10-K 1 psx_20121231-10k.htm 10-K PSX_2012.12.31-10K
2012

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
 
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
December 31, 2012
 
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from

to
 

Commission file number: 001-35349
Phillips 66
(Exact name of registrant as specified in its charter)
Delaware
 
45-3779385
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
3010 Briarpark Drive, Houston, Texas 77042
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-293-6600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange
on which registered
Common Stock, $.01 Par Value
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[x] Yes [ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
 [ ] Yes [x] No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
[x] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
  [x] Yes [  ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
 Large accelerated filer [x]
Accelerated filer [ ]
 Non-accelerated filer [ ]
 Smaller reporting company [ ]
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
 [ ] Yes [x] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 29, 2012, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of $33.24, was $20.8 billion. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and executive officers to be affiliates, and deducted their stockholdings in determining the aggregate market value.
The registrant had 621,509,611 shares of common stock outstanding at January 31, 2013.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013 (Part III)



TABLE OF CONTENTS
Item
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 



Unless otherwise indicated, “the company,” “we,” “our,” “us” and “Phillips 66” are used in this report to refer to the businesses of Phillips 66 and its consolidated subsidiaries. This Annual Report on Form 10-K contains forward-looking statements including, without limitation, statements relating to our 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 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,” beginning on page 52.


PART I

Items 1 and 2. BUSINESS AND PROPERTIES


CORPORATE STRUCTURE

Phillips 66, headquartered in Houston, Texas, was incorporated in Delaware on November 10, 2011, in connection with, and in anticipation of, a restructuring of ConocoPhillips. On April 4, 2012, the ConocoPhillips Board of Directors approved the separation of its downstream businesses into an independent, publicly traded company named Phillips 66. In accordance with the Separation and Distribution Agreement between ConocoPhillips and Phillips 66, the two companies were separated by ConocoPhillips distributing to its stockholders all 625,272,302 shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Each ConocoPhillips shareholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. A registration statement on Form 10, as amended through the time of its effectiveness, describing the Separation was filed by Phillips 66 with the U.S. Securities and Exchange Commission (SEC) and was declared effective on April 12, 2012 (the Form 10). On May 1, 2012, Phillips 66 stock began trading “regular-way” on the New York Stock Exchange under the “PSX” stock symbol.

We have organized our reporting structure based on the grouping of similar products and services, resulting in three operating segments:

1)
R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. This segment also includes power generation operations. The R&M segment's “refining” and “marketing, specialties and other” operations are disclosed separately for supplemental reporting purposes.
 
2)
Midstream—This segment gathers, processes, transports and markets natural gas; and transports, fractionates and markets natural gas liquids (NGL) in the United States. The Midstream segment includes our 50 percent equity investment in DCP Midstream, LLC (DCP Midstream).

3)
ChemicalsThis segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem).

At December 31, 2012, Phillips 66 had approximately 13,500 employees.



1


SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 26—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.


REFINING AND MARKETING (R&M)

At December 31, 2012, our R&M segment represented 77 percent of Phillips 66's total assets. Our R&M segment primarily refines crude oil and other feedstocks into petroleum products (such as gasolines, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. This segment also engages in power generation activities. R&M has operations in the United States, Europe and Asia.

2


Refining

The table below depicts information for each of our U.S. and international refineries at December 31, 2012:
 
 
 
 
 
 
 
Thousands of Barrels Daily
 
 
Region/Refinery
 
Location
 
Interest

 
Net Crude Throughput
Capacity
 
Net Clean Product
Capacity**
 
Clean
Product
Yield
Capability

At
December 31, 2012

 
Effective
January 1, 2013

Gasolines

 
Distillates

 
Atlantic Basin/Europe
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bayway
 
Linden, NJ
 
100.00
%
 
238

 
238

 
145

 
115

 
90
%
Humber
 
N. Lincolnshire, United Kingdom
 
100.00

 
221

 
221

 
85

 
115

 
81

Whitegate
 
Cork, Ireland
 
100.00

 
71

 
71

 
15

 
30

 
65

MiRO*
 
Karlsruhe, Germany
 
18.75

 
58

 
58

 
25

 
25

 
85

 
 
 
 
 
 
588

 
588

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alliance
 
Belle Chasse, LA
 
100.00

 
247

 
247

 
125

 
120

 
86

Lake Charles
 
Westlake, LA
 
100.00

 
239

 
239

 
90

 
115

 
70

Sweeny
 
Old Ocean, TX
 
100.00

 
247

 
247

 
125

 
120

 
87

 
 
 
 
 
 
733

 
733

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Central Corridor
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wood River
 
Roxana, IL
 
49.60

 
152

 
154

 
75

 
55

 
83

Borger
 
Borger, TX
 
49.60

 
72

 
72

 
50

 
25

 
89

Ponca City
 
Ponca City, OK
 
100.00

 
187

 
190

 
105

 
80

 
91

Billings
 
Billings, MT
 
100.00

 
58

 
59

 
35

 
25

 
89

 
 
 
 
 
 
469

 
475

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Western/Pacific
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ferndale
 
Ferndale, WA
 
100.00

 
100

 
101

 
55

 
30

 
75

Los Angeles
 
Carson/ Wilmington, CA
 
100.00

 
139

 
139

 
80

 
65

 
88

San Francisco
 
Arroyo Grande/San Francisco, CA
 
100.00

 
120

 
120

 
55

 
60

 
83

Melaka
 
Melaka, Malaysia
 
47.00

 
80

 
80

 
20

 
50

 
80

 
 
 
 
 
 
439

 
440

 
 
 
 
 
 
 
 
 
 
 
 
2,229

 
2,236

 
 
 
 
 
 
*Mineraloelraffinerie Oberrhein GmbH.
**Clean product capacities are maximum rates for each clean product category, independent of each other. They are not additive when calculating the clean product yield capability for each refinery.









3


Primary crude oil characteristics and sources of crude oil for our refineries are as follows:
 
 
Characteristics
 
Sources
 
Sweet
Medium
Sour
Heavy
Sour
High
TAN* 
 
United
States
Canada
South
America
Europe
& Central Asia
Middle East
& Africa
Bayway
l
 
 
 
 
 l
 
 
l
l
Humber
l
l
 
l
 
 
 
 
l
l
Whitegate
l
 
 
 
 
 
 
 
l
l
MiRO
l
l
 
 
 
 
 
 
l
l
Alliance
l
 
 
 
 
l
 
 
 
l
Lake Charles
l
l
l
l
 
l
 
l
 
 
Sweeny
l
 
l
l
 
l
 
l
 
l
Wood River
l
 
l
l
 
l
l
 
 
 
Borger
 
l
l
 
 
l
l
 
 
 
Ponca City
l
l
l
 
 
l
l
 
 
 
Billings
 
l
l
 
 
 
l
 
 
 
Ferndale
l
l
 
 
 
l
l
 
 
 
Los Angeles
 
l
l
l
 
l
l
l
 
l
San Francisco
l
l
l
l
 
l
 
 
 
l
Melaka
l
l
l
 
 
 
 
 
 
l
*High TAN (Total Acid Number): acid content greater than or equal to 1.0 milligram of potassium hydroxide (KOH) per gram.


Atlantic Basin/Europe Region

Bayway Refinery
The Bayway Refinery is located on the New York Harbor in Linden, New Jersey. Bayway refining units include a fluid catalytic cracking unit, two hydrodesulfurization units, a reformer, alkylation unit and other processing equipment. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, as well as petrochemical feedstocks, residual fuel oil and home heating oil. Refined products are distributed to East Coast customers by pipeline, barge, railcar and truck. The complex also includes a 775-million-pound-per-year polypropylene plant.

Humber Refinery
The Humber Refinery is located on the east coast of England in North Lincolnshire, United Kingdom. It produces a high percentage of transportation fuels, such as gasoline and diesel. Humber’s facilities encompass fluid catalytic cracking, thermal cracking and coking. The refinery has two coking units with associated calcining plants, which upgrade the heaviest part of the crude barrel and imported feedstocks into light oil products and high-value graphite and anode petroleum cokes. Humber is the only coking refinery in the United Kingdom and is one of the world’s largest producers of specialty graphite cokes and one of Europe’s largest anode coke producers. Approximately 50 percent of the light oils produced in the refinery are marketed in the United Kingdom, while the other products are exported to the rest of Europe and the United States.

Whitegate Refinery
The Whitegate Refinery is located in Cork, Ireland, and is Ireland’s only refinery. The refinery primarily produces transportation fuels, such as gasoline, diesel and fuel oil, which are distributed to the inland market, as well as being exported to Europe and the United States. We also operate a crude oil and products storage complex consisting of 7.5 million barrels of storage capacity and an offshore mooring buoy, located in Bantry Bay, about 80 miles southwest of the refinery in southern Cork County.

4


MiRO Refinery
The Mineraloelraffinerie Oberrhein GmbH (MiRO) Refinery, located on the Rhine River in Karlsruhe in southwest Germany, is a joint venture in which we own an 18.75 percent interest. Facilities include three crude unit trains, fluid catalytic cracking, petroleum coking and calcining, hydrodesulfurization units, reformers, isomerization and aromatics recovery units, ethyl tert-butyl ether (ETBE) and alkylation units. MiRO produces a high percentage of transportation fuels, such as gasoline and diesel. Other products include petrochemical feedstocks, home heating oil, bitumen, and anode- and fuel-grade petroleum coke. Refined products are delivered to customers in southwest Germany, northern Switzerland and western Austria by truck, railcar and barge.

Trainer Refinery
In June 2012, we sold the Trainer Refinery and associated terminal and pipeline assets.

Gulf Coast Region

Alliance Refinery
The Alliance Refinery is located on the Mississippi River in Belle Chasse, Louisiana. The single-train facility includes fluid catalytic cracking units, hydrodesulfurization units, a reformer and aromatics unit, and a delayed coking unit. Alliance produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks, home heating oil and anode petroleum coke. The majority of the refined products are distributed to customers in the southeastern and eastern United States through major common-carrier pipeline systems and by barge. Refined products are also sold into export markets through the refinery's marine terminal.

Lake Charles Refinery
The Lake Charles Refinery is located in Westlake, Louisiana. Its facilities include fluid catalytic cracking, hydrocracking, delayed coking and hydrodesulfurization units. The refinery produces a high percentage of transportation fuels, such as gasoline, off-road diesel and jet fuel, along with home heating oil. The majority of its refined products are distributed by truck, railcar, barge or major common-carrier pipelines to customers in the southeastern and eastern United States. Refined products can also be sold into export markets through the refinery’s marine terminal. Refinery facilities also include a specialty coker and calciner, which produce graphite petroleum coke for the steel industry.

Excel Paralubes
We own a 50 percent interest in Excel Paralubes, a joint venture which owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles Refinery. The facility produces approximately 20,000 barrels per day of high-quality, clear hydrocracked base oils.

Sweeny Refinery
The Sweeny Refinery is located in Old Ocean, Texas, approximately 65 miles southwest of Houston. Refinery facilities include fluid catalytic cracking, delayed coking, alkylation, a continuous regeneration reformer and hydrodesulfurization units. The refinery receives crude oil primarily via tankers, through wholly and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks and home heating oil. We operate nearby terminals and storage facilities, along with pipelines that connect these facilities to the refinery. Refined products are distributed throughout the Midwest and southeastern United States by pipeline, barge and railcar.

MSLP
Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by ConocoPhillips and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery triggered the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which was exercised on August 28, 2009. PDVSA has initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal held hearings on the merits of the dispute in December 2012, and we expect a final ruling in the fourth quarter of 2013. Following the Separation, Phillips 66 generally indemnifies ConocoPhillips for liabilities, if any, arising out of the exercise of the call right or otherwise with respect to the joint venture or the refinery.

5


Central Corridor Region

WRB Refining LP (WRB)
We are the operator and managing partner of WRB, which consists of the Wood River and Borger refineries.

Prior to the Separation, ConocoPhillips had two 50/50 North American business ventures with Cenovus Energy Inc. (Cenovus): a Canadian upstream general partnership, FCCL Partnership (FCCL), and a downstream U.S. limited partnership, WRB Refining LP. In accordance with the Separation and Distribution Agreement, ConocoPhillips retained its 50 percent interest in FCCL and a 0.4 percent interest in WRB, while contributing its remaining 49.6 percent interest in WRB to us in the Separation. We expect to purchase ConocoPhillips' 0.4 percent interest in WRB during 2013.

WRB’s gross processing capability of heavy Canadian or similar crudes ranges between 235,000 and 255,000 barrels per day after the completion of the coker and refining expansion (CORE) project at the Wood River Refinery, which occurred in late 2011.
 
Wood River Refinery
The Wood River Refinery is located in Roxana, Illinois, about 15 miles northeast of St. Louis, Missouri, at the convergence of the Mississippi and Missouri rivers. Operations include three distilling units, two fluid catalytic cracking units, hydrocracking, coking, reforming, hydrotreating and sulfur recovery. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks, asphalt and coke. Finished product leaves Wood River by pipeline, rail, barge and truck. The CORE Project resulted in a 5 percent increase in clean product yield and doubled gross heavy crude oil capacity to between 200,000 and 220,000 barrels per day, dependent on the quality of available heavy crudes.
 
Borger Refinery
The Borger Refinery is located in Borger, Texas, in the Texas Panhandle, approximately 50 miles north of Amarillo. The refinery facilities encompass coking, fluid catalytic cracking, hydrodesulfurization and naphtha reforming, and a 45,000-barrel-per-day NGL fractionation facility. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, as well as coke, NGL and solvents. Refined products are transported via pipelines from the refinery to West Texas, New Mexico, Colorado and the Midcontinent region.

In connection with the Separation, we entered into a put agreement and a feedstock right of first offer agreement with Cenovus. Under the put agreement, if Cenovus suffers a transportation constraint it cannot mitigate which threatens to shut in FCCL production, we will be required to purchase FCCL-produced crude oil from Cenovus, subject to a maximum daily volume amount and provided we have pipeline capacity available after meeting any other contractual obligations, at a price equal to the lower of fair market value or the “break even value” of such crude oil compared to other crude oils that could be processed at one of our refineries. Under the feedstock right of first offer agreement, if we plan to enter into a six-month or longer term agreement to acquire Canadian crude oil for the Wood River Refinery or the Borger Refinery, we will be required to first notify Cenovus and offer Cenovus the opportunity to supply FCCL-produced crude oil according to the specified terms.

Ponca City Refinery
The Ponca City Refinery is located in Ponca City, Oklahoma. Its facilities include fluid catalytic cracking, delayed coking and hydrodesulfurization units. It produces a full range of products, including gasoline, diesel, jet fuel, liquefied petroleum gas (LPG) and anode-grade petroleum coke. Finished petroleum products are primarily shipped by company-owned and common carrier pipelines to markets throughout the Midcontinent region.

Billings Refinery
The Billings Refinery is located in Billings, Montana. Its facilities include fluid catalytic cracking and hydrodesulfurization units, in addition to a delayed coker, which converts heavy, high-sulfur residue into higher-value light oils. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and aviation fuels, as well as fuel-grade petroleum coke. Finished petroleum products from the refinery are delivered by pipeline, railcar and truck. The pipelines transport most of the refined products to markets in Montana, Wyoming, Utah and Washington State.








6


Western/Pacific Region

Ferndale Refinery
The Ferndale Refinery is located on Puget Sound in Ferndale, Washington, approximately 20 miles south of the U.S.-Canada border. Facilities include a fluid catalytic cracker, an alkylation unit, a diesel hydrotreater and an S-ZorbTM unit. The refinery produces transportation fuels such as gasoline and diesel. Other products include residual fuel oil, which supplies the northwest marine transportation market. Most refined products are distributed by pipeline and barge to major markets in the northwest United States.

Los Angeles Refinery
The Los Angeles Refinery consists of two linked facilities located about five miles apart in Carson and Wilmington, California, approximately 15 miles southeast of Los Angeles International Airport. Carson serves as the front end of the refinery by processing crude oil, and Wilmington serves as the back end by upgrading the intermediate products to finished products. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include fuel-grade petroleum coke. The refinery produces California Air Resources Board (CARB)-grade gasoline by blending ethanol to meet government-mandated oxygenate requirements. Refined products are distributed to customers in California, Nevada and Arizona by pipeline and truck.

San Francisco Refinery
The San Francisco Refinery consists of two facilities linked by a 200-mile pipeline. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, California, while the Rodeo facility is in the San Francisco Bay Area. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading into finished petroleum products. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petroleum coke. It also produces CARB-grade gasoline by blending ethanol to meet government-mandated oxygenate requirements. The majority of the refined products are distributed by pipeline, railcar and barge to customers in California.

Melaka Refinery
The Melaka Refinery in Melaka, Malaysia, is a joint venture refinery in which we own a 47 percent interest. Melaka produces a full range of refined petroleum products and capitalizes on coking technology to upgrade low-cost feedstocks into higher-margin products. Our share of refined products is transported by tanker and marketed in Malaysia and other Asian markets.


Marketing

Marketing—United States
In the United States, as of December 31, 2012, we marketed gasoline, diesel and aviation fuel through approximately 8,500 marketer-owned or -supplied outlets in 49 states. The majority of these sites utilize the Phillips 66, Conoco or 76 brands.

At December 31, 2012, our wholesale operations utilized a network of marketers operating approximately 7,100 outlets. We have placed a strong emphasis on the wholesale channel of trade because of its lower capital requirements. In addition, we held brand-licensing agreements with approximately 500 sites. Our refined products are marketed on both a branded and unbranded basis. A high percentage of our branded marketing sales are made in the Midcontinent, Rockies and West Coast regions, where our wholesale marketing operations provide efficient off-take from our refineries. The Gulf Coast and East Coast regions do not require a highly integrated marketing and distribution infrastructure to secure product placement for refinery pull-through. In these markets, most sales are conducted via unbranded sales. We are expanding our export capability at our U.S. coastal refineries to meet growing international demand and increase flexibility to provide product to the highest-value markets.

In addition to automotive gasoline and diesel, we produce and market jet fuel and aviation gasoline, which is used by smaller piston-engine aircraft. At December 31, 2012, aviation gasoline and jet fuel were sold through dealers and independent marketers at approximately 900 Phillips 66-branded locations in the United States.

Lubricants
We manufacture and sell automotive, commercial and industrial lubricants which are marketed worldwide under the Phillips 66, Conoco, 76 and Kendall brands, as well as other private label brands. We also manufacture Group II and import Group III base oils and market both globally under the respective brand names Pure Performance and Ultra-S.



7


Premium Coke & Polypropylene
We manufacture and market high-quality graphite and anode-grade petroleum cokes in the United States and Europe for use in the global steel and aluminum industries. We also manufacture and market polypropylene to North America under the COPYLENE brand name.

Marketing—International
We have marketing operations in five European countries. Our European marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a low-cost, high-volume approach. We use the JET brand name to market retail and wholesale products in Austria, Germany and the United Kingdom. In addition, a joint venture in which we have an equity interest markets products in Switzerland under the Coop brand name.

We also market aviation fuels, LPG, heating oils, transportation fuels, marine bunker fuels, bitumen and fuel coke specialty products to commercial customers and into the bulk or spot market in the above countries and Ireland.

As of December 31, 2012, we had approximately 1,425 marketing outlets in our European operations, of which approximately 915 were company owned and 310 were dealer owned. We also held brand-licensing agreements with approximately 200 sites. In addition, through our joint venture operations in Switzerland, we have interests in 250 additional sites.


Transportation

We own or lease various assets to provide environmentally safe, strategic and timely delivery of crude oil, refined products, natural gas and NGL. These assets include pipeline systems; petroleum product, crude oil and LPG terminals; a petroleum coke handling facility; a fleet of marine vessels; and a fleet of railcars.

Pipelines and Terminals
At December 31, 2012, our Transportation organization managed over 18,000 miles of crude oil, natural gas, NGL and petroleum products pipeline systems in the United States, including those partially owned or operated by affiliates and approximately 3,200 miles reported in our Midstream segment for the Rockies Express, Sand Hills and Southern Hills pipeline systems. We owned or operated 39 finished product terminals, 37 storage locations, 5 LPG terminals, 10 crude oil terminals and 1 petroleum coke exporting facility.

In June 2012, we sold the Trainer Refinery with associated terminal and pipeline assets, and in November 2012, we sold the Riverhead Terminal.


8


The following table depicts our ownership interest in major R&M pipeline systems as of December 31, 2012:
 
Name
 
Origination/Terminus
 
Interest
 
Size
 
Miles
 
Capacity
MBD
Crude
 
 
 
 
 
 
 
 
 
 
 
Coast and Valley System
 
Central CA/Bay Area, CA
 
100
%
  
 
8”-12”
 
702

 
307

Clifton Ridge
 
Clifton Ridge, LA/Westlake, LA
 
100

  
 
20”
 
10

 
270

Cushing (CushPo)
 
Cushing, OK/Ponca City, OK
 
100

  
 
18”
 
62

 
130

WA Line
 
Odessa, TX/Borger, TX
 
100

  
 
12”, 14”
 
300

 
118

Oklahoma Mainline/CPL
 
Wichita Falls, TX/Ponca City, OK
 
100

  
 
12”
 
217

 
100

Line O
 
Cushing, OK/Borger, TX
 
100

  
 
10”
 
276

 
37

Line 80 (Gaines Borger)
 
Gaines, TX/Borger, TX
 
100

  
 
8”, 12”
 
237

 
33

Glacier
 
Cut Bank, MT/Billings, MT
 
79

  
 
8”-12”
 
865

 
100

 
 
 
 
 
 
 
 
 
 
 
 
Petroleum Product
 
 
 
 
 
 
 
 
 
 
 
Sweeny to Pasadena
 
Sweeny, TX/Pasadena, TX
 
100

  
 
12”, 18”
 
120

 
264

Gold Line
 
Borger, TX/St. Louis, IL
 
100

  
 
8”-16”
 
681

 
120

Standish
 
Marland Junction, OK/Wichita, KS
 
100

  
 
18”
 
100

 
80

Borger to Amarillo
 
Borger, TX/Amarillo, TX
 
100

  
 
8”, 10”
 
93

 
76

Wood River
 
Ponca City, OK/Mt. Vernon, MO
 
100

  
 
10”, 12”
 
250

 
45

Okla. City/Cherokee 8”
 
Ponca City, OK/Okla. City, OK
 
100

  
 
8”
 
215

 
46

Wichita/Ark City 1&2
 
Ponca City, OK/Wichita, KS
 
100

  
 
8”, 10”
 
105

 
55

Seminoe
 
Billings, MT/Sinclair, WY
 
100

  
 
6”-10”
 
342

 
33

Borger-Denver
 
McKee, TX/Denver, CO
 
70

  
 
6”-12”
 
405

 
38

Pioneer
 
Sinclair, WY/Salt Lake City, UT
 
50

  
 
8”, 12”
 
562

 
63

ATA Line
 
Amarillo, TX/Albuquerque, NM
 
50

  
 
6”, 10”
 
293

 
20

Heartland
 
McPherson, KS/Des Moines, IA
 
50

  
 
8”, 6”
 
49

 
30

Yellowstone
 
Billings, MT/Spokane, WA
 
46

  
 
6”-10”
 
710

 
66

Harbor
 
Woodbury, NJ/Linden, NJ
 
33

  
 
16”
 
80

 
104

SAAL
 
Amarillo, TX/Amarillo and
Lubbock, TX
 
33

  
 
6”
 
121

 
18

Explorer
 
Texas Gulf Coast/Chicago, IL
 
14

  
 
24”, 28”
 
1,835

 
500

 
 
 
 
 
 
 
 
 
 
 
 
NGL
 
 
 
 
 
 
 
 
 
 
 
Line EZ
 
Rankin, TX/Sweeny, TX
 
100

 
10”
 
434

 
101

Blue Line
 
Borger, TX/St. Louis, IL
 
100

  
 
8”-12”
 
666

 
29

Powder River
 
Douglas, WY/Borger, TX
 
100

  
 
6”-8”
 
695

 
19

Chisholm
 
Kingfisher, OK/Conway, KS
 
50

  
 
8”-10”
 
202

 
42

Skelly-Belvieu
 
Skellytown, TX/Mont Belvieu, TX
 
50

  
 
8”
 
571

 
29

 
 
 
 
 
 
 
 
 
 
 
 
LPG
 
 
 
 
 
 
 
 
 
 
 
Medford PBC
 
Ponca City, OK/Medford, OK
 
100

  
 
4”-12”
 
42

 
60

Conway to Wichita
 
Conway, KS/Wichita, KS
 
100

  
 
12”
 
55

 
38

*100% interest held by CPChem. Operated by Phillips 66.





9


Tankers
At December 31, 2012, we utilized 12 double-hulled crude oil tankers that we chartered, with capacities ranging in size from 713,000 to 2,100,000 barrels. These tankers are primarily used to transport feedstocks to certain of our refineries. Additionally, in 2012, we entered into time charters on two Jones Act tankers to deliver shale crude to our Gulf Coast and East Coast refineries.
 
Truck and Rail
Truck and rail operations support our U.S. refinery and specialty operations. Rail movements are provided via a diverse fleet of more than 8,500 owned and leased railcars. In October 2012, we entered into an operating lease covering 2,000 new railcars under construction. We took delivery of the first 50 railcars in February 2013, and the remaining railcars are expected to be delivered in batches throughout 2013 and early 2014. This is an expansion of our existing rail business and will encompass delivery of advantaged crude to our refineries on the East and West Coasts. Truck movements are provided through approximately 150 third-party truck companies, as well as through Sentinel Transportation LLC, in which we hold an equity interest.


Specialty Businesses

We manufacture and sell a variety of specialty products including pipeline flow improvers and anode material for high-power lithium-ion batteries. Our specialty products are marketed under the LiquidPower and CPreme brand names.


Other

Immingham Combined Heat and Power Plant
The Immingham Combined Heat and Power Plant is a wholly owned 1,180-megawatt facility in the United Kingdom, which provides steam and electricity to the Humber Refinery and steam to a neighboring refinery, as well as merchant power into the U.K. market. The plant is capable of generating up to approximately 2.0 million pounds per hour of process steam.

Sweeny Cogeneration
We own a 50 percent operating interest in Sweeny Cogeneration, L.P., a joint venture which owns a simple-cycle cogeneration power plant located adjacent to the Sweeny Refinery. The plant generates electricity and provides process steam to the refinery, as well as merchant power into the Texas market. The plant has a net electrical output of 440 megawatts and is capable of generating up to 3.6 million pounds per hour of process steam.


MIDSTREAM

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract NGL from the raw gas stream. The remaining residue gas is marketed to electric utilities, industrial users and gas marketing companies. Most of the NGL is fractionated—separated into individual components such as ethane, propane and butane—and marketed as chemical feedstock, fuel or blendstock. Total NGL extracted in 2012, including our share of equity affiliates, was 201,000 barrels per day, compared with 192,000 barrels per day in 2011. The Midstream segment also includes an interstate natural gas transmission line.

DCP Midstream
Our Midstream segment includes our 50 percent equity investment in DCP Midstream, which is headquartered in Denver, Colorado. As of December 31, 2012, DCP Midstream owned or operated 62 natural gas processing facilities, with a net processing capacity of approximately 7.1 billion cubic feet per day. Its natural gas pipeline systems included gathering services for these facilities, as well as natural gas transmission, and totaled approximately 63,000 miles of pipeline. DCP Midstream also owned or operated 12 NGL fractionation plants, along with natural gas and NGL storage facilities, a propane wholesale marketing business and NGL pipeline assets.

In 2012, DCP Midstream gathered, processed and/or transported an average of 7.1 trillion British thermal units (TBTU) per day of natural gas, and produced approximately 402,000 barrels per day of NGL, compared with 7.0 TBTU per day and 383,000 barrels per day in 2011.

10


The residual natural gas, primarily methane, which results from processing raw natural gas, is sold by DCP Midstream at market-based prices to marketers and end users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under the following types of contractual arrangements. More than 70 percent of the natural gas volumes gathered and processed are under percentage-of-proceeds contracts.
 
Percentage-of-proceeds/index arrangements.  In general, DCP Midstream purchases natural gas from producers at the wellhead or other receipt points, gathers the wellhead natural gas through its gathering system, treats and processes it, and then sells the residue natural gas and NGL based on index prices from published market indices. DCP Midstream remits to the producers either an agreed-upon percentage of the actual proceeds received from the sale of the residue natural gas and NGL, or an agreed-upon percentage of the proceeds based on index-related prices for natural gas and NGL, regardless of the actual amount of sales proceeds which DCP Midstream receives. Certain of these arrangements may also result in DCP Midstream returning all or a portion of the residue natural gas and/or the NGL to the producer in lieu of returning sales proceeds. DCP Midstream's revenues from percentage-of-proceeds/index arrangements relate directly with the price of NGL and, to a lesser extent, natural gas and crude oil.
  
Fee-based arrangements.  DCP Midstream receives a fee or fees for one or more of the following services: gathering, processing, compressing, treating, storing or transporting natural gas and fractionating, storing and transporting NGL. Fee-based arrangements include natural gas purchase arrangements pursuant to which DCP Midstream purchases natural gas at the wellhead or other receipt points at an index-related price at the delivery point less a specified amount, generally the same as the fees it would otherwise charge for gathering the natural gas from the wellhead location to the delivery point. The revenue DCP Midstream earns from these arrangements is directly related to the volume of natural gas or NGL that flows through its systems and is not directly dependent on commodity prices. However, to the extent that a sustained decline in commodity prices results in a decline in volumes, DCP Midstream's revenues from these arrangements could be reduced.

Keep-whole and wellhead purchase arrangements.  DCP Midstream gathers raw natural gas from producers for processing, markets the NGL and returns to the producer residue natural gas with a British thermal unit (BTU) content equivalent to the BTU content of the natural gas gathered. This arrangement keeps the producer whole in regard to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, DCP Midstream purchases natural gas from the producer at the wellhead or defined receipt point for processing and markets the resulting NGL and residue gas at market prices. DCP Midstream is exposed to the difference between the value of the NGL extracted from processing and the value of the BTU-equivalent of the residue natural gas, or "frac spread." Under these type of contracts, DCP Midstream benefits in periods when NGL prices are higher relative to natural gas prices.
DCP Midstream markets a portion of its NGL to us and CPChem under an existing 15-year supply agreement, with a primary term ending December 31, 2014. Should the contract not be renegotiated or renewed, it provides for a five-year ratable wind-down period. This purchase commitment is on an “if-produced, will-purchase” basis and is expected to have a relatively stable purchase pattern over the remaining term of the contract. Under the agreement, NGL is purchased at various published market-index prices, less transportation and fractionation fees.
DCP Midstream is constructing a natural gas processing plant in the Eagle Ford shale area of Texas. The plant, named the Eagle Plant, is expected to have a capacity of 200 million cubic feet per day and be accompanied by related NGL infrastructure. The Eagle Plant is mechanically complete and is in the process of commencing operations, and will increase DCP Midstream's total natural gas processing capacity in the area to 1 billion cubic feet per day.
DCP Midstream is building two major NGL pipelines. The Sand Hills Pipeline will consist of approximately 720 miles of pipeline with initial capacity of 200,000 barrels per day, with expansion to 350,000 barrels per day possible. The Sand Hills Pipeline will provide NGL transportation from the Permian Basin and Eagle Ford region to the premium NGL markets on the Gulf Coast. In December 2012, the first phase of the Sand Hills Pipeline, which extends from Eagle Ford to Mont Belvieu, was placed in service. The second phase of the project, with deliveries from the Permian Basin, is expected to be completed in the second quarter of 2013.

The Southern Hills Pipeline will consist of more than 800 miles of NGL pipeline with initial capacity of approximately 150,000 barrels per day of Y-grade NGL, with expansion to 175,000 barrels per day expected. The Southern Hills Pipeline will be connected to several DCP Midstream processing plants and anticipated third-party producers, and will provide NGL transportation from the Midcontinent to Mont Belvieu, Texas. The Southern Hills Pipeline is expected to be in service in mid-2013.


11


During the fourth quarter of 2012, Spectra Energy and Phillips 66 each acquired a one-third direct interest in both the Southern Hills and Sand Hills pipeline projects from DCP Midstream.

Rockies Express Pipeline LLC (REX)
We have a 25 percent interest in REX. The REX natural gas pipeline runs 1,679 miles from Cheyenne, Colorado, to Clarington, Ohio, and has a natural gas transmission capacity of 1.8 billion cubic feet per day, with most of its system having a pipeline diameter of 42 inches. Numerous compression facilities support the pipeline system. The REX pipeline is designed to enable natural gas producers in the Rocky Mountain region to deliver natural gas supplies to the Midwest and eastern regions of the United States.

Other Midstream
Outside of DCP Midstream and REX, our U.S. natural gas and NGL business includes the following:
 
A one-third direct interest in both the Sand Hills and Southern Hills pipeline projects, which currently are under construction by DCP Midstream.

A 22.5 percent equity interest in Gulf Coast Fractionators, which owns an NGL fractionation plant in Mont Belvieu, Texas. We operate the facility, and our net share of capacity is 32,625 barrels per day. In July 2012, the previously announced expansion of Gulf Coast Fractionators became operational and the total capacity of the fractionation facility expanded to 145,000 barrels per day.

A 40 percent interest in a fractionation plant in Conway, Kansas. Our net share of capacity is 43,200 barrels per day.

A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas. Our net share of capacity is 26,000 barrels per day.

Marketing operations that optimize the flow of NGL and market propane on a wholesale basis.


CHEMICALS

The Chemicals segment consists of our 50 percent equity investment in CPChem, which is headquartered in The Woodlands, Texas. At the end of 2012, CPChem owned or had joint-venture interests in 36 manufacturing facilities and 2 research and development centers around the world.

CPChem’s business is structured around two primary operating segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P segment produces and markets ethylene, propylene, and other olefin products, which are primarily consumed within CPChem for the production of polyethylene, normal alpha olefins, polypropylene and polyethylene pipe. The SA&S segment manufactures and markets aromatics 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 including organosulfur chemicals, solvents, catalysts, drilling chemicals, mining chemicals and high-performance engineering plastics and compounds.

The manufacturing of petrochemicals and plastics involves the conversion of hydrocarbon-based raw material feedstock into higher-value products, often through a thermal process referred to in the industry as “cracking.” For example, ethylene can be produced from cracking the feedstocks ethane, propane, butane, natural gasoline or certain refinery liquids, such as naphtha and gas oil. The produced ethylene has a number of uses, primarily as a raw material for the production of plastics, such as polyethylene and polyvinyl chloride (PVC). Plastic resins, such as polyethylene, are manufactured in a thermal/catalyst process, and the produced output is used as a further raw material for various applications, such as packaging and plastic pipe.

CPChem, including through its subsidiaries and equity affiliates, has manufacturing facilities located in Belgium, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.

12


The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2012:
 
 
Millions of Pounds per Year
 
U.S.

 
Worldwide

O&P
 
 
 
Ethylene
7,830

 
10,305

Propylene
2,975

 
3,480

High-density polyethylene
4,205

 
6,500

Low-density polyethylene
620

 
620

Linear low-density polyethylene
420

 
420

Polypropylene

 
310

Normal alpha olefins
1,490

 
2,005

Polyalphaolefins
105

 
235

Polyethylene pipe
590

 
590

Total O&P
18,235

 
24,465

 
 
 
 
SA&S
 
 
 
Benzene
1,600

 
2,530

Cyclohexane
1,060

 
1,455

Paraxylene
1,000

 
1,000

Styrene
1,050

 
1,875

Polystyrene
835

 
1,335

K-Resin® SBC
100

 
170

Specialty chemicals
605

 
705

Ryton® PPS
55

 
75

Total SA&S
6,305

 
9,145

Capacities include CPChem’s share in equity affiliates.


In December 2011, CPChem announced plans to pursue a project to construct a world-scale ethane cracker and two polyethylene facilities in the U.S. Gulf Coast region. The project would leverage the development of significant shale gas resources in the United States. CPChem's Cedar Bayou facility in Baytown, Texas, would be the location of the 3.3 billion-pound-per-year ethylene unit. In April 2012, CPChem announced that the two polyethylene facilities, each with an annual capacity of 1.1 billion pounds, would be located on a site near CPChem's Sweeny facility in Old Ocean, Texas. The final investment decision is expected in 2013.

In March 2012, CPChem announced plans to expand the NGL Fractionator Complex at its Sweeny facility in Old Ocean, Texas. The NGL fractionation expansion will increase its capacity by approximately 22,000 barrels per day, or a 19 percent increase over its current capacity. The project is expected to be completed in 2013.

In April 2012, CPChem announced plans to build a 1-hexene plant capable of producing up to 550 million pounds per year at its Cedar Bayou facility in Baytown, Texas. 1-hexene, a normal alpha olefin, is a critical component used in the manufacture of polyethylene, a plastic resin commonly converted into film, pipe, detergent bottles and food and beverage containers. Construction started in 2012, and the project is anticipated to start up during the first half of 2014.

Saudi Polymers Company (SPCo), a 35-percent-owned joint venture company of CPChem, owns and operates an integrated petrochemicals complex adjacent to S-Chem (two 50/50 SA&S joint ventures) at Jubail Industrial City, Saudi Arabia. SPCo produces ethylene, propylene, polyethylene, polypropylene, polystyrene and 1-hexene. SPCo announced commercial production in October 2012.
  
In association with the SPCo project, CPChem committed to build a nylon 6,6 manufacturing plant and a number of polymer conversion projects at Jubail Industrial City, Saudi Arabia. The projects are being undertaken through CPChem's 50 percent owned joint venture company Petrochemical Conversion Company Ltd. The projects are slated to begin operations in 2013.



13


Our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if, at any time after the Separation, we experience a change in control or if both Standard & Poor's Ratings Services (S&P) and Moody's Investors Service (Moody's) lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks.


TECHNOLOGY DEVELOPMENT

Our Technology organization focuses in three areas: 1) advanced engineering optimization for our existing businesses, 2) sustainability technologies for a changing regulatory environment, and 3) future growth opportunities. Technology creates value through evaluation of advantaged crudes, models for increasing clean product yield, and through research to increase safety and reliability. Research allows Phillips 66 to be well positioned to address threats like corrosion, water consumption, and changing climate regulations. For example, we are progressing the technology development of second-generation biofuels both internally and with external collaborators.


COMPETITION

Our R&M segment competes primarily in the United States, Europe and Asia. Based on the statistics published in the December 3, 2012, issue of the Oil & Gas Journal, we are one of the largest refiners of petroleum products in the United States. Worldwide, our refining capacity ranked in the top 10 among non-government-controlled companies. In the Chemicals segment, CPChem generally ranked within the top 10 producers of many of its major product lines, based on average 2012 production capacity, as published by industry sources. Petroleum products, petrochemicals and plastics are typically delivered into the worldwide commodity markets. Elements of competition for both our R&M and Chemicals segments include product improvement, new product development, low-cost structures, and efficient manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to branded products.

The Midstream segment, through our equity investment in DCP Midstream and our other operations, competes with numerous integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver components of natural gas to end users in the commodity natural gas markets. DCP Midstream is one of the leading natural gas gatherers and processors in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of NGL, based on published industry sources. Principal methods of competing include economically securing the right to purchase raw natural gas for gathering systems, managing the pressure of those systems, operating efficient NGL processing plants and securing markets for the products produced.


GENERAL

At December 31, 2012, we held a total of 493 active patents in 46 countries worldwide, including 211 active U.S. patents. During 2012, we received 16 patents in the United States and 40 foreign patents. Our products and processes generated licensing revenues of $14 million in 2012. The overall profitability of any business segment is not dependent on any single patent, trademark, license or franchise.

Company-sponsored research and development activities charged against earnings were $76 million, $74 million and $56 million in 2012, 2011 and 2010, respectively.

In support of our goal to attain zero incidents, we have implemented a comprehensive Health, Safety and Environmental (HSE) management system to support our business units in achieving consistent management of HSE risks across our enterprise.  The management system is designed to ensure that personal safety, process safety, and environmental impact risks are identified and mitigation steps are taken to reduce the risk.  The management system requires periodic audits to ensure compliance with government regulations, as well as our internal requirements. Our commitment to continuous improvement is reflected in annual goal setting and performance measurement.

Please see the environmental information contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contingencies” under the captions “Environmental” and “Climate

14


Change.” It includes information on expensed and capitalized environmental costs for 2012 and those expected for 2013 and 2014.


Website Access to SEC Reports
Our Internet website address is http://www.phillips66.com. Information contained on our Internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC's website at http://www.sec.gov.



15


Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

Our operating results and our future rate of growth are exposed to the effects of changing commodity prices and refining and petrochemical margins.

Our revenues, operating results and future rate of growth are highly dependent on a number of factors, including fixed and variable expenses (including the cost of crude oil and other refinery feedstocks) and the margin relative to those expenses at which we are able to sell refined products. In recent years, the prices of crude oil and refined products have fluctuated substantially. These prices depend on numerous factors beyond our control, including the global supply and demand for crude oil, gasoline and other refined products, which are subject to, among other things:
 
Changes in the global economy and the level of foreign and domestic production of crude oil and refined products.
Availability of crude oil and refined products and the infrastructure to transport crude oil and refined products.
Local factors, including market conditions, the level of operations of other refineries in our markets, and the volume of refined products imported.
Threatened or actual terrorist incidents, acts of war and other global political conditions.
Government regulations.
Weather conditions, hurricanes or other natural disasters.

The price of crude oil influences prices for refined products. We do not produce crude oil and must purchase all of the crude oil we process. Many crude oils available on the world market will not meet the quality restrictions for use in our refineries. Others are not economical to use due to excessive transportation costs or for other reasons. The prices for crude oil and refined products can fluctuate differently based on global, regional and local market conditions. In addition, the timing of the relative movement of the prices (both among different classes of refined products and among various global markets for similar refined products), as well as the overall change in refined product prices, can reduce refining margins and could have a significant impact on our refining, wholesale marketing and retail operations, revenues, operating income and cash flows. Also, crude oil supply contracts generally have market-responsive pricing provisions. We normally purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the refined products from these feedstocks could have a significant effect on our financial results. We also purchase refined products produced by others for sale to our customers. Price level changes during the periods between purchasing and selling these refined products also could have a material adverse effect on our business, financial condition and results of operations.

Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on acceptable terms and can adversely affect the financial strength of our business partners.

Our ability to obtain credit and capital depends in large measure on the state of the credit and capital markets, which is beyond our control. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, access to those markets, which could constrain our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, preventing them from meeting their obligations to us.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generated from operations with proceeds from financing activities. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions to fund their commitments to us under our liquidity facilities. Accordingly, we may not be able to obtain the full amount of the funds available under our liquidity facilities to satisfy our cash requirements, and our failure to do so could have a material adverse effect on our operations and financial position.





16


Deterioration in our credit profile could increase our costs of borrowing money and limit our access to the capital markets and commercial credit, and could trigger co-venturer rights under joint venture arrangements.

Our credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our borrowing costs would increase, and our funding sources could decrease. In addition, a failure by us to maintain an investment grade rating could affect our business relationships with suppliers and operating partners. For example, our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if we experience a change in control or if both S&P and Moody's lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks. As a result of these factors, a downgrade of our credit ratings could have a materially adverse impact on our future operations and financial position.

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.

Our business is subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:
 
The discharge of pollutants into the environment.
Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).
The handling, use, storage, transportation, disposal and clean up of hazardous materials and hazardous and nonhazardous wastes.
The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.

To the extent there are significant changes in the Earth's climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.

Domestic and worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and international governments through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments could limit our ability to operate in, or gain access to, opportunities in various countries, as well as limit our ability to obtain the optimum slate of crude oil and other refinery feedstocks. Our foreign operations and those of our joint ventures are further subject to risks of loss of revenue, equipment and property as a result of expropriation, acts of terrorism, war, civil unrest and other political risks; unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities; and difficulties enforcing rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Actions by both the United States and host governments may affect our operations significantly in the future.

Renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for refined products. Tax incentives and other subsidies can make renewable fuels and alternative energy more competitive with refined products than they otherwise might be, which may reduce refined product margins and hinder the ability of refined products to compete with renewable fuels.


17


Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.

To approve a large-scale capital project, the project must meet an acceptable level of return on the capital to be employed in the project. We base these forecasted project economics on our best estimate of future market conditions. Most large-scale projects take many years to complete. During this multi-year period, market conditions can change from those we forecast, and these changes could be significant. Accordingly, we may not be able to realize our expected returns from a large investment in a capital project, and this could negatively impact our results of operations, cash flows and our return on capital employed.

Our investments in joint ventures decrease our ability to manage risk.

We conduct some of our operations, including a large part of our Midstream segment and our entire Chemicals segment, through joint ventures in which we share control with our joint venture participants. Our joint venture participants may have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or our joint venture participants may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint-venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

Activities in our Chemicals and Midstream segments involve numerous risks that may result in accidents or otherwise affect the ability of our equity affiliates to make distributions to us.

There are a variety of hazards and operating risks inherent in the manufacture of petrochemicals and the gathering, processing, transmission, storage, and distribution of natural gas and NGL, such as spills, leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of human life, damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Should any of these risks materialize, it could have a material adverse effect on the business and financial condition of CPChem, DCP Midstream or REX and negatively impact their ability to make future distributions to us.

Our operations present hazards and risks, which may not be fully covered by insurance, if insured. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.

The scope and nature of our operations present a variety of operational hazards and risks, including explosions, fires, toxic emissions, maritime hazards and natural catastrophes, that must be managed through continual oversight and control. For example, the operation of refineries, power plants, fractionators, pipelines and terminals is inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or refined products terminals, or in connection with any facilities that receive our wastes or by-products for treatment or disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with their remediation under federal, state, local and international environmental laws or common law, and could be liable for property damage to third-parties caused by contamination from releases and spills. These and other risks are present throughout our operations. As protection against these hazards and risks, we maintain insurance against many, but not all, potential losses or liabilities arising from such operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.

We often utilize the services of third parties to transport crude oil, NGL and refined products to and from our facilities. In addition to our own operational risks discussed above, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of a pipeline or vessel to transport crude oil or refined product to or from one or more of our refineries could have a material adverse effect on our business, financial condition, results of operations and cash flows.


18


Increased regulation of hydraulic fracturing could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely impact our results of operations.

An increasing percentage of crude oil supplied to our refineries and the oil and gas production of DCP Midstream's customers is being developed from unconventional sources, such as deep oil and gas shales. These reservoirs require hydraulic fracturing completion processes to release the hydrocarbons from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate hydrocarbon production. The U.S. Environmental Protection Agency, as well as several state agencies, have commenced studies and/or convened hearings regarding the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be. Any additional levels of regulation and permits required with the adoption of new laws and regulations at the federal or state level could result in our having to rely on higher priced crude oil for our refineries and lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through DCP Midstream's gathering systems. This could materially adversely affect our results of operations and the ability of DCP Midstream to make cash distributions to us.

Because of the natural decline in production from existing wells in DCP Midstream's areas of operation, its success depends on its ability to obtain new sources of natural gas and NGL. Any decrease in the volumes of natural gas DCP Midstream gathers could adversely affect its business and operating results.

DCP Midstream's gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, its cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on its gathering and transportation pipeline systems and NGL pipelines and the asset utilization rates at its natural gas processing plants, DCP Midstream must continually obtain new supplies. The primary factors affecting DCP Midstream's ability to obtain new supplies of natural gas and NGL, and to attract new customers to its assets, include the level of successful drilling activity near these assets, the demand for natural gas and crude oil, producers' desire and ability to obtain necessary permits in an efficient manner, natural gas field characteristics and production performance, surface access and infrastructure issues, and its ability to compete for volumes from successful new wells. If DCP Midstream is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells or because of competition, throughput on its pipelines and the utilization rates of its treating and processing facilities would decline. This could have a material adverse effect on its business, results of operations, financial position and cash flows, and its ability to make cash distributions to us.

Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We do not produce any of our crude oil feedstocks. Some of our competitors, however, obtain a portion of their feedstocks from their own production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our business. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers.

We may incur losses as a result of our forward-contract activities and derivative transactions.

We currently use commodity derivative instruments, and we expect to continue their use in the future. If the instruments we utilize to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions involve the risk that counterparties may be unable to satisfy their obligations to us. If any of our counterparties were to default on its obligations to us under the hedging contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. The risk of counterparty default is heightened in a poor economic environment.


19


A significant interruption in one or more of our facilities could adversely affect our business.

Our operations could be subject to significant interruption if one or more of our facilities were to experience a major accident or mechanical failure, power outage, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any facility were to experience an interruption in operations, earnings from the facility could be materially adversely affected (to the extent not recoverable through insurance, if insured) because of lost production and repair costs. A significant interruption in one or more of our facilities could also lead to increased volatility in prices for feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

Our performance depends on the uninterrupted operation of our facilities, which are becoming increasingly dependent on our information technology systems.

Our performance depends on the efficient and uninterrupted operation of the manufacturing equipment in our production facilities. The inability to operate one or more of our facilities due to a natural disaster; power outage; labor dispute; or failure of one or more of our information technology, telecommunications, or other systems could significantly impair our ability to manufacture our products. Our manufacturing equipment is becoming increasingly dependent on our information technology systems. A disruption in our information technology systems due to a catastrophic event or security breach could interrupt or damage our operations. In addition, we could be subject to reputational harm or liability if confidential customer information is misappropriated from our information technology systems. Despite our security measures and business continuity plans, these systems could be vulnerable to disruption, and any such disruption could negatively affect our financial condition and results of operations.

The level of returns on pension and postretirement plan assets and the actuarial assumptions used for valuation purposes could affect our earnings and cash flows in future periods.

Assumptions used in determining projected benefit obligations and the expected return on plan assets for our pension plan and other postretirement benefit plans are evaluated by us in consultation with outside actuaries. If we determine that changes are warranted in the assumptions used, such as the discount rate, expected long-term rate of return, or health care cost trend rate, our future pension and postretirement benefit expenses and funding requirements could increase. In addition, several factors could result in actual results differing significantly from the actuarial assumptions that we use. Funding obligations are determined based on the value of assets and liabilities on a specific date as required under relevant regulations. Future pension funding requirements, and the timing of funding payments, could be affected by legislation enacted by governmental authorities.

In connection with the Separation, ConocoPhillips has agreed to indemnify us for certain liabilities and we have agreed to indemnify ConocoPhillips for certain liabilities. If we are required to act on these indemnities to ConocoPhillips, we may need to divert cash to meet those obligations and our financial results could be negatively impacted. The ConocoPhillips indemnity may not be sufficient to insure us against the full amount of liabilities for which it has been allocated responsibility, and ConocoPhillips may not be able to satisfy its indemnification obligations in the future.

Pursuant to the Indemnification and Release Agreement and certain other agreements with ConocoPhillips entered into in connection with the Separation, ConocoPhillips agreed to indemnify us for certain liabilities, and we agreed to indemnify ConocoPhillips for certain liabilities. Indemnities that we may be required to provide ConocoPhillips are not subject to any cap, may be significant and could negatively impact our business, particularly indemnities relating to our actions that could impact the tax-free nature of the distribution of Phillips 66 stock. Third parties could also seek to hold us responsible for any of the liabilities that ConocoPhillips has agreed to retain. Further, the indemnity from ConocoPhillips may not be sufficient to protect us against the full amount of such liabilities, and ConocoPhillips may not be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from ConocoPhillips any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks could negatively affect our business, results of operations and financial condition.

We are subject to continuing contingent liabilities of ConocoPhillips following the Separation.

Notwithstanding the Separation, there are several significant areas where the liabilities of ConocoPhillips may become our obligations. For example, under the Internal Revenue Code and the related rules and regulations, each corporation that was a member of the ConocoPhillips consolidated U.S. federal income tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the Separation is jointly and severally liable for the U.S. federal

20


income tax liability of the entire ConocoPhillips consolidated tax reporting group for that taxable period. In connection with the Separation, we entered into the Tax Sharing Agreement with ConocoPhillips that allocates the responsibility for prior period taxes of the ConocoPhillips consolidated tax reporting group between us and ConocoPhillips. ConocoPhillips may be unable to pay any prior period taxes for which it is responsible, and we could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.

If the distribution in connection with the Separation, together with certain related transactions, does not qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, our stockholders and ConocoPhillips could be subject to significant tax liability and, in certain circumstances, we could be required to indemnify ConocoPhillips for material taxes pursuant to indemnification obligations under the Tax Sharing Agreement.

ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) substantially to the effect that, among other things, the distribution, together with certain related transactions, qualified as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The private letter ruling and the tax opinion that ConocoPhillips received relied on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the private letter ruling nor the opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the private letter ruling does not address all the issues that are relevant to determining whether the distribution qualified for tax-free treatment. Notwithstanding the private letter ruling and the tax opinion, the IRS could determine the distribution should be treated as a taxable transaction for U.S. federal income tax purposes if it determines any of the representations, assumptions or undertakings that were included in the request for the private letter ruling are false or have been violated or if it disagrees with the conclusions in the opinion that are not covered by the IRS ruling.

If the IRS were to determine that the distribution failed to qualify for tax-free treatment, in general, ConocoPhillips would be subject to tax as if it had sold the Phillips 66 common stock in a taxable sale for its fair market value, and ConocoPhillips stockholders who received shares of Phillips 66 common stock in the distribution would be subject to tax as if they had received a taxable distribution equal to the fair market value of such shares.

Under the Tax Sharing Agreement, we would generally be required to indemnify ConocoPhillips against any tax resulting from the distribution to the extent that such tax resulted from (i) an acquisition of all or a portion of our stock or assets, whether by merger or otherwise, (ii) other actions or failures to act by us, or (iii) any of our representations or undertakings being incorrect or violated. Our indemnification obligations to ConocoPhillips and its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify ConocoPhillips or such other persons under the circumstances set forth in the Tax Sharing Agreement, we may be subject to substantial liabilities.

We may not be able to engage in desirable strategic or capital-raising transactions due to limitations imposed on us as part of the Separation. In addition, under some circumstances, we could be liable for adverse tax consequences resulting from engaging in significant strategic or capital-raising transactions.

To preserve the tax-free treatment to ConocoPhillips of the distribution, for the two-year period following the distribution we may be prohibited, except in specified circumstances, from:
 
Entering into any transaction pursuant to which all or a portion of our stock would be acquired, whether by merger or otherwise.
Issuing equity securities beyond certain thresholds.
Repurchasing our common stock beyond certain thresholds.
Ceasing to actively conduct the refining business.
Taking or failing to take any other action that prevents the distribution and related transactions from being tax-free.

These restrictions may limit our ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of our business.


Item 1B. UNRESOLVED STAFF COMMENTS

None.



21


Item 3. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment, for this reporting period. It describes those matters previously reported in the Form 10 and in the Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2012, June 30, 2012, and September 30, 2012, that were not resolved prior to the fourth quarter of 2012. No new reportable matters arose during the fourth quarter of 2012 that were not previously reported. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to Phillips 66, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to SEC regulations.

Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.

New Matters
There were no new reportable matters that arose during the fourth quarter of 2012 that were not previously reported.

Matters Previously Reported
In October 2007, we received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at the Bayway Refinery and proposing a penalty of $156,000. We are working with the EPA and the U.S. Coast Guard to resolve this matter.

On May 19, 2010, the Lake Charles Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. We are working with the LDEQ to resolve this matter.

In October 2011, we were notified by the Attorney General of the State of California that it was conducting an investigation into possible violations of the regulations relating to the operation of underground storage tanks at gas stations in California. On January 3, 2013, we received notice of a lawsuit filed by the California Attorney General that alleges such violations. We are contesting these allegations.

On November 28, 2011, the Borger Refinery received a Notice of Enforcement from the Texas Commission on Environmental Quality (TCEQ) for alleged emissions events that occurred during inclement weather in January and February 2011. The TCEQ is seeking a penalty of $120,000. We are working with TCEQ to resolve this matter.

In December 2011, we were notified by the EPA of alleged violations related to the use of Renewable Identification Numbers (RINs). Phillips 66 was one of several companies that entered into Administrative Settlement Agreements (ASAs) with the EPA to settle allegations that it had used invalid RINs for its 2010 and 2011 fuel program compliance. Under the ASA, we will pay a maximum of $350,000 in penalties for the use of invalid RINs covered thereunder. Payments are made upon demand from the EPA. To date, $250,000 has been paid and it is anticipated that the EPA will demand the final $100,000 in 2013.

On March 7, 2012, the Bay Area Air Quality Management District (District) in California issued a $302,500 demand to settle five Notices of Violations (NOVs) issued between 2008 and 2010. The NOVs allege non-compliance with the District rules and/or facility permit conditions. We are working with the District to resolve this matter.

On September 19, 2012, the District issued a $213,500 demand to settle 14 NOVs issued in 2009 and 2010 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. We are working with the District to resolve this matter.


22


On October 15, 2012, the District issued a $313,000 demand to settle 13 other NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. We are working with the District to resolve this matter.

In May 2012, the Illinois Attorney General's office filed and notified us of a complaint with respect to operations at the WRB Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party's hazardous waste permit. The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures; additional spill reporting; and yet-to-be specified amounts for fines and penalties. We are working with the Illinois Environmental Protection Agency and Attorney General's office to resolve these allegations.


Item 4. MINE SAFETY DISCLOSURES

Not applicable.



23


EXECUTIVE OFFICERS OF THE REGISTRANT
 
Name
Position Held
Age*

 
 
 
Greg C. Garland
Chairman, President and Chief Executive Officer
55

C. Doug Johnson
Vice President and Controller
53

Paula A. Johnson
Senior Vice President, Legal, General Counsel and Corporate Secretary
49

Greg G. Maxwell
Executive Vice President, Finance and Chief Financial Officer
56

Tim G. Taylor
Executive Vice President, Commercial, Marketing, Transportation and Business Development
59

Lawrence M. Ziemba
Executive Vice President, Refining, Project Development and Procurement
57

*On February 15, 2013.
 
 


There are no family relationships among any of the officers named above. The Board of Directors annually elects the officers to serve until a successor is elected and qualified or as otherwise provided in our By-Laws. Set forth below is information about the executive officers identified above.

Greg C. Garland became Chairman of the Board of Directors, President and Chief Executive Officer of Phillips 66 on April 30, 2012. Mr. Garland was appointed Senior Vice President, Exploration and Production—Americas for ConocoPhillips in October 2010, having previously served as President and Chief Executive Officer of Chevron Phillips Chemical Company LLC (CPChem) since 2008. Prior to that, he served as Senior Vice President, Planning and Specialty Products at CPChem from 2000 to 2008. Prior to joining CPChem in 2000, he held several senior positions with Phillips Petroleum Company.

C. Doug Johnson became Vice President and Controller of Phillips 66 on April 30, 2012. Mr. Johnson served as General Manager, Upstream Finance, Strategy and Planning at ConocoPhillips since 2010. Prior to this, he served as General Manager, Downstream Finance from 2008 to 2010 and General Manager, Upstream Finance from 2005 to 2008.

Paula A. Johnson became Senior Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66 on April 30, 2012. Ms. Johnson served as Deputy General Counsel, Corporate, and Chief Compliance Officer of ConocoPhillips since 2010. Prior to this, she served as Deputy General Counsel, Corporate from 2009 to 2010 and Managing Counsel, Litigation and Claims from 2006 to 2009.

Greg G. Maxwell became Executive Vice President, Finance and Chief Financial Officer of Phillips 66 on April 30, 2012. Mr. Maxwell retired as CPChem's Senior Vice President, Chief Financial Officer and Controller in 2012, a position held since 2003. He served as Vice President and Controller of CPChem from 2000 to 2003. Prior to joining CPChem in 2000, he held several senior positions with Phillips Petroleum Company.

Tim G. Taylor became Executive Vice President, Commercial, Marketing, Transportation and Business Development of Phillips 66 on April 30, 2012. Mr. Taylor retired as Chief Operating Officer of CPChem in 2011. Prior to this, Mr. Taylor served as Executive Vice President, Olefins and Polyolefins, at CPChem from 2008 to 2011, and Senior Vice President, Olefins and Polyolefins, from 2000 to 2008. Prior to joining CPChem in 2000, he held several senior positions with Phillips Petroleum Company.

Lawrence M. Ziemba became Executive Vice President, Refining, Project Development and Procurement, of Phillips 66 on April 30, 2012. Mr. Ziemba served as President, Global Refining, at ConocoPhillips since 2010. Prior to this, he served as President, U.S. Refining, from 2003 to 2010.




24


PART II

Item 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Common Stock Prices and Cash Dividends Per Share

Phillips 66's common stock is traded on the New York Stock Exchange (NYSE) under the symbol “PSX.” The following table reflects intraday high and low sales prices of, and dividends declared on, our common stock for each quarter starting May 1, 2012, the date on which our stock began trading "regular-way" on the NYSE:

 
Stock Price
 
 
 
High
 
Low

 
Dividends

2012
 
 
 
 
Second Quarter
$
34.91
 
28.75

 

Third Quarter
48.22
 
32.35

 
.20

Fourth Quarter
54.32
 
42.45

 
.25



Closing Stock Price at December 31, 2012
 
 
 
$
53.10

Closing Stock Price at January 31, 2013
 
 
 
$
60.57

Number of Stockholders of Record at January 31, 2013
 
 
 
49,200



Issuer Purchases of Equity Securities

 
 
 
 
 
 
 
Millions of Dollars

Period
Total Number of Shares Purchased*

 
Average Price Paid per Share

 
Total Number of Shares Purchased
as Part of Publicly Announced Plans
or Programs**

 
Approximate Dollar Value of Shares
that May Yet Be Purchased Under the Plans or Programs

 
 
 
 
 
 
 
 
October 1-31, 2012
1,514,825

 
$
45.64

 
1,511,300

 
$
820

November 1-30, 2012
1,618,344

 
48.05

 
1,618,344

 
742

December 1-31, 2012
1,881,822

 
52.19

 
1,879,852

 
1,644

Total
5,014,991

 
$
48.87

 
5,009,496

 
 
*Includes repurchase of common shares from company employees in connection with the company's broad-based employee incentive plans.
**In July 2012, our Board of Directors authorized the repurchase of up to $1 billion of our outstanding common stock. We began purchases under this authorization, which has no expiration date, in the third quarter of 2012. In December 2012, an additional repurchase of up to $1 billion was approved by our Board of Directors, bringing the total program to $2 billion. The shares will be repurchased from time to time in the open market at the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements and the Tax Sharing Agreement entered into in connection with the Separation. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Shares of stock repurchased are held as treasury shares.



25


Item 6. SELECTED FINANCIAL DATA

Prior to the Separation, the following selected financial data consisted of the combined operations of the downstream businesses of ConocoPhillips. All financial information presented after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66. Accordingly:

The selected income statement data for the year ended December 31, 2012, consists of the consolidated results of Phillips 66 for the eight months ended December 31, 2012, and of the combined results of the downstream businesses for the four months ended April 30, 2012. The selected income statement data for the years ended December 31, 2011, 2010, 2009 and 2008, consist entirely of the combined results of the downstream businesses.

The selected balance sheet data at December 31, 2012, consists of the consolidated balances of Phillips 66, while the selected balance sheet data at December 31, 2011, 2010, 2009 and 2008, consist of the combined balances of the downstream businesses.

 
Millions of Dollars Except Per Share Amounts
 
2012

 
2011

 
2010

 
2009

 
2008

 
 
 
 
 
 
 
 
 
 
Sales and other operating revenues
$
179,460

 
196,088

 
146,561

 
112,692

 
171,706

Net income
4,131

 
4,780

 
740

 
479

 
2,665

Net income attributable to Phillips 66
4,124

 
4,775

 
735

 
476

 
2,662

Per common share*
 
 
 
 
 
 
 
 
 
Basic
6.55

 
7.61

 
1.17

 
0.76

 
4.24

Diluted
6.48

 
7.52

 
1.16

 
0.75

 
4.19

Total assets
48,073

 
43,211

 
44,955

 
42,880

 
38,934

Long-term debt
6,961

 
361

 
388

 
403

 
417

Cash dividends declared per common share
0.45

 

 

 

 

*See Note 12—Earnings Per Share, in the Notes to Consolidated Financial Statements.


To ensure full understanding, you should read the selected financial data presented above in conjunction with “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and accompanying notes included elsewhere in this Annual Report on Form 10-K.



26


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. 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,” beginning on page 52.

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 international downstream company with refining and marketing, midstream and chemicals businesses. At December 31, 2012, we had total assets of $48 billion. Our common stock trades on the New York Stock Exchange under the symbol “PSX.”

We have organized our operations into three operating segments:

Refining and Marketing (R&M). This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. This segment also includes power generation activities, as well as specialties businesses such as flow improvers and lubricants.

Midstream. This segment gathers, processes, transports and markets natural gas; and transports, fractionates and markets natural gas liquids (NGL) in the United States. The Midstream segment includes our 50 percent equity investment in DCP Midstream, LLC (DCP Midstream).

Chemicals. This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem).

The Separation
On April 4, 2012, the ConocoPhillips Board of Directors approved the separation of its downstream businesses into an independent, publicly traded company named Phillips 66. In accordance with the Separation and Distribution Agreement, the two companies were separated by ConocoPhillips distributing to its stockholders all 625,272,302 shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Each ConocoPhillips shareholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. In conjunction with the Separation, ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) to the effect that, based on certain facts, assumptions, representations and undertakings set forth in the ruling, for U.S. federal income tax purposes, the distribution of Phillips 66 stock was not taxable to ConocoPhillips or U.S. holders of ConocoPhillips common stock, except with respect to cash received in lieu of fractional share interests. Following the Separation, ConocoPhillips retained no ownership interest in Phillips 66, and each company now has separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness, describing the Separation was filed by Phillips 66 with the U.S. Securities and Exchange Commission (SEC) and was declared effective on April 12, 2012 (the Form 10).


27


Basis of Presentation
Prior to the Separation on April 30, 2012, our results of operations, financial position and cash flows consisted of ConocoPhillips' refining, marketing and transportation operations; its natural gas gathering, processing, transmission and marketing operations, including its equity investment in DCP Midstream; its petrochemical operations, conducted through its equity investment in CPChem; its power generation operations; and an allocable portion of its corporate costs (together, the “downstream businesses”). These financial statements have been presented as if the downstream businesses had been combined for all periods presented. All intercompany transactions and accounts within the downstream businesses were eliminated. The assets and liabilities have been reflected on a historical cost basis, as all of the assets and liabilities presented were wholly owned by ConocoPhillips and were transferred within the ConocoPhillips consolidated group. The statement of income for periods prior to the Separation includes expense allocations for certain corporate functions historically performed by ConocoPhillips and not allocated to its operating segments, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. These allocations were based primarily on specific identification of time and/or activities associated with the downstream businesses, employee headcount or capital expenditures, and our management believes the assumptions underlying the allocations were reasonable. The combined financial statements may not necessarily reflect all of the actual expenses that would have been incurred had we been a stand-alone company during the periods presented prior to the Separation. All financial information presented after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66.

Executive Overview
We reported earnings of $4.1 billion in 2012. Refining margins remained strong in 2012, particularly in the Midcontinent region. Chemicals margins also remained robust in 2012. We generated cash from operations in 2012 of $4.3 billion, which we used to fund capital expenditures and investments of $1.7 billion, pay dividends of $282 million, repurchase $356 million of our common shares, make a $1.0 billion pre-payment on our debt, and increase our cash and cash equivalents balance to $3.5 billion at December 31, 2012. We ended 2012 with approximately $5.0 billion of total capacity under our available liquidity facilities.

Our solid financial results in 2012 allowed us to accelerate our strategy of creating value for shareholders:

We increased our quarterly dividend rate by 25 percent in the fourth quarter of 2012, to $0.25 per share. We also announced in the fourth quarter of 2012 that the annual dividend rate would be further increased by an additional 25 percent, effective in 2013.

We initiated a $1 billion share repurchase program in the third quarter of 2012 and, in the fourth quarter, we increased the program to $2 billion. Through December 31, 2012, we repurchased $356 million of our common shares.

We continue to focus on the following strategic areas:

Operating safely, reliably and in an environmentally sound manner. Safety and reliability are our first priority, and 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. 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 2012, our worldwide refining capacity utilization rate was 93 percent, compared with 92 percent in 2011. Additionally, we strive to conduct our operations in a manner consistent with our environmental stewardship principles.

Improving our advantaged crude runs in our refineries. U.S. crude production continued to increase and limited infrastructure for takeaway options resulted in lower feedstock costs for U.S. refiners with refineries that run advantaged crudes. Refineries capable of processing West Texas Intermediate (WTI) crude and crude oils that price relative to WTI, primarily the Midcontinent and Gulf Coast refineries, benefited from these lower regional feedstock prices. We are already running advantaged crude in eight of our refineries in the United States. We are moving advantaged crude by truck, rail, barge and ocean-going vessel to our refineries. We have expanded our truck, rail rack and marine capability, and we are leasing 2,000 additional railcars to deliver advantaged crude to our refineries.

Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, are high priorities. Operating and overhead costs increased 5 percent in 2012, compared with 2011, primarily due to the Separation. However, we have established “Optimize 66,” a program that concentrates on not only cost reductions, but also on process improvements, to improve our overall effectiveness and eliminate the cost “dis-synergies” resulting from the Separation.


28


Funding growth and enhancing returns. Our capital program plan for 2013 is $3.7 billion, 3 percent higher than the 2012 program. This includes our portion of planned capital spending by DCP Midstream, CPChem and WRB Refining LP (WRB) totaling $1.8 billion, which is not expected to require cash outlays by us. The other $1.9 billion represents our consolidated investments in R&M, Midstream and Corporate and Other. This program is designed to grow our Midstream and Chemicals segments and to improve returns in our R&M segment. We intend to grow our Midstream segment both through our ownership in DCP Midstream and our own Phillips 66 midstream assets. We have invested directly in the Sand Hills and Southern Hills pipelines, and we have announced our plans to form a master limited partnership to grow additional midstream and transportation infrastructure in the future. We intend to grow our Chemicals segment through our ownership in CPChem. CPChem has large olefins and polyolefins projects underway in the U.S. Gulf Coast region. In the R&M segment, we plan to improve returns through increasing our advantaged crude runs in our refineries, while selectively investing in smaller, higher-return projects.
  
Business Environment
Results for our R&M segment depend largely on refining and marketing margins, cost control, refinery throughput, and product yields. The crack spread is a measure of the difference between market prices for refined petroleum products and crude oil, and it is used within our industry as an indicator for refining margins. Both domestic and international industry average crack spreads increased from 2010 to 2011 and again from 2011 to 2012. The improvements were consistent with improved global demand for refined products resulting from worldwide economic recovery along with limited net increases in global refining capacity. U.S. margins in the Midcontinent were especially strong, which can be attributed to the region's crude feedstock advantage.

In addition, U.S. crude production continued to increase, and limited infrastructure for takeaway options resulted in advantaged crude prices for U.S. refiners with access to advantaged crudes. Midcontinent refiners were especially advantaged. Increasing pressure on inventories in the Midcontinent continued to cause WTI crude to trade at a deep discount relative to crudes such as Light Louisiana Sweet (LLS) and Brent. Refineries capable of processing WTI crude and crude oils that price relative to WTI, primarily the Midcontinent and Gulf Coast refineries, benefited from these lower regional feedstock prices.

The Midstream segment's results are closely linked to NGL prices relative to crude oil prices and, to a lesser extent, natural gas prices. NGL prices improved in both 2010 and 2011 along with crude oil prices, but decreased in 2012 while crude prices stayed relatively stable. The NGL price decrease in 2012 was primarily due to growing NGL production from liquids-rich shale plays, while a corresponding demand increase from the petrochemical industry has not yet materialized as projects remain under development.

The Chemicals segment consists of our 50 percent equity investment in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors. The chemicals and plastics industry experienced robust margin improvement from 2010 to 2011, and then again in 2012. Generally, ethylene margins improved in regions of the world where production is based upon NGL versus crude-derived feedstocks. In particular, North American ethane-based crackers benefited from the lower-priced feedstocks.


29


RESULTS OF OPERATIONS

Consolidated Results

A summary of the company’s earnings by business segment follows:
 
 
Millions of Dollars
 
Year Ended December 31
 
2012

 
2011

 
2010

 
 
 
 
 
 
R&M
$
3,729

 
3,848

 
146

Midstream
6

 
403

 
262

Chemicals
823

 
716

 
486

Corporate and Other
(434
)
 
(192
)
 
(159
)
Net income attributable to Phillips 66
$
4,124

 
4,775

 
735



2012 vs. 2011

Earnings for Phillips 66 decreased 14 percent in 2012, primarily resulting from:

A $1,437 million after-tax decrease in net gains on asset dispositions in 2012. 2011 results included significant gains on the disposition of three pipeline systems.
A $648 million after-tax increase in impairments in 2012, primarily reflecting 2012 impairments of our equity investments in Rockies Express Pipeline LLC (REX), a natural gas transmission system, and Malaysian Refining Company Sdn. Bdh. (MRC), a refining company in Melaka, Malaysia.
A $137 million after-tax increase in net interest expense, reflecting the issuance of $7.8 billion of debt during the first-half of 2012 in association with the Separation.
Lower NGL prices during 2012, which contributed to decreased earnings from our Midstream segment.

These items were partially offset by:

Improved refining margins in the R&M segment.
Improved ethylene and polyethylene margins in the Chemicals segment.

2011 vs. 2010

Earnings for Phillips 66 increased $4,040 million in 2011. The improved results in 2011 were primarily the result of:
 
Improved results from our R&M segment, reflecting significantly higher domestic refining margins.
Higher net gains from asset dispositions. 2011 net gains from asset dispositions were $1,546 million after tax, compared with 2010 gains of $118 million after tax.
Lower property impairments. 2010 earnings included a $1,174 million after-tax impairment of our formerly owned Wilhelmshaven Refinery (WRG) in Germany, which was partly offset by a $303 million after-tax impairment and warehouse inventory write-down associated with our Trainer Refinery in 2011.
Increased earnings in the Chemicals segment, primarily due to higher margins and volumes in the olefins and polyolefins business line.
Improved earnings from the Midstream segment, mainly due to higher NGL prices.

30


Income Statement Analysis

2012 vs. 2011

Sales and other operating revenues decreased 8 percent in 2012, while purchased crude oil and products decreased 11 percent. The decreases were mainly due to processing lower refining volumes at our wholly owned refineries, resulting from the shutdown of Trainer Refinery in September 2011, combined with lower crude oil and NGL prices.

Equity in earnings of affiliates increased 10 percent in 2012, primarily resulting from improved earnings from WRB and CPChem. Equity in earnings of WRB increased 43 percent, mainly due to higher refining margins in the Central Corridor, combined with processing higher volumes associated with the startup of the coker and refining expansion (CORE) project at the Wood River Refinery. Equity in earnings of CPChem increased 22 percent, primarily resulting from higher ethylene and polyethylene margins. These improvements were partially offset by:

Lower earnings from DCP Midstream, mainly due to a decrease in NGL prices.
Lower earnings from Excel Paralubes, Merey Sweeny, L.P. (MSLP) and MRC, mainly due to lower margins.
The absence of earnings from Colonial Pipeline Company, which was sold in December 2011.

Net gain on dispositions decreased 88 percent in 2012, primarily resulting from 2011 gains associated with the disposition of three pipeline systems, compared with a net gain associated with the sale of Trainer Refinery and associated terminal and pipeline assets in the second quarter of 2012. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.
  
Other income increased $90 million in 2012, primarily associated with a keep-whole payment received from a third party associated with the sale of its ownership interest in REX, gains from trading activities not directly related to our physical business, and income received from ConocoPhillips associated with shared services.

Selling, general and administrative expenses increased 22 percent in 2012, primarily resulting from one-time and incremental costs associated with the Separation, as well as incremental costs relating to a prior retail disposition program.

Impairments in 2012 included our investments in MRC and REX, a marine terminal and associated assets, and equipment formerly associated with the canceled WRG upgrade project. Impairments in 2011 included the Trainer Refinery and associated terminal and pipeline assets. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Interest and debt expense increased $229 million in 2012, primarily due to approximately $7.8 billion of new debt issued in March and April of 2012. For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.

2011 vs. 2010

Sales and other operating revenues increased 34 percent in 2011, while purchased crude oil and products increased 38 percent. These increases were primarily due to higher prices for petroleum products, crude oil and NGL.

Equity in earnings of affiliates increased 61 percent in 2011. The increase primarily resulted from:

Improved earnings from WRB, mainly due to higher refining margins.
Improved earnings from CPChem, primarily due to higher margins and volumes in the olefins and polyolefins business line and the startup of Q-Chem II at the end of 2010.
Improved earnings from DCP Midstream, primarily as a result of higher NGL prices.

Net gain on dispositions increased $1,397 million in 2011. Gains in 2011 primarily resulted from the disposition of three pipeline systems, partially offset by the loss on sale of WRG in 2011. Gains in 2010 mainly included the gain on sale of our 50 percent interest in CFJ Properties. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.


31


Impairments decreased 72 percent in 2011, primarily as a result of the $1,514 million impairment of WRG in 2010, partially offset by the $467 million Trainer Refinery impairment in 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Foreign currency transaction gains increased $119 million in 2011, as a result of the U.S. dollar weakening against the British pound and euro during 2011, compared with a strengthening in 2010.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

32


Segment Results

R&M
 
 
Year Ended December 31
 
2012

 
2011

 
2010

 
Millions of Dollars
Net Income (Loss) Attributable to Phillips 66
 
 
 
 
 
United States
$
3,730

 
3,637

 
1,013

International
(1
)
 
211

 
(867
)
 
$
3,729

 
3,848

 
146

 
 
 
 
 
 
 
Dollars Per Barrel
Refining Margins
 
 
 
 
 
Atlantic Basin/Europe
$
9.36

 
5.96

 
6.81

Gulf Coast
9.02

 
8.01

 
7.24

Central Corridor
25.06

 
19.68

 
7.96

Western/Pacific
11.04

 
9.13

 
8.10

Worldwide
13.42

 
9.70

 
7.38

 
 
 
 
 
 
 
Dollars Per Gallon
U.S. Average Wholesale Prices*
 
 
 
 
 
Gasoline
$
3.00

 
2.94

 
2.24

Distillates
3.19

 
3.12

 
2.30

*Excludes excise taxes.
 
 
 
 
 
 
 
 
 
 
 
 
Thousands of Barrels Daily
Operating Statistics
 
 
 
 
 
Refining operations*
 
 
 
 
 
Atlantic Basin/Europe
 
 
 
 
 
Crude oil capacity
588

 
726

 
1,033

Crude oil processed
555

 
682

 
686

Capacity utilization (percent)
94
%
 
94

 
66

Refinery production
599

 
736

 
746

Gulf Coast
 
 
 
 
 
Crude oil capacity
733

 
733

 
733

Crude oil processed
657

 
658

 
668

Capacity utilization (percent)
90
%
 
90

 
91

Refinery production
743

 
748

 
757

Central Corridor
 
 
 
 
 
Crude oil capacity
470

 
471

 
471

Crude oil processed
454

 
433

 
427

Capacity utilization (percent)
97
%
 
92

 
91

Refinery production
471

 
448

 
443

Western/Pacific
 
 
 
 
 
Crude oil capacity
439

 
435

 
420

Crude oil processed
398

 
393

 
375

Capacity utilization (percent)
91
%
 
91

 
89

Refinery production
419

 
419

 
395

Worldwide
 
 
 
 
 
Crude oil capacity
2,230

 
2,365

 
2,657

Crude oil processed
2,064

 
2,166

 
2,156

Capacity utilization (percent)
93
%
 
92

 
81

Refinery production
2,232

 
2,351

 
2,341

*Includes our share of equity affiliates.
 
 
 
 
 
 
 
 
 
 
 

33


 
Year Ended December 31
 
2012

 
2011

 
2010

 
Thousands of Barrels Daily
Petroleum products sales volumes
 
 
 
 
 
Gasoline
1,218

 
1,309

 
1,292

Distillates
1,141

 
1,219

 
1,189

Other products
502

 
600

 
559

 
2,861

 
3,128

 
3,040



The R&M segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. This segment also includes power generation operations. R&M has operations mainly in the United States, Europe and Asia.

2012 vs. 2011

R&M reported earnings of $3,729 million in 2012, a decrease of $119 million, or 3 percent, compared with 2011. See the “Business Environment and Executive Overview” section for information on industry crack spreads and other market factors impacting this year's results.

The decrease in earnings in 2012 was primarily due to lower net gains on disposition of assets, higher impairments and increased maintenance and repair expense associated with our Bayway Refinery as a result of severe weather disruptions. These items were partially offset by improved worldwide refining margins driven by improved market conditions and optimizing access to lower-cost crude oil feedstocks.

During 2012, R&M included an after-tax gain of $106 million from the sale of the Trainer Refinery and associated terminal and pipeline assets, compared with an after-tax gain of $1,595 million in 2011 on the sale of Seaway Products Pipeline Company and our ownership interest in Colonial Pipeline Company and Seaway Crude Pipeline Company. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Additionally, during 2012, R&M results included an after-tax impairment of $564 million on our equity investment in MRC, an after-tax impairment of $27 million on the Riverhead Terminal and a $42 million after-tax impairment related to equipment formerly associated with the canceled WRG upgrade project, compared with an after-tax impairment of $303 million on the Trainer Refinery during 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Our worldwide refining capacity utilization rate was 93 percent in 2012, compared with 92 percent in 2011. The current year improvement was primarily due to improved market conditions, partially offset by higher turnaround and maintenance activities, as well as severe weather disruptions.

2011 vs. 2010

R&M reported earnings of $3,848 million in 2011, an increase of $3,702 million compared with 2010. The increase in 2011 was primarily due to significantly higher U.S. refining margins, higher refining volumes, higher net gains from asset sales, foreign currency gains and the absence of the 2010 WRG impairment, partially offset by lower international refining margins and the $303 million after-tax impairment and warehouse inventory write-down associated with the idling of the Trainer Refinery in 2011.

In 2011, gains from asset sales of $1,627 million after tax mainly resulted from the sales of Seaway Products Pipeline Company, and our equity investments in Seaway Crude Pipeline Company and Colonial Pipeline Company. These gains were partially offset by the loss on the sale of WRG and related warehouse inventory write-downs. In 2010, gains from asset sales of $113 million after tax were mainly associated with the sale of our 50 percent interest in CFJ Properties.

Our worldwide refining capacity utilization rate was 92 percent in 2011, compared with 81 percent for 2010. The 2011 rate mainly reflected lower turnaround activity and the removal of WRG from our refining capacities effective January 1, 2011, partially offset by higher planned and unplanned downtime.



34


Midstream
 
 
Year Ended December 31
 
2012

 
2011

 
2010

 
Millions of Dollars
 
 
 
 
 
 
Net Income Attributable to Phillips 66*
$
6

 
403

 
262

*Includes DCP Midstream-related earnings:
$
179

 
287

 
210

 
 
 
 
 
 
 
Dollars Per Barrel
Average Sales Prices
 
 
 
 
 
U.S. NGL*
 
 
 
 
 
Equity affiliates
$
34.24

 
50.64

 
41.28

*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
Operating Statistics
 
 
 
 
 
NGL extracted*
201

 
192

 
184

NGL fractionated**
105

 
112

 
120

*Includes our share of equity affiliates.
**Excludes DCP Midstream.


The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract NGL from the raw gas stream. The remaining residue gas is marketed to electric utilities, industrial users and gas marketing companies. Most of the NGL are fractionated—separated into individual components such as ethane, propane and butane—and marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, as well as other NGL fractionation, trading and marketing businesses in the United States. The Midstream segment also includes our 25 percent interest in REX and a one-third direct interest in both the Southern Hills and Sand Hills pipeline projects.

2012 vs. 2011

Earnings from the Midstream segment decreased $397 million in 2012, compared with 2011. The decrease was primarily due to impairments of our equity investment in REX during 2012 and decreased equity earnings from DCP Midstream, partially offset by a keep-whole payment received from a third party associated with the sale of its ownership interest in REX.

During 2012, we recorded after-tax impairments totaling $303 million on our equity investment in REX. The impairments primarily reflect a diminished view of fair value of west-to-east natural gas transmission, due to the impact of shale gas production in the northeast. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

The decrease in earnings of DCP Midstream in 2012 mainly resulted from lower NGL prices and, to a lesser extent, lower natural gas prices, partially offset by lower depreciation and increased gain from the issuance of limited partner units by DCP Midstream Partners, L.P., as described below, and favorable volume impacts due to higher NGL extracted from liquid rich areas (such as Permian Basin, Eagle Ford Shale and Denver-Julesburg Basin). See the “Business Environment and Executive Overview” section for additional information on NGL prices.

During the second quarter of 2012, DCP Midstream completed a review of the estimated depreciable lives of its major classes of properties, plants and equipment. As a result of that review, the depreciable lives were extended. This change in accounting estimate was implemented on a prospective basis, effective April 1, 2012. DCP Midstream estimates its depreciation will be lowered approximately $240 million per year (on a 100 percent basis), which would be an estimated after-tax benefit to our equity in earnings from DCP Midstream of approximately $75 million.


35


DCP Midstream Partners, L.P., a subsidiary of DCP Midstream, issues, from time to time, limited partner units to the public. These issuances benefited our equity in earnings from DCP Midstream by approximately $24 million after tax in 2012, compared with approximately $11 million after tax in 2011.

2011 vs. 2010

Midstream earnings increased 54 percent in 2011, compared with 2010. The increase was primarily due to higher equity earnings from DCP Midstream as a result of significantly higher NGL prices. Indexed NGL prices were 23 percent higher in 2011 than in 2010. Also benefiting 2011 earnings were higher fees received for NGL fractionation services, reflecting favorably renegotiated contracts. These items were partially offset by higher costs at DCP Midstream, primarily due to higher maintenance and repair costs and increased depreciation expense.


Chemicals
 
 
Year Ended December 31
 
2012

 
2011

 
2010

 
Millions of Dollars
 
 
 
 
 
 
Net Income Attributable to Phillips 66
$
823

 
716

 
486

 
 
 
 
 
 
 
Millions of Pounds
CPChem Externally Marketed Sales Volumes*
 
 
 
 
 
Olefins and polyolefins
14,967

 
14,305

 
12,585

Specialties, aromatics and styrenics
6,719

 
6,704

 
6,318

 
21,686

 
21,009

 
18,903

*Represents 100 percent of CPChem's outside sales of produced petrochemical products, as well as commission sales from equity affiliates.


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.

2012 vs. 2011

Earnings from the Chemicals segment increased $107 million, or 15 percent, in 2012, compared with 2011. The increase was primarily driven by higher ethylene and polyethylene margins and lower utility costs, partially offset by a loss on early extinguishment of debt and fixed asset impairments. Ethylene margins benefited from lower feedstock costs, particularly lower ethane and propane prices during 2012. Utility costs benefited from lower natural gas prices during 2012.

During 2012, CPChem retired $1 billion of fixed-rate debt. CPChem also incurred prepayment premiums and wrote off the associated unamortized debt issuance costs. As a result, CPChem recognized a loss on early extinguishment of debt in 2012 of $287 million (100 percent basis), which decreased our equity in earnings from CPChem, on an after-tax basis, by approximately $90 million.
  
In addition, during 2012, CPChem recorded fixed asset impairments totaling $91 million (100 percent basis), which decreased our equity in earnings from CPChem, on an after-tax basis, by $28 million. These asset impairments primarily included certain specialties, aromatics and styrenics asset groups and were mainly driven by decreases in cash flow projections.

2011 vs. 2010

Chemicals segment earnings increased $230 million, or 47 percent, in 2011, compared with 2010. The improvement primarily resulted from higher margins, volumes and equity earnings from CPChem’s olefins and polyolefins business line. The specialties, aromatics and styrenics business line also contributed to the increase in earnings due to higher margins.



36


Corporate and Other
 
 
Millions of Dollars
 
Year Ended December 31
 
2012

 
2011

 
2010

Net Loss Attributable to Phillips 66
 
 
 
 
 
Net interest expense
$
(148
)
 
(11
)
 

Corporate general and administrative expenses
(116
)
 
(76
)
 
(71
)
Technology
(49
)
 
(53
)
 
(44
)
Repositioning costs
(55
)
 

 

Other
(66
)
 
(52
)
 
(44
)
 
$
(434
)
 
(192
)
 
(159
)


2012 vs. 2011

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $137 million in 2012, compared with 2011, primarily due to approximately $7.8 billion of new debt issued in March and April of 2012. For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.

Corporate general and administrative expenses increased $40 million in 2012, compared with 2011. The increase was primarily due to incremental costs and expenses associated with operating as a stand-alone company for the eight months subsequent to the Separation.

Repositioning costs consist of expenses related to the Separation. Expenses incurred in the eight-month period subsequent to the Separation primarily included compensation and benefits, employee relocations and moves, information systems, and shared services costs.

Changes in the "Other" category were mainly due to an after-tax impairment of $16 million on a corporate property in 2012.

2011 vs. 2010

Net interest expense increased $11 million in 2011, primarily as a result of various tax-related adjustments in 2010. Technology’s net loss increased in 2011, mainly due to higher project expenses and lower licensing revenues. The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. Changes in the “Other” category were mainly due to higher environmental expenses associated with sites no longer in operation.



37


CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

 
Millions of Dollars
Except as Indicated
 
 
2012

 
2011

 
2010

 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
4,296

 
5,006

 
2,092

 
Short-term debt
13

 
30

 
29

 
Total debt
6,974

 
391

 
417

 
Total equity
20,806

 
23,293

 
26,026

 
Percent of total debt to capital*
25
%
 
2

 
2

 
Percent of floating-rate debt to total debt
15
%
 
13

 
12

 
*Capital includes total debt and total equity.
 


To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, but rely primarily on cash generated from operating activities. Proceeds from asset dispositions, funds from the issuance of debt, and, prior to April 30, 2012, proceeds from ConocoPhillips have also been sources of liquidity.

During 2012, we generated $4.3 billion in operating cash flows and received $7.8 billion in proceeds from the issuance of debt. During 2012, the primary uses of this available cash were $1.7 billion in capital expenditures and investments; $5.3 billion of distributions to ConocoPhillips as part of the Separation; $1.2 billion of debt repayment; $0.4 billion to repurchase common stock; and $0.3 billion to pay dividends on our common stock. We ended 2012 with cash and cash equivalents of $3.5 billion.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our credit facility programs and 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 in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, repayment of debt and share repurchases.

Significant Sources of Capital

Operating Activities
During 2012, cash of $4,296 million was provided by operating activities, a 14 percent decrease from cash from operations of $5,006 million in 2011. The decrease in the 2012 period primarily reflects the impact of working capital changes. Accounts payable activity lowered cash from operations by $985 million in 2012, primarily reflecting lower commodity prices and volumes. Inventory management had a reduced benefit to working capital in 2012, compared with 2011 (discussed in more detail below). Partially offsetting the negative impact of working capital changes in 2012 were:

Improved U.S. refining margins during 2012, reflecting improved market conditions and increasing access to lower-cost crude oil feedstocks.
Increased distributions from equity affiliates, particularly WRB, whose refineries are located in the Central Corridor region.

During 2011, cash of $5,006 million was provided by operating activities, a 139 percent increase from cash from operations of $2,092 million in 2010. The increase was primarily due to a significant improvement in U.S. refining margins in 2011, particularly in the Central Corridor region; increased distributions from equity affiliates, including CPChem, DCP Midstream and WRB; and inventory liquidations in 2011, compared with inventory builds in 2010.

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.

38



Generally, demand for gasoline is higher during the spring and summer months than during the fall and winter months in most of our markets due to seasonal changes in highway traffic. As a result, the R&M segment's operating results in the first and fourth quarters are generally lower than in the second and third quarters. However, our cash flow from operations may not always follow this seasonal trend in operating results, due to working capital fluctuations associated with inventory management. Historically, we have built inventory levels during the first quarter (thus lowering cash flow from operations) and lowered inventory levels in the fourth quarter (increasing cash flow from operations). In 2012, we used operating cash flows of $1.5 billion in the first quarter to build inventories, while the liquidation of inventories in the fourth quarter provided operating cash flows of $2.3 billion. For the full year 2012, inventory management had a lower benefit to cash from operations, compared with 2011, reflecting that a portion of our normal fourth-quarter inventory draw took place late in the year, such that cash realizations did not transpire prior to December 31.

The level and quality of output from our refineries also impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that caused by margins and prices. Our worldwide crude oil throughput capacity utilization was 93 percent in 2012, compared with 92 percent in 2011. We are forecasting 2013 utilization to remain in the low 90-percent range.

As part of our normal process, we made a scheduled U.S. federal income tax payment in the fourth quarter of 2012 using the IRS safe harbor method for estimated 2012 taxable income. We determined that a portion of that payment is refundable as an overpayment of estimated tax, and we intend to file for a "quick refund" with the IRS in the first quarter of 2013. We expect this refund to benefit cash from operations in the first quarter of 2013 by approximately $350 million.

Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including WRB, DCP Midstream and CPChem. Over the three years ended December 31, 2012, we received distributions of $1,932 million from WRB, $884 million from DCP Midstream and $1,380 million from CPChem. We cannot control the amount of future distributions from equity affiliates; therefore future distributions by these and other equity affiliates are not assured.

Asset Sales
Proceeds from asset sales in 2012 were $286 million, compared with $2,627 million in 2011 and $662 million in 2010. The 2012 proceeds from asset sales included the sale of our refinery and associated terminal and pipeline assets located in Trainer, Pennsylvania, as well as the sale of our Riverhead Terminal located in Riverhead, New York. The 2011 proceeds from asset sales included the sale of our ownership interests in Colonial Pipeline Company and Seaway Crude Pipeline Company, as well as the Wilhelmshaven Refinery and Seaway Products Pipeline Company. The 2010 proceeds included the sale of our 50 percent interest in CFJ Properties.

Credit Facilities
In February 2012, we entered into a five-year revolving credit agreement with a syndicate of financial institutions. Under the terms of the revolving credit agreement, we have a borrowing capacity of up to $4.0 billion. We have not borrowed under this facility. However, as of December 31, 2012, $51 million in letters of credit had been issued that were supported by this facility.

The revolving credit agreement 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 credit agreement 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 revolving credit agreement also provides for customary fees, including administrative agent fees and commitment fees.

During April 2012, a newly formed, wholly owned subsidiary entered into a trade receivables securitization facility. The facility has a term of three years and an aggregate capacity of $1.2 billion. As of December 31, 2012, we had not borrowed under the facility, but we had obtained $166 million in letters of credit under the facility that were collateralized by $166 million of the trade receivables held by the subsidiary.


39


Debt Financings
During March 2012, we issued, through a private placement, $5.8 billion of debt consisting of:

$0.8 billion aggregate principal amount of 1.950% Senior Notes due 2015.
$1.5 billion aggregate principal amount of 2.950% Senior Notes due 2017.
$2.0 billion aggregate principal amount of 4.300% Senior Notes due 2022.
$1.5 billion aggregate principal amount of 5.875% Senior Notes due 2042.

The notes are guaranteed by Phillips 66 Company, a wholly owned subsidiary. In connection with the private placement, we and Phillips 66 Company entered into a Registration Rights Agreement with the initial purchasers of the notes pursuant to which we agreed, for the benefit of the holders of the notes, to use our commercially reasonable efforts to file with the SEC and cause to be effective a registration statement with respect to a registered offer to exchange each series of notes for new notes that are guaranteed by Phillips 66 Company with terms substantially identical in all material respects to such series of notes.

On November 5, 2012, we filed a registration statement on Form S-4 with the SEC in accordance with the Registration Rights Agreement outlining our offer to exchange our $5.8 billion senior notes for substantially identical notes without transfer restrictions. The registration statement was declared effective on November 15, 2012, and the exchange offer for the notes was completed in January 2013 with 99.9 percent participation.

During April 2012, approximately $185 million of previously existing debt was retired. Also during April, we closed on $2.0 billion of new debt in the form of a three-year amortizing term loan. The term loan bears interest at a variable rate based on referenced rates plus a margin dependent upon the credit rating of our senior unsecured long-term debt as determined from time to time by S&P and Moody's. As of December 31, 2012, the interest rate was 1.47 percent. In December 2012, we made a $1.0 billion pre-payment on the term loan.

Our senior unsecured long-term debt has been rated investment grade by S&P and Moody's. 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 $5.2 billion in 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.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations, we enter into agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. In April 2012, in connection with the Separation, we entered into an agreement to guarantee 100 percent of certain outstanding debt obligations of MSLP. At December 31, 2012, the aggregate principal amount of MSLP debt guaranteed by us was $233 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, 2012, was $7.0 billion and our debt-to-capital ratio was 25 percent, within our target range of 20-to-30 percent. In December 2012, we made a $1.0 billion pre-payment on our $2.0 billion term loan. As a result of this prepayment, we have no material scheduled debt maturities in 2013. However, we expect to repay the remaining $1.0 billion of the term loan before year-end 2013.

On February 10, 2013, our Board of Directors declared a quarterly cash dividend of $0.3125 per common share, payable March 1, 2013, to holders of record at the close of business on February 21, 2013. This represented a 25 percent increase over our fourth-quarter 2012 dividend rate of $0.25 per share and a 56 percent increase over our initial dividend rate after the Separation of $0.20 per share.

40


On July 31, 2012, our Board of Directors authorized the repurchase of up to $1 billion of our outstanding common stock. On December 7, 2012, our Board authorized an additional $1 billion share repurchase, bringing the total repurchase program to $2 billion. We began purchases under this program, which has no expiration date, in the third quarter of 2012. The shares are repurchased in the open market at the company's discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements and the Tax Sharing Agreement entered into in connection with the Separation. 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. Through December 31, 2012, $356 million was used to repurchase 7,603,896 shares. Shares of stock repurchased are held as treasury shares.

Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2012.
 
 
Millions of Dollars
 
Payments Due by Period
 
Total

 
Up to
1 Year

 
Years
2-3

 
Years
4-5

 
After
5 Years

 
 
 
 
 
 
 
 
 
 
Debt obligations (a)
$
6,968

 
12

 
1,828

 
1,531

 
3,597

Capital lease obligations
6

 
1

 
2

 
3

 

Total debt
6,974

 
13

 
1,830

 
1,534

 
3,597

Interest on debt
4,044

 
258

 
490

 
421

 
2,875

Operating lease obligations
1,843

 
424

 
714

 
324

 
381

Purchase obligations (b)
133,571

 
46,796

 
20,232

 
13,921

 
52,622

Other long-term liabilities (c)
 
 
 
 
 
 
 
 
 
Asset retirement obligations
314

 
16

 
19

 
17

 
262

Accrued environmental costs
530

 
88

 
117

 
85

 
240

Unrecognized tax benefits (d)
10

 
10

 
(d)

 
(d)

 
(d)

Total
$
147,286

 
47,605

 
23,402

 
16,302

 
59,977

 
(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 and legally binding and that 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 $82,634 million. In addition, $40,478 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 87 years, and $7,245 million from Excel Paralubes, for base oil over the remaining contractual term of 12 years.

Purchase obligations of $1,155 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 2013 through 2017 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 $55 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 $65 million for 2013 and then approximately $200 million per year for the remaining four years. Our minimum funding in 2013 is expected to be $65 million in the United States and $55 million outside the United States.

(d)
Excludes unrecognized tax benefits of $148 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

41


excludes interest and penalties of $15 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
 
2013
Budget

 
2012

 
2011

 
2010

Capital Expenditures and Investments