billion, to $2.7 billion.
In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs, asset sales and our ability to issue securities using our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to external sources of funds as described below under “Significant Sources of Capital,” will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, debt repayment and share repurchases.
Significant Sources of Capital
Operating Activities
During 2016, cash of $2,963 million was provided by operating activities, a 48 percent decrease compared with 2015. The decrease was primarily attributable to lower realized refining margins, as well as a reduction in distributions from our equity affiliates. This decrease was partially offset by positive working capital of $501 million in 2016 compared to a negative working capital impact of $221 million in 2015. The positive working capital impact in 2016 was primarily driven by increased refining payables, due to an increase in feedstock costs at the end of 2016 as compared with 2015, and the timing of tax payments and refunds, partially offset by an increase in receivables, resulting from higher commodity prices. See the following paragraph for a discussion of 2015 working capital effects.
During 2015, cash of $5,713 million was provided by operating activities, a 62 percent increase from cash from operations of $3,529 million in 2014. Net income in 2015 was lower than 2014; however, in both years large noncash items affected earnings, including the gain on the PSPI exchange in 2014, recognition in 2015 and 2014 of a deferred gain from a 2013 asset disposition, and goodwill and other asset impairments by DCP Midstream in 2015. Excluding these items, underlying earnings in 2015 were slightly improved compared with 2014, primarily reflecting increased refining margins and increased domestic marketing volumes, partially offset by lower midstream prices. Negative working capital impacted operating cash flow by $221 million and $1,020 million in 2015 and 2014, respectively. The lower negative working capital impact in 2015 was driven by decreased refining payables due to lower feedstock costs in 2015 as compared with 2014, partially offset by a reduction in receivables due to reduced commodity prices.
Our short- and long-term operating cash flows are highly dependent upon refining and marketing margins, NGL prices and chemicals margins. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have little or no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level and quality of output from our refineries also impacts our cash flows. Factors such as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions can affect output. We actively manage the operations of our refineries, and any variability in their operations typically has not been as significant to cash flows as that caused by margins and prices. Our worldwide refining crude oil capacity utilization was 96 percent in 2016, compared with 91 percent in 2015.
Equity Affiliates
Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including DCP Midstream, CPChem and WRB. Over the three years ended December 31, 2016, we received distributions of $237 million from DCP Midstream, $2,241 million from CPChem and $1,568 million from WRB. We cannot control the amount or timing of future distributions from equity affiliates; therefore, future distributions by these and other equity affiliates are not assured.
Effective January 1, 2017, DCP Midstream, LLC and DCP Partners closed a transaction in which DCP Midstream, LLC contributed subsidiaries owning all of its operating assets, $424 million of cash and $3.15 billion of debt to DCP Partners, in exchange for DCP Partners units which had an estimated fair value of $1.125 billion at the time of the transaction. We and our co-venturer retained our 50/50 investment in DCP Midstream, LLC, and DCP Midstream, LLC retained its incentive distribution rights in DCP Partners through its ownership of the general partner of DCP Partners. After the transaction, DCP Midstream, LLC held a 38 percent interest in DCP Partners. DCP Midstream, LLC, through its ownership of the general partner, has agreed, if required, to forgo receipt of incentive distribution rights up to $100 million annually (100 percent basis) through 2019, to support a minimum distribution coverage ratio for DCP Partners. In connection with the transaction, DCP Midstream, LLC terminated its revolving credit agreement, which had previously served to limit distributions to its owners while amounts had been borrowed under the facility. As a result, we expect distributions to the owners of DCP Midstream, LLC to resume in 2017 as it receives distributions from DCP Partners.
In 2015, CPChem made a special distribution to its owners, with our share totaling $696 million. CPChem funded the distribution by issuing $1.4 billion of senior notes with maturities ranging from three to five years, with a combination of fixed and variable interest rates. This cash inflow from CPChem was included in operating cash flows, as we had cumulative undistributed equity earnings attributable to CPChem in excess of the amount distributed. CPChem’s U.S. Gulf Coast project is expected to be completed and begin commercial operations during 2017. As a result, we expect distributions from CPChem to increase starting in 2017, as capital spending by CPChem on this project ends.
WRB is a 50-percent-owned business venture with Cenovus Energy Inc. (Cenovus). Cenovus was obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007. In 2014, Cenovus prepaid its remaining balance under this obligation. As a result, WRB declared a special dividend, which was distributed to the co-venturers in 2014. Of the $1,232 million that we received, $760 million was considered a return on our investment in WRB (an operating cash inflow), and $472 million was considered a return of our investment in WRB (an investing cash inflow). The return-of-investment portion of the dividend was included in the “Proceeds from asset dispositions” line in our consolidated statement of cash flows. A further $129 million of distributions from WRB during 2014 was considered a return of investment.
Asset Sales
Net proceeds from asset sales in 2016 were $156 million compared with $70 million in 2015 and $1,244 million in 2014. The 2016 net proceeds were primarily attributed to the sale of the Whitegate Refinery in Ireland. The 2015 net proceeds were attributed to the sale of the Bantry Bay terminal in Ireland and the sale of certain retail sites in Kansas and Missouri, and were partially offset by a working capital true-up related to the 2014 sale of our interest in the Malaysia Refining Company Sdn. Bdh. (MRC). The 2014 proceeds included a portion of the WRB special dividend as discussed above, as well as the sale of our interest in MRC.
Foreign Cash Holdings
At December 31, 2016, approximately 53 percent of our consolidated cash and cash equivalents balance was available to fund domestic opportunities without incurring material U.S. income taxes in excess of the amounts already accrued in the financial statements. We believe the remaining amount, primarily attributable to cash we hold in foreign locations where we have asserted our intention to indefinitely reinvest earnings, does not materially affect our consolidated liquidity due to the following factors:
| • | A substantial portion of our foreign cash supports the liquidity needs and regulatory requirements of our foreign operations. |
| • | We have the ability to fund a significant portion of our domestic capital requirements with cash provided by domestic operating activities. |
| • | We have access to U.S. capital markets through our $5 billion committed revolving credit facility, commercial paper program, and universal shelf registration statement. |
See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information on income taxes associated with foreign earnings.
Phillips 66 Partners LP
In 2013 we formed Phillips 66 Partners LP, a publicly traded master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product, and NGL pipelines and terminals, as well as other Midstream assets.
Ownership
At December 31, 2016, we owned a 59 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while its public unitholders owned a 39 percent limited partner interest. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements, for additional information on why we consolidate the partnership. As a result of this consolidation, the public unitholders’ ownership interest in Phillips 66 Partners is reflected as a $1,306 million noncontrolling interest in our consolidated balance sheet at December 31, 2016. Generally, drop down transactions to Phillips 66 Partners will eliminate in consolidation, except for third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. Through the public offerings of common units and senior notes discussed below, our consolidated cash increased by $2.1 billion, consolidated debt increased by $1.1 billion and consolidated equity increased by $791 million.
Debt and Equity Financings
During the three years ended December 31, 2016, Phillips 66 Partners closed on the following public securities offerings in which it raised net proceeds of approximately $3.6 billion:
| • | In October 2016, Phillips 66 Partners received net proceeds of $1,111 million from the issuance of $500 million of 3.55% Senior Notes due 2026 and $625 million of 4.90% Senior Notes due 2046. |
| • | In August 2016, Phillips 66 Partners received net proceeds of $299 million from a public offering of 6 million common units, at a price of $50.22 per unit. |
| • | In June 2016, Phillips 66 Partners began issuing common units under a continuous offering program, which allows for the offering of up to $250 million of common units. Through December 31, 2016, net proceeds of $19 million had been received under this program. |
| • | In May 2016, Phillips 66 Partners received net proceeds of $656 million from a public offering of 12.65 million common units, at a price of $52.40 per unit. |
| • | 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 5.25 million common units, at a price of $75.50 per unit. |
Phillips 66 Partners primarily used these net proceeds to fund the cash portion of acquisitions of assets from Phillips 66. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on Phillips 66 Partners and additional details on assets contributed to the partnership by us during 2016.
Credit Facilities and Commercial Paper
In October 2016, we amended our Phillips 66 revolving credit facility, primarily to extend the term from December 2019 to October 2021. Borrowing capacity under the Phillips 66 facility remained at $5 billion. The facility may be used for direct bank borrowings, as support for issuances of letters of credit, or as support for our commercial paper program. The facility is with a broad syndicate of financial institutions and contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control. Borrowings under the facility will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor’s Ratings Services (S&P) and Moody’s Investors Service (Moody’s). The facility also provides for customary fees, including administrative agent fees and commitment fees. As of December 31, 2016, no amount had been directly drawn under our $5 billion credit facility; however, $51 million in letters of credit had been issued that were supported by this facility.
We have a $5 billion commercial paper program for short-term working capital needs that is supported by our revolving credit facility. Commercial paper maturities are generally limited to 90 days. As of December 31, 2016, we had no borrowings under our commercial paper program.
Phillips 66 Partners also amended its revolving credit facility in October 2016, primarily to increase its borrowing capacity to $750 million and to extend the term from November 2019 to October 2021. The Phillips 66 Partners facility is with a broad syndicate of financial institutions. As of December 31, 2016, $210 million was outstanding under the partnership’s facility.
Debt Financing
Our $7.5 billion of outstanding Senior Notes issued by Phillips 66 are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Our senior unsecured long-term debt has been rated investment grade by S&P (BBB+) and Moody’s (A3). We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating deteriorated to a level prohibiting us from accessing the commercial paper market, we would expect to be able to access funds under our liquidity facilities mentioned above.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Other Financing
We have capital lease obligations related to equipment and transportation assets, and the use of an oil terminal in the United Kingdom. These leases mature within the next seventeen years. The present value of our minimum capital lease payments for these obligations as of December 31, 2016, was $188 million.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations, we enter into agreements with other parties to pursue business opportunities, with costs and risks apportioned among the parties as provided by the agreements. In April 2012, in connection with the Separation, we entered into an agreement to guarantee 100 percent of certain outstanding debt obligations of MSLP. At December 31, 2016, the aggregate principal amount of MSLP debt guaranteed by us was $123 million.
In June 2016, the operating lease commenced on our new headquarters facility in Houston, Texas, after construction was deemed substantially complete. Under the lease agreement, we have a residual value guarantee with a maximum future exposure of $554 million. The operating lease has a term of five years and provides us the option, at the end of the lease term, to request to renew the lease, purchase the facility, or assist the lessor in marketing it for resale.
We have residual value guarantees associated with railcar and airplane leases with maximum future potential payments of $363 million. For information on our need to perform under the railcar lease guarantee, see the Capital Requirements section to follow, as well as Note 14—Guarantees, in the Notes to Consolidated Financial Statements. Also see Note 14 for additional information on our guarantees.
Capital Requirements
For information about our capital expenditures and investments, see “Capital Spending” below.
Our debt balance at December 31, 2016, was $10.1 billion and our debt-to-capital ratio was 30 percent. Our target debt-to-capital ratio is between 20 and 30 percent.
On February 8, 2017, our Board of Directors declared a quarterly cash dividend of $0.63 per common share, payable March 1, 2017, to holders of record at the close of business on February 21, 2017.
Our Board of Directors at various times has authorized repurchases of our outstanding common stock which aggregate to a total authorization of up to $9 billion. The share repurchases are expected to be funded primarily through available cash. The shares will be repurchased from time to time in the open market at our discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Since the inception of our share repurchases in 2012 through December 31, 2016, we have repurchased a total of 105,404,649 shares at a cost of $7.4 billion. Shares of stock repurchased are held as treasury shares.
We own a 25 percent interest in the Dakota Access, LLC (DAPL) and Energy Transfer Crude Oil Company, LLC (ETCOP) joint ventures, which have been constructing pipelines to deliver crude oil produced in the Bakken area of North Dakota to market centers in the Midwest and the Gulf Coast. In May 2016, we and our co-venturer executed agreements under which we and our co-venturer would loan DAPL and ETCOP up to a maximum of $2,256 million and $227 million, respectively, with the amounts loaned by us and our co-venturer being proportionate to our ownership interests (Sponsor Loans). In August 2016, DAPL and ETCOP secured a $2.5 billion facility (Facility) with a syndicate of financial institutions on a limited recourse basis with certain guaranties, and the outstanding Sponsor Loans were repaid. Allowable draws under the Facility were initially reduced and finally suspended in September 2016 pending resolution of permitting delays. As a result, DAPL and ETCOP resumed making draws under the Sponsor Loans. The maximum amounts that could be loaned under the Sponsor Loans were reduced on September 22, 2016, to $1,411 million for DAPL and $76 million for ETCOP. As of December 31, 2016, DAPL and ETCOP had $976 million and $22 million, respectively, outstanding under the Sponsor Loans. Our 25 percent share of those loans was $244 million and $6 million, respectively. DAPL was granted the lone outstanding easement to complete work beneath the Missouri River on February 8, 2017. As a result, construction of its pipeline resumed and draws under the Facility were reinitiated to repay the outstanding Sponsor Loans and to continue funding of construction. The DAPL pipeline is expected to be completed and operational by mid-2017. The book values of our investments in DAPL and ETCOP at December 31, 2016, were $403 million and $129 million, respectively.
In the first quarter of 2016, we and our co-venturer in WRB each made a $75 million partner loan to provide for WRB’s operating needs.
On May 1, 2015, the U.S. Department of Transportation issued a final rule focused on the safe transportation of flammable liquids by rail. The final rule, which is being challenged, subjects new and existing railcars transporting crude oil in high volumes to heightened design standards, including thicker tank walls and heat shields, improved pressure relief valves and enhanced braking systems. We are currently evaluating the impact of the new regulations on our crude oil railcar fleet, which is mostly held under operating leases. The regulations become effective subsequent to the expiration dates of our leases. Although we have no direct contractual obligation to retrofit these leased railcars, certain leases are subject to residual value guarantees. Under the lease terms, we have the option either to purchase the railcars
or to return them to the lessors. If railcars are returned to the lessors, we may be required to make the lessors whole under the residual value guarantees, which are subject to a cap. The current market demand for crude oil railcars is low, which has resulted in a decline in crude oil railcar prices. At year-end 2016, based on an outside appraisal of the railcars’ fair value at the end of their lease terms, we estimated a total residual value deficiency of $94 million that would be payable at the end of the lease terms, with approximately one-half due in late 2017 and the other half due in 2019. Due to current market uncertainties, changes in the estimated fair values of railcars could occur, which could increase or decrease our currently estimated residual value deficiency. As of December 31, 2016, our maximum future exposure under the residual value guarantees was approximately $320 million. See Note 14—Guarantees, in the Notes to Consolidated Financial Statements, for information on charges recorded in 2016 associated with the residual value deficiencies and related cease-use costs for railcars permanently taken out of service.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2016:
| Millions of Dollars | |||||||||||||||
| Payments Due by Period | |||||||||||||||
| Total | Up to 1 Year | Years 2-3 | Years 4-5 | After 5 Years | |||||||||||
| Debt obligations (a) | $ | 10,054 | 531 | 548 | 1,049 | 7,926 | |||||||||
| Capital lease obligations | 188 | 19 | 26 | 18 | 125 | ||||||||||
| Total debt | 10,242 | 550 | 574 | 1,067 | 8,051 | ||||||||||
| Interest on debt | 7,360 | 413 | 780 | 762 | 5,405 | ||||||||||
| Operating lease obligations | 1,556 | 404 | 638 | 285 | 229 | ||||||||||
| Purchase obligations (b) | 162,423 | 115,657 | 11,718 | 9,253 | 25,795 | ||||||||||
| Other long-term liabilities (c) | |||||||||||||||
| Asset retirement obligations | 244 | 8 | 13 | 13 | 210 | ||||||||||
| Accrued environmental costs | 496 | 77 | 131 | 62 | 226 | ||||||||||
| Unrecognized tax benefits (d) | 7 | 7 | (d) | (d) | (d) | ||||||||||
| Total | $ | 182,328 | 117,116 | 13,854 | 11,442 | 39,916 |
| (a) | For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements. |
| (b) | Represents any agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms. We expect these purchase obligations will be fulfilled by operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $123,715 million. In addition, $18,438 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 83 years, and $4,732 million from Excel Paralubes, for base oil over the remaining contractual term of 8 years. |
Purchase obligations of $5,435 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and product terminals, to transport, process, treat, and store products. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned facilities where we are the operator.
| (c) | Excludes pensions. For the 2017 through 2021 time period, we expect to contribute an average of $110 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $33 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $130 million for 2017 and then approximately $105 million per year for the remaining four years. Our minimum funding in 2017 is expected to be $55 million in the United States and $35 million outside the United States. |
| (d) | Excludes unrecognized tax benefits of $35 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential refunds. Also excludes interest and penalties of $12 million. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity. |
Capital Spending
| Millions of Dollars | ||||||||||||
| 2017 Budget | 2016 | 2015 | 2014 | |||||||||
| Capital Expenditures and Investments | ||||||||||||
| Midstream | $ | 1,549 | 1,453 | 4,457 | 2,173 | |||||||
| Chemicals | — | — | — | — | ||||||||
| Refining | 905 | 1,149 | 1,069 | 1,038 | ||||||||
| Marketing and Specialties | 132 | 98 | 122 | 439 | ||||||||
| Corporate and Other | 112 | 144 | 116 | 123 | ||||||||
| Total consolidated from continuing operations | $ | 2,698 | 2,844 | 5,764 | 3,773 | |||||||
| Selected Equity Affiliates* | ||||||||||||
| DCP Midstream | $ | 243 | 99 | 438 | 776 | |||||||
| CPChem | 675 | 987 | 1,319 | 886 | ||||||||
| WRB | 135 | 164 | 175 | 140 | ||||||||
| $ | 1,053 | 1,250 | 1,932 | 1,802 |
*Our share of capital spending.
Midstream
Capital spending in our Midstream segment during the three-year period ended December 31, 2016, included:
| • | Construction activities related to the Sweeny Fractionator and Freeport LPG Export Terminal projects. |
| • | Pipeline projects being developed by two of our joint ventures, DAPL and ETCOP. We own a 25 percent interest in each of these joint ventures. |
| • | Acquisition of and projects to increase 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. |
| • | Construction of rail racks to accept advantaged crude deliveries at our Bayway and Ferndale refineries. |
| • | Formation of the STACK JV. |
| • | Spending associated with return, reliability and maintenance projects in our Transportation and NGL businesses. |
During the three-year period ended December 31, 2016, DCP Midstream’s capital expenditures and investments were $2.6 billion on a 100 percent basis. In 2015, we contributed $1.5 billion of cash to DCP Midstream, LLC and our co-venturer contributed its interests in certain operating assets of equal value, that are held as equity investments. Upon completion of this transaction, our interest in DCP Midstream, LLC remained at 50 percent.
In 2015, Rockies Express Pipeline LLC (REX) repaid $450 million of its debt, reducing its long-term debt to approximately $2.6 billion. REX funded the repayment through member cash contributions. Our 25 percent share was approximately $112 million, which we contributed to REX in 2015.
Chemicals
During the three-year period ended December 31, 2016, CPChem had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer. During this period, on a 100 percent basis, CPChem’s capital expenditures and investments were $6.4 billion. In addition, CPChem’s advances to equity affiliates, primarily used for project construction and start-up activities, were $206 million and its repayments received from equity affiliates were $81 million.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2016, was $3.3 billion, primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to increase accessibility of advantaged crudes and improve product yields, improvements to the operating integrity of key processing units, and safety-related projects.
Key projects completed during the three-year period included:
| • | Installation of facilities to reduce nitrous oxide emissions from the fluid catalytic cracker at the Alliance Refinery. |
| • | 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 and Lake Charles refineries. |
| • | Installation of facilities to improve processing of advantaged crudes at the Alliance and Ponca City refineries. |
| • | Installation of facilities to comply with U.S. Environmental Protection Agency (EPA) Tier 3 gasoline regulations at the Alliance and Lake Charles refineries. |
| • | 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 Sweeny and Bayway refineries. |
| • | Installation of facilities to improve processing of advantaged crudes at the Billings Refinery. |
| • | Installation of facilities to improve clean product yield at the Bayway and Ponca City refineries. |
Generally, our equity affiliates in the Refining segment are intended to have self-funding capital programs. During this three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $958 million. We expect WRB’s 2017 capital program to be self-funding.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2016, was primarily for the acquisition of, and investments in, a limited number of retail sites in the Western and Midwestern portions of the United States, which have subsequently been disposed of; the acquisition of Spectrum Corporation, a private label specialty lubricants business headquartered in Memphis, Tennessee; the acquisition of the remaining interest that we did not already own in an entity that operates a power and steam generation plant; reliability and maintenance projects; and projects targeted at developing our new international sites.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2016, was primarily for projects related to information technology and facilities.
2017 Budget
Our 2017 capital budget is $2.7 billion including Phillips 66 Partners’ capital budget of $0.4 billion. This excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $1.1 billion, all of which is expected to be self-funded.
The Midstream capital budget of $1.5 billion is focused on development around its existing infrastructure’s footprint, including continued expansion of the Beaumont Terminal and investment in pipelines and other terminals. Refining’s capital budget of $0.9 billion is directed toward reliability, safety and environmental projects, as well as projects designed to improve clean product yields and lower feedstock costs. In M&S, we plan to invest approximately $0.1 billion to expand and enhance our fuel marketing business. In Corporate and Other, we plan to fund approximately $0.1 billion in projects primarily related to information technology and facilities.
Contingencies
A number of lawsuits involving a variety of claims that arose in the ordinary course of business have been filed against us or are subject to indemnifications provided by us. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for financial recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other potentially responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Legal and Tax Matters
Our legal and tax matters are handled by our legal and tax organizations. These organizations apply their knowledge, experience and professional judgment to the specific characteristics of our cases and uncertain tax positions. We employ a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases and enables the tracking of those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. In the case of income-tax-related contingencies, we monitor tax legislation and court decisions, the status of tax audits and the statute of limitations within which a taxing authority can assert a liability. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.
Environmental
Like other companies in our industry, we are subject to numerous international, federal, state and local environmental laws and regulations. Among the most significant of these international and federal environmental laws and regulations are the:
| • | 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. For example, in California the South Coast Air Quality Management District approved amendments to the Regional Clean Air Incentives Market (RECLAIM) that became effective in 2016, which require a phased reduction of nitrogen oxide emissions through 2022 and potentially affect refineries in the Los Angeles metropolitan area. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of developing infrastructure and marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
An example of this in the fuels area is the Energy Policy Act of 2005, which imposed obligations to provide increasing volumes of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence and Security Act of 2007 (EISA). EISA requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels and stipulates a mix of various types to be included through 2022. We have met the increasingly stringent requirements to date while establishing implementation, operating and capital strategies, along with advanced technology development, to address projected future requirements. It is uncertain how various future requirements contained in EISA, and the regulations promulgated thereunder, may be implemented and what their full impact may be on our operations. For the 2017 compliance year, the U.S. Environmental Protection Agency (EPA) has set volumes of advanced and total renewable fuel at higher levels than mandated in previous years; it is uncertain if these increased obligations will be achievable by fuel producers and shippers without drawing on the Renewable Identification Number (RIN) bank. For compliance years after 2017, we do not know whether the EPA will utilize its authority to reduce statutory volumes. Additionally, we may experience a decrease in demand for refined petroleum products due to the regulatory program as currently promulgated. This program continues to be the subject of possible Congressional review and re-promulgation in revised form, and the EPA’s regulations pertaining to the 2014, 2015, and 2016 compliance years are subject to legal challenge, further creating uncertainty regarding renewable fuel volume requirements and obligations.
The EPA’s Renewable Fuel Standard (RFS) program was also implemented in accordance with the Energy Policy Act of 2005 and EISA. The RFS program sets annual quotas for the percentage of biofuels (such as ethanol) that must be blended into motor fuels consumed in the United States. A RIN represents a serial number assigned to each gallon of biofuel produced or imported into the United States. As a producer of petroleum-based motor fuels, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program. The market for RINs has been the subject of fraudulent third-party activity, and it is reasonably possible that some RINs that we have purchased may be determined to be invalid. Should that occur, we could incur costs to replace those fraudulent RINs. Although the
cost for replacing any fraudulently marketed RINs is not reasonably estimable at this time, we would not expect to incur the full financial impact of fraudulent RINs replacement costs in any single interim or annual period, and would not expect such costs to have a material impact on our results of operations or financial condition.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous previously and currently owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater.
At RCRA-permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2015, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 36 sites within the United States. During 2016, there was one new site for which we received notification of potential liability, three sites were resolved but not closed, and three sites were deemed resolved and closed, leaving 31 unresolved sites with potential liability at December 31, 2016.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites for which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval of a remediation plan. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.
Expensed environmental costs were $648 million in 2016 and are expected to be a similar amount in 2017 and in 2018. Capitalized environmental costs were $224 million in 2016 and are expected to be approximately $170 million and $220 million, in 2017 and 2018, respectively. This amount does not include capital expenditures made for another purpose that have an indirect benefit on environmental compliance.
Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where our generated waste was disposed. We also have accrued for a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Remediation activities vary substantially in duration and cost from site to site,
depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect on our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) emissions reduction, including various regulations proposed or issued by the EPA. These proposed or promulgated laws apply or could apply in states and/or countries where we have interests or may have interests in the future. Laws regulating GHG emissions continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws potentially could have a material impact on our results of operations and financial condition as a result of increasing costs of compliance, lengthening project implementation and agency review items, or reducing demand for certain hydrocarbon products. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
| • | 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 the recently enacted SB32, which requires further reduction of California's GHG emissions to 40 percent below the 1990 emission level by 2030). Other GHG emissions programs in the western U.S. states have been enacted or are under consideration or development, including amendments to California's Low Carbon Fuel Standard, Oregon's Low Carbon Fuel Standard, and Washington's carbon reduction programs. |
| • | 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 the United States, some additional form of regulation is likely to be forthcoming in the future at the federal or state levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws
and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.
Compliance with changes in laws and regulations that create a GHG emission trading program, GHG reduction requirements or carbon taxes could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources.
An example of one such program is California’s cap and trade program, which was promulgated pursuant to the State’s Global Warming Solutions Act. The program had been limited to certain stationary sources, which include our refineries in California, but beginning in January 2015 expanded to include emissions from transportation fuels distributed in California. Inclusion of transportation fuels in California’s cap and trade program as currently promulgated has increased our cap and trade program compliance costs. The ultimate impact on our financial performance, either positive or negative, from this and similar programs, will depend on a number of factors, including, but not limited to:
| • | 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 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 such emissions. GHG emissions, legal requirements regulating such emissions, and the possible physical effects of climate change on our coastal assets are incorporated into our planning, investment, and risk management decision-making.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussion of critical accounting estimates, along with the discussion of contingencies in this report, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected. If the sum of the undiscounted pre-tax cash flows of an asset group is less than the carrying value, including applicable liabilities, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets (for example, at a refinery complex level). Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined using one or more of the following methods: the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of similar assets, adjusted using principal market participant assumptions when necessary. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future volumes, commodity prices, operating costs, margins, discount rates and capital project decisions, considering all available information at the date of review.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment when there are indicators of a loss in value, such as a lack of sustained earnings capacity or a current fair value less than the investment’s carrying amount. When it is determined that an indicated impairment is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value.
When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that allows for recovery. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants and a market analysis of comparable assets, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.
Asset Retirement Obligations
Under various contracts, permits and regulations, we have legal obligations to remove tangible equipment and restore the land at the end of operations at certain operational sites. Our largest asset removal obligations involve asbestos abatement at refineries. Estimating the timing and amount of payments for future asset removal costs is difficult. Most of these removal obligations are many years, or decades, in the future, and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
Environmental Costs
In addition to asset retirement obligations discussed above, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries, underground storage sites and non-operated sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, timing and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
Intangible Assets and Goodwill
At December 31, 2016, we had $764 million of intangible assets that we have determined to have indefinite useful lives, and are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have finite useful lives, amortization will commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to annual impairment tests that require management’s judgment of the estimated fair value of these intangible assets.
At December 31, 2016, we had $3.3 billion of goodwill recorded in conjunction with past business combinations. Goodwill is not amortized. Instead, goodwill is subject to at least annual reviews for impairment at a reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment.
Because quoted market prices for our reporting units are not available, management applies judgment in determining the estimated fair values of the reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make this fair value determination, including observed market earnings multiples of comparable companies, our common stock price and associated total company market capitalization. Sales or dispositions of significant assets within a reporting unit are allocated a portion of that reporting unit’s goodwill, based on relative fair values, which impacts the amount of gain or loss on the sale or disposition.
We completed our annual impairment test, as of October 1, 2016, and concluded that the fair value of each of our reporting units exceeded their respective recorded net book values (including goodwill), by over 25 percent for our Refining reporting unit and by over 100 percent for our Transportation and M&S reporting units. A decline in the estimated fair value of one or more of our reporting units in the future could result in an impairment. For example, a prolonged or significant decline in our stock price or a significant decline in actual or forecasted earnings could provide evidence of a significant decline in fair value and a need to record a material impairment of goodwill for one or more of our reporting units. After we have completed our annual test, we continue to monitor for impairment indicators, which can lead to further goodwill impairment testing.
Tax Assets and Liabilities
Our operations are subject to various taxes, including federal, state and foreign income taxes, property taxes, and transactional taxes such as excise, sales/use and payroll taxes. We record tax liabilities based on our assessment of existing tax laws and regulations. The recording of tax liabilities requires significant judgment and estimates. We recognize the financial statement effects of an income tax position when it is more likely than not that the position will be sustained upon examination by a taxing authority. A contingent liability related to a transactional tax claim is recorded if the loss is both probable and estimable. Actual incurred tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.
In determining our income tax provision, we assess the likelihood our deferred tax assets will be recovered through future taxable income. Valuation allowances reduce deferred tax assets to an amount that will, more likely than not, be realized. Judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against our deferred tax assets. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, we expect the net deferred tax assets will more likely than not be realized as offsets to reversing deferred tax liabilities and as reductions to future taxable income. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised.
New tax laws and regulations, as well as changes to existing tax laws and regulations, are continuously being proposed or promulgated. The implementation of future legislative and regulatory tax initiatives could result in increased tax liabilities that cannot be predicted at this time.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans impacts the obligations on the balance sheet and the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future interest rates, future health care cost-trend rates, and rates of utilization of health care services by
retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A one percentage-point decrease in the discount rate assumption would increase annual benefit expense by an estimated $60 million, while a one percentage-point decrease in the return on plan assets assumption would increase annual benefit expense by an estimated $30 million. In determining the discount rate, we use yields on high-quality fixed income investments with payments matched to the estimated distributions of benefits from our plans.
In 2016 and 2015, we used expected long-term rates of return of 6.75 percent and 7 percent, respectively, for the U.S. pension plan assets, which account for 74 percent of our overall pension plan assets. The actual U.S. pension plan asset returns were a gain of 7 percent in 2016 and a loss of less than 1 percent in 2015. For the past ten years, actual returns averaged 6 percent for the U.S. pension plan assets.
NEW ACCOUNTING STANDARDS
In January 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-04, “Intangibles—Goodwill and Other—Simplifying the Test for Goodwill Impairment,” which eliminates Step 2 from the goodwill impairment test. Under the revised test, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Public business entities should apply the guidance in ASU No. 2017-04 for its annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2017-04.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations: Clarifying the Definition of a Business,” which clarifies the definition of a business with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The amendment provides a screen for determining when a transaction involves the acquisition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then the transaction does not involve the acquisition of a business. If the screen is not met, then the amendment requires that to be considered a business, the operation must include at a minimum an input and a substantive process that together significantly contribute to the ability to create an output. The guidance may reduce the number of transactions accounted for as business acquisitions. Public business entities should apply the guidance in ASU No. 2017-01 to annual periods beginning after December 15, 2017, including interim periods within those periods, with early adoption permitted. The amendments should be applied prospectively, and no disclosures are required at the effective date. We are currently evaluating the provisions of ASU No. 2017-01.
In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash,” which clarifies the classification and presentation of changes in restricted cash. The amendment requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. Public business entities should apply the guidance in ASU No. 2016-18 on a retrospective basis for annual periods beginning after December 15, 2017, including interim periods within those annual periods, with early adoption permitted. We do not expect the adoption of this ASU to have a material impact on our financial statements.
In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which clarifies the treatment of several cash flow categories. In addition, ASU No. 2016-15 clarifies that when cash receipts and cash payments have aspects of more than one class of cash flows and cannot be separated, classification will depend on the predominant source or use. Public business entities should apply
the guidance in ASU No. 2016-15 on a retrospective basis for annual periods beginning after December 15, 2017, including interim periods within those annual periods, with early adoption permitted. We are currently evaluating the provisions of ASU No. 2016-15 and assessing the impact on our financial statements.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The new standard amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. Public business entities should apply the guidance in ASU No. 2016-13 for annual periods beginning after December 15, 2019, including interim periods within those annual periods. Early adoption will be permitted for annual periods beginning after December 15, 2018. We are currently evaluating the provisions of ASU No. 2016-13 and assessing the impact on our financial statements.
In March 2016, the FASB issued ASU No. 2016-09, “Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment award transactions including accounting for income taxes and classification of excess tax benefits on the statement of cash flows, forfeitures and minimum statutory tax withholding requirements. Public business entities should apply the guidance in ASU No. 2016-09 for annual periods beginning after December 15, 2016, including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the provisions of ASU No. 2016-09 and assessing the impact on our financial statements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” In the new standard, the FASB modified its determination of whether a contract is a lease rather than whether a lease is a capital or operating lease under the previous accounting principles generally accepted in the United States (GAAP). A contract represents a lease if a transfer of control occurs over an identified property, plant and equipment for a period of time in exchange for consideration. Control over the use of the identified asset includes the right to obtain substantially all of the economic benefits from the use of the asset and the right to direct its use. The FASB continued to maintain two classifications of leases — financing and operating — which are substantially similar to capital and operating leases in the previous lease guidance. Under the new standard, recognition of assets and liabilities arising from operating leases will require recognition on the balance sheet. The effect of all leases in the statement of comprehensive income and the statement of cash flows will be largely unchanged. Lessor accounting will also be largely unchanged. Additional disclosures will be required for financing and operating leases for both lessors and lessees. Public business entities should apply the guidance in ASU No. 2016-02 for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the provisions of ASU No. 2016-02 and assessing its impact on our financial statements.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” to meet its objective of providing more decision-useful information about financial instruments. The majority of this ASU’s provisions amend only the presentation or disclosures of financial instruments; however, one provision will also affect net income. Equity investments carried under the cost method or lower of cost or fair value method of accounting, in accordance with current GAAP, will have to be carried at fair value upon adoption of ASU No. 2016-01, with changes in fair value recorded in net income. For equity investments that do not have readily determinable fair values, a company may elect to carry such investments at cost less impairments, if any, adjusted up or down for price changes in similar financial instruments issued by the investee, when and if observed. Public business entities should apply the guidance in ASU No. 2016-01 for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption prohibited. We are currently evaluating the provisions of ASU No. 2016-01. Our initial review indicates that ASU No. 2016-01 will have a limited impact on our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under GAAP and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets and expand disclosure requirements. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendment in this ASU defers the effective date of ASU No. 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier adoption is permitted only as of annual reporting
periods beginning after December 31, 2016, including interim reporting periods within that reporting period. Retrospective or modified retrospective application of the accounting standard is required. ASU No. 2014-09 was further amended in March 2016 by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASU No. 2016-20, “Technical Corrections to Topic 606, Revenue from Contracts with Customers.” As part of our assessment work-to-date, we have formed an implementation work team, completed training on the new ASU’s revenue recognition model and are continuing our contract review and documentation. Our expectation is to adopt the standard on January 1, 2018, using the modified retrospective application. In addition, we expect to present revenue net of sales-based taxes collected from our customers resulting in no impact to earnings. Sales-based taxes include excise taxes on petroleum product sales as noted on our consolidated statement of income. Our evaluation of the new ASU is ongoing, which includes understanding the impact of adoption on earnings from equity method investments. Based upon our analysis to-date, we have not identified any other material impact on our financial statements other than disclosures.
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