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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, 2015, we had total assets of $48.6 billion.
Executive Overview
We reported earnings of $4.2 billion in 2015 and generated $5.7 billion in cash from operating activities. Phillips 66 Partners LP issued $1.1 billion of debt and $384 million of its common units to the public. We used available cash primarily to fund capital expenditures and investments of $5.8 billion, pay dividends of $1.2 billion, repurchase $1.5 billion of our common stock, and repay $800 million of senior notes that came due in 2015. We ended 2015 with $3.1 billion of cash and cash equivalents and approximately $4.9 billion of total capacity under our available liquidity facilities.
Our financial performance in 2015 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. 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 these costs using various methodologies that are reported to senior management. 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 2015, our worldwide refining crude oil capacity utilization rate was 91 percent. |
| • | Growth. We have budgeted $3.9 billion in capital expenditures and investments in 2016, including $0.3 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 2016 capital program is expected to be $5.3 billion. This program is designed primarily to grow our Midstream and Chemicals segments, which have planned expansions for manufacturing and logistics capacity. The need for additional new gathering and processing, pipeline, storage and distribution infrastructure–driven by domestic unconventional crude oil, natural gas liquids (NGL) and natural gas production–is creating capital investment opportunities in our Midstream business. Over the next few years, CPChem plans significant |
reinvestment of its earnings to build additional manufacturing capacity benefiting from cost-advantaged NGL feedstocks. We continue to focus on funding the most attractive growth opportunities across our portfolio.
In 2013, we formed Phillips 66 Partners, a master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other transportation and midstream assets. Phillips 66 Partners provides a cost-efficient vehicle to fund Midstream growth.
| • | 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 2015, 93 percent of the company's U.S. crude slate was advantaged. |
| • | Distributions. We believe shareholder value is enhanced through, among other things, consistent and ongoing growth of regular dividends, supplemented by share repurchases. We increased our quarterly dividend rate by 12 percent during 2015, and have increased it 180 percent since our separation from ConocoPhillips in 2012 (the Separation). Regular dividends demonstrate the confidence our management has in our capital structure and operation’s capability to generate free cash flow throughout the business cycle. Through December 31, 2015, we have cumulatively repurchased $6.4 billion, or approximately 92.5 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. In October 2015, our Board of Directors increased our current share repurchase authorization by $2 billion resulting in a total authorization of $4 billion. Since July 2012, our Board of Directors has authorized repurchases of our outstanding common stock totaling up to $9 billion. |
| • | High-Performing Organization. We strive to attract, train, 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 of thought, and creating a great place to work. We foster an environment of learning and development through structured programs focused on enhancing functional and technical skills where employees are engaged in our business and committed to their own, as well as the company’s, success. |
Business Environment
The dramatic fall in commodity prices, which started during the second half of 2014, continued throughout 2015. The U.S. oil rig count declined over 60 percent and crude oil production declined well below its peak which was set during the second quarter of 2015. Additionally, the discount for U.S. benchmark West Texas Intermediate (WTI) vs. the international benchmark Brent narrowed over the course of 2015 as logistical constraints between oil producing areas and major refining centers were incrementally removed during the year. Falling commodity prices have had a variety of impacts, both favorable and unfavorable, on our downstream 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. NGL prices weakened throughout 2015 as NGL production growth from liquids-rich shale plays outpaced domestic demand growth from the petrochemical industry while export capacity remained constrained—driving prices lower and pushing inventories higher. Natural gas prices weakened throughout 2015 as well, as natural gas production growth continued and unseasonably warm weather limited demand.
During 2015, 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; however, the ethylene-to-polyethylene chain margins were compressed in 2015 because of the significant decline in crude oil prices that began in 2014.
Our Refining segment is 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 2015, the U.S. 3:2:1 crack spread (three barrels of crude oil producing two barrels of gasoline and one barrel of diesel) improved over 2014 across all quarters, largely attributable to strong gasoline crack spreads which were driven by robust demand growth both in the U.S. and globally. The diesel crack spread weakened throughout 2015, driven by growing product inventories as a result of high refinery utilization to capture robust gasoline cracks and an unseasonably warm fourth quarter. The U.S. West Coast crack spread increased year over year as a result of significant refinery planned/unplanned maintenance in the region.
European refineries benefited during 2015 as domestic and export gasoline demand expanded considerably. Northwest European crack spreads on average increased in the first three quarters of the year and declined in the fourth quarter resulting in an average increase in 2015 compared to 2014. Strong margins were driven by the strength in gasoline margins which offset subdued diesel cracks during much of the year as large volumes of imported diesel from the United States, India, Asia Pacific and Russia kept diesel margins under pressure throughout the second half of the year.
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 primarily determined 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 the company’s earnings follows:
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2015 | 2014 | 2013 | |||||||
| Midstream | $ | 13 | 507 | 469 | |||||
| Chemicals | 962 | 1,137 | 986 | ||||||
| Refining | 2,555 | 1,771 | 1,747 | ||||||
| Marketing and Specialties | 1,187 | 1,034 | 894 | ||||||
| Corporate and Other | (490 | ) | (393 | ) | (431 | ) | |||
| Income from continuing operations attributable to Phillips 66 | 4,227 | 4,056 | 3,665 | ||||||
| Discontinued Operations | — | 706 | 61 | ||||||
| Net income attributable to Phillips 66 | $ | 4,227 | 4,762 | 3,726 |
2015 vs. 2014
Our earnings from continuing operations increased $171 million, or 4 percent, in 2015, primarily resulting from:
| • | Improved realized refining margins as a result of increased gasoline crack spreads and improved secondary product margins. |
| • | Recognition of $242 million after-tax in 2015, compared with $126 million after-tax in 2014, of the deferred gain related to the sale in 2013 of the Immingham Combined Heat and Power Plant (ICHP). |
These increases were partially offset by:
| • | Lower equity earnings from DCP Midstream, primarily as a result of goodwill and other asset impairments and lower commodity prices. |
| • | Lower ethylene margins in our Chemicals segment. |
2014 vs. 2013
Our earnings from continuing operations increased $391 million, or 11 percent, in 2014, primarily resulting from:
| • | A gain on disposition and related deferred tax adjustment associated with the sale of Malaysian Refining Company Sdn. Bdh. (MRC), together totaling $369 million after-tax. |
| • | Improved ethylene and polyethylene margins in our Chemicals segment. |
| • | Improved worldwide marketing margins. |
| • | Recognition in 2014 of $126 million, after-tax, of the previously deferred gain related to the sale in 2013 of the ICHP. |
| • | Improved secondary products margins in our Refining segment. |
These increases were partially offset by:
| • | A $131 million after-tax impairment related to the Whitegate Refinery in Cork, Ireland. |
| • | Lower realized gasoline and distillate margins as a result of decreased market crack spreads and lower feedstock advantage. |
| • | Lower equity earnings from DCP Midstream, reflecting the sharp drop in NGL and crude oil prices in the second half of 2014. |
Discontinued operations in 2014 included the recognition of a noncash $696 million after-tax gain related to the Phillips Specialty Products Inc. (PSPI) share exchange.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
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 due to the significant downturn in commodity prices since mid-2014. |
| • | 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 its 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 were no significant impairments in 2015, compared with 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.
2014 vs. 2013
Sales and other operating revenues decreased 6 percent in 2014, while purchased crude oil and products decreased 8 percent. The decreases were primarily due to lower average prices for crude oil and petroleum products.
Equity in earnings of affiliates decreased 20 percent in 2014, primarily resulting from decreased earnings from WRB and DCP Midstream, partially offset by increased equity earnings from CPChem.
| • | Equity in earnings of WRB decreased 69 percent, mainly due to lower refining margins in the Central Corridor as a result of lower market crack spreads and a lower feedstock advantage, as well as lower interest income received from equity affiliates. |
| • | Equity in earnings of DCP Midstream decreased 36 percent, primarily due to a decrease in most commodity prices, as well as increased costs associated with planned asset growth. |
| • | Equity in earnings of CPChem increased 20 percent, primarily driven by improved ethylene and polyethylene realized margins related to increased sales prices. |
Net gain on dispositions in 2014 was $295 million, compared with $55 million in 2013, primarily resulting from net gains associated with the sale of our interest in MRC in the amount of $145 million, as well as the partial recognition of the previously deferred gain related to the sale of ICHP in the amount of $126 million. In 2013, net gain on dispositions primarily resulted from a $48 million gain on the sale of our E-GasTM Technology business. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.
Selling, general and administrative expenses increased 13 percent in 2014, primarily due to additional fees under marketing consignment fuels agreements, as well as costs associated with acquisitions.
Impairments in 2014 were $150 million, compared with $29 million in 2013. In 2014, we recorded a $131 million impairment of the Whitegate Refinery. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.
Income from discontinued operations increased $645 million in 2014, compared to 2013, due to the completion of the PSPI share exchange in 2014. See Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements, for additional information on this transaction.
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 | |||||||||
| 2015 | 2014 | 2013 | |||||||
| Millions of Dollars | |||||||||
| Net Income (Loss) Attributable to Phillips 66 | |||||||||
| Transportation | $ | 288 | 233 | 199 | |||||
| DCP Midstream | (324 | ) | 135 | 210 | |||||
| NGL | 49 | 139 | 60 | ||||||
| Total Midstream | $ | 13 | 507 | 469 | |||||
| Dollars Per Unit | |||||||||
| Weighted Average NGL Price* | |||||||||
| DCP Midstream (per gallon) | $ | 0.45 | 0.89 | 0.90 |
*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* | 3,264 | 3,206 | 3,144 | |||||
| Terminals | 1,981 | 1,683 | 1,274 | |||||
| Operating Statistics | ||||||||
| NGL extracted** | 410 | 454 | 426 | |||||
| NGL fractionated*** | 112 | 109 | 115 |
*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, 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 Midstream segment includes our master limited partnership, Phillips 66 Partners LP, as well as our 50 percent equity investment in DCP Midstream.
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 Midstream Partners, LP (DCP Partners), a master limited partnership formed by DCP Midstream, 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 Sweeny Fractionator One. These decreases were partially offset by higher earnings from equity affiliates.
See the “Business Environment and Executive Overview” section for information on market factors impacting this year’s results.
As previously disclosed, in early 2015 we and our co-venturer in DCP Midstream agreed to forgo cash distributions from DCP Midstream due to the significant decrease in commodity prices since mid-2014. The sustained weak commodity price environment during 2015 caused DCP Midstream to impair its goodwill in 2015 by $460 million, and impair certain assets and in-process capital projects in the fourth quarter of 2015 by an additional $342 million. To strengthen its balance sheet, during the fourth quarter of 2015 we contributed $1.5 billion of cash to DCP Midstream, while our co-venturer contributed its interests in certain operating assets held as equity investments. At December 31, 2015, the carrying value of our investment in DCP Midstream was approximately $2.3 billion. We will continue to monitor DCP Midstream’s operations and the continued weak commodity price environment for any further impacts on DCP Midstream or the carrying value of our investment.
2014 vs. 2013
Earnings from the Midstream segment increased $38 million in 2014, compared with 2013. The improvement was primarily driven by higher earnings from our Transportation and NGL businesses, partially offset by lower earnings from DCP Midstream.
Transportation earnings increased $34 million in 2014, compared with 2013. This increase primarily resulted from increased throughput fees, as well as higher earnings associated with railcar activity in 2014. These increases were partially offset by higher earnings attributable to noncontrolling interests, reflecting the contribution of previously wholly owned assets to Phillips 66 Partners.
The $75 million decrease in earnings of DCP Midstream in 2014 primarily resulted from a decrease in NGL and crude prices in the latter part of 2014. NGL and crude prices have continued to decline in the early part of 2015. In addition, earnings decreased as costs associated with asset growth and maintenance increased in 2014, compared with 2013. Earnings further declined due to DCP Midstream’s contribution of assets to DCP Partners. Following the contribution, a percentage of the earnings from these assets are attributable to public unitholders, thus decreasing income attributable to DCP Midstream and, thereby, Phillips 66. See the “Business Environment and Executive Overview” section for additional information on market factors impacting DCP Midstream’s results.
DCP Partners unit issuances benefited our equity in earnings from DCP Midstream, on an after-tax basis, by approximately $45 million in 2014, compared with approximately $62 million in 2013.
Earnings from the NGL business increased $79 million, compared with 2013. The increase was primarily due to improved margins driven by strong propane prices in early 2014. Additionally, 2014 earnings benefited from gains related to seasonal propane and butane storage activity. Also, earnings improved due to higher equity earnings from DCP Sand Hills, LLC (Sand Hills) and DCP Southern Hills, LLC (Southern Hills). These increases were partially offset by an increase in costs associated with growth projects.
Chemicals
| Year Ended December 31 | |||||||||
| 2015 | 2014 | 2013 | |||||||
| Millions of Dollars | |||||||||
| Net Income Attributable to Phillips 66 | $ | 962 | 1,137 | 986 | |||||
| Millions of Pounds | |||||||||
| CPChem Externally Marketed Sales Volumes* | |||||||||
| Olefins and Polyolefins | 16,916 | 16,815 | 16,071 | ||||||
| Specialties, Aromatics and Styrenics | 5,301 | 6,294 | 6,230 | ||||||
| 22,217 | 23,109 | 22,301 | |||||||
| *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 | % | 88 | 88 |
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.
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 the 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.
See the “Business Environment and Executive Overview” section for information on market factors impacting CPChem’s results.
2014 vs. 2013
Earnings from the Chemicals segment increased $151 million, or 15 percent, in 2014, compared with 2013. The increase in earnings was primarily driven by improved ethylene and polyethylene realized margins due to higher sales prices. Additionally, Chemicals benefited from higher equity earnings from CPChem’s O&P equity affiliates.
These increases were partially offset by lower ethylene and polyethylene sales volumes and increased costs related to the Port Arthur facility fire. In addition, impairments of $69 million after-tax in 2014 further offset a portion of the increase to earnings.
Refining
| Year Ended December 31 | |||||||||
| 2015 | 2014 | 2013 | |||||||
| Millions of Dollars | |||||||||
| Net Income Attributable to Phillips 66 | |||||||||
| Atlantic Basin/Europe | $ | 569 | 198 | 9 | |||||
| Gulf Coast | 551 | 252 | 113 | ||||||
| Central Corridor | 857 | 967 | 1,540 | ||||||
| Western/Pacific | 578 | 354 | 85 | ||||||
| Worldwide | $ | 2,555 | 1,771 | 1,747 | |||||
| Dollars Per Barrel | |||||||||
| Refining Margins | |||||||||
| Atlantic Basin/Europe | $ | 9.39 | 8.94 | 7.09 | |||||
| Gulf Coast | 9.29 | 7.64 | 6.49 | ||||||
| Central Corridor | 14.88 | 15.63 | 19.30 | ||||||
| Western/Pacific | 16.86 | 8.89 | 8.83 | ||||||
| Worldwide | 11.84 | 9.93 | 9.90 | ||||||
| Thousands of Barrels Daily | |||||||||
| Operating Statistics | |||||||||
| Refining operations* | |||||||||
| Atlantic Basin/Europe | |||||||||
| Crude oil capacity | 588 | 588 | 588 | ||||||
| Crude oil processed | 539 | 554 | 546 | ||||||
| Capacity utilization (percent) | 92 | % | 94 | 93 | |||||
| Refinery production | 587 | 605 | 578 | ||||||
| Gulf Coast | |||||||||
| Crude oil capacity | 738 | 733 | 733 | ||||||
| Crude oil processed | 654 | 676 | 651 | ||||||
| Capacity utilization (percent) | 89 | % | 92 | 89 | |||||
| Refinery production | 733 | 771 | 736 | ||||||
| Central Corridor | |||||||||
| Crude oil capacity | 492 | 485 | 477 | ||||||
| Crude oil processed | 465 | 475 | 472 | ||||||
| Capacity utilization (percent) | 95 | % | 98 | 99 | |||||
| Refinery production | 486 | 494 | 489 | ||||||
| Western/Pacific | |||||||||
| Crude oil capacity | 360 | 440 | 440 | ||||||
| Crude oil processed | 330 | 403 | 410 | ||||||
| Capacity utilization (percent) | 92 | % | 92 | 93 | |||||
| Refinery production | 359 | 435 | 445 | ||||||
| Worldwide | |||||||||
| Crude oil capacity | 2,178 | 2,246 | 2,238 | ||||||
| Crude oil processed | 1,988 | 2,108 | 2,079 | ||||||
| Capacity utilization (percent) | 91 | % | 94 | 93 | |||||
| Refinery production | 2,165 | 2,305 | 2,248 | ||||||
| *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 14 refineries, mainly in the United States and Europe.
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.
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 91 percent in 2015, compared to 94 percent in 2014. The decrease reflects higher unplanned downtime and turnaround activities.
Effective January 1, 2015, we aligned the results of the activities previously included in “Other Refining” into the Atlantic Basin/Europe, Gulf Coast, Central Corridor, and Western/Pacific refining regions. There were no changes to the consolidated Refining operating segment as a result of this alignment. The new alignment is presented for the year ended December 31, 2015, with the prior periods retrospectively adjusted for comparability.
2014 vs. 2013
Earnings for the Refining segment were $1,771 million in 2014, an increase of $24 million, or 1 percent, compared with 2013. The slight increase in earnings in 2014 was primarily due to higher realized refining margins related to secondary products, as well as increased volumes. In addition, earnings were impacted by a gain on disposition and a related deferred tax adjustment associated with the sale of MRC, together totaling $369 million after-tax.
These increases were mostly offset by:
| • | Lower earnings from decreased gasoline and distillate margins. |
| • | Negative impacts due to inventory draws in a declining price environment. |
| • | Impairment of the Whitegate Refinery of $131 million after-tax. |
| • | Lower interest income received from equity affiliates. |
Our worldwide refining crude oil capacity utilization rate was 94 percent in 2014, compared to 93 percent in 2013. The increase reflects lower unplanned downtime related to power outages that occurred in the Gulf Coast region in 2013.
Marketing and Specialties
| Year Ended December 31 | |||||||||
| 2015 | 2014 | 2013 | |||||||
| Millions of Dollars | |||||||||
| Net Income Attributable to Phillips 66 | |||||||||
| Marketing and Other | $ | 1,004 | 836 | 688 | |||||
| Specialties | 183 | 198 | 206 | ||||||
| Total Marketing and Specialties | $ | 1,187 | 1,034 | 894 | |||||
| Dollars Per Barrel | |||||||||
| Realized Marketing Fuel Margin* | |||||||||
| U.S. | $ | 1.65 | 1.51 | 1.21 | |||||
| International | 4.40 | 5.22 | 4.36 | ||||||
| *On third-party petroleum products sales. | |||||||||
| Dollars Per Gallon | |||||||||
| U.S. Average Wholesale Prices* | |||||||||
| Gasoline | $ | 1.92 | 2.72 | 2.88 | |||||
| Distillates | 1.77 | 2.95 | 3.10 | ||||||
| *Excludes excise taxes. | |||||||||
| Thousands of Barrels Daily | |||||||||
| Marketing Petroleum Products Sales | |||||||||
| Gasoline | 1,205 | 1,195 | 1,174 | ||||||
| Distillates | 953 | 979 | 967 | ||||||
| Other | 16 | 17 | 17 | ||||||
| 2,174 | 2,191 | 2,158 |
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.
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.
See the “Business Environment and Executive Overview” section for information on marketing fuel margins and other market factors impacting 2015 results.
2014 vs. 2013
Earnings from the M&S segment increased $140 million, or 16 percent, in 2014, compared with 2013. Both U.S. and international marketing margins benefited from the timing effect of falling gasoline prices experienced in the second half of 2014. U.S. marketing also benefited from a full year of consignment agreements entered into in 2013, while international marketing margins also benefited from foreign exchange gains in 2014.
In 2014, we recognized $126 million after-tax of the deferred gain related to the sale in 2013 of the ICHP, increasing earnings. These increases were partially offset by the lack of ICHP earnings in 2014, compared with earnings of $53 million in 2013.
Corporate and Other
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2015 | 2014 | 2013 | |||||||
| Net Loss Attributable to Phillips 66 | |||||||||
| Net interest expense | $ | (186 | ) | (160 | ) | (166 | ) | ||
| Corporate general and administrative expenses | (157 | ) | (156 | ) | (145 | ) | |||
| Technology | (60 | ) | (58 | ) | (50 | ) | |||
| Other | (87 | ) | (19 | ) | (70 | ) | |||
| Total Corporate and Other | $ | (490 | ) | (393 | ) | (431 | ) |
2015 vs. 2014
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. 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 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 increase in costs in 2015 was primarily due to foreign tax credit carryforwards that were utilized in 2014 and other tax adjustments made in 2015.
2014 vs. 2013
Net interest expense decreased $6 million in 2014, compared with 2013, primarily due to increased capitalized interest. This decrease in expense was partially offset due to an increase in average debt outstanding in 2014, reflecting the issuance of debt in late 2014. For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.
Corporate general and administrative expenses increased $11 million in 2014, compared with 2013. The increase was primarily due to increased employee benefit costs and charitable contributions.
The decrease in other costs was primarily due to increased utilization of foreign tax credit carryforwards. In addition, higher environmental costs negatively affected our 2013 results.
Discontinued Operations
| Millions of Dollars | |||||||||
| Year Ended December 31 | |||||||||
| 2015 | 2014 | 2013 | |||||||
| Net Income Attributable to Phillips 66 | |||||||||
| Discontinued operations | $ | — | 706 | 61 |
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 | ||||||||||
| 2015 | 2014 | 2013 | ||||||||
| Cash and cash equivalents | $ | 3,074 | 5,207 | 5,400 | ||||||
| Net cash provided by operating activities | 5,713 | 3,529 | 6,027 | |||||||
| Short-term debt | 44 | 842 | 24 | |||||||
| Total debt | 8,887 | 8,635 | 6,125 | |||||||
| Total equity | 23,938 | 22,037 | 22,392 | |||||||
| Percent of total debt to capital* | 27 | % | 28 | 21 | ||||||
| Percent of floating-rate debt to total debt | 1 | % | 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 2015, we generated $5.7 billion in cash from operations and received $1.1 billion from Phillips 66 Partners’ issuance of senior notes and $0.4 billion from the issuance of Phillips 66 Partners’ common units to the public. We used available cash primarily for capital expenditures and investments ($5.8 billion), including a contribution to DCP Midstream ($1.5 billion); debt repayments ($0.9 billion); repurchases of our common stock ($1.5 billion); and dividend payments on our common stock ($1.2 billion). During 2015, cash and cash equivalents decreased by $2.1 billion, to $3.1 billion.
In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs, asset sales and our ability to issue securities using our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to external sources of funds as described below under “Significant Sources of Capital,” will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, debt repayment and share repurchases.
Significant Sources of Capital
Operating Activities
During 2015, cash of $5,713 million was provided by operating activities, a 62 percent increase over 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. See the following paragraph for a discussion of 2014 working capital effects.
During 2014, cash of $3,529 million was provided by operating activities, a 41 percent decrease from cash from operations of $6,027 million in 2013. Although net income was higher in 2014 than in 2013, certain large noncash items benefitted 2014 earnings, including the gain on the PSPI exchange, gains from asset dispositions and the deferred tax effects of certain asset dispositions. Excluding these items, underlying earnings in 2014 were similar to 2013. However, working capital negatively impacted 2014 operating cash flow by $1,020 million, compared with a positive impact of $880 million in 2013. Working capital impacts in 2014 reflected the negative impact of lower commodity prices on accounts payable, with a lesser positive impact on accounts receivable as we generally carry higher payables on our
balance sheet than receivables. By comparison, accounts payable activity increased cash from operations by $360 million in 2013, reflecting both higher volumes and commodity prices, while lower refining margins, reflecting less favorable market conditions and tightening of crude differentials, negatively impacted 2013 working capital. Benefiting 2014 operating cash flow, compared with 2013, was the receipt of a special distribution from WRB, of which $760 million was considered an operating cash flow, partially offset by lower distributions from CPChem.
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 91 percent in 2015, compared with 94 percent in 2014. We expect 2016 utilization to be in the mid 90-percent range.
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, 2015, we received distributions of $452 million from DCP Midstream, $2,879 million from CPChem and $2,938 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. We and our co-venturer in DCP Midstream have agreed to forgo distributions from DCP Midstream during the current low-commodity price environment.
During the second quarter of 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.
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 2015 were $70 million, compared with $1,244 million in 2014 and $1,214 million in 2013. 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 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. The 2013 proceeds included the sale of a power plant in the United Kingdom, as well as our gasification technology.
Foreign Cash Holdings
At December 31, 2015, approximately 44 percent of our consolidated cash and cash equivalents balance was available to fund domestic opportunities without incurring material additional 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 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.
Income Taxes
As part of our normal tax administrative process, we made scheduled U.S. federal income tax payments in 2015 using the Internal Revenue Service (IRS) safe harbor method for estimated 2015 taxable income. We determined that a portion of those payments is refundable as an overpayment of estimated tax, primarily due to U.S. tax legislation enacted late in the year, and we filed a refund claim with the IRS in the first quarter of 2016. We expect this refund to benefit cash from operations in the first quarter of 2016 by approximately $590 million.
Phillips 66 Partners LP
Initial Public Offering
In 2013, we formed Phillips 66 Partners LP, a master limited partnership, to own, operate, develop and acquire primarily fee-based crude oil, refined petroleum product and NGL pipelines and terminals, as well as other transportation and midstream assets. On July 26, 2013, Phillips 66 Partners completed its initial public offering (IPO) of 18,888,750 common units at a price of $23.00 per unit. Phillips 66 Partners received $404 million in net proceeds from the sale of the units, after deducting underwriting discounts, commissions, structuring fees and offering expenses.
Contributions to Phillips 66 Partners LP
Effective March 1, 2014, we contributed to Phillips 66 Partners certain transportation, terminaling and storage assets for total consideration of $700 million. These assets consisted of the Gold Line products system and the Medford spheres, two recently constructed refinery-grade propylene storage spheres. Phillips 66 Partners financed the acquisition with cash on hand of $400 million (primarily reflecting its IPO proceeds), the issuance to us of 3,530,595 and 72,053 additional common and general partner units, respectively, valued at $140 million, and a five-year, $160 million note payable to a subsidiary of Phillips 66.
Effective December 1, 2014, we contributed to Phillips 66 Partners certain logistics assets for total consideration of $340 million. These assets consisted of two recently constructed crude oil rail-unloading facilities located at or adjacent to our Bayway and Ferndale refineries, and the Cross Channel Connector pipeline assets located near the partnership’s Pasadena terminal. Phillips 66 Partners financed the acquisition with the borrowing of $28 million under its revolving credit facility, the assumption of a five-year, $244 million note payable to a subsidiary of Phillips 66, and the issuance to Phillips 66 of 1,066,412 common and 21,764 general partner units valued at $68 million.
In addition to these two transactions, we made smaller contributions to Phillips 66 Partners of projects under development in the fourth quarter of 2014, for consideration in the aggregate of approximately $55 million.
Effective March 2, 2015, we contributed to Phillips 66 Partners our one-third equity interests in Sand Hills and Southern Hills, as well as our 19.5 percent equity interest in Explorer Pipeline Company (Explorer), for total consideration of $1,010 million. Each of these investments is accounted for under the equity method of accounting. Phillips 66 Partners financed the acquisition with $880 million in cash, partially funded by a public offering of common units representing limited partner interests and debt financing, and the issuance to us of 1,587,376 and 139,538 additional common units and general partner units, respectively, with an aggregate fair value of $130 million.
Effective December 1, 2015, we contributed to Phillips 66 Partners our 40 percent equity interest in Bayou Bridge Pipeline, LLC (Bayou Bridge) for total consideration of $70 million. This investment is accounted for under the equity method of accounting. Phillips 66 Partners financed one-half of the acquisition with a $35 million note payable to us and one-half with the issuance to us of 606,056 and 12,369 additional common units and general partner units, respectively,
having an aggregate fair value of $35 million. Phillips 66 Partners immediately repaid the note payable. See Note 13—Debt and Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information.
Ownership
At December 31, 2015, we owned a 69 percent limited partner interest and a 2 percent general partner interest in Phillips 66 Partners, while its public unitholders owned a 29 percent limited partner interest. We consolidate Phillips 66 Partners as a variable interest entity for financial reporting purposes. See Note 3—Variable Interest Entities (VIEs), 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 an $809 million noncontrolling interest in our financial statements at December 31, 2015. Generally, contributions of assets by us to Phillips 66 Partners will eliminate in consolidation, except for third-party debt or equity offerings made by Phillips 66 Partners to finance such transactions. For the first contribution in 2015 together with the public offerings of common units and senior notes discussed below, our consolidated cash increased by $1.5 billion, consolidated debt increased by $1.1 billion and consolidated equity increased by $384 million as a result of the transactions. The Bayou Bridge contribution in 2015 discussed above did not impact our consolidated financial statements. For the 2014 contributions discussed above, the first did not impact our consolidated financial statements, while the second increased consolidated cash and debt by $28 million at the time of the transaction.
Debt and Equity Financings
In February 2015, Phillips 66 Partners closed on a public offering of $1.1 billion aggregate principal amount of unsecured senior notes, consisting of:
| • | $300 million of 2.646% Senior Notes due 2020. |
| • | $500 million of 3.605% Senior Notes due 2025. |
| • | $300 million of 4.680% Senior Notes due 2045. |
Interest on each series of the senior notes is payable semi-annually in arrears.
In February 2015, Phillips 66 Partners completed a public offering of 5,250,000 common units representing limited partner interests. The net proceeds received at closing were $384 million.
Phillips 66 Partners used a portion of the net proceeds of both the debt and equity offerings to fund its March 2015 acquisition transaction described above. See Note 27—Phillips 66 Partners LP, in the Notes to Consolidated Financial Statements, for additional information on this acquisition.
Credit Facilities and Commercial Paper
Phillips 66 has a $5 billion revolving credit facility that extends until December 2019. 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, 2015, 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. As a result, we ended 2015 with $4.9 billion of capacity under this facility.
We have a $5 billion commercial paper program for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. As of December 31, 2015, we had no borrowings under our commercial paper program.
Phillips 66 Partners has a $500 million revolving credit facility that extends until November 2019. The Phillips 66 Partners facility is with a broad syndicate of financial institutions. As of December 31, 2015, no amounts were outstanding under the facility.
Debt Financing
Our $7.5 billion of outstanding Senior Notes were issued by Phillips 66 and 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 eighteen years. The present value of our minimum capital lease payments for these obligations as of December 31, 2015, was $208 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 Merey Sweeny, L.P. (MSLP). At December 31, 2015, the aggregate principal amount of MSLP debt guaranteed by us was $157 million.
For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated Financial Statements.
Capital Requirements
For information about our capital expenditures and investments, see “Capital Spending” below.
Our debt balance at December 31, 2015, was $8.9 billion and our debt-to-capital ratio was 27 percent. Excluding Phillips 66 Partners’ debt of $1.1 billion and its noncontrolling interest of $809 million, our adjusted debt-to-capital ratio at December 31, 2015, was 25 percent. Our target adjusted debt-to-capital ratio, excluding the impact of Phillips 66 Partners, is between 20 and 30 percent.
On February 3, 2016, our Board of Directors declared a quarterly cash dividend of $0.56 per common share, payable March 1, 2016, to holders of record at the close of business on February 16, 2016. We are forecasting a double-digit percentage increase in our quarterly dividend rate in 2016.
During the second half of 2013, we entered into a construction agency agreement and an operating lease agreement with a financial institution for the construction of our new headquarters facility in Houston, Texas. Under the construction agency agreement, we act as construction agent for the financial institution over a construction period of up to three years and eight months, during which time we request cash draws from the financial institution to fund construction costs. Through December 31, 2015, approximately $486 million had been drawn to fund construction costs, of which approximately $440 million is recourse to us should certain events of default occur. The operating lease becomes effective after construction is substantially complete and we are able to occupy the facility. 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 financial institution in marketing it for resale. We expect the lease to commence in the first half of 2016.
On October 9, 2015, our Board of Directors increased our current share repurchase authorization by $2 billion resulting in a total authorization of $4 billion. Since July 2012, our Board of Directors has authorized repurchases of our
outstanding common stock totaling 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, 2015, we have repurchased a total of 92,503,292 shares at a cost of $6.4 billion. Shares of stock repurchased are held as treasury shares.
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 significant decline in crude oil railcar prices. Due to current market uncertainties, it is not currently possible to reasonably estimate the future market value for railcars at the end of their lease terms.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2015:
| Millions of Dollars | |||||||||||||||
| Payments Due by Period | |||||||||||||||
| Total | Up to 1 Year | Years 2-3 | Years 4-5 | After 5 Years | |||||||||||
| Debt obligations (a) | $ | 8,679 | 28 | 1,565 | 352 | 6,734 | |||||||||
| Capital lease obligations | 208 | 16 | 31 | 22 | 139 | ||||||||||
| Total debt | 8,887 | 44 | 1,596 | 374 | 6,873 | ||||||||||
| Interest on debt | 6,735 | 394 | 714 | 678 | 4,949 | ||||||||||
| Operating lease obligations | 2,009 | 510 | 726 | 405 | 368 | ||||||||||
| Purchase obligations (b) | 62,691 | 23,502 | 8,497 | 5,530 | 25,162 | ||||||||||
| Other long-term liabilities (c) | |||||||||||||||
| Asset retirement obligations | 251 | 7 | 16 | 10 | 218 | ||||||||||
| Accrued environmental costs | 485 | 64 | 104 | 70 | 247 | ||||||||||
| Unrecognized tax benefits (d) | 13 | 13 | (d) | (d) | (d) | ||||||||||
| Total | $ | 81,071 | 24,534 | 11,653 | 7,067 | 37,817 |
| (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 $32,326 million. In addition, $16,807 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 84 years, and $4,409 million from Excel Paralubes, for base oil over the remaining contractual term of 9 years. |
Purchase obligations of $5,600 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 2016 through 2020 time period, we expect to contribute an average of $170 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $50 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 $50 million for 2016 and then approximately $200 million per year for the remaining four years. Our minimum funding in 2016 is expected to be $50 million in the United States and $50 million outside the United States. |
| (d) | Excludes unrecognized tax benefits of $69 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 $19 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 | ||||||||||||
| 2016 Budget | 2015 | 2014 | 2013 | |||||||||
| Capital Expenditures and Investments | ||||||||||||
| Midstream | $ | 2,346 | 4,457 | 2,173 | 597 | |||||||
| Chemicals | — | — | — | — | ||||||||
| Refining | 1,217 | 1,069 | 1,038 | 820 | ||||||||
| Marketing and Specialties | 137 | 122 | 439 | 226 | ||||||||
| Corporate and Other | 180 | 116 | 123 | 136 | ||||||||
| Total consolidated from continuing operations | $ | 3,880 | 5,764 | 3,773 | 1,779 | |||||||
| Discontinued operations | $ | — | — | — | 27 | |||||||
| Selected Equity Affiliates* | ||||||||||||
| DCP Midstream | $ | 223 | 438 | 776 | 971 | |||||||
| CPChem** | 1,016 | 1,319 | 886 | 613 | ||||||||
| WRB | 184 | 175 | 140 | 109 | ||||||||
| $ | 1,423 | 1,932 | 1,802 | 1,693 |
*Our share of capital spending.
**2014 amount restated.
Midstream
During the three-year period ended December 31, 2015, DCP Midstream’s capital expenditures and investments were $4.4 billion on a 100 percent basis. In 2013 and 2014, we made additional investments of $0.3 billion in both Sand Hills and Southern Hills, increasing our total direct investment to $0.8 billion. In October 2015, we contributed $1.5 billion of cash to DCP Midstream and our co-venturer contributed its interests in certain operating assets of equal value, that are held as equity investments. Upon completion of this transaction, our interest in DCP Midstream remained at 50 percent.
Other capital spending in our Midstream segment during the three-year period ended December 31, 2015, included:
| • | Construction activities related to our Sweeny Fractionator One and Freeport LPG Export Terminal projects. |
| • | Acquisition of a 7.1 million-barrel-storage-capacity crude oil and petroleum products terminal located near Beaumont, Texas. |
| • | Construction of rail racks to accept advantaged crude deliveries at our Bayway and Ferndale refineries. |
| • | Purchase of an additional 5.7 percent interest in the refined products Explorer pipeline. |
| • | Pipeline projects being developed by two of our joint ventures, Dakota Access LLC (DAPL) and Energy Transfer Crude Oil Company, LLC (ETCOP). We own a 25 percent interest in each of these joint ventures. |
| • | Spending associated with return, reliability and maintenance projects in our Transportation and NGL businesses. |
In April 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 April 2015.
Chemicals
During the three-year period ended December 31, 2015, 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 $5.6 billion. In addition, CPChem’s advances to equity affiliates, primarily used for project construction and start-up activities, were $0.3 billion and its repayments received from equity affiliates were $0.1 billion.
Refining
Capital spending for the Refining segment during the three-year period ended December 31, 2015, was $2.9 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 new coke drums at the Ponca City refinery. |
| • | 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 Sweeny and Lake Charles refineries. |
| • | Installation of facilities to improve processing of advantaged crudes at Alliance and Ponca City refineries. |
Major construction activities in progress include:
| • | Installation of a crude tank to increase accessibility of waterborne crude at the Los Angeles Refinery. |
| • | Installation of facilities to comply with U.S. Environmental Protection Agency (EPA) Tier 3 gasoline regulations at the Sweeny, Alliance, Bayway and Lake Charles refineries. |
| • | Installation of facilities to improve processing of advantaged crudes at Billings refinery. |
| • | Installation of facilities to improve clean product yield at 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 $0.9 billion. We expect WRB’s 2016 capital program to be self-funding.
Marketing and Specialties
Capital spending for the M&S segment during the three-year period ended December 31, 2015, 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 growing our international marketing business.
Corporate and Other
Capital spending for Corporate and Other during the three-year period ended December 31, 2015, was primarily for projects related to information technology and facilities.
2016 Budget
Our 2016 capital budget is $3.9 billion including Phillips 66 Partners’ capital budget of $0.3 billion. This excludes our portion of planned capital spending by joint ventures DCP Midstream, CPChem and WRB totaling $1.4 billion, all of which are expected to be self-funded.
The Midstream capital budget of $2.3 billion is focused on growth projects, such as continued construction of the 150,000 barrels-per-day Freeport LPG Export Terminal on the U.S. Gulf Coast, the new DAPL and ETCOP pipeline projects, expansion of the Beaumont Terminal, and the Bayou Bridge pipeline project.
Refining’s capital budget of $1.2 billion is directed toward reliability, safety and environmental projects, including compliance with the new Tier 3 gasoline specifications, as well as projects designed to improve product yields and lower feedstock costs.
In Marketing and Specialties, we plan to invest approximately $0.1 billion for growth and sustaining capital. The growth investment reflects our continued plans to expand and enhance our fuel marketing business.
In Corporate and Other, we plan to fund approximately $0.2 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
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:
| • | U.S. Federal Clean Air Act, which governs air emissions. |
| • | U.S. Federal Clean Water Act, which governs discharges to 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 Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells. |
| • | U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines as well as owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States. |
| • | European Union Trading Directive resulting in the European Union Emissions Trading Scheme (EU ETS), which uses a market-based mechanism to incentivize the reduction of greenhouse gas emissions. |
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of 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 2016 compliance year, the U.S. Environmental Protection Agency (EPA) will require greater volumes of advanced and total renewable fuel 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 2016, 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 recently enacted 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 activity, and we have identified that we have unknowingly purchased RINs in the past that were invalid due to fraudulent activity of third parties. Costs to replace fraudulently marketed RINs that have been determined to be invalid have not been material through December 31, 2015; however, it is reasonably possible that some additional RINs that we have previously purchased may also be determined to be invalid. Should that occur, we could incur additional replacement charges. Although the cost for replacing any additional fraudulently marketed RINs is not reasonably estimable at this time, we could have a possible exposure of approximately $150 million before tax. It could take several years for this possible exposure to reach ultimate resolution; therefore, we would not expect to incur the full financial impact of additional fraudulent RINs replacement costs in any single interim or annual period.
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 past and present 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, 2014, we reported that we had been notified of potential liability under CERCLA and comparable state laws at 34 sites within the United States. During 2015, we were notified of four new sites, settled and closed one site, and resolved one site, leaving 36 unresolved sites with potential liability at December 31, 2015.
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 $581 million in 2015 and are expected to be approximately $655 million in each of the years 2016 and 2017. Capitalized environmental costs were $330 million in 2015 and are expected to be approximately $235 million in each of the years 2016 and 2017. 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.
At December 31, 2015, our balance sheet included total accrued environmental costs of $485 million, compared with $496 million at December 31, 2014, and $492 million at December 31, 2013. We expect to incur a substantial amount of these expenditures within the next 30 years.
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. We consider and take into account future GHG emissions in designing and developing major facilities and projects, and implement energy efficiency initiatives to reduce such emissions. 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, if enacted, 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. Other GHG emissions programs in the western U.S. states have been enacted or are in the process of development, including amendments to California's Low Carbon Fuel Standard, Oregon's Low Carbon Fuel Standard, and Washington's cap and trade program. |
| • | 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 is currently open for agreement by countries until April 22, 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 or GHG reduction requirements 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. |
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 to be generated by an asset group. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, including applicable
liabilities, the carrying value of the long-lived assets included in the asset group 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 values of expected future cash flows using discount rates and other assumptions believed to be consistent with those used by principal market participants; a market multiple of earnings for similar assets; or historical market transactions of similar assets, adjusted using principal market participant assumptions when necessary. 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 reviewed 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, under the above or similar contracts, permits and regulations, 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, 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 responsible parties.
Intangible Assets and Goodwill
At December 31, 2015, we had $770 million of intangible assets determined to have indefinite useful lives, and thus they 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, 2015, 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 and the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets. 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, 2015, and concluded that the fair value of our reporting units exceeded their recorded net book values (including goodwill). The fair values of each of our Refining, Transportation and M&S reporting units exceeded their respective recorded net book values by over 100 percent. However, 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’ve 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 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 1 percentage-point decrease in the discount rate assumption would increase annual benefit expense by an estimated $60 million, while a 1 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 2015 and 2014, the company used an expected long-term rate of return of 7 percent for the U.S. pension plan assets, which account for 73 percent of the company’s pension plan assets. The actual asset returns were a loss of less than 1 percent in 2015 and a gain of 9 percent in 2014. For the past ten years, actual returns averaged 7 percent for the U.S. pension plan assets.
NEW ACCOUNTING STANDARDS
In January 2016, the FASB issued Accounting Standard Update (ASU) No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10),” 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 generally accepted accounting principles, will have to be carried at fair value upon adoption of ASU 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 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 2016-01 and assessing the impact, if any, it may have on our financial position and results of operations.
In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes - Balance Sheet Classification of Deferred Taxes.” The new update will simplify the presentation of deferred income taxes and will require deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The classification shall be made at the tax-paying component level of an entity, after reflecting any offset of deferred tax liabilities, deferred tax assets and any related valuation allowances. Public business entities should apply the guidance in ASU 2015-17 for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application for public entities is permitted. The amendments can be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We are currently evaluating the provisions of ASU 2015-17.
In June 2014, the FASB issued ASU 2014-10, “Development Stage Entities (Topic 915).” The new standard removes the definition of a development stage entity from the Master Glossary of Accounting Standard Codification and the related financial reporting requirements specific to development stage entities. This ASU is intended to reduce cost and complexity of financial reporting for entities that have not commenced planned principal operations. For financial reporting requirements other than the VIE guidance in ASC Topic 810, “Consolidation,” ASU 2014-10 was effective for annual and quarterly reporting periods of public entities beginning after December 15, 2014. For the financial reporting requirements related to VIEs in ASC Topic 810, “Consolidation,” ASU 2014-10 is effective for annual and quarterly reporting periods of public entities beginning after December 15, 2015. Early application for public entities is permitted. We are currently evaluating the provisions of ASU 2014-10. Our preliminary assessment indicates that additional disclosures related to VIEs may be required for our joint ventures if the planned principal operations have not commenced.
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 accounting principles generally accepted in the United States and International Financial Reporting Standards. This ASU is intended to improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets. In August 2015, the FASB issued ASU 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 2014-09 for all entities for one year. Public business entities should apply the guidance in ASU 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. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to-date, we have formed an implementation work team, completed training of the new ASU’s revenue recognition model and begun contract review and documentation.
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