UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
|
| |
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 20172018
OR
|
| |
o | 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 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
|
| |
Delaware | 74-1828067 |
(State or other jurisdiction of | (I.R.S. Employer |
incorporation or organization) | Identification No.) |
One Valero Way
San Antonio, Texas
(Address of principal executive offices)
78249
(Zip Code)
(210) 345-2000
(Registrant’s telephone number, including area code)
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. Yes þ No o
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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
|
|
Large accelerated filer þ Accelerated filer o Non-accelerated filer o |
Smaller reporting company o Emerging growth company o |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of October 31, 20172018 was 437,581,357.424,308,242.
VALERO ENERGY CORPORATION
TABLE OF CONTENTS
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
VALERO ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(millions of dollars, except par value)
| | | September 30, 2017 | | December 31, 2016 | September 30, 2018 | | December 31, 2017 |
| (unaudited) | | | (unaudited) | | |
ASSETS | | | | | | |
Current assets: | | | | | | |
Cash and temporary cash investments | $ | 5,176 |
| | $ | 4,816 |
| |
Cash and cash equivalents | | $ | 3,551 |
| | $ | 5,850 |
|
Receivables, net | 5,959 |
| | 5,901 |
| 8,249 |
| | 6,922 |
|
Inventories | 6,137 |
| | 5,709 |
| 7,501 |
| | 6,384 |
|
Prepaid expenses and other | 170 |
| | 374 |
| 590 |
| | 156 |
|
Total current assets | 17,442 |
| | 16,800 |
| 19,891 |
| | 19,312 |
|
Property, plant, and equipment, at cost | 39,527 |
| | 37,733 |
| 41,841 |
| | 40,010 |
|
Accumulated depreciation | (12,253 | ) | | (11,261 | ) | (13,413 | ) | | (12,530 | ) |
Property, plant, and equipment, net | 27,274 |
| | 26,472 |
| 28,428 |
| | 27,480 |
|
Deferred charges and other assets, net | 3,272 |
| | 2,901 |
| 3,575 |
| | 3,366 |
|
Total assets | $ | 47,988 |
| | $ | 46,173 |
| $ | 51,894 |
| | $ | 50,158 |
|
LIABILITIES AND EQUITY | | | | | | |
Current liabilities: | | | | | | |
Current portion of debt and capital lease obligations | $ | 121 |
| | $ | 115 |
| $ | 199 |
| | $ | 122 |
|
Accounts payable | 6,677 |
| | 6,357 |
| 10,224 |
| | 8,348 |
|
Accrued expenses | 817 |
| | 694 |
| 553 |
| | 712 |
|
Taxes other than income taxes payable | 1,223 |
| | 1,084 |
| 1,275 |
| | 1,321 |
|
Income taxes payable | 292 |
| | 78 |
| 231 |
| | 568 |
|
Total current liabilities | 9,130 |
| | 8,328 |
| 12,482 |
| | 11,071 |
|
Debt and capital lease obligations, less current portion | 8,364 |
| | 7,886 |
| 8,877 |
| | 8,750 |
|
Deferred income taxes | 7,362 |
| | 7,361 |
| |
Deferred income tax liabilities | | 4,725 |
| | 4,708 |
|
Other long-term liabilities | 1,908 |
| | 1,744 |
| 2,850 |
| | 2,729 |
|
Commitments and contingencies |
| |
|
| |
|
Equity: | | | | | | |
Valero Energy Corporation stockholders’ equity: | | | | | | |
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 673,501,593 shares issued | 7 |
| | 7 |
| 7 |
| | 7 |
|
Additional paid-in capital | 7,060 |
| | 7,088 |
| 7,042 |
| | 7,039 |
|
Treasury stock, at cost; 235,534,764 and 222,000,024 common shares | (12,939 | ) | | (12,027 | ) | |
Treasury stock, at cost; 248,855,313 and 239,603,534 common shares | | (14,334 | ) | | (13,315 | ) |
Retained earnings | 27,135 |
| | 26,366 |
| 30,430 |
| | 29,200 |
|
Accumulated other comprehensive loss | (893 | ) | | (1,410 | ) | (1,235 | ) | | (940 | ) |
Total Valero Energy Corporation stockholders’ equity | 20,370 |
|
| 20,024 |
| 21,910 |
|
| 21,991 |
|
Noncontrolling interests | 854 |
| | 830 |
| 1,050 |
| | 909 |
|
Total equity | 21,224 |
| | 20,854 |
| 22,960 |
| | 22,900 |
|
Total liabilities and equity | $ | 47,988 |
| | $ | 46,173 |
| $ | 51,894 |
| | $ | 50,158 |
|
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(millions of dollars, except per share amounts)
(unaudited)
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 |
Operating revenues (a) | $ | 23,562 |
| | $ | 19,649 |
| | $ | 67,588 |
| | $ | 54,947 |
| |
Revenues (a) | | $ | 30,849 |
| | $ | 23,562 |
| | $ | 88,303 |
| | $ | 67,588 |
|
Cost of sales: | | | | | | | | | | | | | | |
Cost of materials and other | 20,329 |
| | 17,033 |
| | 59,366 |
| | 47,660 |
| 27,701 |
| | 20,329 |
| | 79,317 |
| | 59,366 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) | 1,125 |
| | 1,062 |
| | 3,339 |
| | 3,093 |
| 1,193 |
| | 1,135 |
| | 3,439 |
| | 3,370 |
|
Depreciation and amortization expense | 484 |
| | 458 |
| | 1,457 |
| | 1,391 |
| 504 |
| | 484 |
| | 1,499 |
| | 1,457 |
|
Lower of cost or market inventory valuation adjustment | — |
| | — |
| | — |
| | (747 | ) | |
Total cost of sales | 21,938 |
| | 18,553 |
| | 64,162 |
| | 51,397 |
| 29,398 |
| | 21,948 |
| | 84,255 |
| | 64,193 |
|
Other operating expenses | 44 |
| | — |
| | 44 |
| | — |
| 10 |
| | 44 |
| | 41 |
| | 44 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) | 229 |
| | 192 |
| | 597 |
| | 507 |
| 209 |
| | 225 |
| | 695 |
| | 592 |
|
Depreciation and amortization expense | 13 |
| | 12 |
| | 39 |
| | 35 |
| 13 |
| | 13 |
| | 39 |
| | 39 |
|
Asset impairment loss | — |
| | — |
| | — |
| | 56 |
| |
Operating income | 1,338 |
| | 892 |
| | 2,746 |
| | 2,952 |
| 1,219 |
| | 1,332 |
| | 3,273 |
| | 2,720 |
|
Other income, net | 17 |
| | 12 |
| | 50 |
| | 35 |
| 42 |
| | 23 |
| | 88 |
| | 76 |
|
Interest and debt expense, net of capitalized interest | (114 | ) | | (115 | ) | | (354 | ) | | (334 | ) | (111 | ) | | (114 | ) | | (356 | ) | | (354 | ) |
Income before income tax expense | 1,241 |
| | 789 |
| | 2,442 |
| | 2,653 |
| 1,150 |
| | 1,241 |
| | 3,005 |
| | 2,442 |
|
Income tax expense | 378 |
| | 144 |
| | 686 |
| | 652 |
| 276 |
| | 378 |
| | 674 |
| | 686 |
|
Net income | 863 |
| | 645 |
| | 1,756 |
| | 2,001 |
| 874 |
| | 863 |
| | 2,331 |
| | 1,756 |
|
Less: Net income attributable to noncontrolling interests | 22 |
| | 32 |
| | 62 |
| | 79 |
| 18 |
| | 22 |
| | 161 |
| | 62 |
|
Net income attributable to Valero Energy Corporation stockholders | $ | 841 |
| | $ | 613 |
| | $ | 1,694 |
| | $ | 1,922 |
| $ | 856 |
| | $ | 841 |
| | $ | 2,170 |
| | $ | 1,694 |
|
| | | | | | | | | | | | | | |
Earnings per common share | $ | 1.91 |
| | $ | 1.33 |
| | $ | 3.80 |
| | $ | 4.12 |
| $ | 2.01 |
| | $ | 1.91 |
| | $ | 5.05 |
| | $ | 3.80 |
|
Weighted-average common shares outstanding (in millions) | 439 |
| | 458 |
| | 444 |
| | 465 |
| 425 |
| | 439 |
| | 428 |
| | 444 |
|
| | | | | | | | |
Earnings per common share – assuming dilution | $ | 1.91 |
| | $ | 1.33 |
| | $ | 3.80 |
| | $ | 4.12 |
| $ | 2.01 |
| | $ | 1.91 |
| | $ | 5.05 |
| | $ | 3.80 |
|
Weighted-average common shares outstanding – assuming dilution (in millions) | 441 |
| | 460 |
| | 446 |
| | 467 |
| 427 |
| | 441 |
| | 430 |
| | 446 |
|
Dividends per common share | $ | 0.70 |
| | $ | 0.60 |
| | $ | 2.10 |
| | $ | 1.80 |
| |
_______________________________________________ | | | | | | | | | | | | | | |
Supplemental information: | | | | | | | | | | | | | | |
(a) Includes excise taxes on sales by certain of our international operations | $ | 1,447 |
| | $ | 1,398 |
| | $ | 4,103 |
| | $ | 4,263 |
| $ | 1,338 |
| | $ | 1,447 |
| | $ | 4,272 |
| | $ | 4,103 |
|
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(millions of dollars)
(unaudited)
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 |
Net income | $ | 863 |
| | $ | 645 |
| | $ | 1,756 |
| | $ | 2,001 |
| $ | 874 |
| | $ | 863 |
| | $ | 2,331 |
| | $ | 1,756 |
|
Other comprehensive income (loss): | | | | | | | | | | | | | | |
Foreign currency translation adjustment | 228 |
| | (117 | ) | | 510 |
| | (197 | ) | 23 |
| | 228 |
| | (223 | ) | | 510 |
|
Net gain on pension and other postretirement benefits | 4 |
| | — |
| | 11 |
| | 6 |
| 8 |
| | 4 |
| | 25 |
| | 11 |
|
Other comprehensive income (loss) before income tax expense (benefit) | 232 |
| | (117 | ) | | 521 |
| | (191 | ) | |
Income tax expense (benefit) related to items of other comprehensive income (loss) | 1 |
| | 1 |
| | 3 |
| | (5 | ) | |
Other comprehensive income (loss) before income tax expense | | 31 |
| | 232 |
| | (198 | ) | | 521 |
|
Income tax expense related to items of other comprehensive income (loss) | | 1 |
| | 1 |
| | 5 |
| | 3 |
|
Other comprehensive income (loss) | 231 |
| | (118 | ) | | 518 |
| | (186 | ) | 30 |
| | 231 |
| | (203 | ) | | 518 |
|
Comprehensive income | 1,094 |
| | 527 |
| | 2,274 |
| | 1,815 |
| 904 |
| | 1,094 |
| | 2,128 |
| | 2,274 |
|
Less: Comprehensive income attributable to noncontrolling interests | 23 |
| | 32 |
| | 63 |
| | 80 |
| 21 |
| | 23 |
| | 162 |
| | 63 |
|
Comprehensive income attributable to Valero Energy Corporation stockholders | $ | 1,071 |
| | $ | 495 |
| | $ | 2,211 |
| | $ | 1,735 |
| $ | 883 |
| | $ | 1,071 |
| | $ | 1,966 |
| | $ | 2,211 |
|
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(millions of dollars)
(unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Valero Energy Corporation Stockholders’ Equity | | | | |
| Common Stock | | Additional Paid-in Capital | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total | | Non- controlling Interests | | Total Equity |
Balance as of June 30, 2018 | $ | 7 |
| | $ | 7,032 |
| | $ | (13,923 | ) | | $ | 29,915 |
| | $ | (1,262 | ) | | $ | 21,769 |
| | $ | 1,035 |
| | $ | 22,804 |
|
Net income | — |
| | — |
| | — |
| | 856 |
| | — |
| | 856 |
| | 18 |
| | 874 |
|
Dividends on common stock ($0.80 per share) | — |
| | — |
| | — |
| | (341 | ) | | — |
| | (341 | ) | | — |
| | (341 | ) |
Stock-based compensation expense | — |
| | 11 |
| | — |
| | — |
| | — |
| | 11 |
| | — |
| | 11 |
|
Transactions in connection with stock-based compensation plans | — |
| | — |
| | (15 | ) | | — |
| | — |
| | (15 | ) | | — |
| | (15 | ) |
Stock purchases under purchase programs | — |
| | — |
| | (396 | ) | | — |
| | — |
| | (396 | ) | | — |
| | (396 | ) |
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) |
Other | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | | 7 |
| | 6 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 27 |
| | 27 |
| | 3 |
| | 30 |
|
Balance as of September 30, 2018 | $ | 7 |
| | $ | 7,042 |
| | $ | (14,334 | ) | | $ | 30,430 |
|
| $ | (1,235 | ) |
| $ | 21,910 |
|
| $ | 1,050 |
|
| $ | 22,960 |
|
| | | | | | | | | | | | | | | |
Balance as of June 30, 2017 | $ | 7 |
| | $ | 7,096 |
| | $ | (12,660 | ) | | $ | 26,603 |
| | $ | (1,123 | ) | | $ | 19,923 |
| | $ | 842 |
| | $ | 20,765 |
|
Net income | — |
| | — |
| | — |
| | 841 |
| | — |
| | 841 |
| | 22 |
| | 863 |
|
Dividends on common stock ($0.70 per share) | — |
| | — |
| | — |
| | (309 | ) | | — |
| | (309 | ) | | — |
| | (309 | ) |
Stock-based compensation expense | — |
| | 12 |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | 12 |
|
Transactions in connection with stock-based compensation plans | — |
| | (7 | ) | | (3 | ) | | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) |
Stock purchases under purchase program | — |
| | — |
| | (276 | ) | | — |
| | — |
| | (276 | ) | | — |
| | (276 | ) |
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (11 | ) | | (11 | ) |
Other | — |
| | (41 | ) | | — |
| | — |
| | — |
| | (41 | ) | | — |
| | (41 | ) |
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 230 |
| | 230 |
| | 1 |
| | 231 |
|
Balance as of September 30, 2017 | $ | 7 |
| | $ | 7,060 |
|
| $ | (12,939 | ) |
| $ | 27,135 |
|
| $ | (893 | ) |
| $ | 20,370 |
|
| $ | 854 |
|
| $ | 21,224 |
|
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY (Continued)
(millions of dollars)
(unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Valero Energy Corporation Stockholders’ Equity | | | | |
| Common Stock | | Additional Paid-in Capital | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total | | Non- controlling Interests | | Total Equity |
Balance as of December 31, 2017 | $ | 7 |
| | $ | 7,039 |
| | $ | (13,315 | ) | | $ | 29,200 |
| | $ | (940 | ) | | $ | 21,991 |
| | $ | 909 |
| | $ | 22,900 |
|
Reclassification of stranded income tax effects of Tax Reform per ASU 2018-02 (see Note 1) | — |
| | — |
| | — |
| | 91 |
| | (91 | ) | | — |
| | — |
| | — |
|
Net income | — |
| | — |
| | — |
| | 2,170 |
| | — |
| | 2,170 |
| | 161 |
| | 2,331 |
|
Dividends on common stock ($2.40 per share) | — |
| | — |
| | — |
| | (1,031 | ) | | — |
| | (1,031 | ) | | — |
| | (1,031 | ) |
Stock-based compensation expense | — |
| | 40 |
| | — |
| | — |
| | — |
| | 40 |
| | — |
| | 40 |
|
Transactions in connection with stock-based compensation plans | — |
| | (34 | ) | | (115 | ) | | — |
| | — |
| | (149 | ) | | — |
| | (149 | ) |
Stock purchases under purchase programs | — |
| | — |
| | (904 | ) | | — |
| | — |
| | (904 | ) | | — |
| | (904 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | 32 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (63 | ) | | (63 | ) |
Other | — |
| | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) | | 10 |
| | 7 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (204 | ) | | (204 | ) | | 1 |
| | (203 | ) |
Balance as of September 30, 2018 | $ | 7 |
| | $ | 7,042 |
|
| $ | (14,334 | ) |
| $ | 30,430 |
|
| $ | (1,235 | ) |
| $ | 21,910 |
|
| $ | 1,050 |
|
| $ | 22,960 |
|
| | | | | | | | | | | | | | | |
Balance as of December 31, 2016 | $ | 7 |
| | $ | 7,088 |
| | $ | (12,027 | ) | | $ | 26,366 |
| | $ | (1,410 | ) | | $ | 20,024 |
| | $ | 830 |
| | $ | 20,854 |
|
Net income | — |
| | — |
| | — |
| | 1,694 |
| | — |
| | 1,694 |
| | 62 |
| | 1,756 |
|
Dividends on common stock ($2.10 per share) | — |
| | — |
| | — |
| | (936 | ) | | — |
| | (936 | ) | | — |
| | (936 | ) |
Stock-based compensation expense | — |
| | 37 |
| | — |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
|
Transactions in connection with stock-based compensation plans | — |
| | (34 | ) | | 13 |
| | — |
| | — |
| | (21 | ) | | — |
| | (21 | ) |
Stock purchases under purchase programs | — |
| | — |
| | (925 | ) | | — |
| | — |
| | (925 | ) | | — |
| | (925 | ) |
Issuance of Valero Energy Partners LP common units | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 33 |
| | 33 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (56 | ) | | (56 | ) |
Other | — |
| | (31 | ) | | — |
| | 11 |
| | — |
| | (20 | ) | | (16 | ) | | (36 | ) |
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 517 |
| | 517 |
| | 1 |
| | 518 |
|
Balance as of September 30, 2017 | $ | 7 |
| | $ | 7,060 |
|
| $ | (12,939 | ) |
| $ | 27,135 |
|
| $ | (893 | ) |
| $ | 20,370 |
|
| $ | 854 |
|
| $ | 21,224 |
|
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(millions of dollars)
(unaudited)
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | | 2016 | 2018 | | 2017 |
Cash flows from operating activities: | | | | | | |
Net income | $ | 1,756 |
| | $ | 2,001 |
| $ | 2,331 |
| | $ | 1,756 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
Depreciation and amortization expense | 1,496 |
| | 1,426 |
| 1,538 |
| | 1,496 |
|
Lower of cost or market inventory valuation adjustment | — |
| | (747 | ) | |
Asset impairment loss | — |
| | 56 |
| |
Deferred income tax expense | 80 |
| | 193 |
| |
Deferred income tax expense (benefit) | | (62 | ) | | 80 |
|
Changes in current assets and current liabilities | 544 |
| | 953 |
| (1,174 | ) | | 544 |
|
Changes in deferred charges and credits and other operating activities, net | (54 | ) | | (60 | ) | 60 |
| | (54 | ) |
Net cash provided by operating activities | 3,822 |
| | 3,822 |
| 2,693 |
| | 3,822 |
|
Cash flows from investing activities: | | | | | | |
Capital expenditures | (913 | ) | | (912 | ) | (1,168 | ) | | (913 | ) |
Deferred turnaround and catalyst costs | (381 | ) | | (474 | ) | (661 | ) | | (381 | ) |
Investments in joint ventures | (373 | ) | | — |
| (124 | ) | | (373 | ) |
Acquisition of undivided interest in crude system assets | (72 | ) | | — |
| |
Capital expenditures of certain variable interest entities | | (89 | ) | | — |
|
Peru Acquisition, net of cash acquired | | (466 | ) | | — |
|
Acquisitions of undivided interests | | (181 | ) | | (72 | ) |
Minor acquisitions | | (88 | ) | | — |
|
Other investing activities, net | (1 | ) | | 2 |
| 9 |
| | (1 | ) |
Net cash used in investing activities | (1,740 | ) | | (1,384 | ) | (2,768 | ) | | (1,740 | ) |
Cash flows from financing activities: | | | | | | |
Proceeds from debt issuances or borrowings | — |
| | 1,653 |
| |
Proceeds from debt issuances and borrowings | | 1,329 |
| | — |
|
Repayments of debt and capital lease obligations | (15 | ) | | (28 | ) | (1,352 | ) | | (15 | ) |
Purchase of common stock for treasury | (951 | ) | | (1,167 | ) | (1,081 | ) | | (951 | ) |
Common stock dividends | (936 | ) | | (840 | ) | (1,031 | ) | | (936 | ) |
Proceeds from issuance of Valero Energy Partners LP common units | 36 |
| | 3 |
| — |
| | 36 |
|
Distributions to noncontrolling interests (public unitholders) of Valero Energy Partners LP | (29 | ) | | (22 | ) | |
Distributions to other noncontrolling interests | (27 | ) | | (32 | ) | |
Contributions from noncontrolling interests | | 32 |
| | — |
|
Distributions to noncontrolling interests | | (63 | ) | | (56 | ) |
Other financing activities, net | (21 | ) | | (146 | ) | (15 | ) | | (21 | ) |
Net cash used in financing activities | (1,943 | ) | | (579 | ) | (2,181 | ) | | (1,943 | ) |
Effect of foreign exchange rate changes on cash | 221 |
| | (24 | ) | (43 | ) | | 221 |
|
Net increase in cash and temporary cash investments | 360 |
| | 1,835 |
| |
Cash and temporary cash investments at beginning of period | 4,816 |
| | 4,114 |
| |
Cash and temporary cash investments at end of period | $ | 5,176 |
| | $ | 5,949 |
| |
Net increase (decrease) in cash and cash equivalents | | (2,299 | ) | | 360 |
|
Cash and cash equivalents at beginning of period | | 5,850 |
| | 4,816 |
|
Cash and cash equivalents at end of period | | $ | 3,551 |
| | $ | 5,176 |
|
See Condensed Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| |
1. | BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES |
Basis of Presentation
General
As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole.
These unaudited financial statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Operating results for the nine months ended September 30, 20172018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.2018.
The balance sheet as of December 31, 20162017 has been derived from our audited financial statements as of that date. For further information, refer to our financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 20162017.
Reclassifications
Effective January 1, 2017, we revised our reportable segments to reflect a new reportable segment — VLP. The results of the VLP segment include the results of Valero Energy Partners LP (VLP), our majority-owned master limited partnership. OurCertain prior period segment information has been retrospectively adjusted to reflect our current segment presentation. See Note 10 for additional information.
Certain amounts reported for the three and nine months ended September 30, 2016 have been reclassified to conform to the 20172018 presentation. The changes were primarily due to the separate presentation of depreciation and amortization expense related to operating expenses and general and administrative expenses.
Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.
Accounting Pronouncements Adopted DuringRevenue Recognition
Background
We adopted the Period
In July 2015, theprovisions of Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-11, “InventoryCodification Topic 606, “Revenue from Contracts with Customers,” (Topic 330),606) on January 1, 2018, as described below in “Accounting Pronouncements Adopted on January 1, 2018.” Accordingly, our revenue recognition accounting policy has been revised to simplifyreflect the measurement of inventory measured using the first-in, first-out or average cost methods. The provisions of this ASU require the inventory to be measured at the lower of cost and net realizable value rather than the lower of cost or market. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The provisions of this ASU are to be applied prospectively and are effective for annual reporting periods beginning after December 15, 2016, and interim reporting periods within those annual periods, with early adoption permitted. Our adoption of this ASU effective January 1,standard.
Revised Policy
Our revenues are primarily generated from contracts with customers. We generate revenue from contracts with customers from the sale of products by our refining and ethanol segments. Our VLP segment generates intersegment revenues from transportation and terminaling activities provided to our refining segment that are eliminated in consolidation. Revenues are recognized when we satisfy our performance obligation to transfer products to our customers, which typically occurs at a point in time upon shipment or delivery of the products, and for an amount that reflects the transaction price that is allocated to the performance obligation.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2017 didThe customer is able to direct the use of, and obtain substantially all of the benefits from, the products at the point of shipment or delivery. As a result, we consider control to have transferred upon shipment or delivery because we have a present right to payment at that time, the customer has legal title to the asset, we have transferred physical possession of the asset, and the customer has significant risks and rewards of ownership of the asset.
Our contracts with customers state the final terms of the sale, including the description, quantity, and price for goods sold. Payment is typically due in full within two to ten days of delivery. In the normal course of business, we generally do not affectaccept product returns.
The transaction price is the consideration that we expect to be entitled to in exchange for our financial position or results of operations since the majorityproducts. The transaction price for substantially all of our inventorycontracts is statedgenerally based on commodity market pricing (i.e., variable consideration). As such, this market pricing may be constrained (i.e., not estimable) at last-in, first-out (LIFO).the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. Some of our contracts also contain variable consideration in the form of sales incentives to our customers, such as discounts and rebates. For contracts that include variable consideration, we estimate the factors that determine the variable consideration in order to establish the transaction price.
In October 2016,We have elected to exclude from the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740),” to improvemeasurement of the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. The provisions of this ASU require an entity to recognize the income tax consequences of intra-entity transfers of assets other than inventory immediately when the transfer occurs. These provisionstransaction price all taxes assessed by governmental authorities that are effective for annual reporting periods beginning after December 15, 2017,both imposed on and interim reporting periods within those annual periods, with early adoption permitted. The provisions should be applied on a modified retrospective basisconcurrent with a cumulative-effect adjustmentspecific revenue-producing transaction and collected by us from a customer (e.g., sales tax, use tax, value-added tax, etc.). We continue to include in the transaction price excise taxes that are imposed on certain inventories in our international operations. The amount of such taxes is provided in supplemental information in a footnote on the statements of income.
There are instances where we provide shipping services in relation to the opening balance of retained earnings asgoods sold to our customer. Shipping and handling costs that occur before the customer obtains control of the beginninggoods are deemed to be fulfillment activities and are included in cost of materials and other. We have elected to account for shipping and handling activities that occur after the period of adoption to recognize the income tax consequences of intra-entity transfers of assets that occurred before the adoption date. Our early adoption of this ASU using the modified retrospective method effective January 1, 2017 did not have a material effect on our financial position or results of operations. Adoption of this guidance more accurately reflects the economics of an intra-entity asset transfer when it occurs by eliminating the previous exception that prohibited the recognition of the income tax consequences of an intra-entity asset transfer until the asset had been sold to an outside party.
In October 2016, the FASB issued ASU No. 2016-17, “Consolidation (Topic 810),” to provide guidance on how a reporting entity that is a single decision makercustomer has obtained control of a variable interest entity (VIE) should treat indirect interestsgood as fulfillment activities rather than as a promised service and we have included these activities in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary. The provisionscost of this ASU are effective for annual reporting periods beginning after December 15, 2016,materials and interim reporting periods within those annual periods, with early adoption permitted. The provisions should be applied on a retrospective basis to all relevant prior periods beginning with the fiscal year in which the VIE guidance was adopted with a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Our adoption of this ASU effective January 1, 2017 did not affect our financial position or results of operations.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805),” to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The provisions of this ASU provide a more robust framework to use in determining when a set of assets and activities is a business by clarifying the requirements related to inputs, processes, and outputs. These provisions are to be applied prospectively and are effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted. Our early adoption of this ASU effective January 1, 2017 did not affect our financial position or results of operations. However, more of our future acquisitions may be accounted for as asset acquisitions.other.
Accounting Pronouncements Not Yet Adopted During 2018
In May 2014,Topic 606
As previously noted, we adopted the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” to clarifyprovisions of Topic606 on January 1, 2018. Topic 606 clarifies the principles for recognizing revenue. This new standard is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within those annual periods. We have completed our evaluation of the provisions of this standardrevenue and concluded that our adoption will not change the amount or timing of revenues recognized by us, nor will it affect our financial position. The majority of our revenues are generated from the sale of refined petroleum products and ethanol. These revenues are largely based on the current spot (market) prices of the products sold, which represent consideration specifically allocable to the products being sold on a given day, and we recognize those revenues
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
upon delivery and transfer of title to the products to our customers. The time at which delivery and transfer of title occurs is the point when our control of the products is transferred to our customers and when our performance obligation to our customers is fulfilled. We will adopt this new standard effective January 1, 2018, and we will usesupersedes previous revenue recognition requirements under “Revenue Recognition (Topic 605),” using the modified retrospective method of adoption as permitted by the standard. Under thatthis method, the cumulative effect of initially applying the standard is recognized as an adjustment to the opening balance of retained earnings, and revenues reported in the periods prior to the date of adoption are not changed.We doelected to apply the transition guidance for Topic 606 only to contracts that were not however, expectcompleted as of the date of adoption. There was no material impact to make such anour financial position as a result of adopting Topic 606; therefore, there was no cumulative-effect adjustment to retained earnings. We are currently developingearnings as of January1, 2018. Additionally, there was no material impact to our revenue disclosuresfinancial position or results of operations as of and enhancingfor the three and nine months ended September 30, 2018. See “Revenue Recognition” above for a discussion of our accounting systems to enable the preparationpolicy affected by our adoption of such disclosures as well as the implementation of our internal controls.Topic 606. Also see Note 12 for further
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
information on our revenues. We implemented new processes in order to monitor ongoing compliance with accounting and disclosure requirements.
ASU No. 2016-01
In January 2016, the FASB issued ASUAccounting Standards Update (ASU) No. 2016-01, “Financial Instruments—Overall (Subtopic 825-10),: Recognition and Measurement of Financial Assets and Financial Liabilities,” (ASU No. 2016-01) to enhance the reporting model for financial instruments regarding certain aspects of recognition, measurement, presentation, and disclosure. We adopted the provisions of ASU No. 2016-01 on January1, 2018 using the cumulative-effect method of adoption as required by the ASU. The adoption of this ASU did not affect our financial position or our results of operations as of or for the three and nine months ended September 30, 2018, but it resulted in reduced disclosures as it eliminated the requirement to disclose the methods and significant assumptions used to estimate the fair value of financial instruments.
ASU No. 2017-04
In January 2017, the FASB issued ASU No. 2017-04, “Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” (ASU No. 2017-04) to simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the provisions of this ASU, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, including goodwill (rather than under the current method of comparing the implied fair value of goodwill with its carrying amount), and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment charge should not exceed the carrying amount of goodwill allocated to that reporting unit. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. The provisions of ASU No. 2017-04 are effective for annual or any interim goodwill impairment tests in reporting periods beginning after December 15, 2017, and interim reporting periods within those annual periods. This2019 on a prospective basis, with early adoption permitted. We adopted the provisions of ASU is to be applied using a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption.No. 2017-04 on October 1, 2018. The adoption of this ASU effective January 1, 2018 will not affecthave an immediate effect on our financial position or results of operations, but willmay result in revised disclosures.additional disclosures, as it is applied prospectively to impairment tests performed after the date of adoption.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” to increase the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This new standard is effective for annual reporting periods beginning after December 15, 2018, and interim reporting periods within those annual periods, with early adoption permitted. We will adopt this new standard on January 1, 2019 and we expect to use the modified retrospective method of adoption as permitted by the standard. We are developing enhanced contracting and lease evaluation processes and information systems to support such processes, as well as new and enhanced accounting systems to account for our leases and support the required disclosures. We continue to evaluate the effect that adopting this standard will have on our financial statements and related disclosures.2017-07
In March 2017, the FASB issued ASU No. 2017-07, “Compensation—Retirement Benefits (Topic 715),: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which(ASU No. 2017-07) that requires employers to report the service cost component of net periodic pension cost and net periodic postretirement benefit cost in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. It also requires the other components of net periodic pension cost and net periodic postretirement benefit cost (non-service cost components) to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. This ASU is to be appliedWe retrospectively for income statement items and prospectively for any capitalized benefit costs. Theadopted the provisions of this ASU are effective for annual reporting periods beginning after December 15, 2017, and interim reporting periods within those annual periods, with early adoption permitted.No. 2017-07 on January 1, 2018. The adoption of this ASU effective January 1, 2018 willdid not affect our financial position or results of operations, but willdid result in the reclassification of the non-service cost components from “operatingoperating expenses (excluding depreciation and amortization)”amortization expense) and “generalgeneral and administrative expenses (excluding depreciation and amortization)”amortization expense) to “otherother income, net.”
In May 2017, the FASB issued ASU No. 2017-09, “Compensation—Stock Compensation (Topic 718),” to reduce diversity This resulted in practice, as well as reduce costan increase of $10 million and complexity regarding$31 million in operating expenses (excluding depreciation and amortization expense) and a change to the terms or conditionsdecrease of $4 million and
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
$5 million in general and administrative expenses (excluding depreciation and amortization expense) for the three and nine months ended September 30, 2017, respectively.
ASU No. 2017-09
In May 2017, the FASB issued ASU No. 2017-09, “Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting,” (ASU No. 2017-09) to reduce diversity in practice, as well as reduce cost and complexity regarding a change to the terms or conditions of a share-based payment award. We adopted ASU No. 2017-09 on January 1, 2018. The adoption of this ASU did not have an immediate effect on our financial position or results of operations as it is applied prospectively to an award modified on or after adoption.
ASU No. 2018-02
In February 2018, the FASB issued ASU No. 2018-02, “Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” (ASU No. 2018-02) that allows for the stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017 (Tax Reform) to be reclassified from accumulated other comprehensive income to retained earnings. The provisions of ASU No. 2018-02 are effective for annual reporting periods beginning after December15, 2018, and interim reporting periods within those annual reporting periods, with early adoption permitted. This ASU shall be applied either at the beginning of the annual or interim period of adoption or retrospectively to each period in which the income tax effects of Tax Reform affects the items remaining in accumulated other comprehensive income. We adopted ASU No. 2018-02 on January 1, 2018 and elected to reclassify the stranded income tax effects of Tax Reform from accumulated other comprehensive loss to retained earnings as of the beginning of the interim period of adoption. The adoption of this ASU did not affect our financial position or results of operations but resulted in the reclassification of $91 million of income tax benefits related to Tax Reform from accumulated other comprehensive loss to retained earnings as presented in our statement of equity and in Note 7 under “Accumulated Other Comprehensive Loss.”We release stranded income tax effects from accumulated other comprehensive loss to retained earnings on an individual item basis as those items are reclassified into income.
ASU No. 2018-05
In March 2018, the FASB issued ASU No. 2018-05, “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118,” (ASU No. 2018-05) to amend certain Securities and Exchange Commission (SEC) material in Topic 740 for the income tax accounting implications of the recently issued Tax Reform. This guidance clarifies the application of Topic 740 in situations where a registrant does not have the necessary information available, prepared, or analyzed in reasonable detail to complete the accounting under Topic 740 for certain income tax effects of Tax Reform for the reporting period in which Tax Reform was enacted. See Note 10 for a discussion of the impact of this ASU.
ASU No. 2018-13
In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement,” (ASU No. 2018-13) to improve the effectiveness of disclosures in the notes to financial statements by removing, modifying, and adding certain disclosure requirements for fair value measurements. For example, entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but will be required to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The provisions of ASU No. 2018-13 are effective for all
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
entities for annual reporting periods, beginning after December 15, 2019, and interim periods within those annual reporting periods, with early adoption permitted. Certain provisions of this ASU, primarily related to disclosures, require the prospective method of adoption, with the remaining provisions applied retrospectively. We adopted all of the provisions of ASU No. 2018-13 on October 1, 2018. The adoption of this ASU will not affect our financial position or results of operations, but will result in revised disclosures.
Accounting Pronouncements Not Yet Adopted
Topic 842
In February 2016, the FASB issued “Leases (Topic 842),” (Topic 842) to increase the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This new standard is effective for annual reporting periods beginning after December 15, 2018, and interim reporting periods within those annual reporting periods, with early adoption permitted. We will adopt this new standard on January 1, 2019, and we expect to use the optional transition method, which allows us to recognize a cumulative-effect adjustment to the opening balance of retained earnings at the date of adoption and apply the new disclosure requirements beginning in the period of adoption.
The new standard provides a number of optional practical expedients and we expect to elect the following:
Transition Elections. We expect to elect the package of practical expedients that permits us to not reassess under the new standard our prior conclusions about lease identification, lease classification, and initial direct costs, as well as the practical expedient that permits us to not assess existing land easements under the new standard.
Ongoing Accounting Policy Elections. We expect to elect the short-term lease recognition exemption whereby right-of-use (ROU) assets and lease liabilities will not be recognized for leasing arrangements with terms less than one year, and the practical expedient to not separate lease and non-lease components for all classes of underlying assets other than the marine transportation asset class.
We are enhancing our contracting and lease evaluation systems and related processes, and we are developing a new lease accounting system to capture our leases and support the required disclosures. We have monitored and will continue to monitor the adoption process to ensure compliance with accounting and disclosure requirements. We also continue the integration of our lease accounting system with our general ledger, including the modifications to our related procurement and payment processes during the fourth quarter of 2018.
We anticipate this standard will have a material impact on (i) the recognition of ROU assets and lease liabilities on our balance sheet for our operating leases, (ii) the derecognition of existing assets under construction in a build-to-suit lease arrangement (see Note 6 under “Commitments—MVP Terminal”), and (iii) the presentation of new disclosures about our leasing activities. However, we do not expect adoption to have a material impact on our results of operations or liquidity. We expect our accounting for capital leases to remain substantially unchanged.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ASU No. 2016-13
In June 2016, the FASB issued “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” (ASU No. 2016-13) to improve financial reporting by requiring the immediate recognition of credit losses on financial instruments held by a reporting entity. This ASU requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. It also requires enhanced disclosures, including qualitative and quantitative requirements that provide additional information about the amounts recorded in the financial statements. The provisions of this ASU are effective for annual reporting periods beginning after December 15, 2017,2019, and interim reporting periods within those annual reporting periods, with early adoption permitted.permitted for annual periods beginning after December 15, 2018. The adoptionprovisions of this ASU should be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which this ASU is effective (i.e., the modified-retrospective approach). We expect to adopt ASU No. 2016-13 effective January 1, 2018 will2020 and we do not have an immediate effect onexpect such adoption to affect our financial position or our results of operations as it will be applied prospectively to an award modified on or after adoption.operations.
ASU No. 2017-12
In August 2017, the FASB issued ASU No. 2017-12, “Derivatives and Hedging (Topic 815),: Targeted Improvements to Accounting for Hedging Activities,” (ASU No. 2017-12) to improve and simplify accounting guidance for hedge accounting. The provisions of this ASU are effective for annual reporting periods beginning after December 15, 2018, and interim reporting periods within those annual reporting periods, with early adoption permitted. We use economic hedgesderivative instruments to managehedge our commodity price risk; however, we have not designated these hedgesderivative instruments as fair value or cash flow hedges. Ashedges (see Note 15). Certain provisions of this ASU, primarily related to disclosures, require the prospective method of adoption, with the remaining provisions applied through a result,cumulative-effect adjustment to retained earnings as of the adoption date. The adoption of this ASU No. 2017-12 effective January 1, 2019 is not expected to affect our financial position or results of operations.
Cost ClassificationsASU No. 2018-14
“CostIn August 2018, the FASB issued ASU No. 2018-14, “Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans,” (ASU No. 2018-14) to improve the effectiveness of materialsdisclosures in the notes to financial statements by removing, modifying, and other” primarily includesadding certain disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For example, entities will no longer be required to disclose the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost of materials that are a component of our products sold. These costs includeover the next fiscal year, but will be required to (i) disclose the direct cost of materials (such as crude oilweighted-average interest crediting rates for cash balance plans and other refinery feedstocks, refined petroleum productsplans with promised interest crediting rates and blendstocks, and ethanol feedstocks and products) that are a component(ii) provide an explanation of our products sold; (ii) costs related to the delivery (such as shipping and handling costs) of products sold; (iii) costs related to our environmental credit obligations to comply with various governmental and regulatory programs (such as the cost of renewable identification numbers (RINs) as required by the U.S. Environmental Protection Agency’s (EPA) Renewable Fuel Standard and emission credits under various cap-and-trade systems, as defined in Note 12); (iv)reasons for significant gains and losses on our commodity derivative instruments; and (v) certain excise taxes.
“Operating expenses (excluding depreciation and amortization expense)” include costs to operate our refineries, ethanol plants, and VLP’s logistics assets, except for depreciation and amortization expense. These costs primarily include employee-related expenses, energy and utility costs, catalysts and chemical costs, and repairs and maintenance expenses. “Depreciation and amortization expense” associated with our operations is separately presented in our statement of income as a component of cost of sales and is disclosed by reportable segment in Note 10.
“Other operating expenses” include costs, if any, incurred by our reportable segments that are not associated with our cost of sales.
Prior to the Aruba Disposition discussed below, we recognized an asset impairment loss of $56 million in June 2016 representing all of the remaining carrying value of our long-lived assets in Aruba. These assets were primarily related to changes in the benefit obligation for the period. The provisions of ASU No. 2018-14 are effective for annual reporting periods ending after December 15, 2020 on a retrospective basis for all periods presented, with early adoption permitted. We anticipate adopting ASU No. 2018-14 on December 31, 2018. The adoption of this ASU will not affect our crude oil and refined petroleum products terminal and transshipment facilityfinancial position or results of operations, but will result in Aruba (collectively, the Aruba Terminal), which were included in our refining segment. We recognized the impairment loss at that time because we concluded that it was more likely than not that we would ultimately transfer ownership of these assets to the Government of Aruba (GOA) as a result of agreements entered into in June 2016 between the GOA, CITGO Aruba Refining N.V. (CAR), and CITGO Petroleum Corporation (together with CAR and certain other affiliates, collectively, CITGO) providing for, among other things, therevised disclosures.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
GOA’s leaseASU No. 2018-17
In October 2018, the FASB issued ASU No. 2018-17, “Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities,” (ASU No. 2018-17) to reduce the cost and complexity of financial reporting associated with consolidation of variable interest entities (VIEs). We consolidate a VIE when we have a variable interest in an entity for which we are the primary beneficiary as further described in Note 8. One of the provisions of this ASU amends how a decision maker or service provider determines whether its fee is a variable interest. This guidance requires reporting entities to consider indirect interests held through related parties under common control on a proportional basis rather than as the equivalent of a direct interest in its entirety (as currently required in GAAP). The provisions of this ASU are effective for annual reporting periods beginning after December 15, 2019, and interim reporting periods within those assetsannual reporting periods, with early adoption permitted. The provisions should be applied on a retrospective basis with a cumulative-effect adjustment to CITGO. (See Note 12 for disclosure relatedretained earnings as of the beginning of the earliest period presented. We expect to the methodadopt ASU No. 2018-17 effective January 1, 2019 and we do not expect such adoption to determine fair value.)affect our financial position or results of operations, but may impact future transactions with VIEs.
In September 2016 and in connection with the Aruba Disposition discussed below, our U.S. subsidiaries were unable to collect outstanding debt obligations owed to them by our Aruba subsidiaries, which resulted in the recognition by us of an income tax benefit in the U.S. of $42 million during the three and nine months ended September 30, 2016. We had no income tax effect in Aruba from the cancellation of debt or other effects of the Aruba Disposition because of net operating loss carryforwards associated with our operations in Aruba against which we had previously recorded a full valuation allowance.
EffectivePending Acquisition of Ethanol Plants
On October 1, 2016,8, 2018, we (i) transferred ownershipentered into an agreement to acquire three ethanol plants from two subsidiaries of allGreen Plains Inc. for total cash consideration of our assets in Aruba, other than certain hydrocarbon inventories and working capital, to Refineria di Aruba N.V., an entity wholly-owned by the GOA, (ii) settled our obligations under various agreements with the GOA, including agreements that required us to dismantle our leasehold improvements under certain conditions, and (iii) sold the$300 million plus working capital of our Aruba operations, including hydrocarbon inventories, toapproximately $28 million. The ethanol plants are located in Bluffton, Indiana; Lakota, Iowa; and Riga, Michigan with a combined ethanol production capacity of 280 million gallons per year. We expect the GOAacquisition will be completed in the fourth quarter of 2018.
Pending Merger with Valero Energy Partners LP (VLP)
On October 18, 2018, we entered into a definitive Agreement and CITGO. We refer to this transaction as the “Aruba Disposition.” The agreements associatedPlan of Merger (Merger Agreement and, together with the Aruba Disposition were finalized in September 2016, including approvaltransactions contemplated thereby, the Merger Transaction) with VLP pursuant to which we have agreed to acquire, for cash, all of such agreementsthe outstanding publicly held common units of VLP at a price of $42.25 per common unit, for an aggregate transaction value of approximately $950 million. The Merger Transaction is expected to close as soon as possible following the satisfaction of certain customary closing conditions. We currently consolidate the financial statements of VLP (see Note 8) and we reflect noncontrolling interests on our balance sheet for the portion of VLP’s partners’ capital held by VLP’s public common unitholders. Upon the Aruba Parliament. Weclosing of the Merger Transaction, VLP will become an indirect wholly owned subsidiary and we will no longer own any assets or have any operations in Aruba.reflect its noncontrolling interest on our balance sheet. In addition, we will no longer attribute a portion of VLP’s net income to noncontrolling interests.
Inventories consistedPeru Acquisition
On May 14, 2018, we acquired 100 percent of the issued and outstanding equity interests in Pure Biofuels del Peru S.A.C. (Pure Biofuels) from Pegasus Capital Advisors L.P. and various minority equity holders (collectively, the sellers). Pure Biofuels markets refined petroleum products through a network of logistics assets throughout Peru. Pure Biofuels owns a terminal at the Port of Callao, near Lima, with approximately 1 million barrels of storage capacity for refined petroleum and renewable products. Through one of its
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
subsidiaries, Pure Biofuels also owns a 180,000-barrel storage terminal in Paita, in northern Peru, which is scheduled to commence operations later in 2018. We paid $466 million from available cash on hand, of which $130 million was for working capital. The amount paid for working capital was adjusted in the third quarter of 2018 and is subject to further adjustment pending the final working capital settlement that is expected to be completed in the fourth quarter of 2018. This acquisition, which is referred to as the Peru Acquisition, is consistent with our general business strategy and broadens the geographic diversity of our refining segment.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date, which are preliminary and subject to change after the completion of an independent appraisal that we expect to complete in the fourth quarter of 2018 (in millions):.
|
| | | | | | | |
| September 30, 2017 |
| December 31, 2016 |
Refinery feedstocks | $ | 2,357 |
| | $ | 2,068 |
|
Refined petroleum products and blendstocks | 3,304 |
| | 3,153 |
|
Ethanol feedstocks and products | 223 |
| | 238 |
|
Materials and supplies | 253 |
| | 250 |
|
Inventories | $ | 6,137 |
| | $ | 5,709 |
|
|
| | | |
Current assets, net of cash acquired | $ | 156 |
|
Property, plant, and equipment | 137 |
|
Deferred charges and other assets | 445 |
|
Current liabilities, excluding current portion of debt | (26 | ) |
Debt assumed, including current portion | (137 | ) |
Deferred income tax liabilities | (81 | ) |
Other long-term liabilities | (22 | ) |
Noncontrolling interest | (6 | ) |
Total consideration, net of cash acquired | $ | 466 |
|
InventoriesDeferred charges and other assets primarily include identifiable intangible assets of $210 million and goodwill of $228 million. Identifiable intangible assets, which consist of customer contracts and relationships, are valued atamortized on a straight-line basis over ten years. Goodwill is calculated as the lowerexcess of costthe consideration transferred over the estimated fair values of the underlying tangible and identifiable intangible assets acquired and liabilities assumed. Goodwill represents the future economic benefits expected to be recognized from our expansion into the South American refined petroleum products market arising from other assets acquired that were not individually identified and separately recognized. We determined that the entire balance of goodwill is related to the refining segment. None of the goodwill is expected to be deductible for tax purposes.
The Peru Acquisition purchase agreement provides for a potential earn-out payment based on Pure Biofuels’ earnings for the period from January 1, 2021 through December 31, 2021, or market.if certain events occur, for the period from January 1, 2020 through December 31, 2020. The sellers are entitled to receive the contingent earn-out payments if certain financial metrics are achieved by Pure Biofuels. As of December 31, 2015,September 30, 2018, we haddid not record a valuation reservecontingent liability with respect to this earn-out agreement based on our preliminary estimate of $766 millionits fair value.
Our consolidated statements of income include the results of operations of Pure Biofuels since the date of acquisition, and such results are reflected in order to state our inventories at market. We recorded a change in our lowerthe refining segment. Results of cost or market inventory valuation reserve that resulted in a netbenefitoperations since the date of acquisition, supplemental pro forma financial information, and acquisition-related costs have not been presented for the Peru Acquisition as such information is not material to our results of operations of $747 million for the nine months ended September 30, 2016.
As of September 30, 2017 and December 31, 2016, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by $1.9 billion for both periods. As of September 30, 2017 and December 31, 2016, our non-LIFO inventories accounted for $770 million and $641 million, respectively, of our total inventories.operations.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Inventories consisted of the following (in millions):
|
| | | | | | | |
| September 30, 2018 |
| December 31, 2017 |
Refinery feedstocks | $ | 2,607 |
| | $ | 2,427 |
|
Refined petroleum products and blendstocks | 4,423 |
| | 3,459 |
|
Ethanol feedstocks and products | 211 |
| | 242 |
|
Materials and supplies | 260 |
| | 256 |
|
Inventories | $ | 7,501 |
| | $ | 6,384 |
|
As of September 30, 2018 and December 31, 2017, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by $4.7 billion and $3.0 billion, respectively, and our non-LIFO inventories accounted for $1.4 billion and $1.0 billion, respectively, of our total inventories.
| |
5. | DEBT AND CAPITAL LEASE OBLIGATIONS |
Debt
There was no significant activity related to our debt during the nine months ended September 30, 2017.
During the nine months ended September 30, 2016,2018, the following activity occurred related to our debt:occurred:
We issued in a public offering $750 million aggregate principal amount of our 4.35 percent Senior Notes due June 1, 2028. Gross proceeds from this debt issuance were $749 million before deducting the underwriting discount and other debt issuance costs totaling $7 million. The proceeds were used to redeem our 9.375 percent Senior Notes due March 15, 2019 (9.375 percent Senior Notes) for $787 million, which includes an early redemption fee of $37 million that was charged to other income, net.
VLP borrowed $139issued in a public offering $500 million aggregate principal amount of its 4.5 percent Senior Notes due March 15, 2028. Gross proceeds from this debt issuance were $498 million before deducting the underwriting discount and $210other debt issuance costs totaling $5 million. The proceeds are available only to the operations of VLP and were used to repay the outstanding balance of $410 million under itson VLP’s $750 million senior unsecured revolving credit facility (the VLP Revolver) and $85 million of its notes payable to us, which is eliminated in connection with VLP’s acquisitions from us of the McKee Terminal Services Business in April 2016 and the Meraux and Three Rivers Terminal Services Business in September 2016, respectively;
consolidation.
we issued $1.25 billion of 3.4 percent senior notes due September 15, 2026. Proceeds from this debt issuance totaled $1.246 billion and wereCentral Mexico Terminals, which is the name used in October 2016by us to redeem $750 million aggregate principal amount of our 6.125 percent Senior Notes due 2017 and $200 million aggregate principal amount of our 7.2 percent Senior Notes due 2017. We also incurred $10 million of debt issuance costs; and
onerefer to certain of our consolidated joint venturesVIEs and is further described and defined in Note 8, entered into a C$72combined $340 million senior securedunsecured revolving credit facility.facility (IEnova Revolver) with IEnova (defined in Note 8). Central Mexico Terminals borrowed $71 million and had no repayments under the IEnova Revolver. The IEnova Revolver matures in February 2028. However, IEnova may terminate the IEnova Revolver at any time and demand repayment of all outstanding amounts; therefore, such amounts are reflected in current portion of debt. The IEnova Revolver is available only to the operations of Central Mexico Terminals, and the creditors of Central Mexico Terminals do not have recourse against Valero.
We had outstanding borrowings, letters of credit issued, and availability under our credit facilities as follows (in millions):
|
| | | | | | | | | | | | | | | | | | |
| | | | | | September 30, 2017 |
| | Facility Amount | | Maturity Date | | Outstanding Borrowings | | Letters of Credit Issued | | Availability |
Committed facilities: | | | | | | | | | | |
Valero Revolver | | $ | 3,000 |
| | November 2020 | | $ | — |
| | $ | 367 |
| | $ | 2,633 |
|
VLP Revolver | | $ | 750 |
| | November 2020 | | $ | 30 |
| | $ | — |
| | $ | 720 |
|
Canadian Revolver | | C$ | 25 |
| | November 2017 | | C$ | — |
| | C$ | 10 |
| | C$ | 15 |
|
Accounts receivable sales facility | | $ | 1,300 |
| | July 2018 | | $ | 100 |
| | n/a |
| | $ | 1,200 |
|
Letter of credit facility | | $ | 100 |
| | November 2017 | | n/a |
| | $ | — |
| | $ | 100 |
|
Uncommitted facilities: | | | | | | | | | | |
Letter of credit facilities | | n/a |
| | n/a | | n/a |
| | $ | 212 |
| | n/a |
|
Letters of credit issued as of September 30, 2017 expire at various times in 2017 through 2020.
In June 2017, one of our committed letter of credit facilities with a borrowing capacity of $125 million expired and was not renewed.
As of September 30, 2017 and December 31, 2016, the borrowings on the VLP Revolver bear interest at a variable rate, which was 2.75 percent and 2.3125 percent, respectively. As of September 30, 2017 and
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Outstanding borrowings under the IEnova Revolver bear interest at the three-month LIBO rate for the applicable interest period in effect from time to time plus the applicable margin. The interest rate under the IEnova Revolver is subject to adjustment, with agreement by both parties, based upon changes in market conditions. As of September 30, 2018, the variable rate was 5.987 percent.
We retired $137 million of debt assumed in connection with the Peru Acquisition with available cash on hand.
During the nine months ended September 30, 2017, we had no significant debt activity.
We had outstanding borrowings, letters of credit issued, and availability under our credit facilities as follows (amounts in millions and currency in U.S. dollars, except as noted):
|
| | | | | | | | | | | | | | | | | | |
| | | | | | September 30, 2018 |
| | Facility Amount | | Maturity Date | | Outstanding Borrowings | | Letters of Credit Issued | | Availability |
Committed facilities: | | | | | | | | | | |
Valero Revolver | | $ | 3,000 |
| | November 2020 | | $ | — |
| | $ | 60 |
| | $ | 2,940 |
|
VLP Revolver | | $ | 750 |
| | November 2020 | | $ | — |
| | $ | — |
| | $ | 750 |
|
IEnova Revolver | | $ | 340 |
| | February 2028 | | $ | 71 |
| | n/a |
| | $ | 269 |
|
Canadian Revolver (a) | | C$ | 75 |
| | November 2018 | | C$ | — |
| | C$ | 5 |
| | C$ | 70 |
|
Accounts receivable sales facility | | $ | 1,300 |
| | July 2019 | | $ | 100 |
| | n/a |
| | $ | 1,200 |
|
Letter of credit facility (a) | | $ | 100 |
| | November 2018 | | n/a |
| | $ | — |
| | $ | 100 |
|
Uncommitted facilities: | | | | | | | | | | |
Letter of credit facilities | | n/a |
| | n/a | | n/a |
| | $ | 307 |
| | n/a |
|
___________________
| |
(a) | This facility is expected to be amended to extend the maturity date from November 2018 to November 2019. |
Letters of credit issued as of September 30, 2018 expire at various times in 2018 through 2020.
As of September 30, 2018 and December 31, 2016,2017, the variable interest rate on the accounts receivable sales facility was 1.91242.7959 percent and 1.34222.0387 percent, respectively.
In October 2017, one of our Canadian subsidiaries amended its committed revolving credit facility (the Canadian Revolver) to increase the borrowing capacity from C$25 million to C$75 million under which it may borrow and obtain letters of credit and to extend the maturity date from November 2017 to November 2018.
In connection with VLP’s acquisitions of Parkway Pipeline LLC and Valero Partners Port Arthur, LLC, subsidiaries of ours that own certain pipeline and terminaling assets, VLP borrowed $118 million and $262 million, respectively, under the VLP Revolver on November 1, 2017. These borrowings bear interest at variable rates, which were 2.75 percent and 2.875 percent, respectively, as of November 1, 2017.
Other Disclosures
Interest and debt expense, net of capitalized interest is comprised of the following (in millions):
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 |
Interest and debt expense | $ | 134 |
| | $ | 129 |
| | $ | 402 |
| | $ | 387 |
| $ | 134 |
| | $ | 134 |
| | $ | 417 |
| | $ | 402 |
|
Less capitalized interest | 20 |
| | 14 |
| | 48 |
| | 53 |
| 23 |
| | 20 |
| | 61 |
| | 48 |
|
Interest and debt expense, net of capitalized interest | $ | 114 |
| | $ | 115 |
| | $ | 354 |
| | $ | 334 |
| $ | 111 |
| | $ | 114 |
| | $ | 356 |
| | $ | 354 |
|
Capital Leases
In January 2017, we recognized capital lease assets and related obligations totaling approximately $490 million for the lease of storage tanks located at three of our refineries. These lease agreements have initial terms of 10 years each with successive 10-year automatic renewals.
16
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
5.6. | COMMITMENTS AND CONTINGENCIES |
Commitments
MVP Terminal
We have a 50 percent membership interest in MVP Terminalling, LLC (MVP), a Delaware limited liability company formed in September 2017 with a subsidiary of Magellan Midstream Partners LP (Magellan), to construct, own, and operate the Magellan Valero Pasadena marine terminal (MVP Terminal) located adjacent to the Houston Ship Channel in Pasadena, Texas. The MVP Terminal will contain (i) approximately 5 million barrelsConstruction of storage capacity, (ii) a dock withphases one and two ship berths, and (iii) a three-bay truck rack facility. In connection with our terminaling agreement with MVP, described below, we will have dedicated use of (i) approximately 4 million barrels of storage, (ii) one ship berth, and (iii) the three-bay truck rack facility. Constructionproject began in 2017 with a total estimated cost of $840 million, for phases one and two of the project, of which we expecthave committed to contribute 50 percent (approximately $420 million). The project could expand up to four phases with a total project cost of approximately $1.4 billion if warranted by additional demand and agreed to by Magellan and us. WeSince inception, we have contributed $77$188 million to MVP, through September 2017; no further contributions are required to be madeof which $107 million was contributed during the remainder of 2017.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
nine months ended September 30, 2018.
Concurrent with the formation of MVP, we entered into a terminallingterminaling agreement with MVP to utilize the MVP Terminal upon completion of phase two, of construction, which is expected to occur in early 2020. The terminallingterminaling agreement has an initial term of 12 years with two five-year automatic renewals, and year-to-year renewals thereafter.
Due to our membership interest in MVP and because we determined that the terminallingterminaling agreement was determined to be a capital lease, we are the accounting owner of the MVP Terminal during the construction period. Accordingly, as of September 30, 2017,2018, we recorded an asset of $110$442 million in property, plant, and equipment forrepresenting 100 percent of the construction costs incurred by MVP, as well as capitalized interest incurred by us, and a long-term liability of $55$254 million payable to Magellan. The amounts recorded for the portion of the construction costs associated with the payable to Magellan are noncash investing and financing items, respectively.
Central Texas Pipeline and Terminal Projects
We have committed to a 40 percent undivided interest in a project with a subsidiary of Magellan to jointly build a 135-mile, 16-inchan estimated 130-mile, 20-inch refined petroleum products pipeline with a capacity of up to 150,000 barrels per day from Houston to Hearne, Texas. The pipeline is expected to be completed in mid-2019. OurThe estimated cost forof our 40 percent undivided interest in this pipeline is $170 million. Since inception, capital expenditures have totaled $50 million, of which $43 million was spent during the nine months ended September 30, 2018.
Sunrise Pipeline System
In addition,Effective January 31, 2018, we will separately build, own, and operateentered into a joint ownership agreement with Sunrise Pipeline LLC, a subsidiary of Plains All American Pipeline, L.P. (Plains), that provides us a 20 percent undivided interest in the Sunrise Pipeline System expansion to be constructed by Plains. The Sunrise Pipeline System is expected to contain (i) a 262-mile, 24-inch crude oil pipeline (the Sunrise Pipeline) that originates at Plains’ terminal in Hearne, a terminal in Williamson County,Midland, Texas and a 70-mile, 12-inch refined petroleum products pipeline connecting the two terminals. The new pipeline and terminals are expected to supply up to 60,000ends at Plains’ station in Wichita Falls, Texas with throughput capacity of approximately 500,000 barrels per day, intoand (ii) two 270,000 shell barrel capacity tanks located at the centralColorado City, Texas area. Our estimated coststation. The Sunrise Pipeline System expansion is expected to be placed in service in the fourth quarter of 2018. Capital expenditures totaled $138 million for these projects is $210 million with expected completion in mid-2019.the nine months ended September 30, 2018.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Environmental Matters
We are involved, together with several other companies, in an environmental cleanup in the Village of Hartford, Illinois (the Village) and during 2015, one of these companies assumed the ongoing remediationenvironmental cleanup in the Village pursuant to a federal court order. We had previously conducted an initial response in the Village, along with other companies, pursuant to an administrative order issued by the EPA.U.S. Environmental Protection Agency (EPA). The parties involved in the initial response may have further claims among themselves for costs already incurred.
We also continue to be engaged in site assessment and interim measures at the adjacentour shutdown refinery site, which is adjacent to the Village. During the second quarter of 2018, we acquired as partentered into a consent order with the Illinois EPA that was approved by the state court on July 26, 2018. In the consent order, we assumed the underlying liability for full cleanup of an acquisition in 2005,our shutdown refinery site, and we recorded an adjustment to our existing environmental liability related to this matter, which did not materially affect our financial position or results of operations as of or for the nine months ended September 30, 2018. We continue to seek contribution under Illinois law in state court and are pursuing claims under the Comprehensive Environmental Response, Compensation and Liability Act in litigation withfederal court from other potentially responsible parties andparties. Factors underlying the Illinois EPA relating to the remediationexpected cost of the site. In each of these matters, we have various defenses, limitations, and potential rights for contribution from the other responsible parties. We have recorded a liability for our expected contribution obligations. However, because of the unpredictable nature of these cleanups, the methodology for allocation of liabilities, and the State of Illinois’ failure to directly sue third parties responsible for historic contamination at the site, it is reasonably possible that we could incur a loss in a range of $0 to $200 million in excess of the amount of our accrual to ultimately resolve these matters. Factors underlying this estimated rangecleanup are expectedsubject to change from time to time, and actual results may vary significantly from thisthe current estimate.
Litigation Matters
We are party to claims and legal proceedings arising in the ordinary course of business. We have not recorded a loss contingency liability with respect to some of these matters because we have determined that it is remote that a loss has been incurred. For other matters, we have recorded a loss contingency liability where we have determined that it is probable that a loss has been incurred and that the loss is reasonably estimable. These
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
loss contingency liabilities are not material to our financial position. We re-evaluate and update our loss contingency liabilities as matters progress over time, and we believe that any changes to the recorded liabilities will not be material to our financial position, results of operations, or liquidity.
Reconciliation of BalancesShare Activity
The following is a reconciliation ofThere was no significant share activity during the beginningnine months ended September 30, 2018 and ending balances of equity attributable to our stockholders, equity attributable to noncontrolling interests, and total equity (in millions):2017.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
| Valero Stockholders’ Equity | | Non- controlling Interests (a) | | Total Equity | | Valero Stockholders’ Equity | | Non- controlling Interests (a) | | Total Equity |
Balance as of beginning of period | $ | 20,024 |
| | $ | 830 |
| | $ | 20,854 |
| | $ | 20,527 |
| | $ | 827 |
| | $ | 21,354 |
|
Net income | 1,694 |
| | 62 |
| | 1,756 |
| | 1,922 |
| | 79 |
| | 2,001 |
|
Dividends | (936 | ) | | — |
| | (936 | ) | | (840 | ) | | — |
| | (840 | ) |
Stock-based compensation expense | 37 |
| | — |
| | 37 |
| | 33 |
| | — |
| | 33 |
|
Stock purchases in connection with stock-based compensation plans | (27 | ) | | — |
| | (27 | ) | | (43 | ) | | — |
| | (43 | ) |
Stock purchases under purchase program | (925 | ) | | — |
| | (925 | ) | | (1,120 | ) | | — |
| | (1,120 | ) |
Issuance of Valero Energy Partners LP common units | — |
| | 33 |
| | 33 |
| | — |
| | 6 |
| | 6 |
|
Distributions to noncontrolling interests | — |
| | (56 | ) | | (56 | ) | | — |
| | (54 | ) | | (54 | ) |
Other | (14 | ) | | (16 | ) | | (30 | ) | | 47 |
| | (68 | ) | | (21 | ) |
Other comprehensive income (loss) | 517 |
| | 1 |
| | 518 |
| | (187 | ) | | 1 |
| | (186 | ) |
Balance as of end of period | $ | 20,370 |
| | $ | 854 |
| | $ | 21,224 |
| | $ | 20,339 |
| | $ | 791 |
| | $ | 21,130 |
|
___________________
| |
(a) | The noncontrolling interests relate to third-party ownership interests in VIEs for which we are the primary beneficiary and therefore consolidate. See Note 7 for information about our consolidated VIEs. |
Common Stock Dividends
On October 31, 2018, our board of directors declared a quarterly cash dividend of $0.80 per common share payable on December 12, 2018 to holders of record at the close of business on November 20, 2018.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Share Activity
Activity in the number of shares of common stock and treasury stock was as follows (in millions):
|
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
| Common Stock | | Treasury Stock | | Common Stock | | Treasury Stock |
Balance as of beginning of period | 673 |
| | (222 | ) | | 673 |
| | (200 | ) |
Transactions in connection with stock-based compensation plans: | | | | | | | |
Stock issuances | — |
| | — |
| | — |
| | 1 |
|
Stock purchases | — |
| | — |
| | — |
| | (1 | ) |
Stock purchases under purchase program | — |
| | (14 | ) | | — |
| | (20 | ) |
Balance as of end of period | 673 |
| | (236 | ) | | 673 |
| | (220 | ) |
Common Stock Dividends
On November 1, 2017, our board of directors declared a quarterly cash dividend of $0.70 per common share payable on December 12, 2017 to holders of record at the close of business on November 21, 2017.
Accumulated Other Comprehensive Loss
Changes in accumulated other comprehensive loss by component, net of tax, were as follows (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
| Foreign Currency Translation Adjustment | | Defined Benefit Plans Items | | Total | | Foreign Currency Translation Adjustment | | Defined Benefit Plans Items | | Total |
Balance as of beginning of period | $ | (1,021 | ) | | $ | (389 | ) | | $ | (1,410 | ) | | $ | (605 | ) | | $ | (328 | ) | | $ | (933 | ) |
Other comprehensive income (loss) before reclassifications | 509 |
| | — |
| | 509 |
| | (198 | ) | | 8 |
| | (190 | ) |
Amounts reclassified from accumulated other comprehensive loss | — |
| | 8 |
| | 8 |
| | — |
| | 3 |
| | 3 |
|
Net other comprehensive income (loss) | 509 |
| | 8 |
| | 517 |
| | (198 | ) | | 11 |
| | (187 | ) |
Balance as of end of period | $ | (512 | ) | | $ | (381 | ) | | $ | (893 | ) | | $ | (803 | ) | | $ | (317 | ) | | $ | (1,120 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 |
| Foreign Currency Translation Adjustment | | Defined Benefit Plans Items | | Total | | Foreign Currency Translation Adjustment | | Defined Benefit Plans Items | | Total |
Balance as of beginning of period | $ | (507 | ) | | $ | (433 | ) | | $ | (940 | ) | | $ | (1,021 | ) | | $ | (389 | ) | | $ | (1,410 | ) |
Other comprehensive income (loss) before reclassifications | (224 | ) | | — |
| | (224 | ) | | 509 |
| | — |
| | 509 |
|
Amounts reclassified from accumulated other comprehensive loss | — |
| | 20 |
| | 20 |
| | — |
| | 8 |
| | 8 |
|
Other comprehensive income (loss) | (224 | ) | | 20 |
| | (204 | ) | | 509 |
| | 8 |
| | 517 |
|
Reclassification of stranded income tax effects of Tax Reform to retained earnings per ASU 2018-02 (see Note 1) | — |
| | (91 | ) | | (91 | ) | | — |
| | — |
| | — |
|
Balance as of end of period | $ | (731 | ) | | $ | (504 | ) | | $ | (1,235 | ) | | $ | (512 | ) | | $ | (381 | ) | | $ | (893 | ) |
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
7.8. | VARIABLE INTEREST ENTITIES |
Consolidated VIEs
In the normal course of business, we have financial interests in certain entities that have been determined to be VIEs. We consolidate a VIE when we have a variable interest in an entity for which we are the primary beneficiary such that we have (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially bebeneficiary. Our significant to the VIE. In order to make this determination, we evaluated our contractual arrangements with the VIEs, including arrangements for the use of assets, purchases of products and services, debt, equity, or management of operating activities.
Our significantconsolidated VIE’s include:
VLP, a publicly traded master limited partnership formed to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets; and
Diamond Green Diesel Holdings LLC (DGD), a joint venture formed to construct and operate a biodiesel plant that processes animal fats, used cooking oils, and other vegetable oils into renewable green diesel.diesel; and
Central Mexico Terminals (previously referred to by us as VPM Terminals), a collective group of three subsidiaries of Infraestructura Energetica Nova, S.A.B. de C.V. (IEnova), a Mexican company and subsidiary of Sempra Energy, a U.S. public company. We have terminaling agreements with Central Mexico Terminals that represent variable interests. We do not have an ownership interest in Central Mexico Terminals.
The VIEs’ assets can only be used to settle their own obligations and the VIEs’ creditors have no recourse to our assets. We do not provide financial guarantees to our VIEs. Although we have provided credit facilities to thesome of our VIEs in support of their construction or acquisition activities, these transactions are eliminated
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
in consolidation. Our financial position, results of operations, and cash flows are impacted by our consolidated VIEs’ performance, net of intercompany eliminations, to the extent of our ownership interest in each VIE.
The following tables present summarized balance sheet information for the significant assets and liabilities of our VIEs, which are included in our balance sheets (in millions).
|
| | | | | | | | | | | | | | | |
| September 30, 2017 |
| VLP | | DGD | | Other | | Total |
Assets | | | | | | | |
Cash and temporary cash investments | $ | 116 |
| | $ | 148 |
| | $ | 14 |
| | $ | 278 |
|
Other current assets | 1 |
| | 54 |
| | — |
| | 55 |
|
Property, plant, and equipment, net | 955 |
| | 391 |
| | 129 |
| | 1,475 |
|
Liabilities | | | | | | | |
Current liabilities | $ | 26 |
| | $ | 25 |
| | $ | 7 |
| | $ | 58 |
|
Debt and capital lease obligations, less current portion | 525 |
| | — |
| | 45 |
| | 570 |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | | | | | | | | | | | | | |
| September 30, 2018 |
| VLP | | DGD | | Central Mexico Terminals | | Other | | Total |
Assets | | | | | | | | | |
Cash and cash equivalents | $ | 128 |
| | $ | 78 |
| | $ | 1 |
| | $ | 20 |
| | $ | 227 |
|
Other current assets | 1 |
| | 94 |
| | 17 |
| | 51 |
| | 163 |
|
Property, plant, and equipment, net | 1,414 |
| | 567 |
| | 138 |
| | 118 |
| | 2,237 |
|
Liabilities | | | | | | | | | |
Current liabilities, including current portion of debt and capital lease obligations | $ | 34 |
| | $ | 40 |
| | $ | 95 |
| | $ | 5 |
| | $ | 174 |
|
Debt and capital lease obligations, less current portion | 990 |
| | — |
| | — |
| | 38 |
| | 1,028 |
|
| | | December 31, 2016 | December 31, 2017 |
| VLP | | DGD | | Other | | Total | VLP | | DGD | | Central Mexico Terminals | | Other | | Total |
Assets | | | | | | | | | | | | | | | | |
Cash and temporary cash investments | $ | 71 |
| | $ | 167 |
| | $ | 15 |
| | $ | 253 |
| |
Cash and cash equivalents | | $ | 42 |
| | $ | 123 |
| | $ | 1 |
| | $ | 13 |
| | $ | 179 |
|
Other current assets | 3 |
| | 87 |
| | — |
| | 90 |
| 2 |
| | 66 |
| | 4 |
| | — |
| | 72 |
|
Property, plant, and equipment, net | 865 |
| | 355 |
| | 133 |
| | 1,353 |
| 1,416 |
| | 435 |
| | 51 |
| | 127 |
| | 2,029 |
|
Liabilities | | | | | | | | | | | | | | | | |
Current liabilities | $ | 15 |
| | $ | 17 |
| | $ | 7 |
| | $ | 39 |
| |
Current liabilities, including current portion of debt and capital lease obligations | | $ | 27 |
| | $ | 33 |
| | $ | 26 |
| | $ | 9 |
| | $ | 95 |
|
Debt and capital lease obligations, less current portion | 525 |
| | — |
| | 46 |
| | 571 |
| 905 |
| | — |
| | — |
| | 43 |
| | 948 |
|
Non-Consolidated VIEs
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations and are primarily accounted for as equity investments. However,MVP is one of our non-consolidated VIEs and is accounted for under owner accounting and is further described below and in Note 5.
Asas described in Note 5, we have a 50 percent membership interest in MVP, which was formed to construct, own, and operate the MVP Terminal. MVP was determined to be a VIE because the power to direct the activities that most significantly impact its economic performance is not required to be held by its two members, but is held by Magellan, as operator under a construction, operating, and management agreement with MVP. For this reason and because Magellan holds a 50 percent interest in MVP that provides it with significant economic rights and obligations, we determined that we are not the primary beneficiary.6. As of September 30, 2017,2018, our maximum exposure to loss was $77$188 million, which represents our equity investment in MVP. We have not provided any financial support to MVP other than amounts previously required by our membership interest.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The components of net periodic benefit cost (credit) related to our defined benefit plans were as follows (in millions):
|
| | | | | | | | | | | | | | | |
| Pension Plans | | Other Postretirement Benefit Plans |
| 2017 | | 2016 | | 2017 | | 2016 |
Three months ended September 30: | | | | | | | |
Service cost | $ | 31 |
| | $ | 28 |
| | $ | 1 |
| | $ | 2 |
|
Interest cost | 21 |
| | 21 |
| | 3 |
| | 3 |
|
Expected return on plan assets | (37 | ) | | (35 | ) | | — |
| | — |
|
Amortization of: | | | | | | | |
Net actuarial (gain) loss | 13 |
| | 13 |
| | — |
| | (1 | ) |
Prior service credit | (5 | ) | | (5 | ) | | (4 | ) | | (4 | ) |
Special charges (credits) | 3 |
| | (7 | ) | | — |
| | — |
|
Net periodic benefit cost | $ | 26 |
| | $ | 15 |
| | $ | — |
| | $ | — |
|
| | | | | | | |
Nine months ended September 30: | | | | | | | |
Service cost | $ | 92 |
| | $ | 84 |
| | $ | 4 |
| | $ | 5 |
|
Interest cost | 64 |
| | 63 |
| | 8 |
| | 9 |
|
Expected return on plan assets | (112 | ) | | (104 | ) | | — |
| | — |
|
Amortization of: | | | | | | | |
Net actuarial (gain) loss | 40 |
| | 37 |
| | (2 | ) | | (1 | ) |
Prior service credit | (15 | ) | | (15 | ) | | (12 | ) | | (12 | ) |
Special charges (credits) | 3 |
| | (7 | ) | | — |
| | — |
|
Net periodic benefit cost (credit) | $ | 72 |
| | $ | 58 |
| | $ | (2 | ) | | $ | 1 |
|
We contributed $104 million and $132 million, respectively, to our pension plans and $17 million and $12 million, respectively, to our other postretirement benefit plans during the nine months ended September 30, 2017 and 2016. Of the $104 million contributed to our pension plans during the nine months ended September 30, 2017, $80 million was discretionary and was contributed during the third quarter of 2017.
As a result of the discretionary pension contributions discussed above, our expected contributions to our pension plans have increased to $108 million for 2017. Our anticipated contributions to our other postretirement benefit plans during 2017 have not changed from the amount previously disclosed in our financial statements for the year ended December 31, 2016.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
9. | EARNINGS PER COMMON SHAREEMPLOYEE BENEFIT PLANS |
Earnings per common shareThe components of net periodic benefit cost (credit) related to our defined benefit plans were computed as follows (dollars and shares in millions, except per share amounts)(in millions):
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2017 | | 2016 |
| Participating Securities | | Common Stock | | Participating Securities | | Common Stock |
Earnings per common share: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 841 |
| | | | $ | 613 |
|
Less dividends paid: | | | | | | | |
Common stock | | | 308 |
| | | | 275 |
|
Participating securities | | | 1 |
| | | | 1 |
|
Undistributed earnings | | | $ | 532 |
| | | | $ | 337 |
|
Weighted-average common shares outstanding | 2 |
| | 439 |
| | 1 |
| | 458 |
|
Earnings per common share: | | | | | | | |
Distributed earnings | $ | 0.70 |
| | $ | 0.70 |
| | $ | 0.60 |
| | $ | 0.60 |
|
Undistributed earnings | 1.21 |
| | 1.21 |
| | 0.73 |
| | 0.73 |
|
Total earnings per common share | $ | 1.91 |
| | $ | 1.91 |
| | $ | 1.33 |
| | $ | 1.33 |
|
| | | | | | | |
Earnings per common share – assuming dilution: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 841 |
| | | | $ | 613 |
|
Weighted-average common shares outstanding | | | 439 |
| | | | 458 |
|
Common equivalent shares | | | 2 |
| | | | 2 |
|
Weighted-average common shares outstanding – assuming dilution | | | 441 |
| | | | 460 |
|
Earnings per common share – assuming dilution | | | $ | 1.91 |
| | | | $ | 1.33 |
|
|
| | | | | | | | | | | | | | | |
| Pension Plans | | Other Postretirement Benefit Plans |
| 2018 | | 2017 | | 2018 | | 2017 |
Three months ended September 30: | | | | | | | |
Service cost | $ | 33 |
| | $ | 31 |
| | $ | 2 |
| | $ | 1 |
|
Interest cost | 22 |
| | 21 |
| | 2 |
| | 3 |
|
Expected return on plan assets | (40 | ) | | (37 | ) | | — |
| | — |
|
Amortization of: | | | | | | | |
Net actuarial (gain) loss | 16 |
| | 13 |
| | (1 | ) | | — |
|
Prior service credit | (5 | ) | | (5 | ) | | (2 | ) | | (4 | ) |
Special charges | 2 |
| | 3 |
| | — |
| | — |
|
Net periodic benefit cost | $ | 28 |
| | $ | 26 |
| | $ | 1 |
| | $ | — |
|
| | | | | | | |
Nine months ended September 30: | | | | | | | |
Service cost | $ | 100 |
| | $ | 92 |
| | $ | 5 |
| | $ | 4 |
|
Interest cost | 68 |
| | 64 |
| | 7 |
| | 8 |
|
Expected return on plan assets | (122 | ) | | (112 | ) | | — |
| | — |
|
Amortization of: | | | | | | | |
Net actuarial (gain) loss | 49 |
| | 40 |
| | (2 | ) | | (2 | ) |
Prior service credit | (14 | ) | | (15 | ) | | (8 | ) | | (12 | ) |
Special charges | 7 |
| | 3 |
| | — |
| | — |
|
Net periodic benefit cost (credit) | $ | 88 |
| | $ | 72 |
| | $ | 2 |
| | $ | (2 | ) |
The components of net periodic benefit cost (credit) other than the service cost component (i.e., the non-service cost components) are included in the line item other income, net in the statements of income.
We contributed $132 million and $104 million, respectively, to our pension plans and $15 million and $17 million, respectively, to our other postretirement benefit plans during the nine months ended September 30, 2018 and 2017. Of the $132 million contributed to our pension plans during the nine months ended September 30, 2018, $110 million was discretionary and was contributed during the third quarter of 2018.
As a result of the discretionary pension contributions discussed above, our expected contributions to our pension plans have increased to $141 million for 2018. Our anticipated contributions to our other postretirement benefit plans during 2018 have not changed from the amount previously disclosed in our financial statements for the year ended December 31, 2017.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
| Participating Securities | | Common Stock | | Participating Securities | | Common Stock |
Earnings per common share: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 1,694 |
| | | | $ | 1,922 |
|
Less dividends paid: | | | | | | | |
Common stock | | | 933 |
| | | | 837 |
|
Participating securities | | | 3 |
| | | | 3 |
|
Undistributed earnings | | | $ | 758 |
| | | | $ | 1,082 |
|
Weighted-average common shares outstanding | 2 |
| | 444 |
| | 1 |
| | 465 |
|
Earnings per common share: | | | | | | | |
Distributed earnings | $ | 2.10 |
| | $ | 2.10 |
| | $ | 1.80 |
| | $ | 1.80 |
|
Undistributed earnings | 1.70 |
| | 1.70 |
| | 2.32 |
| | 2.32 |
|
Total earnings per common share | $ | 3.80 |
| | $ | 3.80 |
| | $ | 4.12 |
| | $ | 4.12 |
|
| | | | | | | |
Earnings per common share – assuming dilution: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 1,694 |
| | | | $ | 1,922 |
|
Weighted-average common shares outstanding | | | 444 |
| | | | 465 |
|
Common equivalent shares | | | 2 |
| | | | 2 |
|
Weighted-average common shares outstanding – assuming dilution | | | 446 |
| | | | 467 |
|
Earnings per common share – assuming dilution | | | $ | 3.80 |
| | | | $ | 4.12 |
|
Participating securities include restricted stock and performance awards granted under our 2011 Omnibus Stock Incentive Plan.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On December 22, 2017, Tax Reform was enacted, which resulted in significant changes to the U.S. Internal Revenue Code of 1986, as amended (the Code), and was effective beginning on January 1, 2018. Tax Reform introduced significant and complex changes to the Code, and regulatory guidance from the Internal Revenue Service (IRS) is needed in order to properly account for many of the changes. In response, the SEC issued Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act,” that was codified through the issuance of ASU No. 2018-05 as described in Note 1, which requires that the effects of Tax Reform be recorded for items where the accounting is complete, as well as for items where a reasonable estimate can be made (referred to as provisional amounts). For items where reasonable estimates cannot be made, provisional amounts should not be recorded and those items should continue to be accounted for under the Code prior to changes from Tax Reform until a reasonable estimate can be made.
We recorded the effects of Tax Reform for the year ended December 31, 2017 in accordance with ASU No. 2018-05, which included provisional amounts associated with the one-time transition tax on the deemed repatriation of previously undistributed accumulated earnings and profits of our international subsidiaries. We also identified items where reasonable estimates could not be made at that time.
We did not revise our initial provisional estimate during the three and nine months ended September 30, 2018, and we have not completed our accounting for the income tax effects of Tax Reform. We continue to gather additional information in order to revise our initial estimates. Any adjustments to our initial estimates will be recorded in the fourth quarter of 2018.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
11. | EARNINGS PER COMMON SHARE |
Earnings per common share were computed as follows (dollars and shares in millions, except per share amounts):
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2018 | | 2017 |
| Participating Securities | | Common Stock | | Participating Securities | | Common Stock |
Earnings per common share: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 856 |
| | | | $ | 841 |
|
Less dividends paid: | | | | | | | |
Common stock | | | 340 |
| | | | 308 |
|
Participating securities | | | 1 |
| | | | 1 |
|
Undistributed earnings | | | $ | 515 |
| | | | $ | 532 |
|
Weighted-average common shares outstanding | 1 |
| | 425 |
| | 2 |
| | 439 |
|
Earnings per common share: | | | | | | | |
Distributed earnings | $ | 0.80 |
| | $ | 0.80 |
| | $ | 0.70 |
| | $ | 0.70 |
|
Undistributed earnings | 1.21 |
| | 1.21 |
| | 1.21 |
| | 1.21 |
|
Total earnings per common share | $ | 2.01 |
| | $ | 2.01 |
| | $ | 1.91 |
| | $ | 1.91 |
|
| | | | | | | |
Earnings per common share – assuming dilution: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 856 |
| | | | $ | 841 |
|
Weighted-average common shares outstanding | | | 425 |
| | | | 439 |
|
Common equivalent shares | | | 2 |
| | | | 2 |
|
Weighted-average common shares outstanding – assuming dilution | | | 427 |
| | | | 441 |
|
Earnings per common share – assuming dilution | | | $ | 2.01 |
| | | | $ | 1.91 |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 |
| Participating Securities | | Common Stock | | Participating Securities | | Common Stock |
Earnings per common share: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 2,170 |
| | | | $ | 1,694 |
|
Less dividends paid: | | | | | | | |
Common stock | | | 1,028 |
| | | | 933 |
|
Participating securities | | | 3 |
| | | | 3 |
|
Undistributed earnings | | | $ | 1,139 |
| | | | $ | 758 |
|
Weighted-average common shares outstanding | 1 |
| | 428 |
| | 2 |
| | 444 |
|
Earnings per common share: | | | | | | | |
Distributed earnings | $ | 2.40 |
| | $ | 2.40 |
| | $ | 2.10 |
| | $ | 2.10 |
|
Undistributed earnings | 2.65 |
| | 2.65 |
| | 1.70 |
| | 1.70 |
|
Total earnings per common share | $ | 5.05 |
| | $ | 5.05 |
| | $ | 3.80 |
| | $ | 3.80 |
|
| | | | | | | |
Earnings per common share – assuming dilution: | | | | | | | |
Net income attributable to Valero stockholders | | | $ | 2,170 |
| | | | $ | 1,694 |
|
Weighted-average common shares outstanding | | | 428 |
| | | | 444 |
|
Common equivalent shares | | | 2 |
| | | | 2 |
|
Weighted-average common shares outstanding – assuming dilution | | | 430 |
| | | | 446 |
|
Earnings per common share – assuming dilution | | | $ | 5.05 |
| | | | $ | 3.80 |
|
Participating securities include restricted stock and performance awards granted under our 2011 Omnibus Stock Incentive Plan.
| |
12. | REVENUES AND SEGMENT INFORMATION |
EffectiveRevenue from Contracts with Customers
Disaggregation of Revenue
Revenue is presented in the table below under “Segment Information” disaggregated by product because this is the level of disaggregation that management has determined to be beneficial to users of our financial statements.
Receivables from Contracts with Customers
Our receivables from contracts with customers are included in receivables, net and totaled $6.0 billion and $5.7 billion as of September 30, 2018 and January 1, 2017, we revised2018, respectively.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Remaining Performance Obligations
The majority of our reportable segmentscontracts with customers are spot contracts and therefore have no remaining performance obligations. Our remaining contracts with customers are primarily term contracts. The transaction price for these term contracts includes an immaterial fixed amount and variable consideration (i.e., a commodity price). The variable consideration is allocated entirely to aligna wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation; therefore, the variable consideration is not included in the remaining performance obligation. As of September 30, 2018, after excluding contracts with certain changes in how our chief operating decision maker manages and allocates resourcesan original expected duration of one year or less, the aggregate amount of the transaction price allocated to our business. Accordingly, we created a new reportable segment — VLP. The results ofremaining performance obligations was not material as the VLP segment, which include the results of our majority-owned master limited partnership referred to by the same name, were transferred from the refining segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation.transaction price for these contracts includes only an immaterial fixed amount.
As a result, weSegment Information
We have three reportable segments as follows:
Refining– refining, ethanol, and VLP. Each segment includes our refining operations, the associated marketing activities, and certain logistics assets that support our refining operations that are not owned by VLP;
Ethanol segment includes our ethanol operations, the associated marketing activities, and logistics assets that support our ethanol operations; and
VLP segment includes the results of VLP, which provides transportation and terminaling services in support of our refining segment.
Operations that are not included in any of the reportable segments are included in the corporate category.
Our reportable segments are is a strategic business unitsunit that offeroffers different products and services. They are managed separately as each business requiresservices by employing unique technologies and marketing strategies. Performancestrategies and whose operations and operating performance are managed and evaluated separately. Operating performance is evaluatedmeasured based on segmentthe operating income generated by the segment, which includes revenues and expenses that are directly attributable to the management of the respective segment. Intersegment sales are generally derived from transactions made at prevailing market rates. The following is a description of each segment’s business operations.
The refining segment includes the operations of our 15 petroleum refineries, the associated marketing activities, and certain logistics assets that support our refining operations that are not owned by VLP. The principal products manufactured by our refineries and sold by this segment include gasolines and blendstocks (e.g., conventional gasolines, premium gasolines, and gasoline meeting the specifications of the California Air Resources Board (CARB)), distillates (e.g., diesel, low-sulfur diesel, ultra-low-sulfur diesel, CARB diesel, jet fuel, and other distillates), and other products (e.g., asphalt, petrochemicals, lubricants, and other refined petroleum products).
The ethanol segment includes the operations of our 11 ethanol plants, the associated marketing activities, and logistics assets that support our ethanol operations. The principal products manufactured by our ethanol plants are ethanol and distillers grains. We sell some ethanol to our refining segment for blending into gasoline, which is sold to that segment’s customers as a finished gasoline product.
The VLP segment includes the results of VLP. VLP generates revenue from transportation and terminaling activities provided to our refining segment. All of VLP’s revenues are intersegment revenues that are generated under commercial agreements with our refining segment. Revenues generated under these agreements are eliminated in consolidation.
Operations that are not included in any of the reportable segments are included in the corporate category.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table reflects activity related to ourthe components of operating income by reportable segmentssegment (in millions):
| | | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Three months ended September 30, 2017: | | | | | | | | | | |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 22,728 |
| | $ | 834 |
| | $ | — |
| | $ | — |
| | $ | 23,562 |
| |
Three months ended September 30, 2018: | | | | | | | | | | |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 29,984 |
| | $ | 864 |
| | $ | — |
| | $ | 1 |
| | $ | 30,849 |
|
Intersegment revenues | 1 |
| | 48 |
| | 110 |
| | (159 | ) | | — |
| 5 |
| | 68 |
| | 140 |
| | (213 | ) | | — |
|
Total operating revenues | 22,729 |
| | 882 |
| | 110 |
| | (159 | ) | | 23,562 |
| |
Total revenues | | 29,989 |
| | 932 |
| | 140 |
| | (212 | ) | | 30,849 |
|
Cost of sales: | | | | | | | | | | | | | | | | | | |
Cost of materials and other | 19,818 |
| | 669 |
| | — |
| | (158 | ) | | 20,329 |
| 27,137 |
| | 776 |
| | — |
| | (212 | ) | | 27,701 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) | 986 |
| | 114 |
| | 26 |
| | (1 | ) | | 1,125 |
| 1,047 |
| | 116 |
| | 31 |
| | (1 | ) | | 1,193 |
|
Depreciation and amortization expense | 455 |
| | 17 |
| | 12 |
| | — |
| | 484 |
| 466 |
| | 19 |
| | 19 |
| | — |
| | 504 |
|
Total cost of sales | 21,259 |
| | 800 |
| | 38 |
| | (159 | ) | | 21,938 |
| 28,650 |
| | 911 |
| | 50 |
| | (213 | ) | | 29,398 |
|
Other operating expenses | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
| 10 |
| | — |
| | — |
| | — |
| | 10 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) | — |
| | — |
| | — |
| | 229 |
| | 229 |
| — |
| | — |
| | — |
| | 209 |
| | 209 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 13 |
| | 13 |
| — |
| | — |
| | — |
| | 13 |
| | 13 |
|
Operating income (loss) by segment | $ | 1,429 |
| | $ | 82 |
| | $ | 69 |
| | $ | (242 | ) | | $ | 1,338 |
| |
Operating income by segment | | $ | 1,329 |
| | $ | 21 |
| | $ | 90 |
| | $ | (221 | ) | | $ | 1,219 |
|
| | | | | | | | | | | | | | | | | | |
Three months ended September 30, 2016: | | | | | | | | | | |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 18,718 |
| | $ | 931 |
| | $ | — |
| | $ | — |
| | $ | 19,649 |
| |
Three months ended September 30, 2017: | | | | | | | | | | |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 22,728 |
| | $ | 834 |
| | $ | — |
| | $ | — |
| | $ | 23,562 |
|
Intersegment revenues | — |
| | 56 |
| | 92 |
| | (148 | ) | | — |
| 1 |
| | 48 |
| | 110 |
| | (159 | ) | | — |
|
Total operating revenues | 18,718 |
| | 987 |
| | 92 |
| | (148 | ) | | 19,649 |
| |
Total revenues | | 22,729 |
| | 882 |
| | 110 |
| | (159 | ) | | 23,562 |
|
Cost of sales: | | | | | | | | | | | | | | | | | | |
Cost of materials and other | 16,424 |
| | 757 |
| | — |
| | (148 | ) | | 17,033 |
| 19,818 |
| | 669 |
| | — |
| | (158 | ) | | 20,329 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) | 931 |
| | 107 |
| | 24 |
| | — |
| | 1,062 |
| 996 |
| | 114 |
| | 26 |
| | (1 | ) | | 1,135 |
|
Depreciation and amortization expense | 429 |
| | 17 |
| | 12 |
| | — |
| | 458 |
| 455 |
| | 17 |
| | 12 |
| | — |
| | 484 |
|
Total cost of sales | 17,784 |
| | 881 |
| | 36 |
| | (148 | ) | | 18,553 |
| 21,269 |
| | 800 |
| | 38 |
| | (159 | ) | | 21,948 |
|
Other operating expenses | | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) | — |
| | — |
| | — |
| | 192 |
| | 192 |
| — |
| | — |
| | — |
| | 225 |
| | 225 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 12 |
| | 12 |
| — |
| | — |
| | — |
| | 13 |
| | 13 |
|
Operating income (loss) by segment | $ | 934 |
| | $ | 106 |
| | $ | 56 |
| | $ | (204 | ) | | $ | 892 |
| |
Operating income by segment | | $ | 1,419 |
| | $ | 82 |
| | $ | 69 |
| | $ | (238 | ) | | $ | 1,332 |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| | | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Nine months ended September 30, 2017: | | | | | | | | | | |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 65,030 |
| | $ | 2,558 |
| | $ | — |
| | $ | — |
| | $ | 67,588 |
| |
Nine months ended September 30, 2018: | | | | | | | | | | |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 85,675 |
| | $ | 2,625 |
| | $ | — |
| | $ | 3 |
| | $ | 88,303 |
|
Intersegment revenues | 1 |
| | 136 |
| | 326 |
| | (463 | ) | | — |
| 10 |
| | 156 |
| | 407 |
| | (573 | ) | | — |
|
Total operating revenues | 65,031 |
| | 2,694 |
| | 326 |
| | (463 | ) | | 67,588 |
| |
Total revenues | | 85,685 |
| | 2,781 |
| | 407 |
| | (570 | ) | | 88,303 |
|
Cost of sales: | | | | | | | | | | | | | | | | | | |
Cost of materials and other | 57,662 |
| | 2,166 |
| | — |
| | (462 | ) | | 59,366 |
| 77,608 |
| | 2,279 |
| | — |
| | (570 | ) | | 79,317 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) | 2,935 |
| | 330 |
| | 75 |
| | (1 | ) | | 3,339 |
| 3,013 |
| | 336 |
| | 93 |
| | (3 | ) | | 3,439 |
|
Depreciation and amortization expense | 1,358 |
| | 63 |
| | 36 |
| | — |
| | 1,457 |
| 1,385 |
| | 57 |
| | 57 |
| | — |
| | 1,499 |
|
Total cost of sales | 61,955 |
| | 2,559 |
| | 111 |
| | (463 | ) | | 64,162 |
| 82,006 |
| | 2,672 |
| | 150 |
| | (573 | ) | | 84,255 |
|
Other operating expenses | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
| 41 |
| | — |
| | — |
| | — |
| | 41 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) | — |
| | — |
| | — |
| | 597 |
| | 597 |
| — |
| | — |
| | — |
| | 695 |
| | 695 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 39 |
| | 39 |
| — |
| | — |
| | — |
| | 39 |
| | 39 |
|
Operating income (loss) by segment | $ | 3,035 |
| | $ | 135 |
| | $ | 212 |
| | $ | (636 | ) | | $ | 2,746 |
| |
Operating income by segment | | $ | 3,638 |
| | $ | 109 |
| | $ | 257 |
| | $ | (731 | ) | | $ | 3,273 |
|
| | | | | | | | | | | | | | | | | | |
Nine months ended September 30, 2016: | | | | | | | | | | |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 52,302 |
| | $ | 2,645 |
| | $ | — |
| | $ | — |
| | $ | 54,947 |
| |
Nine months ended September 30, 2017: | | | | | | | | | | |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 65,030 |
| | $ | 2,558 |
| | $ | — |
| | $ | — |
| | $ | 67,588 |
|
Intersegment revenues | — |
| | 135 |
| | 258 |
| | (393 | ) | | — |
| 1 |
| | 136 |
| | 326 |
| | (463 | ) | | — |
|
Total operating revenues | 52,302 |
| | 2,780 |
| | 258 |
| | (393 | ) | | 54,947 |
| |
Total revenues | | 65,031 |
| | 2,694 |
| | 326 |
| | (463 | ) | | 67,588 |
|
Cost of sales: | | | | | | | | | | | | | | | | | | |
Cost of materials and other | 45,790 |
| | 2,263 |
| | — |
| | (393 | ) | | 47,660 |
| 57,662 |
| | 2,166 |
| | — |
| | (462 | ) | | 59,366 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) | 2,716 |
| | 305 |
| | 72 |
| | — |
| | 3,093 |
| 2,966 |
| | 330 |
| | 75 |
| | (1 | ) | | 3,370 |
|
Depreciation and amortization expense | 1,308 |
| | 48 |
| | 35 |
| | — |
| | 1,391 |
| 1,358 |
| | 63 |
| | 36 |
| | — |
| | 1,457 |
|
Lower of cost or market inventory valuation adjustment | (697 | ) | | (50 | ) | | — |
| | — |
| | (747 | ) | |
Total cost of sales | 49,117 |
| | 2,566 |
| | 107 |
| | (393 | ) | | 51,397 |
| 61,986 |
| | 2,559 |
| | 111 |
| | (463 | ) | | 64,193 |
|
Other operating expenses | | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) | — |
| | — |
| | — |
| | 507 |
| | 507 |
| — |
| | — |
| | — |
| | 592 |
| | 592 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 35 |
| | 35 |
| — |
| | — |
| | — |
| | 39 |
| | 39 |
|
Asset impairment loss | 56 |
| | — |
| | — |
| | — |
| | 56 |
| |
Operating income (loss) by segment | $ | 3,129 |
| | $ | 214 |
| | $ | 151 |
| | $ | (542 | ) | | $ | 2,952 |
| |
Operating income by segment | | $ | 3,004 |
| | $ | 135 |
| | $ | 212 |
| | $ | (631 | ) | | $ | 2,720 |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table provides a disaggregation of revenues by reportable segment (in millions). Refining and ethanol segment revenues are disaggregated for our principal products, and VLP segment revenues are disaggregated by activity type.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | | 2017 | | 2018 | | 2017 |
Refining: | | | | | | | |
Gasolines and blendstocks | $ | 12,664 |
| | $ | 10,310 |
| | $ | 35,810 |
| | $ | 29,368 |
|
Distillates | 14,052 |
| | 10,477 |
| | 41,169 |
| | 29,909 |
|
Other product revenues | 3,273 |
| | 1,942 |
| | 8,706 |
| | 5,754 |
|
Total refining revenues | 29,989 |
| | 22,729 |
| | 85,685 |
| | 65,031 |
|
Ethanol: | | | | | | | |
Ethanol | 755 |
| | 740 |
| | 2,240 |
| | 2,290 |
|
Distillers grains | 177 |
| | 142 |
| | 541 |
| | 404 |
|
Total ethanol revenues | 932 |
| | 882 |
| | 2,781 |
| | 2,694 |
|
VLP: | | | | | | | |
Pipeline transportation | 31 |
| | 23 |
| | 93 |
| | 71 |
|
Terminaling | 107 |
| | 86 |
| | 309 |
| | 253 |
|
Storage and other | 2 |
| | 1 |
| | 5 |
| | 2 |
|
Total VLP revenues | 140 |
| | 110 |
| | 407 |
| | 326 |
|
Corporate – other revenues | 1 |
| | — |
| | 3 |
| | — |
|
Elimination of intersegment revenues | (213 | ) | | (159 | ) | | (573 | ) | | (463 | ) |
Revenues | $ | 30,849 |
| | $ | 23,562 |
| | $ | 88,303 |
| | $ | 67,588 |
|
Total assets by reportable segment were as follows (in millions):
| | | September 30, 2017 | | December 31, 2016 | September 30, 2018 | | December 31, 2017 |
Refining | $ | 39,450 |
| | $ | 38,095 |
| $ | 44,168 |
| | $ | 40,382 |
|
Ethanol | 1,319 |
| | 1,316 |
| 1,312 |
| | 1,344 |
|
VLP | 1,110 |
| | 972 |
| 1,600 |
| | 1,517 |
|
Corporate and eliminations | 6,109 |
| | 5,790 |
| 4,814 |
| | 6,915 |
|
Total assets | $ | 47,988 |
| | $ | 46,173 |
| $ | 51,894 |
| | $ | 50,158 |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
11.13. | SUPPLEMENTAL CASH FLOW INFORMATION |
In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | | 2016 | 2018 | | 2017 |
Decrease (increase) in current assets: | | | | | | |
Receivables, net | $ | 74 |
| | $ | (278 | ) | $ | (1,307 | ) | | $ | 74 |
|
Inventories | (285 | ) | | 557 |
| (1,134 | ) | | (285 | ) |
Prepaid expenses and other | 138 |
| | 137 |
| (65 | ) | | 138 |
|
Increase (decrease) in current liabilities: | | | | | | |
Accounts payable | 227 |
| | 494 |
| 1,890 |
| | 227 |
|
Accrued expenses | 121 |
| | 46 |
| (168 | ) | | 121 |
|
Taxes other than income taxes payable | 78 |
| | 8 |
| (32 | ) | | 78 |
|
Income taxes payable | 191 |
| | (11 | ) | (358 | ) | | 191 |
|
Changes in current assets and current liabilities | $ | 544 |
| | $ | 953 |
| $ | (1,174 | ) | | $ | 544 |
|
Cash flows related to interest and income taxes were as follows (in millions):
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 |
Interest paid in excess of amount capitalized | $ | 344 |
| | $ | 356 |
|
Income taxes paid, net | 1,116 |
| | 357 |
|
Noncash investing and financing activities during the nine months ended September 30, 2018 included the recognition of terminal assets and related obligation totaling $160 million under owner accounting as described in Note 6.Noncash investing and financing activities during the nine months ended September 30, 2017 included the recognition of (i) a capital lease assetassets and related obligation associated with an agreementobligations totaling approximately $490 million for the lease of storage tanks nearlocated at three of our refineries as described in Note 4 and (ii) terminal assets and related obligation recordedtotaling $55 million under owner accounting as described in Note 5. There were no significant noncash investing and financing activities during the nine months ended September 30, 2016.
Cash flows reflected as “other financing activities, net” for the nine months ended September 30, 2016 included the payment of a long-term liability of $137 million owed to a joint venture partner associated with an owner-method joint venture investment.6.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash flows related to interest and income taxes were as follows (in millions):
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
Interest paid in excess of amount capitalized | $ | 356 |
| | $ | 312 |
|
Income taxes paid, net | 357 |
| | 305 |
|
| |
12.14. | FAIR VALUE MEASUREMENTS |
Recurring Fair Value Measurements
The following tables below present information (in millions) about our assets and liabilities recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 20172018 and December 31, 20162017.
We have elected to offset the fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty, including any related cash collateral assets or obligations as shown below; however, fair value amounts by hierarchy level are presented in the following tables below on a gross basis. We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.
| | | September 30, 2017 | September 30, 2018 |
| | | Total Gross Fair Value | | Effect of Counter- party Netting | | Effect of Cash Collateral Netting | | Net Carrying Value on Balance Sheet | | Cash Collateral Paid or Received Not Offset | | | Total Gross Fair Value | | Effect of Counter- party Netting | | Effect of Cash Collateral Netting | | Net Carrying Value on Balance Sheet | | Cash Collateral Paid or Received Not Offset |
| Fair Value Hierarchy | | Fair Value Hierarchy | |
| Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | |
Assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity derivative contracts | $ | 861 |
| | $ | 34 |
| | $ | — |
| | $ | 895 |
| | $ | (882 | ) | | $ | (11 | ) | | $ | 2 |
| | $ | — |
| $ | 2,072 |
| | $ | 12 |
| | $ | — |
| | $ | 2,084 |
| | $ | (2,058 | ) | | $ | — |
| | $ | 26 |
| | $ | — |
|
Foreign currency contracts | 6 |
| | — |
| | — |
| | 6 |
| | n/a |
| | n/a |
| | 6 |
| | n/a |
| |
Investments of certain benefit plans | 63 |
| | — |
| | 8 |
| | 71 |
| | n/a |
| | n/a |
| | 71 |
| | n/a |
| 63 |
| | — |
| | 9 |
| | 72 |
| | n/a |
| | n/a |
| | 72 |
| | n/a |
|
Total | $ | 930 |
| | $ | 34 |
| | $ | 8 |
| | $ | 972 |
| | $ | (882 | ) | | $ | (11 | ) | | $ | 79 |
| |
| $ | 2,135 |
| | $ | 12 |
| | $ | 9 |
| | $ | 2,156 |
| | $ | (2,058 | ) | | $ | — |
| | $ | 98 |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | |
| | | | | |
| | | | | | | | |
| | | | | |
| | |
Commodity derivative contracts | $ | 974 |
| | $ | 16 |
| | $ | — |
| | $ | 990 |
| | $ | (882 | ) | | $ | (108 | ) | | $ | — |
| | $ | (171 | ) | $ | 2,109 |
| | $ | 10 |
| | $ | — |
| | $ | 2,119 |
| | $ | (2,058 | ) | | $ | (61 | ) | | $ | — |
| | $ | (88 | ) |
Environmental credit obligations | — |
| | 231 |
| | — |
| | 231 |
| | n/a |
| | n/a |
| | 231 |
| | n/a |
| — |
| | 16 |
| | — |
| | 16 |
| | n/a |
| | n/a |
| | 16 |
| | n/a |
|
Physical purchase contracts | — |
| | 8 |
| | — |
| | 8 |
| | n/a |
| | n/a |
| | 8 |
| | n/a |
| — |
| | 11 |
| | — |
| | 11 |
| | n/a |
| | n/a |
| | 11 |
| | n/a |
|
Foreign currency contracts | 1 |
| | — |
| | — |
| | 1 |
| | n/a |
| | n/a |
| | 1 |
| | n/a |
| 3 |
| | — |
| | — |
| | 3 |
| | n/a |
| | n/a |
| | 3 |
| | n/a |
|
Total | $ | 975 |
| | $ | 255 |
| | $ | — |
| | $ | 1,230 |
| | $ | (882 | ) | | $ | (108 | ) | | $ | 240 |
| |
| $ | 2,112 |
| | $ | 37 |
| | $ | — |
| | $ | 2,149 |
| | $ | (2,058 | ) | | $ | (61 | ) | | $ | 30 |
| |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| | | December 31, 2016 | December 31, 2017 |
| | | Total Gross Fair Value | | Effect of Counter- party Netting | | Effect of Cash Collateral Netting | | Net Carrying Value on Balance Sheet | | Cash Collateral Paid or Received Not Offset | | | Total Gross Fair Value | | Effect of Counter- party Netting | | Effect of Cash Collateral Netting | | Net Carrying Value on Balance Sheet | | Cash Collateral Paid or Received Not Offset |
| Fair Value Hierarchy | | Fair Value Hierarchy | |
| Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | |
Assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity derivative contracts | $ | 874 |
| | $ | 38 |
| | $ | — |
| | $ | 912 |
| | $ | (875 | ) | | $ | — |
| | $ | 37 |
| | $ | — |
| $ | 875 |
| | $ | 19 |
| | $ | — |
| | $ | 894 |
| | $ | (893 | ) | | $ | — |
| | $ | 1 |
| | $ | — |
|
Foreign currency contracts | 3 |
| | — |
| | — |
| | 3 |
| | n/a |
| | n/a |
| | 3 |
| | n/a |
| |
Investments of certain benefit plans | 58 |
| | — |
| | 11 |
| | 69 |
| | n/a |
| | n/a |
| | 69 |
| | n/a |
| 65 |
| | — |
| | 8 |
| | 73 |
| | n/a |
| | n/a |
| | 73 |
| | n/a |
|
Total | $ | 935 |
| | $ | 38 |
| | $ | 11 |
| | $ | 984 |
| | $ | (875 | ) | | $ | — |
| | $ | 109 |
| |
| $ | 940 |
| | $ | 19 |
| | $ | 8 |
| | $ | 967 |
| | $ | (893 | ) | | $ | — |
| | $ | 74 |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity derivative contracts | $ | 872 |
| | $ | 23 |
| | $ | — |
| | $ | 895 |
| | $ | (875 | ) | | $ | (20 | ) | | $ | — |
| | $ | (88 | ) | $ | 955 |
| | $ | 14 |
| | $ | — |
| | $ | 969 |
| | $ | (893 | ) | | $ | (76 | ) | | $ | — |
| | $ | (102 | ) |
Environmental credit obligations | — |
| | 188 |
| | — |
| | 188 |
| | n/a |
| | n/a |
| | 188 |
| | n/a |
| — |
| | 104 |
| | — |
| | 104 |
| | n/a |
| | n/a |
| | 104 |
| | n/a |
|
Physical purchase contracts | — |
| | 5 |
| | — |
| | 5 |
| | n/a |
| | n/a |
| | 5 |
| | n/a |
| — |
| | 6 |
| | — |
| | 6 |
| | n/a |
| | n/a |
| | 6 |
| | n/a |
|
Foreign currency contracts | | 7 |
| | — |
| | — |
| | 7 |
| | n/a |
| | n/a |
| | 7 |
| | n/a |
|
Total | $ | 872 |
| | $ | 216 |
| | $ | — |
| | $ | 1,088 |
| | $ | (875 | ) | | $ | (20 | ) | | $ | 193 |
| |
|
| $ | 962 |
| | $ | 124 |
| | $ | — |
| | $ | 1,086 |
| | $ | (893 | ) | | $ | (76 | ) | | $ | 117 |
| |
|
|
A description of our assets and liabilities recognized at fair value along with the valuation methods and inputs we used to develop their fair value measurements are as follows:
Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in Note 13, some of these contracts are designated as hedging instruments.swaps. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.
Physical purchase contracts represent the fair value of fixed-price corn purchase contracts. The fair values of these purchase contracts are measured using a market approach based on quoted prices from the commodity exchange or an independent pricing service and are categorized in Level 2 of the fair value hierarchy.
Investments of certain benefit plans consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified benefit plans. The assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quoted prices from national securities exchanges. The assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Foreign currency contracts consist of foreign currency exchange and purchase contracts entered into for our international operations to manage our exposure to exchange rate fluctuations on transactions denominated in currencies other than the local (functional) currencies of those operations. These contracts are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy.
Environmental credit obligations represent our liability for the purchase of (i) biofuel credits (primarily RINsRenewable Identification Numbers (RINs) in the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce and (ii) emission credits under the California Global Warming Solutions Act (the California cap-and-trade system, also known as AB 32), Quebec’s Environmental Quality Act (the Quebec cap-and-trade system), and Ontario’s Climate Change Mitigation and Low-Carbon Economy Act (the Ontario cap-and-trade system),similar programs, (collectively, the cap-and-trade systems). To the degree we are unable to blend biofuels (such as ethanol and biodiesel) at percentages required under the biofuel programs, we must purchase biofuel credits to comply with these programs. Under the cap-and-trade systems, we must purchase emission credits to comply with these systems. These programs are further described in Note 1315 under “Environmental Compliance Program Price Risk.” The liability for environmental credits is based on our deficit for such credits as of the balance sheet date, if any, after considering any credits acquired or under contract, and is equal to the product of the credits deficit and the market price of these credits as of the balance sheet date. The environmental credit obligations are categorized in Level 2 of the fair value hierarchy and are measured at fair value using the market approach based on quoted prices from an independent pricing service.
There were no transfers between levels for assets and liabilities held as of September 30, 20172018 and December 31, 20162017 that were measured at fair value on a recurring basis.
There was no significant activity during the three and nine months ended September 30, 20172018 and 20162017 related to the fair value amounts categorized in Level 3 as of September 30, 20172018 and December 31, 20162017.
Nonrecurring Fair Value Measurements
As discussed in Note 2, we concluded that the Aruba Terminal was impaired as of June 30, 2016, which resulted in an asset impairment loss of $56 million that was recorded in June 2016. The fair value of the Aruba Terminal was determined using an income approach and was classified in Level 3. We employed a probability-weighted approach to possible future cash flow scenarios, including transferring ownership of the business to the GOA or continuing to operate the business.
There were no assets or liabilities that were measured at fair value on a nonrecurring basis as of September 30, 20172018 and December 31, 20162017.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Other Financial Instruments
Financial instruments that we recognize in our balance sheets at their carrying amounts are shown in the following table below along with their associated fair values (in millions):
| | | September 30, 2017 | | December 31, 2016 | | September 30, 2018 | | December 31, 2017 |
| Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | Fair Value Hierarchy | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Financial assets: | | | | | | | | | | | | | | | |
Cash and temporary cash investments | $ | 5,176 |
| | $ | 5,176 |
| | $ | 4,816 |
| | $ | 4,816 |
| |
Cash and cash equivalents | | Level 1 | | $ | 3,551 |
| | $ | 3,551 |
| | $ | 5,850 |
| | $ | 5,850 |
|
Financial liabilities: | | | | | | | | | | | | | | | |
Debt (excluding capital leases) | 7,930 |
| | 9,195 |
| | 7,926 |
| | 8,882 |
| Level 2 | | 8,467 |
| | 9,328 |
| | 8,310 |
| | 9,795 |
|
The methods and significant assumptions used to estimate the fair value of these financial instruments are as follows:
The fair value of cash and temporary cash investments approximates the carrying value due to the low level of credit risk of these assets combined with their short maturities and market interest rates (Level 1).
The fair value of debt is determined primarily using the market approach based on quoted prices provided by third-party brokers and vendor pricing services (Level 2).
32
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| |
13.15. | PRICE RISK MANAGEMENT ACTIVITIES |
We are exposed to market risks primarily related to the volatility in the price of commodities, and foreign currency exchange rates, and the price of credits needed to comply with various government and regulatory programs. We enter into derivative instruments to manage some of these risks, including derivative instruments related to the various commodities we purchase or produce, and foreign currency exchange and purchase contracts, as described below under “Risk Management Activities by Type of Risk.” These derivative instruments are recorded as either assets or liabilities measured at their fair values (see Note 12)14), as summarized below under “Fair Values of Derivative Instruments,” with changes in fair value recognized currently in income. The effect of these derivative instruments on our income is summarized below under “Effect of Derivative Instruments on Income.”
Risk Management Activities by Type of Risk
Commodity Price Risk
We are exposed to market risks related to the volatility in the price of crude oil, refined petroleum products (primarily gasoline and distillate), grain (primarily corn), soybean oil, and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including futures, swaps, and options. We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. Our positions in commodity derivative instruments are monitored and managed on a daily basis by our risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
To manage commodity price risk, we use economic hedges, which are not designated as fair value or cash flow hedges, and we use fair value and cash flow hedges from time to time. We also enter into certain commodity derivative instruments for trading purposes. Our objectives for entering into hedges or trading derivatives are described below.
Economic Hedges – Economic hedges represent commodity derivative instruments that are used to manage price volatility in certain (i) feedstock and refined petroleum product inventories, (ii) fixed-price purchase contracts, and (iii) forecasted feedstock, refined petroleum product or natural gas purchases and refined petroleum product sales. The objectives of our economic hedges are to hedge price volatility in certain feedstock and refined petroleum product inventories and to lock in the price of forecasted feedstock, refined petroleum product, or natural gas purchases or refined petroleum product sales at existing market prices that we deem favorable. Economic hedges are not designated as fair value or cash flow hedges for accounting purposes, usually due to the difficulty of establishing the required documentation at the date the derivative instrument is entered into for them to qualify as hedging instruments for accounting purposes.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of September 30, 2017,2018, we had the following outstanding commodity derivative instruments that were used as economic hedges, as well as commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels and soybean oil contracts that are presented in thousands of pounds).
|
| | | | | | | | | |
| | Notional Contract Volumes by Year of Maturity |
Derivative Instrument | | 2017 | | 2018 | | 2019 |
Crude oil and refined petroleum products: | | | | | | |
Swaps – long | | 13,369 |
| | 725 |
| | — |
|
Swaps – short | | 12,889 |
| | 650 |
| | — |
|
Futures – long | | 99,816 |
| | 7,014 |
| | — |
|
Futures – short | | 107,940 |
| | 6,982 |
| | — |
|
Corn: | | | | | | |
Futures – long | | 19,060 |
| | 20 |
| | 35 |
|
Futures – short | | 24,985 |
| | 18,070 |
| | 45 |
|
Physical contracts – long | | 13,065 |
| | 9,223 |
| | 11 |
|
Soybean oil: | | | | | | |
Futures – long | | 63,059 |
| | — |
| | — |
|
Futures – short | | 157,018 |
| | — |
| | — |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | | | |
| | Notional Contract Volumes by Year of Maturity |
Derivative Instrument | | 2018 | | 2019 | | 2020 |
Crude oil and refined petroleum products: | | | | | | |
Swaps – long | | 17,645 |
| | 560 |
| | — |
|
Swaps – short | | 17,262 |
| | 180 |
| | — |
|
Futures – long | | 83,979 |
| | 3,353 |
| | — |
|
Futures – short | | 100,549 |
| | 3,399 |
| | — |
|
Corn: | | | | | | |
Futures – long | | 18,540 |
| | 250 |
| | — |
|
Futures – short | | 38,785 |
| | 10,230 |
| | 45 |
|
Physical contracts – long | | 22,612 |
| | 10,004 |
| | 43 |
|
Soybean oil: | | | | | | |
Futures – long | | 99,899 |
| | — |
| | — |
|
Futures – short | | 226,317 |
| | 42,179 |
| | — |
|
Trading Derivatives – Our objective for entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions for crude oil and refined petroleum products.
As of September 30, 20172018, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units and corn contracts that are presented in thousands of bushels)barrels).
| | | | Notional Contract Volumes by Year of Maturity | | Notional Contract Volumes by Year of Maturity |
Derivative Instrument | | 2017 | | 2018 | | 2018 | | 2019 |
Crude oil and refined petroleum products: | | | | | | | | |
Swaps – long | | 1,922 |
| | 134 |
| |
Swaps – short | | 1,922 |
| | 134 |
| |
Futures – long | | 56,273 |
| | 25,948 |
| | 62,616 |
| | 13,896 |
|
Futures – short | | 55,234 |
| | 26,933 |
| | 62,161 |
| | 14,321 |
|
Options – long | | 39,380 |
| | 142,450 |
| | 29,227 |
| | 500 |
|
Options – short | | 38,980 |
| | 142,450 |
| | 29,250 |
| | 500 |
|
Natural gas: | | | | | |
Futures – long | | 600 |
| | — |
| |
Futures – short | | 300 |
| | — |
| |
Corn: | | | | | |
Futures – long | | 400 |
| | — |
| |
We had no commodity derivative contracts outstanding as of September 30, 20172018 and 20162017 or during the three and nine months ended September 30, 20172018 and 20162017 that were designated as fair value or cash flow hedges.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions entered into by our international operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes and therefore are classified as economic hedges. As of September 30, 20172018, we had forward contracts to purchase $514$569 million of U.S. dollars. TheseAll of these commitments matured on or before October 31, 2017.2018.
Environmental Compliance Program Price Risk
We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory environmental compliance programs. To manage this risk, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are derivative instruments; however, we elect the normal purchase exception and do not record these contracts at their fair values. Certain of these programs require us to blend biofuels into the products we produce, and we are subject to such programs in most of the countries in which we operate. These countries set annual quotas
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
for the percentage of biofuels that must be blended into the motor fuels consumed in these countries. As a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the applicable quota. To the degree we are unable to blend at the applicable rate, we must purchase biofuel credits (primarily RINs in the U.S.). We are exposed to the volatility in the market price of these credits, and we manage that risk by purchasing biofuel credits when prices are deemed favorable. The cost of meeting our obligations under these compliance programs was $230$94 million and $198$230 million for the three months ended September 30, 20172018 and 2016,2017, respectively, and $631$431 million and $532631 million for the nine months ended September 30, 20172018 and 2016,2017, respectively. These amounts are reflected in cost of materials and other.
We are subject to additional requirements under greenhouse gas (GHG) emission programs, including the cap-and-trade systems, as discussed in Note 12.14. Under these cap-and-trade systems, we purchase various GHG emission credits available on the open market. Therefore, we are exposed to the volatility in the market price of these credits. The cost to implement certain provisions of the cap-and-trade systems are significant; however, we recovered the majority of these costs from our customers for the three and nine months ended September 30, 20172018 and 20162017 and expect to continue to recover the majority of these costs in the future. For the three and nine months ended September 30, 20172018 and 2016,2017, the net cost of meeting our obligations under these compliance programs was immaterial.
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of September 30, 20172018 and December 31, 20162017 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 1214 for additional information related to the fair values of our derivative instruments.
As indicated in Note 1214, we net fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The following tables, below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts.
|
| | | | | | | | | |
| Balance Sheet Location | | September 30, 2017 |
| | Asset Derivatives | | Liability Derivatives |
Derivatives not designated as hedging instruments | | | | | |
Commodity contracts: | | | | | |
Futures | Receivables, net | | $ | 861 |
| | $ | 974 |
|
Swaps | Receivables, net | | 27 |
| | 13 |
|
Options | Receivables, net | | 7 |
| | 3 |
|
Physical purchase contracts | Inventories | | — |
| | 8 |
|
Foreign currency contracts | Receivables, net | | 6 |
| | — |
|
Foreign currency contracts | Accrued expenses | | — |
| | 1 |
|
Total | | | $ | 901 |
| | $ | 999 |
|
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | | | |
| Balance Sheet Location | | September 30, 2018 |
| | Asset Derivatives | | Liability Derivatives |
Derivatives not designated as hedging instruments | | | | | |
Commodity contracts: | | | | | |
Futures | Receivables, net | | $ | 2,072 |
| | $ | 2,108 |
|
Swaps | Receivables, net | | 11 |
| | 10 |
|
Options | Receivables, net | | 1 |
| | 1 |
|
Physical purchase contracts | Inventories | | — |
| | 11 |
|
Foreign currency contracts | Accrued expenses | | — |
| | 3 |
|
Total | | | $ | 2,084 |
| | $ | 2,133 |
|
| | | Balance Sheet Location | | December 31, 2016 | Balance Sheet Location | | December 31, 2017 |
| | Asset Derivatives | | Liability Derivatives | | Asset Derivatives | | Liability Derivatives |
Derivatives not designated as hedging instruments | | | | | | | | |
Commodity contracts: | | | | | | | | |
Futures | Receivables, net | | $ | 874 |
| | $ | 872 |
| Receivables, net | | $ | 875 |
| | $ | 955 |
|
Swaps | Receivables, net | | 32 |
| | 21 |
| Receivables, net | | 11 |
| | 11 |
|
Options | Receivables, net | | 6 |
| | 2 |
| Receivables, net | | 8 |
| | 3 |
|
Physical purchase contracts | Inventories | | — |
| | 5 |
| Inventories | | — |
| | 6 |
|
Foreign currency contracts | Receivables, net | | 3 |
| | — |
| Accrued expenses | | — |
| | 7 |
|
Total | | $ | 915 |
| | $ | 900 |
| | $ | 894 |
| | $ | 982 |
|
Market Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, which is the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by our risk control group to ensure compliance with our stated risk management policy. We do not require any
VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.
Effect of Derivative Instruments on Income
The following tables provide information about the gain or loss recognized in income on our derivative instruments and the income statement line items in the statements of income in which such gains and losses are reflected (in millions).
| | Derivatives Designated as Economic Hedges | | Location of Gain (Loss) Recognized in Income on Derivatives | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Location of Gain (Loss) Recognized in Income on Derivatives | | Three Months Ended September 30, | | Nine Months Ended September 30, |
2017 | | 2016 | 2017 | | 2016 | 2018 | | 2017 | 2018 | | 2017 |
Commodity contracts | | Cost of materials and other | | $ | (86 | ) | | $ | 42 |
| | $ | (158 | ) | | $ | (210 | ) | | Cost of materials and other | | $ | (108 | ) | | $ | (86 | ) | | $ | (222 | ) | | $ | (158 | ) |
Foreign currency contracts | | Cost of materials and other | | (16 | ) | | 4 |
| | (42 | ) | | 5 |
| | Cost of materials and other | | (7 | ) | | (16 | ) | | 7 |
| | (42 | ) |
| | Trading Derivatives | | Location of Gain Recognized in Income on Derivatives | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Location of Gain Recognized in Income on Derivatives | | Three Months Ended September 30, | | Nine Months Ended September 30, |
2017 | | 2016 | 2017 | | 2016 | 2018 | | 2017 | 2018 | | 2017 |
Commodity contracts | | Cost of materials and other | | $ | 31 |
| | $ | 13 |
| | $ | 29 |
| | $ | 51 |
| | Cost of materials and other | | $ | 10 |
| | $ | 31 |
| | $ | 97 |
| | $ | 29 |
|
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Form 10-Q, including without limitation our disclosures below under the heading “OVERVIEW AND OUTLOOK,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “scheduled,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “could,” “would,” “should,” “will,” “may,” and similar expressions.
These forward-looking statements include, among other things, statements regarding:
future refining segment margins, including gasoline and distillate margins;
future ethanol segment margins;
expectations regarding feedstock costs, including crude oil differentials, and operating expenses;
anticipated levels of crude oil and refined petroleum product inventories;
our anticipated level of capital investments, including deferred costs for refinery turnarounds and catalyst, capital expenditures for environmental and other purposes, and joint venture investments, and the effect of those capital investments on our results of operations;
anticipated trends in the supply of and demand for crude oil and other feedstocks and refined petroleum products in the regions where we operate, as well as globally;
expectations regarding environmental, tax, and other regulatory initiatives; and
the effect of general economic and other conditions on refining, ethanol, and midstream industry fundamentals.
We based our forward-looking statements on our current expectations, estimates, and projections about ourselves and our industry. We caution that these statements are not guarantees of future performance and involve risks, uncertainties, and assumptions that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in the forward-looking statements. Differences between actual results and any future performance suggested in these forward-looking statements could result from a variety of factors, including the following:
acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined petroleum products or receive feedstocks;
political and economic conditions in nations that produce crude oil or consume refined petroleum products;
demand for, and supplies of, refined petroleum products such as gasoline, diesel, jet fuel, petrochemicals, and ethanol;
demand for, and supplies of, crude oil and other feedstocks;
the ability of the members of the Organization of Petroleum Exporting Countries to agree on and to maintain crude oil price and production controls;
the level of consumer demand, including seasonal fluctuations;
refinery overcapacity or undercapacity;
our ability to successfully integrate any acquired businesses into our operations;
the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;
the level of competitors’ imports into markets that we supply;
accidents, unscheduled shutdowns, or other catastrophes affecting our refineries, machinery, pipelines, equipment, and information systems, or those of our suppliers or customers;
changes in the cost or availability of transportation for feedstocks and refined petroleum products;
the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;
the levels of government subsidies for alternative fuels;
the volatility in the market price of biofuel credits (primarily RINs needed to comply with the U.S. federal Renewable Fuel Standard) and GHG emission credits needed to comply with the requirements of various GHG emission programs;
delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;
earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil, grain and other feedstocks, and refined petroleum products and ethanol;
rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tariffs and tax and environmental regulations, such as those implemented under the California cap-and-trade system (also known as AB 32), the Quebec cap-and-trade system, the Ontario cap-and-trade system, and similar programs, and the U.S. EPA’s regulation of GHGs, which may adversely affect our business or operations;
changes in the credit ratings assigned to our debt securities and trade credit;
changes in currency exchange rates, including the value of the Canadian dollar, the pound sterling, the euro, the Mexican peso, and the euroPeruvian sol relative to the U.S. dollar;
overall economic conditions, including the stability and liquidity of financial markets; and
other factors generally described in the “Risk Factors” section included in our annual report on Form 10-K for the year ended December 31, 20162017 that is incorporated by reference herein.
Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
This Form 10-Q includes references to financial measures that are not defined under U.S. GAAP. These non-GAAP financial measures include adjusted net income attributable to Valero stockholders, refining and ethanol segment margin, and adjusted operating income. We have included these non-GAAP financial measures to help facilitate the comparison of operating results between periods. See the accompanying financial tables in “RESULTS OF OPERATIONS” and note (e) (g)to the accompanying tables for reconciliations of these non-GAAP financial measures to the most directly comparable U.S. GAAP financial measures. Also in note (e)(g), we disclose the reasons why we believe our use of the non-GAAP financial measures provides useful information.
OVERVIEW AND OUTLOOK
Overview
Third Quarter Results
InFor the third quarter of 2017,2018, we reported net income attributable to Valero stockholders of $841$856 million compared to $613$841 million infor the third quarter of 2016,2017, which represents an increase of $228$15 million. This increase isDespite a $91 million decrease in income before income tax expense, our income tax expense decreased by $102 million primarily due to higherthe reduction in the U.S. statutory rate from 35 percent to 21 percent effective January 1, 2018. The $91 million decline in income before income tax expense was primarily driven by a decrease in operating income between the periods (net of the resulting increase of $234 million in income tax expense). as described below.
Operating income was $1.2 billion for the third quarter of 2018 compared to $1.3 billion infor the third quarter of 2017, comparedwhich represents a decrease of $113 million. Excluding the adjustments to $892 millionoperating income reflected in the third quarter of 2016, which represents an increase of $446 million.
Operating income in the third quarter of 2017 was negatively impacted by $44 million of damages associated with Hurricane Harvey, which are reflected in other operating expenses. By excluding these expenses,table on page 45, adjusted operating income wasdecreased $147 million, from $1.4 billion for the third quarter of 2017 which is an increaseto $1.2 billion for the third quarter of $4902018.
The $147 million compared todecrease in adjusted operating incomeis primarily due to the following:
Refining segment. Refining segment adjusted operating income decreased by $121 million primarily due to lower margins on refined petroleum products, partially offset by more favorable discounts on crude oils and other feedstocks and higher throughput volumes. This is more fully described on pages 49 through 51.
Ethanol segment. Ethanol segment operating income decreased by $61 million primarily due to lower ethanol prices, partially offset by higher corn related co-product prices and lower corn prices. This is more fully described on page 51.
VLP segment. VLP segment adjusted operating income increased by $18 million primarily due to incremental revenues, partially offset by higher cost of $892sales, generated from transportation and terminaling activities associated with a terminal and a product pipeline system acquired by VLP in November 2017 that were formerly a part of the refining segment. This is more fully described on pages 51 and 52.
Corporate and eliminations. Corporate and eliminations decreased by $17 million primarily due to expenses in the third quarter of 2016.2017 associated with the termination of the acquisition of certain assets from Plains. This is more fully described on page 52.
First Nine Months Results
For the first nine months of 2018, we reported net income attributable to Valero stockholders of $2.2 billion compared to $1.7 billion for the first nine months of 2017, which represents an increase of $476 million. This increase is due to a $563 million increase in income before income tax expense, partially offset by a $99 million increase in net income attributable to noncontrolling interests. Despite the $563 million increase in income before income tax expense, our income tax expense in the first nine months of 2018 was largely consistent with the first nine months of 2017 due to the reduction in the U.S. statutory tax rate from 35 percent to 21 percent effective January 1, 2018, and the receipt of $170 million of blender’s tax credits in 2018 that were not taxable. The increase in net income attributable to noncontrolling interest is primarily due to $80 million of the blender’s tax credits being associated with a noncontrolling interest holder. The
$563 million increase in income before income tax expense was primarily driven by an increase in operating income between the periods as described below.
Operating income was $3.3 billion for the first nine months of 2018 compared to $2.7 billion for the first nine months of 2017, which represents an increase of $553 million. Excluding the adjustments to operating income reflected in the table on page 56, adjusted operating income increased $488 million, from $2.8 billion for the first nine months of 2017 to $3.3 billion for the first nine months of 2018.
The $490$488 million increase in adjusted operating income is primarily due primarily to the following:
Refining segment. Refining segment adjusted operating income increased by $536$464 million primarily due to higherimproved distillate margins, on refined petroleum productsmore favorable crude oil discounts, and higher throughput volumes,lower costs of biofuel credits, partially offset by lower discounts on sour crude oilsgasoline and other feedstocks and higher operating expenses (excluding depreciation and amortization expense).products margins. This is more fully described on pages 4362 through 45.64.
Ethanol segment. Ethanol segment operating income decreased by $24$26 million primarily due to higher cornlower ethanol prices, partially offset by higher ethanolcorn related co-product prices. This is more fully described on page 45.pages 64 and 65.
VLP segment. VLP segment adjusted operating income increased by $16$42 million primarily due to incremental revenues, partially offset by higher cost of sales, generated from transportation and terminaling services provided to the refining segmentactivities associated with a businessterminal and a product pipeline system acquired by VLP in September 2016 andNovember 2017 that were formerly a part of the acquisition of an undivided interest in crude system assets in January 2017.refining segment. This is more fully described on pages 45 and 46.page 65.
GeneralCorporate and administrative expenses (excluding depreciationeliminations. Adjusted corporate and amortization expense). General and administrative expenses (excluding depreciation and amortization expense) increasedeliminations decreased by $37$8 million primarily due to expenses in the first nine months of 2017 associated with the termination of the acquisition of certain assets from Plains All American Pipeline, L.P. (Plains) of $16 million and higher employee related costs of $11 million.
First Nine Months Results
In the first nine months of 2017, we reported net income attributable to Valero stockholders of $1.7 billion compared to $1.9 billion in the first nine months of 2016, which represents a decrease of $228 million. This decrease is primarily due to lower operating income between the periods. Operating income was $2.7 billion in the first nine months of 2017 compared to $3.0 billion in the first nine months of 2016, which represents a decrease of $206 million.
Operating income in the first nine months of 2017 was negatively impacted by $44 million of damages associated with Hurricane Harvey, which are reflected in other operating expenses. By excluding these other operating expenses, adjusted operating income was $2.8 billion for the first nine months of 2017.
Operating income in the first nine months of 2016 was positively impacted by a noncash benefit from a lower of cost or market inventory valuation adjustment partially offset by a noncash charge from an impairment loss related to our Aruba Terminal. By excluding these items, adjusted operating income was $2.3 billion.
Comparing these adjusted amounts, adjusted operating income in the first nine months of 2017 increased by $529 million compared to the first nine months of 2016.
The $529 million increase in adjusted operating income is due primarily to the following:
Refining segment. Refining segment adjusted operating income increased by $588 million due to higher margins on refined petroleum products and higher throughput volumes, partially offset by lower discounts on sour crude oils and other feedstocks and higher operating expenses (excluding depreciation and amortization expense).Plains. This is more fully described on pages 56 and 57.page 65.
Ethanol segment. Ethanol segment adjusted operating income decreased by $29 million due to lower corn related co-product prices and higher operating expenses (excluding depreciation and amortization expense), partially offset by higher ethanol prices. This is more fully described on pages 57 and 58.
VLP segment. VLP segment adjusted operating income increased by $64 million due to incremental revenues generated from transportation and terminaling services provided to the refining segment associated with businesses acquired in 2016 and the acquisition of an undivided interest in crude system assets in January 2017. This is more fully described on pages 58 and 59.
General and administrative expenses (excluding depreciation and amortization expense). General and administrative expenses (excluding depreciation and amortization expense) increased by $90 million primarily due to an increase in legal and environmental reserves of $25 million, higher employee related costs of $20 million, expenses associated with the termination of the acquisition of certain assets from Plains of $16 million, and increases in charitable contributions and advertising expenses of $6 million and $5 million, respectively.
Additional details and analysis of the changes in operating income and adjusted operating incomefor our business segments and other components of net income, including a reconciliation of non-GAAP financial measures used in this Overview to their most comparable measures reported under U.S.GAAP, are provided below under “RESULTS OF OPERATIONS” beginning on page 36.
Effective January 1, 2017, we revised our reportable segments to reflect a new reportable segment — VLP. The results of operations of the VLP segment were previously included in the refining segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation. See Note 10 of Condensed Notes to Consolidated Financial Statements for additional segment information.
Outlook
Below are several factors that have impacted or may impact our results of operations during the fourth quarter of 2017:2018:
Gasoline margins are expected to decline as domestic demand follows typical seasonal patterns.
Distillate margins are expected to continue to be supported by strong domestic and export demand.
Medium and heavy sour crude oil discounts are expected to remain weaker than their five-year averages as supplies of sour crude oils available in the market remain suppressed.
Sweet crude oil discounts are expected to widen as increased supplies fromexport demand remains strong and freight costs continue to rise. Inland sweet crude oil discounts are expected to remain wide with higher production and limited pipeline capacity to transport crude oil out of the Permian Basin are delivered into U.S. Gulf Coast markets.and other producing regions.
Ethanol segment margins are expected to decline as domestic gasoline demand weakens.
On October 8, 2018, we entered into an agreement to acquire three ethanol plants from Green Plains Inc., which is more fully discussed in Note 2 of Condensed Notes to Consolidated Financial Statements. We expect the acquisition will be completed in the fourth quarter of 2018.
On October 18, 2018, we entered into the Merger Agreement with VLP pursuant to which we have agreed to acquire, for cash, all of the outstanding publicly held common units of VLP, which is more fully discussed in Note 2 of Condensed Notes to Consolidated Financial Statements. The Merger Transaction is expected to close as soon as possible following the satisfaction of certain customary closing conditions. Upon the closing of the Merger Transaction, VLP will become an indirect wholly owned subsidiary and we will no longer reflect a portion of VLP’s earnings as net income attributable to noncontrolling interests.
RESULTS OF OPERATIONS
The following tables highlight our results of operations, our operating performance, and market reference prices that directly impact our operations. In addition, these tables include financial measures that are not defined under U.S. GAAP and represent non-GAAP financial measures. These non-GAAP financial measures are reconciled to their most comparable U.S. GAAP financial measures and include adjusted net income attributable to Valero Energy Corporation stockholders, adjusted operating income, and refining and ethanol segment margin. In note (e)(g) to these tables, we disclose the reasons why we believe our use of non-GAAP financial measures provides useful information.
Effective January 1, 2017, we revised our reportable segments to align with certain changes in how our chief operating decision maker manages and allocates resources to our business. Accordingly, we created a new reportable segment — VLP. The results of the VLP segment, which include the results of our majority-owned master limited partnership referred to by the same name, were transferred from the refining segment. Our prior period segment information has been retrospectively adjusted to reflect our current segment presentation. The narrative following these tables provides an analysis of our results of operations.
Third Quarter Results -
Financial Highlights By Segment and Total Company
(millions of dollars)
| | | Three Months Ended September 30, 2017 | Three Months Ended September 30, 2018 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total Company | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 22,728 |
| | $ | 834 |
| | $ | — |
| | $ | — |
| | $ | 23,562 |
| |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 29,984 |
| | $ | 864 |
| | $ | — |
| | $ | 1 |
| | $ | 30,849 |
|
Intersegment revenues | 1 |
| | 48 |
| | 110 |
| | (159 | ) | | — |
| 5 |
| | 68 |
| | 140 |
| | (213 | ) | | — |
|
Total operating revenues | 22,729 |
| | 882 |
| | 110 |
| | (159 | ) | | 23,562 |
| |
Total revenues | | 29,989 |
| | 932 |
| | 140 |
| | (212 | ) | | 30,849 |
|
Cost of sales: | | | | | | | | | | | | | | | | | | |
Cost of materials and other | 19,818 |
| | 669 |
| | — |
| | (158 | ) | | 20,329 |
| 27,137 |
| | 776 |
| | — |
| | (212 | ) | | 27,701 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) | 986 |
| | 114 |
| | 26 |
| | (1 | ) | | 1,125 |
| 1,047 |
| | 116 |
| | 31 |
| | (1 | ) | | 1,193 |
|
Depreciation and amortization expense | 455 |
| | 17 |
| | 12 |
| | — |
| | 484 |
| 466 |
| | 19 |
| | 19 |
| | — |
| | 504 |
|
Total cost of sales | 21,259 |
| | 800 |
| | 38 |
| | (159 | ) | | 21,938 |
| 28,650 |
| | 911 |
| | 50 |
| | (213 | ) | | 29,398 |
|
Other operating expenses (b)(c) | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
| 10 |
| | — |
| | — |
| | — |
| | 10 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) | — |
| | — |
| | — |
| | 229 |
| | 229 |
| — |
| | — |
| | — |
| | 209 |
| | 209 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 13 |
| | 13 |
| — |
| | — |
| | — |
| | 13 |
| | 13 |
|
Operating income (loss) by segment | $ | 1,429 |
| | $ | 82 |
| | $ | 69 |
| | $ | (242 | ) | | 1,338 |
| |
Operating income by segment | | $ | 1,329 |
| | $ | 21 |
| | $ | 90 |
| | $ | (221 | ) | | 1,219 |
|
Other income, net | | | | | | | | | 17 |
| | | | | | | | | 42 |
|
Interest and debt expense, net of capitalized interest | | | | | | | | | (114 | ) | | | | | | | | | (111 | ) |
Income before income tax expense | | | | | | | | | 1,241 |
| | | | | | | | | 1,150 |
|
Income tax expense(f) | | | | | | | | | 378 |
| | | | | | | | | 276 |
|
Net income | | | | | | | | | 863 |
| | | | | | | | | 874 |
|
Less: Net income attributable to noncontrolling interests | | | | | | | | | 22 |
| | | | | | | | | 18 |
|
Net income attributable to Valero Energy Corporation stockholders | | | | | | | | | $ | 841 |
| | | | | | | | | $ | 856 |
|
___________________
See note references on pages 5360 through 55.
62.
Third Quarter Results -
Financial Highlights By Segment and Total Company (continued)
(millions of dollars)
| | | Three Months Ended September 30, 2016 | Three Months Ended September 30, 2017 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total Company | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 18,718 |
| | $ | 931 |
| | $ | — |
| | $ | — |
| | $ | 19,649 |
| |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 22,728 |
| | $ | 834 |
| | $ | — |
| | $ | — |
| | $ | 23,562 |
|
Intersegment revenues | — |
| | 56 |
| | 92 |
| | (148 | ) | | — |
| 1 |
| | 48 |
| | 110 |
| | (159 | ) | | — |
|
Total operating revenues | 18,718 |
| | 987 |
| | 92 |
| | (148 | ) | | 19,649 |
| |
Total revenues | | 22,729 |
| | 882 |
| | 110 |
| | (159 | ) | | 23,562 |
|
Cost of sales: | | | | | | | | | | | | | | | | | | |
Cost of materials and other | 16,424 |
| | 757 |
| | — |
| | (148 | ) | | 17,033 |
| 19,818 |
| | 669 |
| | — |
| | (158 | ) | | 20,329 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) (d)(b) | 931 |
| | 107 |
| | 24 |
| | — |
| | 1,062 |
| 996 |
| | 114 |
| | 26 |
| | (1 | ) | | 1,135 |
|
Depreciation and amortization expense (d) | 429 |
| | 17 |
| | 12 |
| | — |
| | 458 |
| 455 |
| | 17 |
| | 12 |
| | — |
| | 484 |
|
Total cost of sales | 17,784 |
| | 881 |
| | 36 |
| | (148 | ) | | 18,553 |
| 21,269 |
| | 800 |
| | 38 |
| | (159 | ) | | 21,948 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) | — |
| | — |
| | — |
| | 192 |
| | 192 |
| |
Other operating expenses (c) | | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below) (b) | | — |
| | — |
| | — |
| | 225 |
| | 225 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 12 |
| | 12 |
| — |
| | — |
| | — |
| | 13 |
| | 13 |
|
Operating income (loss) by segment | $ | 934 |
| | $ | 106 |
| | $ | 56 |
| | $ | (204 | ) | | 892 |
| |
Other income, net | | | | | | | | | 12 |
| |
Operating income by segment | | $ | 1,419 |
| | $ | 82 |
| | $ | 69 |
| | $ | (238 | ) | | 1,332 |
|
Other income, net (b) | | | | | | | | | | 23 |
|
Interest and debt expense, net of capitalized interest | | | | | | | | | (115 | ) | | | | | | | | | (114 | ) |
Income before income tax expense | | | | | | | | | 789 |
| | | | | | | | | 1,241 |
|
Income tax expense | | | | | | | | | 144 |
| | | | | | | | | 378 |
|
Net income | | | | | | | | | 645 |
| | | | | | | | | 863 |
|
Less: Net income attributable to noncontrolling interests | | | | | | | | | 32 |
| | | | | | | | | 22 |
|
Net income attributable to Valero Energy Corporation stockholders | | | | | | | | | $ | 613 |
| | | | | | | | | $ | 841 |
|
___________________
See note references on pages 5360 through 55.62.
Third Quarter Results -
Financial Highlights By Segment and Total Company (continued)
(millions of dollars)
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total Company |
Reconciliation of actual (U.S. GAAP) to adjusted (non-GAAP) amounts (e) | | | | | | | | | |
Actual and adjusted operating income (loss) | | | | | | | | | |
Operating income (loss) by segment | $ | 1,429 |
| | $ | 82 |
| | $ | 69 |
| | $ | (242 | ) | | $ | 1,338 |
|
Exclude adjustment: | | | | | | | | | |
Other operating expenses | (41 | ) | | — |
| | (3 | ) | | — |
| | (44 | ) |
Adjusted operating income (loss) | $ | 1,470 |
| | $ | 82 |
| | $ | 72 |
| | $ | (242 | ) | | $ | 1,382 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2018 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Reconciliation of operating income to adjusted operating income (g) | | | | | | | | | |
Operating income by segment (see page 43) | $ | 1,329 |
| | $ | 21 |
| | $ | 90 |
| | $ | (221 | ) | | $ | 1,219 |
|
Exclude: | | | | | | | | | |
Other operating expenses (c) | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
Adjusted operating income | $ | 1,339 |
| | $ | 21 |
| | $ | 90 |
| | $ | (221 | ) | | $ | 1,229 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Reconciliation of operating income to adjusted operating income (g) | | | | | | | | | |
Operating income by segment (see page 44) | $ | 1,419 |
| | $ | 82 |
| | $ | 69 |
| | $ | (238 | ) | | $ | 1,332 |
|
Exclude: | | | | | | | | | |
Other operating expenses (c) | (41 | ) | | — |
| | (3 | ) | | — |
| | (44 | ) |
Adjusted operating income | $ | 1,460 |
| | $ | 82 |
| | $ | 72 |
| | $ | (238 | ) | | $ | 1,376 |
|
___________________
See note references on pages 5360 through 55.62.
Third Quarter Results -
Refining Segment Operating Highlights
(millions of dollars, except per barrel amounts)
| | | Three Months Ended September 30, | Three Months Ended September 30, |
| 2017 | | 2016 | | Change | 2018 |
| 2017 | | Change |
Throughput volumes (thousand barrels per day) | | | | | | |
Throughput volumes (thousand barrels per day (BPD)) | | | | | | |
Feedstocks: | | | | | | | | | | |
Heavy sour crude oil | 446 |
| | 394 |
| | 52 |
| 466 |
| | 446 |
| | 20 |
|
Medium/light sour crude oil | 420 |
| | 520 |
| | (100 | ) | 424 |
| | 420 |
| | 4 |
|
Sweet crude oil | 1,348 |
| | 1,218 |
| | 130 |
| 1,527 |
| | 1,348 |
| | 179 |
|
Residuals | 215 |
| | 282 |
| | (67 | ) | 244 |
| | 215 |
| | 29 |
|
Other feedstocks | 147 |
| | 166 |
| | (19 | ) | 144 |
| | 147 |
| | (3 | ) |
Total feedstocks | 2,576 |
| | 2,580 |
| | (4 | ) | 2,805 |
| | 2,576 |
| | 229 |
|
Blendstocks and other | 317 |
| | 280 |
| | 37 |
| 295 |
| | 317 |
| | (22 | ) |
Total throughput volumes | 2,893 |
| | 2,860 |
| | 33 |
| 3,100 |
| | 2,893 |
| | 207 |
|
| | | | | | | | | | |
Yields (thousand barrels per day) | | | | | | |
Yields (thousand BPD) | | | | | | |
Gasolines and blendstocks | 1,401 |
| | 1,401 |
| | — |
| 1,478 |
| | 1,401 |
| | 77 |
|
Distillates | 1,108 |
| | 1,078 |
| | 30 |
| 1,201 |
| | 1,108 |
| | 93 |
|
Other products (f)(h) | 420 |
| | 426 |
| | (6 | ) | 460 |
| | 420 |
| | 40 |
|
Total yields | 2,929 |
| | 2,905 |
| | 24 |
| 3,139 |
| | 2,929 |
| | 210 |
|
| | | | | | | | | | |
Operating statistics(i) | | | | | | | | | | |
Refining segment margin (e) | $ | 2,911 |
| | $ | 2,294 |
| | $ | 617 |
| |
Adjusted refining segment operating income (e) | $ | 1,470 |
| | $ | 934 |
| | $ | 536 |
| |
Throughput volumes (thousand barrels per day) | 2,893 |
| | 2,860 |
| | 33 |
| |
Refining margin (g) | | $ | 2,852 |
| | $ | 2,911 |
| | $ | (59 | ) |
Adjusted refining operating income (see page 45) (g) | | $ | 1,339 |
| | $ | 1,460 |
| | $ | (121 | ) |
Throughput volumes (thousand BPD) | | 3,100 |
| | 2,893 |
| | 207 |
|
| | | | | | | | | | |
Refining segment throughput margin per barrel (g) | $ | 10.94 |
| | $ | 8.72 |
| | $ | 2.22 |
| |
Refining margin per barrel of throughput | | $ | 10.00 |
| | $ | 10.94 |
| | $ | (0.94 | ) |
Less: | | | | | | | | | | |
Operating expenses (excluding depreciation and amortization reflected below) | 3.71 |
| | 3.54 |
| | 0.17 |
| |
Depreciation and amortization expense | 1.71 |
| | 1.63 |
| | 0.08 |
| |
Adjusted refining segment operating income per barrel (h) | $ | 5.52 |
| | $ | 3.55 |
| | $ | 1.97 |
| |
Operating expenses (excluding depreciation and amortization expense reflected below) per barrel of throughput (b) | | 3.67 |
| | 3.75 |
| | (0.08 | ) |
Depreciation and amortization expense per barrel of throughput | | 1.64 |
| | 1.71 |
| | (0.07 | ) |
Adjusted refining operating income per barrel of throughput | | $ | 4.69 |
| | $ | 5.48 |
| | $ | (0.79 | ) |
___________________
See note references on pages 5360 through 55.62.
Third Quarter Results -
Ethanol Segment Operating Highlights
(millions of dollars, except per gallon amounts)
|
| | | | | | | | | | | |
| Three Months Ended September 30, |
| 2017 | | 2016 | | Change |
Operating statistics | | | | | |
Ethanol segment margin (e) | $ | 213 |
| | $ | 230 |
| | $ | (17 | ) |
Adjusted ethanol segment operating income (e) | $ | 82 |
| | $ | 106 |
| | $ | (24 | ) |
Production volumes (thousand gallons per day) | 4,032 |
| | 3,815 |
| | 217 |
|
| | | | | |
Ethanol segment margin per gallon of production (g) | $ | 0.57 |
| | $ | 0.66 |
| | $ | (0.09 | ) |
Less: | | | | | |
Operating expenses (excluding depreciation and amortization reflected below) | 0.30 |
| | 0.31 |
| | (0.01 | ) |
Depreciation and amortization expense | 0.05 |
| | 0.05 |
| | — |
|
Adjusted ethanol segment operating income per gallon of production (h) | $ | 0.22 |
| | $ | 0.30 |
| | $ | (0.08 | ) |
|
| | | | | | | | | | | |
| Three Months Ended September 30, |
| 2018 | | 2017 | | Change |
Operating statistics (i) | | | | | |
Ethanol margin (g) | $ | 156 |
| | $ | 213 |
| | $ | (57 | ) |
Ethanol operating income | $ | 21 |
| | $ | 82 |
| | $ | (61 | ) |
Production volumes (thousand gallons per day) | 4,069 |
| | 4,032 |
| | 37 |
|
| | | | | |
Ethanol margin per gallon of production | $ | 0.42 |
| | $ | 0.57 |
| | $ | (0.15 | ) |
Less: | | | | | |
Operating expenses (excluding depreciation and amortization expense reflected below) per gallon of production | 0.31 |
| | 0.30 |
| | 0.01 |
|
Depreciation and amortization expense per gallon of production | 0.05 |
| | 0.05 |
| | — |
|
Ethanol operating income per gallon of production | $ | 0.06 |
| | $ | 0.22 |
| | $ | (0.16 | ) |
Third Quarter Results -
VLP Segment Operating Highlights
(millions of dollars, except per barrel amounts)
|
| | | | | | | | | | | |
| Three Months Ended September 30, |
| 2017 | | 2016 | | Change |
Volumes (thousand barrels per day) | | | | | |
Pipeline transportation throughput | 859 |
| | 778 |
| | 81 |
|
Terminaling throughput | 2,694 |
| | 2,394 |
| | 300 |
|
| | | | | |
Operating statistics | | | | | |
Pipeline transportation revenue | $ | 23 |
| | $ | 19 |
| | $ | 4 |
|
Pipeline transportation revenue per barrel (g) | $ | 0.29 |
| | $ | 0.26 |
| | $ | 0.03 |
|
| | | | | |
Terminaling revenue | $ | 86 |
| | $ | 73 |
| | $ | 13 |
|
Terminaling revenue per barrel (g) | $ | 0.34 |
| | $ | 0.33 |
| | $ | 0.01 |
|
| | | | | |
Storage and other revenue | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| | | | | |
Total VLP segment operating revenues | $ | 110 |
| | $ | 92 |
| | $ | 18 |
|
|
| | | | | | | | | | | |
| Three Months Ended September 30, |
| 2018 | | 2017 | | Change |
Operating statistics (i) | | | | | |
Pipeline transportation revenue | $ | 31 |
| | $ | 23 |
| | $ | 8 |
|
Terminaling revenue | 107 |
| | 86 |
| | 21 |
|
Storage and other revenue | 2 |
| | 1 |
| | 1 |
|
Total VLP revenues | $ | 140 |
| | $ | 110 |
| | $ | 30 |
|
| | | | | |
Pipeline transportation throughput (thousand BPD) | 1,141 |
| | 859 |
| | 282 |
|
Pipeline transportation revenue per barrel of throughput | $ | 0.30 |
| | $ | 0.29 |
| | $ | 0.01 |
|
| | | | | |
Terminaling throughput (thousand BPD) | 3,767 |
| | 2,694 |
| | 1,073 |
|
Terminaling revenue per barrel of throughput | $ | 0.31 |
| | $ | 0.34 |
| | $ | (0.03 | ) |
___________________
See note references on pages 5360 through 55.62.
Third Quarter Results -
Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)
|
| | | | | | | | | | | |
| Three Months Ended September 30, |
| 2017 | | 2016 | | Change |
Feedstocks | | | | | |
Brent crude oil | $ | 52.21 |
| | $ | 46.91 |
| | $ | 5.30 |
|
Brent less West Texas Intermediate (WTI) crude oil | 4.05 |
| | 2.03 |
| | 2.02 |
|
Brent less Alaska North Slope (ANS) crude oil | 0.02 |
| | 2.13 |
| | (2.11 | ) |
Brent less Louisiana Light Sweet (LLS) crude oil | 0.57 |
| | 0.38 |
| | 0.19 |
|
Brent less Argus Sour Crude Index (ASCI) crude oil | 3.85 |
| | 5.16 |
| | (1.31 | ) |
Brent less Maya crude oil | 5.66 |
| | 7.88 |
| | (2.22 | ) |
LLS crude oil | 51.64 |
| | 46.53 |
| | 5.11 |
|
LLS less ASCI crude oil | 3.28 |
| | 4.78 |
| | (1.50 | ) |
LLS less Maya crude oil | 5.09 |
| | 7.50 |
| | (2.41 | ) |
WTI crude oil | 48.16 |
| | 44.88 |
| | 3.28 |
|
| | | | | |
Natural gas (dollars per million British thermal units (MMBtu)) | 2.91 |
| | 2.80 |
| | 0.11 |
|
| | | | | |
Products | | | | | |
U.S. Gulf Coast: | | | | | |
CBOB gasoline less Brent | 14.36 |
| | 9.69 |
| | 4.67 |
|
Ultra-low-sulfur diesel less Brent | 15.89 |
| | 10.63 |
| | 5.26 |
|
Propylene less Brent | (1.74 | ) | | (2.76 | ) | | 1.02 |
|
CBOB gasoline less LLS | 14.93 |
| | 10.07 |
| | 4.86 |
|
Ultra-low-sulfur diesel less LLS | 16.46 |
| | 11.01 |
| | 5.45 |
|
Propylene less LLS | (1.17 | ) | | (2.38 | ) | | 1.21 |
|
U.S. Mid-Continent: | | | | | |
CBOB gasoline less WTI | 19.28 |
| | 14.15 |
| | 5.13 |
|
Ultra-low-sulfur diesel less WTI | 21.99 |
| | 15.36 |
| | 6.63 |
|
North Atlantic: | | | | | |
CBOB gasoline less Brent | 17.72 |
| | 11.12 |
| | 6.60 |
|
Ultra-low-sulfur diesel less Brent | 17.06 |
| | 11.52 |
| | 5.54 |
|
U.S. West Coast: | | | | | |
CARBOB 87 gasoline less ANS | 22.11 |
| | 17.68 |
| | 4.43 |
|
CARB diesel less ANS | 20.46 |
| | 14.83 |
| | 5.63 |
|
CARBOB 87 gasoline less WTI | 26.14 |
| | 17.58 |
| | 8.56 |
|
CARB diesel less WTI | 24.49 |
| | 14.73 |
| | 9.76 |
|
New York Harbor corn crush (dollars per gallon) | 0.31 |
| | 0.35 |
| | (0.04 | ) |
___________________
See note references on pages 53 through 55. |
| | | | | | | | | | | |
| Three Months Ended September 30, |
| 2018 | | 2017 | | Change |
Feedstocks (dollars per barrel) | | | | | |
Brent crude oil | $ | 75.93 |
| | $ | 52.21 |
| | $ | 23.72 |
|
Brent less West Texas Intermediate (WTI) crude oil | 6.23 |
| | 4.05 |
| | 2.18 |
|
Brent less Alaska North Slope (ANS) crude oil | 0.38 |
| | 0.02 |
| | 0.36 |
|
Brent less Louisiana Light Sweet (LLS) crude oil | 1.63 |
| | 0.57 |
| | 1.06 |
|
Brent less Argus Sour Crude Index (ASCI) crude oil | 5.12 |
| | 3.85 |
| | 1.27 |
|
Brent less Maya crude oil | 9.74 |
| | 5.66 |
| | 4.08 |
|
LLS crude oil | 74.30 |
| | 51.64 |
| | 22.66 |
|
LLS less ASCI crude oil | 3.49 |
| | 3.28 |
| | 0.21 |
|
LLS less Maya crude oil | 8.11 |
| | 5.09 |
| | 3.02 |
|
WTI crude oil | 69.70 |
| | 48.16 |
| | 21.54 |
|
| | | | | |
Natural gas (dollars per million British Thermal Units (MMBtu)) | 2.96 |
| | 2.91 |
| | 0.05 |
|
| | | | | |
Products (dollars per barrel, unless otherwise noted) | | | | | |
U.S. Gulf Coast: | | | | | |
Conventional Blendstock of Oxygenate Blending (CBOB) gasoline less Brent | 7.08 |
| | 14.36 |
| | (7.28 | ) |
Ultra-low-sulfur diesel less Brent | 13.91 |
| | 15.89 |
| | (1.98 | ) |
Propylene less Brent | 5.49 |
| | (1.74 | ) | | 7.23 |
|
CBOB gasoline less LLS | 8.71 |
| | 14.93 |
| | (6.22 | ) |
Ultra-low-sulfur diesel less LLS | 15.54 |
| | 16.46 |
| | (0.92 | ) |
Propylene less LLS | 7.12 |
| | (1.17 | ) | | 8.29 |
|
U.S. Mid-Continent: | | | | | |
CBOB gasoline less WTI | 16.68 |
| | 19.28 |
| | (2.60 | ) |
Ultra-low-sulfur diesel less WTI | 22.77 |
| | 21.99 |
| | 0.78 |
|
North Atlantic: | | | | | |
CBOB gasoline less Brent | 10.43 |
| | 17.72 |
| | (7.29 | ) |
Ultra-low-sulfur diesel less Brent | 15.54 |
| | 17.06 |
| | (1.52 | ) |
U.S. West Coast: | | | | | |
California Reformulated Gasoline Blendstock of Oxygenate Blending (CARBOB) 87 gasoline less ANS | 13.52 |
| | 22.11 |
| | (8.59 | ) |
CARB diesel less ANS | 17.85 |
| | 20.46 |
| | (2.61 | ) |
CARBOB 87 gasoline less WTI | 19.37 |
| | 26.14 |
| | (6.77 | ) |
CARB diesel less WTI | 23.70 |
| | 24.49 |
| | (0.79 | ) |
New York Harbor corn crush (dollars per gallon) | 0.18 |
| | 0.31 |
| | (0.13 | ) |
Total Company, Corporate, and Other
Operating revenuesRevenues increased $3.9$7.3 billion in the third quarter of 20172018 compared to the third quarter of 20162017 primarily due to increases in refined petroleum product prices associated with our refining segment. This improvement in operating revenues was partiallymore than offset by higher cost of materials and other of $3.3 billion, as well as increasessales between the periods, resulting in operating expenses (excluding depreciation and amortization expense), depreciation and amortization expense, other operating expenses, and general and administrative expenses (excluding depreciation and amortization expense) of $63 million, $27 million, $44 million, and $37 million, respectively. These changes resulted in an increasea decrease in operating income of $446 million, from $892$113 million in the third quarter of 20162018 compared to $1.3 billion in the third quarter of 2017.
Excluding the $44 million of damages associated with Hurricane Harvey, which areadjustments to operating income reflected in other operating expenses,the table on page 45, adjusted operating income was $1.2 billion for the third quarter of 2017 increased $490 million.2018 compared to $1.4 billion for the third quarter of 2017. Details regarding changesthe $147 million decrease in segment margins,adjusted operating expenses (excluding depreciation and amortization expense), and depreciation and amortization expenseincome between the periods are discussed by segment in the individual segment analysis below.
General and administrative expenses (excluding depreciation and amortization expense)Other income, net increased by $37$19 million in the third quarter of 20172018 compared to the third quarter of 20162017 primarily due to expenseshigher equity in earnings associated with the terminationour Diamond Pipeline joint venture of the acquisition of certain assets from Plains of $16$11 million and higher employee related costsinterest income of $11$9 million.
Income tax expense increased $234decreased $102 million fromin the third quarter of 20162018 compared to the third quarter of 2017 primarily as a result of higher income before income tax expense. Thea decrease in our effective tax rates ofrate from 30 percent infor the third quarter of 2017 and 18to 24 percent infor the third quarter of 2016 are lower than2018. The decrease in our effective tax rate is due to the reduction in the U.S. statutory income tax rate offrom 35 percent primarily becauseto 21 percent effective January 1, 2018, partially offset by the impact of a minimum tax on the income from ourof international operations is taxed at statutory rates that are lower than insubsidiaries (the global intangible low-taxes income (GILTI) tax) and the repeal of the U.S. The effective tax rate in the third quartermanufacturing deduction as a result of 2016 was also impacted by a benefit of $42 million associated with our Aruba disposition and a benefit of $35 million resulting from the favorable resolution of an income tax audit. The Aruba disposition matterTax Reform, which is more fully described in Note 210 of Condensed Notes to Consolidated Financial Statements.
Refining Segment Results
Refining segment operating revenues increased $4.0 billion and cost of materials and other increased$3.4$7.3 billion in the third quarter of 20172018 compared to the third quarter of 20162017 primarily due to increases in refined petroleum product prices and crude oil feedstocks, respectively. The resulting $617 million increaseprices. This improvement in refining segment marginrevenues was partiallymore than offset by increases in operating expenses (excluding depreciation and amortization expense), depreciation and amortization expense associated with ourhigher cost of sales and other operating expenses of $55 million, $26 million, and $41 million, respectively,between the periods, resulting in an increasea decrease in refining segment operating income of $495 million, from $934$90 million in the third quarter of 20162018 compared to $1.4 billion in the third quarter of 2017.
Excluding the $41 million of damages associated with Hurricane Harvey, which areadjustments to refining segment operating income reflected in other operating expenses,the table on page 45, refining segment adjusted operating income decreased $121 million from $1.5 billion for the third quarter of 2017 increased $536 million. The reasonsto $1.3 billion for this increase are described below.
As previously noted,the third quarter of 2018. This decrease is primarily due to lower refining segment margin increased $617and higher refining segment operating expenses (excluding depreciation and amortization expense).
Refining segment margin, as defined in note (g) to the accompanying tables (see page 60), decreased $59 million in the third quarter of 20172018 compared to the third quarter of 2016,2017, primarily due to the following:
Increase in distillate margins. We experienced an increase in distillate margins throughout all of our regions in the third quarter of 2017 compared to the third quarter of 2016. For example, the Brent-
based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $15.89 per barrel in the third quarter of 2017 compared to $10.63 per barrel in the third quarter of 2016, representing a favorable increase of $5.26 per barrel. Another example is the Brent-based benchmark reference margin for North Atlantic ultra-low-sulfur diesel that was $17.06 per barrel in the third quarter of 2017 compared to $11.52 per barrel in the third quarter of 2016, representing a favorable increase of $5.54 per barrel. We estimate that the increase in distillate margins in the third quarter of 2017 compared to the third quarter of 2016 had a favorable impact to our refining segment margin of approximately $385 million.
IncreaseDecrease in gasoline margins.We also experienced an increasea decrease in gasoline margins throughout all our regions during the third quarter of 20172018 compared to the third quarter of 2016.2017. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $7.08 per barrel for the third quarter of 2018 compared to $14.36 per barrel duringfor the third quarter of 2017, compared to $9.69 per barrel during the third quarterrepresenting an unfavorable decrease of 2016, representing a favorable increase of $4.67$7.28 per barrel. Another example is the Brent-basedANS-based benchmark reference margin for North Atlantic CBOBU.S. West Coast CARBOB 87 gasoline, which was $17.72$13.52 per barrel duringfor the third quarter of 2018 compared to $22.11 per barrel for the third quarter of 2017, compared to $11.12representing an unfavorable decrease of $8.59 per barrel during the third quarter of 2016, representing a $6.60 per barrel increase.barrel. We estimate that the increasesdecrease in gasoline margins per barrel duringin the third quarter of 20172018 compared to the third quarter of 20162017 had an unfavorable impact to our refining segment margin of approximately $594 million.
Decrease in other products margins. We experienced a decrease in the margins of other products (such as petroleum coke and sulfur) relative to Brent crude oil during the third quarter of 2018 compared to the third quarter of 2017 due to an increase in the cost of crude oils between the periods. Because the market prices for our other products remain relatively stable, our margins decline when the cost of crude oils that we process increases. For example, the benchmark price of Brent crude oil was $75.93 per barrel for the third quarter of 2018 compared to $52.21 per barrel for the third quarter of 2017, representing an unfavorable increase of $23.72 per barrel. We estimate that the decrease in other products margins in the third quarter of 2018 compared to the third quarter of 2017 had an unfavorable impact to our refining segment margin of approximately $78 million.
Decrease in distillate margins. We also experienced a decrease in distillate margins during the third quarter of 2018 compared to the third quarter of 2017. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $13.91 per barrel for the third quarter of 2018 compared to $15.89 per barrel for the third quarter of 2017, representing an unfavorable decrease of $1.98 per barrel. Another example is the ANS-based benchmark reference margin for U.S. West Coast CARB diesel, which was $17.85 per barrel for the third quarter of 2018 compared to $20.46 per barrel for the third quarter of 2017, representing an unfavorable decrease of $2.61 per barrel. We estimate that the decrease in distillate margins per barrel in the third quarter of 2018 compared to the third quarter of 2017 had an unfavorable impact to our refining segment margin of approximately $57 million.
Increase in charges from VLP. Charges from the VLP segment for transportation and terminaling services increased $30 million in the third quarter of 2018 compared to the third quarter of 2017 primarily due to additional services provided by a terminal and a product pipeline system acquired by VLP in November 2017 that were formerly a part of the refining segment. The increase in charges from the VLP segment is more fully discussed in the VLP segment analysis below.
Higher discounts on crude oils. The market prices for refined petroleum products generally track the price of Brent crude oil, which is a benchmark crude oil, and we benefit when we process crude oils that are priced at a discount to Brent crude oil. We benefitted from processing these types of crude oils during the third quarter of 2018 and that benefit improved compared to the third quarter of 2017. For example, WTI crude oil, a light sweet crude oil processed in our U.S. Mid-Continent region, sold at a discount of $6.23 per barrel for the third quarter of 2018 compared to a discount of $4.05 per barrel for the third quarter of 2017, representing a favorable increase of $2.18 per barrel. Another example is Maya crude oil, a sour crude oil processed in our U.S. Gulf Coast region, which sold at a discount to Brent crude oil of $9.74 per barrel for the third quarter of 2018 compared to a discount of $5.66 per barrel for the third quarter of 2017, representing a favorable increase of $4.08 per barrel. We estimate that the increase in the discounts for the crude oils we processed during the third quarter of 2018 compared to the third quarter of 2017 had a favorable impact to our refining segment margin of approximately $359$220 million.
Higher throughput volumes. Refining throughput volumes increased by 33,000 barrels per day207,000 BPD in the third quarter of 2017 despite unplanned downtime at certain2018 primarily due to effects of our U.S. Gulf Coast refineries related to Hurricane Harvey.Harvey in the third quarter of 2017. We estimate that the increase in refining throughput volumes had a positive impact on our refining segment margin of approximately $33$190 million.
LowerHigher discounts on other feedstocks. In addition to crude oil, we utilize other feedstocks, such as natural gas and residuals, in certain of our refining processes. We benefit when we process these other feedstocks that are priced at a discount to Brent crude oil when pricing terms are favorable. While weoil. We benefitted from processing these
types of feedstocks induring the third quarter of 2017,2018 and that benefit declinedimproved compared to the third quarter of 2016.2017. We estimate that the reductionincrease in the discounts for the other feedstocks that we processed induring the third quarter of 2018 compared to the third quarter of 2017 had an unfavorablea favorable impact to our refining segment margin of approximately $88$154 million.
Lower discounts on sour crude oils. The market prices of refined products generally track the price of Brent crude oil, which is a benchmark sweet crude oil, and we benefit when we process crude oils that are priced at a discount to Brent crude oil when pricing terms are favorable. While we benefitted from processing sour crude oils in the third quarter of 2017, that benefit declined compared to the third quarter of 2016. For example, ASCI crude oil sold at a discount of $3.85 per barrel to Brent crude oil in the third quarter of 2017 compared to a discount of $5.16 per barrel in the third quarter of 2016, representing an unfavorable decrease of $1.31 per barrel. Another example is Maya crude oil that sold at a discount of $5.66 per barrel to Brent crude oil in the third quarter of 2017 compared to a discount of $7.88 per barrel in the third quarter of 2016, representing an unfavorable decrease of $2.22 per barrel. We estimate that the reduction in the discounts for sour crude oils that we processed in the third quarter of 2017 had an unfavorable impact to our refining segment margin of approximately $66 million.
Higher costs of biofuel credits. As more fully described in Note 1315 of Condensed Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs, and the cost
of these credits (primarily RINs in the U.S.) increaseddecreased by $32$136 million from $198to $94 million infor the third quarter of 20162018 compared to $230 million infor the third quarter of 2017.
Increase in charges from VLP. Charges from the VLP segment for transportation and terminaling services increased $18 million in the third quarter of 2017 compared to the third quarter of 2016 primarily due to new charges from businesses acquired by VLP during the third quarter of 2016. Details regarding the increase in charges from VLP are discussed in the VLP segment analysis below.
The increase of $55 million in refiningRefining segment operating expenses (excluding depreciation and amortization expense) wasincreased$51 million primarily due to an increase in energy costs driven bymaintenance expenditures of $16 million and higher natural gas prices ($2.91 per MMBtu in the third quartercatalyst and chemicals expenses of 2017 compared to $2.80 per MMBtu in the third quarter of 2016).
The increase of $26 million in depreciation and amortization expense associated with our cost of sales was primarily due to an increase in refinery turnaround and catalyst amortization expense due to costs incurred in the latter part of 2016 in connection with significant turnaround projects at our Port Arthur and Texas City Refineries.$12 million.
Ethanol Segment Results
Ethanol segment operating revenues decreased $105 million and cost of materials and other decreased $88increased $50 million in the third quarter of 20172018 compared to the third quarter of 20162017 primarily due to an increase in ethanol sales volumes and increases in corn related co-product prices, partially offset by lower ethanol prices. This improvement in ethanol segment revenue was more than offset by higher cost of sales between the periods resulting in a decrease in ethanol sales volumes. The resulting $17 million decrease in ethanol segment margin, along with higher operating expenses (excluding depreciation and amortization expense) of $7 million, resulted in a decrease in operating income of $24 million, from $106$61 million in the third quarter of 20162018 compared to $82the third quarter of 2017. This decrease is primarily due to lower ethanol segment margins as outlined below.
Ethanol segment margin, as defined in note (g) to the accompanying tables (see page 60), decreased $57 million in the third quarter of 2017. The reasons for this decrease are described below.
As previously noted, ethanol segment margin decreased $17 million in the third quarter of 20172018 compared to the third quarter of 20162017, primarily due to the following:
Higher corn prices.Lower ethanol prices Corn. Ethanol prices were higherlower in the third quarter of 20172018 compared to the third quarter of 20162017 primarily due to an increase in domestic production. For example, the New York Harbor ethanol price was $1.47 per gallon for the third quarter of 2018 compared to $1.62 per gallon for the third quarter of 2017, representing an unfavorable decrease of $0.15 per gallon. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of approximately $76 million.
Higher co-product prices. An increase in protein values, as compared to soybean meal, had a favorable effect on the prices we received for the corn related co-products that we produced. We estimate that the increase in corn related co-product prices had a favorable impact to our ethanol segment margin of approximately $12 million.
Lower corn prices. Corn prices were lower U.S. corn production expected fromin the current corn crop.third quarter of 2018 compared to the third quarter of 2017. For example, the Chicago Board of Trade (CBOT) corn price was $3.54 per bushel for the third quarter of 2018 compared to $3.61 per bushel infor the third quarter of 2017, compared to $3.32representing a favorable decrease of $0.07 per bushel in the third quarter of 2016.bushel. We estimate that the increasedecrease in the price of corn had an unfavorable impact to our ethanol segment margin of $30 million.
Higher ethanol prices. Ethanol prices were slightly higher in the third quarter of 2017 compared to the third quarter of 2016 primarily due to an increase in ethanol export demand. For example, the New York Harbor ethanol price was $1.62 per gallon in the third quarter of 2017 compared to $1.55 per gallon in the third quarter of 2016. We estimate this increase had a favorable impact to our ethanol segment margin of $15approximately $7 million.
VLP Segment Results
VLP segment operating revenues increased $18$30 million in the third quarter of 20172018 compared to the third quarter of 20162017 primarily due to $23 million of incremental revenues generated from transportation and terminaling services provided toassociated with the Port Arthur terminal and the Parkway pipeline acquired by VLP in November 2017 that were formerly a part of the refining segment associated with a business acquired during the third quarter of 2016 and assets acquired in January 2017, as discussed below. This $18 millionsegment. The increase in VLP segment revenues was partially offset by higher operating expenses (excluding depreciation and amortization expense) and other operating expenses of $2 million and $3 million, respectively, resulting in an increase in operating income of $13 million. Excluding the $3 million of damages associated with Hurricane Harvey, which are reflected in
other operating expenses, adjustedwas partially offset by higher cost of sales, resulting in an increase in VLP segment operating income increased by $16of $21 million in the third quarter of 2018 compared to the third quarter of 2016.2017. Excluding the adjustment reflected in the table on page 45, VLP adjusted operating income increased $18 million.
VLP segment operating revenues increased $18Corporate and Eliminations
Corporate and eliminations, which consists primarily of general and administrative expenses and related depreciation and amortization expense, decreased by $17 million in the third quarter of 20172018 compared to the third quarter of 2016,2017. This decrease is primarily due to the following:
Incremental terminaling throughput from acquired business. VLP experienced an 11 percent increase in terminaling revenuesexpenses incurred in the third quarter of 2017 compared toassociated with the third quartertermination of 2016 generated by contributions from the Meraux and Three Rivers Terminal Services Business, which was acquired in September 2016. The incremental throughput volumes generated by this business had a favorable impact to VLP’s operating revenues of $10 million.
Incremental operating revenues from acquired undivided interest in crude system assets. Incremental throughput volumes related to the acquisition of an undivided interest in crude systemcertain assets in January 2017 had a favorable impact to VLP’s operating revenues of $3 million.from Plains.
First Nine Months Results -
Financial Highlights By Segment and Total Company
(millions of dollars)
| | | Nine Months Ended September 30, 2017 | Nine Months Ended September 30, 2018 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total Company | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 65,030 |
| | $ | 2,558 |
| | $ | — |
| | $ | — |
| | $ | 67,588 |
| |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 85,675 |
| | $ | 2,625 |
| | $ | — |
| | $ | 3 |
| | $ | 88,303 |
|
Intersegment revenues | 1 |
| | 136 |
| | 326 |
| | (463 | ) | | — |
| 10 |
| | 156 |
| | 407 |
| | (573 | ) | | — |
|
Total operating revenues | 65,031 |
| | 2,694 |
| | 326 |
| | (463 | ) | | 67,588 |
| |
Costs of sales: | | | | | | | | | | |
Total revenues | | 85,685 |
| | 2,781 |
| | 407 |
| | (570 | ) | | 88,303 |
|
Cost of sales: | | | | | | | | | | |
Cost of materials and other(a) | 57,662 |
| | 2,166 |
| | — |
| | (462 | ) | | 59,366 |
| 77,608 |
| | 2,279 |
| | — |
| | (570 | ) | | 79,317 |
|
Operating expenses (excluding depreciation and amortization expense reflected below) | 2,935 |
| | 330 |
| | 75 |
| | (1 | ) | | 3,339 |
| 3,013 |
| | 336 |
| | 93 |
| | (3 | ) | | 3,439 |
|
Depreciation and amortization expense | 1,358 |
| | 63 |
| | 36 |
| | — |
| | 1,457 |
| 1,385 |
| | 57 |
| | 57 |
| | — |
| | 1,499 |
|
Total cost of sales | 61,955 |
| | 2,559 |
| | 111 |
| | (463 | ) | | 64,162 |
| 82,006 |
| | 2,672 |
| | 150 |
| | (573 | ) | | 84,255 |
|
Other operating expenses (b)(c) | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
| 41 |
| | — |
| | — |
| | — |
| | 41 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below)(d) | — |
| | — |
| | — |
| | 597 |
| | 597 |
| — |
| | — |
| | — |
| | 695 |
| | 695 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 39 |
| | 39 |
| — |
| | — |
| | — |
| | 39 |
| | 39 |
|
Operating income (loss) by segment | $ | 3,035 |
| | $ | 135 |
| | $ | 212 |
| | $ | (636 | ) | | 2,746 |
| |
Operating income by segment | | $ | 3,638 |
| | $ | 109 |
| | $ | 257 |
| | $ | (731 | ) | | 3,273 |
|
Other income, net(e) | | | | | | | | | 50 |
| | | | | | | | | 88 |
|
Interest and debt expense, net of capitalized interest | | | | | | | | | (354 | ) | | | | | | | | | (356 | ) |
Income before income tax expense | | | | | | | | | 2,442 |
| | | | | | | | | 3,005 |
|
Income tax expense(f) | | | | | | | | | 686 |
| | | | | | | | | 674 |
|
Net income | | | | | | | | | 1,756 |
| | | | | | | | | 2,331 |
|
Less: Net income attributable to noncontrolling interests(a) | | | | | | | | | 62 |
| | | | | | | | | 161 |
|
Net income attributable to Valero Energy Corporation stockholders | | | | | | | | | $ | 1,694 |
| | | | | | | | | $ | 2,170 |
|
___________________
See note references on pages 5360 through 55.62.
First Nine Months Results -
Financial Highlights By Segment and Total Company (continued)
(millions of dollars)
| | | Nine Months Ended September 30, 2016 | Nine Months Ended September 30, 2017 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total Company | Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Operating revenues: | | | | | | | | | | |
Operating revenues from external customers | $ | 52,302 |
| | $ | 2,645 |
| | $ | — |
| | $ | — |
| | $ | 54,947 |
| |
Revenues: | | | | | | | | | | |
Revenues from external customers | | $ | 65,030 |
| | $ | 2,558 |
| | $ | — |
| | $ | — |
| | $ | 67,588 |
|
Intersegment revenues | — |
| | 135 |
| | 258 |
| | (393 | ) | | — |
| 1 |
| | 136 |
| | 326 |
| | (463 | ) | | — |
|
Total operating revenues | 52,302 |
| | 2,780 |
| | 258 |
| | (393 | ) | | 54,947 |
| |
Costs of sales: | | | | | | | | | | |
Total revenues | | 65,031 |
| | 2,694 |
| | 326 |
| | (463 | ) | | 67,588 |
|
Cost of sales: | | | | | | | | | | |
Cost of materials and other | 45,790 |
| | 2,263 |
| | — |
| | (393 | ) | | 47,660 |
| 57,662 |
| | 2,166 |
| | — |
| | (462 | ) | | 59,366 |
|
Operating expenses (excluding depreciation and amortization expense) (d) | 2,716 |
| | 305 |
| | 72 |
| | — |
| | 3,093 |
| |
Operating expenses (excluding depreciation and amortization expense reflected below) (b) | | 2,966 |
| | 330 |
| | 75 |
| | (1 | ) | | 3,370 |
|
Depreciation and amortization expense (d) | 1,308 |
| | 48 |
| | 35 |
| | — |
| | 1,391 |
| 1,358 |
| | 63 |
| | 36 |
| | — |
| | 1,457 |
|
Lower of cost or market inventory valuation adjustment (a) | (697 | ) | | (50 | ) | | — |
| | — |
| | (747 | ) | |
Total cost of sales | 49,117 |
|
| 2,566 |
| | 107 |
| | (393 | ) | | 51,397 |
| 61,986 |
|
| 2,559 |
| | 111 |
| | (463 | ) | | 64,193 |
|
Other operating expenses (c) | | 41 |
| | — |
| | 3 |
| | — |
| | 44 |
|
General and administrative expenses (excluding depreciation and amortization expense reflected below)(b) | — |
| | — |
| | — |
| | 507 |
| | 507 |
| — |
| | — |
| | — |
| | 592 |
| | 592 |
|
Depreciation and amortization expense | — |
| | — |
| | — |
| | 35 |
| | 35 |
| — |
| | — |
| | — |
| | 39 |
| | 39 |
|
Asset impairment loss (c) | 56 |
| | — |
| | — |
| | — |
| | 56 |
| |
Operating income (loss) by segment | $ | 3,129 |
| | $ | 214 |
| | $ | 151 |
| | $ | (542 | ) | | 2,952 |
| |
Other income, net | | | | | | | | | 35 |
| |
Operating income by segment | | $ | 3,004 |
| | $ | 135 |
| | $ | 212 |
| | $ | (631 | ) | | 2,720 |
|
Other income, net (b) | | | | | | | | | | 76 |
|
Interest and debt expense, net of capitalized interest | | | | | | | | | (334 | ) | | | | | | | | | (354 | ) |
Income before income tax expense | | | | | | | | | 2,653 |
| | | | | | | | | 2,442 |
|
Income tax expense | | | | | | | | | 652 |
| | | | | | | | | 686 |
|
Net income | | | | | | | | | 2,001 |
| | | | | | | | | 1,756 |
|
Less: Net income attributable to noncontrolling interests | | | | | | | | | 79 |
| | | | | | | | | 62 |
|
Net income attributable to Valero Energy Corporation stockholders | | | | | | | | | $ | 1,922 |
| | | | | | | | | $ | 1,694 |
|
___________________
See note references on pages 5360 through 55.62.
First Nine Months Results -
Financial Highlights By Segment and Total Company (continued)
(millions of dollars)
|
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total Company |
Reconciliation of actual (U.S. GAAP) to adjusted (non-GAAP) amounts (e) | | | | | | | | | |
Actual and adjusted operating income (loss) | | | | | | | | | |
Operating income (loss) by segment | $ | 3,035 |
| | $ | 135 |
| | $ | 212 |
| | $ | (636 | ) | | $ | 2,746 |
|
Exclude adjustment: | | | | | | | | | |
Other operating expenses (b) | (41 | ) | | — |
| | (3 | ) | | — |
| | (44 | ) |
Adjusted operating income (loss) | $ | 3,076 |
| | $ | 135 |
| | $ | 215 |
| | $ | (636 | ) | | $ | 2,790 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2016 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total Company |
Reconciliation of actual (U.S. GAAP) to adjusted (non-GAAP) amounts (e) | | | | | | | | | |
Actual and adjusted operating income (loss) | | | | | | | | | |
Operating income (loss) | $ | 3,129 |
| | $ | 214 |
| | $ | 151 |
| | $ | (542 | ) | | $ | 2,952 |
|
Exclude adjustments: | | | | | | | | | |
Lower of cost or market inventory valuation adjustment (a) | 697 |
| | 50 |
| | — |
| | — |
| | 747 |
|
Asset impairment loss (c) | (56 | ) | | — |
| | — |
| | — |
| | (56 | ) |
Adjusted operating income (loss) | $ | 2,488 |
| | $ | 164 |
| | $ | 151 |
| | $ | (542 | ) | | $ | 2,261 |
|
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 |
Reconciliation of net income attributable to Valero Energy Corporation stockholders to adjusted net income attributable to Valero Energy Corporation stockholders (g) | | | |
Net income attributable to Valero Energy Corporation stockholders | $ | 2,170 |
| | $ | 1,694 |
|
Exclude adjustments: | | | |
Blender’s tax credit attributable to Valero Energy Corporation shareholders (a) | 90 |
| | — |
|
Income tax expense related to the blender’s tax credit | (11 | ) | | — |
|
Blender’s tax credit attributable to Valero Energy Corporation stockholders, net of taxes | 79 |
| | — |
|
Texas City Refinery fire expenses | (14 | ) | | — |
|
Income tax benefit related to Texas City Refinery fire expenses | 3 |
| | — |
|
Texas City Refinery fire expenses, net of taxes | (11 | ) | | — |
|
Environmental reserve adjustments (d) | (108 | ) | | — |
|
Income tax benefit related to the environmental reserve adjustments | 24 |
| | — |
|
Environmental reserve adjustments, net of taxes | (84 | ) | | — |
|
Loss on early redemption of debt (e) | (38 | ) | | — |
|
Income tax benefit related to the loss on early redemption of debt | 9 |
| | — |
|
Loss on early redemption of debt, net of taxes | (29 | ) | | — |
|
Total adjustments | (45 | ) | | — |
|
Adjusted net income attributable to Valero Energy Corporation stockholders | $ | 2,215 |
| | $ | 1,694 |
|
___________________
See note references on pages 5360 through 55.62.
First Nine Months Results -
Financial Highlights By Segment and Total Company (continued)
(millions of dollars)
|
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2018 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Reconciliation of operating income to adjusted operating income (g) | | | | | | | | | |
Operating income by segment (see page 53) | $ | 3,638 |
| | $ | 109 |
| | $ | 257 |
| | $ | (731 | ) | | $ | 3,273 |
|
Exclude: | | | | | | | | | |
Blender’s tax credit (a) | 170 |
| | — |
| | — |
| | — |
| | 170 |
|
Other operating expenses (c) | (41 | ) | | — |
| | — |
| | — |
| | (41 | ) |
Environmental reserve adjustments (d) | — |
| | — |
| | — |
| | (108 | ) | | (108 | ) |
Adjusted operating income | $ | 3,509 |
| | $ | 109 |
| | $ | 257 |
| | $ | (623 | ) | | $ | 3,252 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
| Refining | | Ethanol | | VLP | | Corporate and Eliminations | | Total |
Reconciliation of operating income to adjusted operating income (g) | | | | | | | | | |
Operating income by segment (see page 54) | $ | 3,004 |
| | $ | 135 |
| | $ | 212 |
| | $ | (631 | ) | | $ | 2,720 |
|
Exclude: | | | | | | | | | |
Other operating expenses (c) | (41 | ) | | — |
| | (3 | ) | | — |
| | (44 | ) |
Adjusted operating income | $ | 3,045 |
| | $ | 135 |
| | $ | 215 |
| | $ | (631 | ) | | $ | 2,764 |
|
___________________
See note references on pages 60 through 62.
First Nine Months Results -
Refining Segment Operating Highlights
(millions of dollars, except per barrel amounts)
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | | 2016 | | Change | 2018 | | 2017 | | Change |
Throughput volumes (thousand barrels per day) | | | | | | |
Throughput volumes (thousand BPD) | | | | | | |
Feedstocks: | | | | | | | | | | |
Heavy sour crude oil | 470 |
| | 401 |
| | 69 |
| 476 |
| | 470 |
| | 6 |
|
Medium/light sour crude oil | 461 |
| | 519 |
| | (58 | ) | 422 |
| | 461 |
| | (39 | ) |
Sweet crude oil | 1,301 |
| | 1,195 |
| | 106 |
| 1,392 |
| | 1,301 |
| | 91 |
|
Residuals | 226 |
| | 281 |
| | (55 | ) | 233 |
| | 226 |
| | 7 |
|
Other feedstocks | 146 |
| | 157 |
| | (11 | ) | 128 |
| | 146 |
| | (18 | ) |
Total feedstocks | 2,604 |
| | 2,553 |
| | 51 |
| 2,651 |
| | 2,604 |
| | 47 |
|
Blendstocks and other | 313 |
| | 302 |
| | 11 |
| 326 |
| | 313 |
| | 13 |
|
Total throughput volumes | 2,917 |
| | 2,855 |
| | 62 |
| 2,977 |
| | 2,917 |
| | 60 |
|
| | | | | | | | | | |
Yields (thousand barrels per day) | | | | | | |
Yields (thousand BPD) | | | | | | |
Gasolines and blendstocks | 1,406 |
| | 1,396 |
| | 10 |
| 1,429 |
| | 1,406 |
| | 23 |
|
Distillates | 1,122 |
| | 1,072 |
| | 50 |
| 1,135 |
| | 1,122 |
| | 13 |
|
Other products (f)(h) | 426 |
| | 425 |
| | 1 |
| 451 |
| | 426 |
| | 25 |
|
Total yields | 2,954 |
| | 2,893 |
| | 61 |
| 3,015 |
| | 2,954 |
| | 61 |
|
| | | | | | | | | | |
Operating statistics(i) | | | | | | | | | | |
Refining segment margin (e) | $ | 7,369 |
| | $ | 6,512 |
| | $ | 857 |
| |
Adjusted operating income (e) | $ | 3,076 |
| | $ | 2,488 |
| | $ | 588 |
| |
Throughput volumes (thousand barrels per day) | 2,917 |
| | 2,855 |
| | 62 |
| |
Refining margin (g) | | $ | 7,907 |
| | $ | 7,369 |
| | $ | 538 |
|
Adjusted refining operating income (see page 56) (g) | | $ | 3,509 |
| | $ | 3,045 |
| | $ | 464 |
|
Throughput volumes (thousand BPD) | | 2,977 |
| | 2,917 |
| | 60 |
|
| | | | | | | | | | |
Refining segment throughput margin per barrel (g) | $ | 9.26 |
| | $ | 8.32 |
| | $ | 0.94 |
| |
Refining margin per barrel of throughput | | $ | 9.73 |
| | $ | 9.26 |
| | $ | 0.47 |
|
Less: | | | | | | | | | | |
Operating expenses (excluding depreciation and amortization expense reflected below) | 3.69 |
| | 3.47 |
| | 0.22 |
| |
Depreciation and amortization expense | 1.71 |
| | 1.67 |
| | 0.04 |
| |
Adjusted operating income per barrel (h) | $ | 3.86 |
| | $ | 3.18 |
| | $ | 0.68 |
| |
Operating expenses (excluding depreciation and amortization expense reflected below) per barrel of throughput (b) | | 3.71 |
| | 3.73 |
| | (0.02 | ) |
Depreciation and amortization expense per barrel of throughput | | 1.70 |
| | 1.71 |
| | (0.01 | ) |
Adjusted refining operating income per barrel of throughput | | $ | 4.32 |
| | $ | 3.82 |
| | $ | 0.50 |
|
___________________
See note references on pages 5360 through 55.62.
First Nine Months Results -
Ethanol Segment Operating Highlights
(millions of dollars, except per gallon amounts)
|
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 | | Change |
Operating statistics | | | | | |
Ethanol segment margin (e) | $ | 528 |
| | $ | 517 |
| | $ | 11 |
|
Adjusted operating income (e) | $ | 135 |
| | $ | 164 |
| | $ | (29 | ) |
Production volumes (thousand gallons per day) | 3,949 |
| | 3,794 |
| | 155 |
|
| | | | | |
Ethanol segment margin per gallon of production (g) | $ | 0.49 |
| | $ | 0.50 |
| | $ | (0.01 | ) |
Less: | | | | | |
Operating expenses (excluding depreciation and amortization reflected below) | 0.31 |
| | 0.29 |
| | 0.02 |
|
Depreciation and amortization expense | 0.05 |
| | 0.05 |
| | — |
|
Adjusted operating income per gallon of production (h) | $ | 0.13 |
| | $ | 0.16 |
| | $ | (0.03 | ) |
|
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 | | Change |
Operating statistics (i) | | | | | |
Ethanol margin (g) | $ | 502 |
| | $ | 528 |
| | $ | (26 | ) |
Ethanol operating income | $ | 109 |
| | $ | 135 |
| | $ | (26 | ) |
Production volumes (thousand gallons per day) | 4,061 |
| | 3,949 |
| | 112 |
|
| | | | | |
Ethanol margin per gallon of production | $ | 0.45 |
| | $ | 0.49 |
| | $ | (0.04 | ) |
Less: | | | | | |
Operating expenses (excluding depreciation and amortization expense reflected below) per gallon of production | 0.30 |
| | 0.31 |
| | (0.01 | ) |
Depreciation and amortization expense per gallon of production | 0.05 |
| | 0.05 |
| | — |
|
Ethanol operating income per gallon of production | $ | 0.10 |
| | $ | 0.13 |
| | $ | (0.03 | ) |
First Nine Months Results -
VLP Segment Operating Highlights
(millions of dollars, except per barrel amounts)
|
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 | | Change |
Operating statistics (i) | | | | | |
Pipeline transportation revenue | $ | 93 |
| | $ | 71 |
| | $ | 22 |
|
Terminaling revenue | 309 |
| | 253 |
| | 56 |
|
Storage and other revenue | 5 |
| | 2 |
| | 3 |
|
Total VLP revenues | $ | 407 |
| | $ | 326 |
| | $ | 81 |
|
| | | | | |
Pipeline transportation throughput (thousand BPD) | 1,079 |
| | 941 |
| | 138 |
|
Pipeline transportation revenue per barrel of throughput | $ | 0.32 |
| | $ | 0.28 |
| | $ | 0.04 |
|
| | | | | |
| | | | | |
Terminaling throughput (thousand BPD) | 3,576 |
| | 2,760 |
| | 816 |
|
Terminaling revenue per barrel of throughput | $ | 0.32 |
| | $ | 0.34 |
| | $ | (0.02 | ) |
|
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 | | Change |
Volumes (thousand barrels per day) | | | | | |
Pipeline transportation throughput | 941 |
| | 849 |
| | 92 |
|
Terminaling throughput | 2,760 |
| | 2,131 |
| | 629 |
|
| | | | | |
Operating statistics | | | | | |
Pipeline transportation revenue | $ | 71 |
| | $ | 58 |
| | $ | 13 |
|
Pipeline transportation revenue per barrel (g) | $ | 0.28 |
| | $ | 0.25 |
| | $ | 0.03 |
|
| | | | | |
Terminaling revenue | $ | 253 |
| | $ | 200 |
| | $ | 53 |
|
Terminaling revenue per barrel (g) | $ | 0.34 |
| | $ | 0.34 |
| | $ | — |
|
| | | | | |
Storage and other revenue | $ | 2 |
| | $ | — |
| | $ | 2 |
|
| | | | | |
Total operating revenues | $ | 326 |
| | $ | 258 |
| | $ | 68 |
|
___________________
See note references on pages 5360 through 55.62
First Nine Months Results -
Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | | 2016 | | Change | 2018 | | 2017 | | Change |
Feedstocks | | | | | | |
Feedstocks (dollars per barrel) | | | | | | |
Brent crude oil | $ | 52.59 |
| | $ | 43.00 |
| | $ | 9.59 |
| $ | 72.67 |
| | $ | 52.59 |
| | $ | 20.08 |
|
Brent less WTI crude oil | 3.18 |
| | 1.80 |
| | 1.38 |
| 5.81 |
| | 3.18 |
| | 2.63 |
|
Brent less ANS crude oil | 0.35 |
| | 1.35 |
| | (1.00 | ) | 0.47 |
| | 0.35 |
| | 0.12 |
|
Brent less LLS crude oil | 0.77 |
| | 0.02 |
| | 0.75 |
| 1.64 |
| | 0.77 |
| | 0.87 |
|
Brent less ASCI crude oil | 4.28 |
| | 5.18 |
| | (0.90 | ) | 5.21 |
| | 4.28 |
| | 0.93 |
|
Brent less Maya crude oil | 7.54 |
| | 8.73 |
| | (1.19 | ) | 10.70 |
| | 7.54 |
| | 3.16 |
|
LLS crude oil | 51.82 |
| | 42.98 |
| | 8.84 |
| 71.03 |
| | 51.82 |
| | 19.21 |
|
LLS less ASCI crude oil | 3.51 |
| | 5.16 |
| | (1.65 | ) | 3.57 |
| | 3.51 |
| | 0.06 |
|
LLS less Maya crude oil | 6.77 |
| | 8.71 |
| | (1.94 | ) | 9.06 |
| | 6.77 |
| | 2.29 |
|
WTI crude oil | 49.41 |
| | 41.20 |
| | 8.21 |
| 66.86 |
| | 49.41 |
| | 17.45 |
|
| | | | |
|
| | | | |
|
|
Natural gas (dollars per MMBtu) | 3.00 |
| | 2.27 |
| | 0.73 |
| 3.01 |
| | 3.00 |
| | 0.01 |
|
| | | | |
|
| | | | |
|
|
Products | | | | |
|
| |
Products (dollars per barrel, unless otherwise noted) | | | | | |
|
|
U.S. Gulf Coast: | | | | |
|
| | | | |
|
|
CBOB gasoline less Brent | 11.17 |
| | 9.54 |
| | 1.63 |
| 7.28 |
| | 11.17 |
| | (3.89 | ) |
Ultra-low-sulfur diesel less Brent | 12.67 |
| | 9.34 |
| | 3.33 |
| 13.72 |
| | 12.67 |
| | 1.05 |
|
Propylene less Brent | (0.16 | ) | | (5.65 | ) | | 5.49 |
| (2.62 | ) | | (0.16 | ) | | (2.46 | ) |
CBOB gasoline less LLS | 11.94 |
| | 9.56 |
| | 2.38 |
| 8.92 |
| | 11.94 |
| | (3.02 | ) |
Ultra-low-sulfur diesel less LLS | 13.44 |
| | 9.36 |
| | 4.08 |
| 15.36 |
| | 13.44 |
| | 1.92 |
|
Propylene less LLS | 0.61 |
| | (5.63 | ) | | 6.24 |
| (0.98 | ) | | 0.61 |
| | (1.59 | ) |
U.S. Mid-Continent: | | | | |
|
| | | | |
|
|
CBOB gasoline less WTI | 15.38 |
| | 12.64 |
| | 2.74 |
| 15.40 |
| | 15.38 |
| | 0.02 |
|
Ultra-low-sulfur diesel less WTI | 16.86 |
| | 12.70 |
| | 4.16 |
| 21.54 |
| | 16.86 |
| | 4.68 |
|
North Atlantic: | | | | |
|
| | | | |
|
|
CBOB gasoline less Brent | 12.99 |
| | 12.02 |
| | 0.97 |
| 9.89 |
| | 12.99 |
| | (3.10 | ) |
Ultra-low-sulfur diesel less Brent | 13.78 |
| | 10.74 |
| | 3.04 |
| 15.58 |
| | 13.78 |
| | 1.80 |
|
U.S. West Coast: | | | | |
|
| | | | |
|
|
CARBOB 87 gasoline less ANS | 20.63 |
| | 18.86 |
| | 1.77 |
| 15.05 |
| | 20.63 |
| | (5.58 | ) |
CARB diesel less ANS | 16.54 |
| | 13.58 |
| | 2.96 |
| 17.94 |
| | 16.54 |
| | 1.40 |
|
CARBOB 87 gasoline less WTI | 23.46 |
| | 19.31 |
| | 4.15 |
| 20.39 |
| | 23.46 |
| | (3.07 | ) |
CARB diesel less WTI | 19.37 |
| | 14.03 |
| | 5.34 |
| 23.28 |
| | 19.37 |
| | 3.91 |
|
New York Harbor corn crush (dollars per gallon) | 0.28 |
| | 0.24 |
| | 0.04 |
| 0.18 |
| | 0.28 |
| | (0.10 | ) |
___________________
See note references on pages 53 through 55.
The following notes relate to references on pages 3743 through 4247 and 4753 through 52.58.
| |
(a) | DuringCost of materials and other for the nine months ended September 30, 2016, we recorded2018 includes a change in our lower of cost or market inventory valuation reserve that was established on December 31, 2015, resulting in a noncash benefit of $747$170 million ($697for the biodiesel blender’s tax credit attributable to volumes blended during 2017. The benefit was recognized in February 2018 because the legislation authorizing the credit was passed and signed into law in that month. The $170 million pre-tax benefit is included in the refining segment and $50includes $80 million attributable to our refiningnoncontrolling interest and ethanol segments, respectively). This adjustment is further discussed in Note 3 of Condensed Notes$90 million attributable to Consolidated Financial Statements. Valero Energy Corporation stockholders. |
| |
(b) | Effective January 1, 2018, we adopted the provisions of Accounting Standards Update 2017-07 “Compensation—Retirement Benefits (Topic 715),” which resulted in the reclassification of the non-service component of net periodic pension cost and net periodic postretirement benefit cost from operating expenses (excluding depreciation and amortization expense) and general and administrative expenses (excluding depreciation and amortization expense) to other income, net. This resulted in an increase of $10 million and $31 million in operating expenses (excluding depreciation and amortization expense) and a decrease of $4 million and $5 million in general and administrative expenses (excluding depreciation and amortization expense) for the three and nine months ended September 30, 2017, respectively. |
| |
(c) | Other operating expenses reflectreflects expenses that are not associated with our cost of sales which for the third quarter of 2017, includes costs incurred at certain ofand include cost to repair, remediate, and restore our U.S. Gulf Coast refineries and certain VLP assets duefacilities to damage associated with Hurricane Harvey.normal operations following a non-operating event such as a natural disaster or a major unplanned outage. |
| |
(c) | Effective October 1, 2016, we (i) transferred ownership of all of our assets in Aruba, other than certain hydrocarbon inventories and working capital, to Refineria di Aruba N.V., an entity wholly-owned by the GOA, (ii) settled our obligations under various agreements with the GOA, including agreements that required us to dismantle our leasehold improvements under certain conditions, and (iii) sold the working capital of our Aruba operations, including hydrocarbon inventories, to the GOA, CITGO Aruba Refining N.V. (CAR), and CITGO Petroleum Corporation (together with CAR and certain other affiliates, collectively, CITGO). We refer to this transaction as the “Aruba Disposition.” |
In June 2016, we recognized an asset impairment loss of $56 million representing all of the remaining carrying value of the long-lived assets of our crude oil and refined petroleum products terminal and transshipment facility in Aruba (collectively, the Aruba Terminal). We recognized the impairment loss at that time because we concluded that it was more likely than not that we would ultimately transfer ownership of these assets to the GOA as a result of agreements entered into in June 2016 between the GOA and CITGO providing for, among other things, the GOA’s lease of those assets to CITGO.
In September 2016 and in connection with the Aruba Disposition, our U.S. subsidiaries cancelled all outstanding debt obligations owed to them by our Aruba subsidiaries, which resulted in the recognition by us of an income tax benefit in the U.S. of $42 million during the three and nine months ended September 30, 2016. This matter is further discussed in Note 2 of Condensed Notes to Consolidated Financial Statements.
| |
(d) | Effective January 1, 2017, we revised our reportable segments to alignGeneral and administrative expenses (excluding depreciation and amortization expense) for the nine months ended September 30, 2018 includes a charge of $108 million for environmental reserve adjustments associated with certain changes in how our chief operating decision maker manages and allocates resources to our business. Accordingly, we created a new reportable segment —VLP. The results of the VLP segment, which include the results of our majority-owned master limited partnership referred to by the same name, were transferred from the refining segment. Comparable prior period information for our refining segment (as well as that segment’s U.S. Gulf Coast and U.S. Mid-Continent regions) and VLP segment has been retrospectively adjusted to reflect our current segment presentation.non-operating sites. |
| |
(e) | Other income, net for the nine months ended September 30, 2018 includes a $38 million charge from the early redemption of $750 million 9.375 percent senior notes due March 15, 2019. |
| |
(f) | As a result of Tax Reform that was enacted on December 22, 2017, the U.S. statutory income tax rate was reduced from 35 percent to 21 percent. Therefore, earnings from our U.S. operations for the three and nine months ended September 30, 2018 are now taxed at 21 percent, resulting in a lower effective tax rate compared to the three and nine months ended September 30, 2017. |
| |
(g) | We use certain financial measures (as noted below) that are not defined under U.S. GAAP and are considered to be non-GAAP measures. |
We have defined these non-GAAP measures and believe they are useful to the external users of our financial statements, including industry analysts, investors, lenders, and rating agencies. We believe these measures are useful to assess our ongoing financial performance because, when reconciled to their most comparable U.S. GAAP measures, they provide improved comparability between periods through the exclusion of certain items that we believe are not indicative of our core operating performance and that may obscure our underlying business results and trends. These non-GAAP measures should not be considered as alternatives to their most comparable U.S. GAAP measures nor should they be considered in isolation or as a substitute for an analysis of our results of operations as reported under U.S. GAAP. In addition, these non-GAAP measures may not be comparable to similarly titled measures used by other companies because we may define them differently, which diminishes the utility of these measures.their utility.
Non-GAAP measures are as follows:
| |
◦ | Refining and ethanol segment marginsAdjusted net income attributable to Valero Energy Corporation stockholders areis defined as segmentnet income attributable to Valero Energy Corporation stockholders excluding the items noted below, along with their related income tax effect. We have excluded these items because we believe that they are not indicative of our core operating performance in 2018 and that their exclusion results in an important measure of our ongoing financial performance to better assess our underlying business results and trends. The basis for our belief with respect to each excluded item is provided below.
|
| |
▪ | Blender’s tax credit – The blender’s tax credit is attributable to volumes blended during 2017 |
and is not related to 2018 activities, as described in note (a).
| |
▪ | Texas City Refinery fire expenses – The costs incurred to respond to and assess the damage caused by the fire that occurred at the Texas City Refinery on April 19, 2018 are specific to that event and are not ongoing costs incurred in our operations. |
| |
▪ | Environmental reserve adjustments – The environmental reserve adjustments are attributable to sites that were shut down by prior owners and subsequently acquired by us (referred to by us as non-operating sites), as described in note (d). |
| |
▪ | Loss on early redemption of debt – The penalty and other expenses incurred in connection with the early redemption of our 9.375percent senior notes due March 15, 2019 (see note (e)) are not associated with the ongoing costs of our borrowing and financing activities. |
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◦ | Refining margin is defined as refining operating income excluding the lower of cost or market inventory valuation adjustment,blender’s tax credit (see note (a)), operating expenses (excluding depreciation and amortization expense), other operating expenses, and depreciation and amortization expense, associated with our cost of sales,as reflected below. |
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◦ | Ethanol margin is defined as ethanol operating income excluding operating expenses (excluding depreciation and the asset impairment lossamortization expense) and depreciation and amortization expense, as shown below:reflected below. |
| | | Three Months Ended September 30, | Three Months Ended September 30, |
| 2017 | | 2016 | 2018 | | 2017 |
| Refining | | Ethanol | | Refining | | Ethanol | Refining | | Ethanol | | Refining | | Ethanol |
Reconciliation of operating income to segment margin | | | | | | | | | | | | | | |
Operating income | $ | 1,429 |
| | $ | 82 |
| | $ | 934 |
| | $ | 106 |
| $ | 1,329 |
| | $ | 21 |
| | $ | 1,419 |
| | $ | 82 |
|
Add back: |
| | | | | | | |
Operating expenses (excluding depreciation and amortization expense) | 986 |
| | 114 |
| | 931 |
| | 107 |
| |
Exclude: | | | | | | | | |
Operating expenses (excluding depreciation and amortization expense reflected below) (b) | | (1,047 | ) | | (116 | ) | | (996 | ) | | (114 | ) |
Depreciation and amortization expense | 455 |
| | 17 |
| | 429 |
| | 17 |
| (466 | ) | | (19 | ) | | (455 | ) | | (17 | ) |
Other operating expenses(c) | 41 |
| | — |
| | — |
| | — |
| (10 | ) | | — |
| | (41 | ) | | — |
|
Segment margin | $ | 2,911 |
| | $ | 213 |
| | $ | 2,294 |
| | $ | 230 |
| $ | 2,852 |
| | $ | 156 |
| | $ | 2,911 |
| | $ | 213 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
| Refining | | Ethanol | | Refining | | Ethanol |
Reconciliation of operating income by segment to segment margin | | | | | | | |
Operating income | $ | 3,035 |
| | $ | 135 |
| | $ | 3,129 |
| | $ | 214 |
|
Add back: | | | | | | | |
Operating expenses (excluding depreciation and amortization expense) | 2,935 |
| | 330 |
| | 2,716 |
| | 305 |
|
Depreciation and amortization expense | 1,358 |
| | 63 |
| | 1,308 |
| | 48 |
|
Lower of cost or market inventory valuation adjustment (a) | — |
| | — |
| | (697 | ) | | (50 | ) |
Other operating expenses | 41 |
| | — |
| | — |
| | — |
|
Asset impairment loss | — |
| | — |
| | 56 |
| | — |
|
Segment margin | $ | 7,369 |
| | $ | 528 |
| | $ | 6,512 |
| | $ | 517 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 |
| Refining | | Ethanol | | Refining | | Ethanol |
Reconciliation of operating income to segment margin | | | | | | | |
Operating income | $ | 3,638 |
| | $ | 109 |
| | $ | 3,004 |
| | $ | 135 |
|
Exclude: | | | | | | | |
Blender’s tax credit (a) | 170 |
| | — |
| | — |
| | — |
|
Operating expenses (excluding depreciation and amortization expense reflected below) (b) | (3,013 | ) | | (336 | ) | | (2,966 | ) | | (330 | ) |
Depreciation and amortization expense | (1,385 | ) | | (57 | ) | | (1,358 | ) | | (63 | ) |
Other operating expenses (c) | (41 | ) | | — |
| | (41 | ) | | — |
|
Segment margin | $ | 7,907 |
| | $ | 502 |
| | $ | 7,369 |
| | $ | 528 |
|
| |
◦ | Adjusted refining segment operating income is defined as refining segment operating income excluding other operating expenses, the lower of cost or market inventory valuation adjustment and the asset impairment loss. |
| |
◦ | Adjusted ethanol segment operating income is defined as ethanol segment operating income excluding the lower of cost or market inventory valuation adjustment.2017 blender’s tax credit received in 2018 (see note (a)) and other operating expenses.
|
| |
◦ | Adjusted VLP segment operating income is defined as VLP segment operating income excluding other operating expenses. |
| |
◦ | Adjusted corporate and eliminations is defined as corporate and eliminations excluding the environmental reserve adjustments associated with certain non-operating sites (see note (d)). |
| |
(f)(h) | Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt. |
| |
(g)(i) | Throughput margin per barrel represents refining segment marginValero uses certain operating statistics (as definednoted below) to evaluate performance between comparable periods. Different companies may calculate them in (e) above) for our refining segment divided by throughput volumes. Ethanol segment margin per gallon of production represents ethanol segment margin (as defined in (e) above) for our ethanol segment divided by production volumes. Pipeline transportation revenue per barrel and terminaling revenue per barrel represents pipeline transportation revenue and terminaling revenue for our VLP segment divided by pipeline transportation throughput and terminaling throughput volumes, respectively. Throughput and production volumes are calculated by multiplying throughput and production volumes per day (as provided in the accompanying tables) by the number of days in the applicable period.different ways. |
| |
(h) | Adjusted operating income per barrel represents adjusted operating income (defined in (e) above) for our refining segment divided by throughput volumes. Adjusted operating income per gallon of production represents adjusted operating income (defined in (e) above) for our ethanol segment divided by production volumes. Throughput and production volumes are calculated by multiplying throughput and production volumes per day (as provided in the accompanying tables) by the number of days in the applicable period. |
All per barrel of throughput and per gallon of production amounts are calculated by dividing the associated dollar amount by the throughput volumes, production volumes, pipeline transportation throughput volumes, or terminaling throughput volumes for the period, as applicable.
Throughput volumes, production volumes, pipeline transportation throughput volumes, and terminaling throughput volumes are calculated by multiplying throughput volumes per day, production volumes per day, pipeline transportation throughput volumes per day, and terminaling throughput volumes per day, respectively, by the number of days in the applicable period.
Total Company, Corporate, and Other
Operating revenuesRevenues increased $12.6$20.7 billion in the first nine months of 20172018 compared to the first nine months of 20162017 primarily due to increases in refined petroleum product prices associated with our refining segment, and we also benefitted from the positive effect from the $56 million asset impairment loss related to our Aruba Terminalsegment. This improvement in 2016. These items were more thanrevenues was partially offset by higher cost of materials and other of $11.7 billion and the negative effect from the $747 million lower of cost or market inventory valuation adjustment in the first nine months of 2016, as well as increases in operating expenses (excluding depreciation and amortization expense), depreciation and amortization expense, other operating expenses,sales and general and administrative expenses (excluding depreciation and amortization expense) of $246 million, $70 million, $44 million, and $90 million, respectively. These changes resultedbetween the periods, resulting in a decreasean increase in operating income of $206$553 million from $3.0 billion in the first nine months of 20162018 compared to $2.7 billion in the first nine months of 2017.
Excluding the $44 million of damages associated with Hurricane Harvey, which areadjustments to operating income reflected in other operating expenses, from 2017 operating income and the $747 million benefit from the lower of cost or market inventory valuation adjustment and the asset impairment loss of $56 million related to our Aruba Terminal from 2016 operating income,table on page 56, adjusted operating income inwas $3.3 billion for the first nine months of 2017 increased by $529 million.2018 compared to $2.8 billion for the first nine months of 2017. Details regarding changesthe $488 million increase in segment margins,adjusted operating expenses (excluding depreciation and amortization expense), and depreciation and amortization expenseincome between the periods are discussed by segment in the individual segment analysis below.
General and administrative expenses (excluding depreciation and amortization expense)Other income, net increased by $90$12 million in the first nine months of 20172018 compared to the first nine months of 20162017 primarily due to an increasehigher equity in legal and environmental reserves of $25 million, higher employee related costs of $20 million, expensesearnings associated with the terminationour Diamond Pipeline joint venture of the acquisition of certain assets from Plains of $16$31 million and increaseshigher interest income of $28 million, partially offset by a $38 million charge from the early redemption of debt as more fully described in charitable contributions and advertising expenses of $6 million and $5 million, respectively.note (e) to the accompanying tables (see page 60).
Income tax expense increased $34decreased $12 million fromin the first nine months of 20162018 compared to the first nine months of 2017 despite lower income beforeprimarily as a result of a decrease in our effective tax rate from 28 percent for the first nine months of 2017 to 22 percent for the first nine months of 2018. The decrease in our effective tax rate is due to the reduction in the U.S. statutory income tax expense primarily duerate from 35 percent to 21 percent effective January 1, 2018, partially offset by the impact of the GILTI tax benefits recognizedand the repeal of the U.S. manufacturing deduction as a result of Tax Reform, which is more fully described in Note 10 of Condensed Notes to Consolidated Financial Statements.
Net income attributable to noncontrolling interests increased by $99 million in the first nine months of 2016 associated with our Aruba disposition and2018 compared to the favorable resolutionfirst nine months of an income2017 primarily due to a benefit of $80 million for the blender’s tax audit. The effective tax rates of 28 percentcredit as more fully described in note (a) to the accompanying tables (see page 60).
Refining Segment Results
Refining segment revenues increased $20.7 billion in the first nine months of 2018 compared to the first nine months of 2017 and 25 percentprimarily due to increases in refined petroleum product prices. This improvement in refining segment revenues was partially offset by higher cost of sales between the periods, resulting in an increase in refining segment operating income of $634 million in the first nine months of 2016 are lower than the U.S. statutory rate of 35 percent primarily because income from our international operations is taxed at statutory rates that are lower than in the U.S. The effective tax rate in2018 compared to the first nine months of 2016 was lower than the rate in the first nine months of 2017 due to the $42 million tax benefit associated with our Aruba disposition and the $35 million tax benefit resulting from the favorable resolution of an income tax audit.2017.
Refining Segment ResultsExcluding the adjustments to refining segment operating income reflected in the tables on page 56, refining segment adjusted operating income increased $464 million from $3.0 billion for the first nine months of 2017 to$3.5 billion for the first nine months of 2018. The components of this increase, along with reasons for the changes in these components, are outlined below.
Refining segment operating revenuesmargin, as defined in note (g) to the accompanying tables (see page 60), increased $12.7 billion and cost of materials and other increased $11.9 billion$538 million in the first nine months of 20172018 compared to the first nine months of 2016 primarily due to increases in refined petroleum product prices and crude oil feedstock costs, respectively. The resulting $857 million increase in refining segment margin along with the positive effect from the $56 million asset impairment loss related to our Aruba Terminal in 2016, was more than offset by the negative effect from the $697 million lower of cost or market inventory valuation adjustment in the first nine months of 2016, as well as increases in operating expenses (excluding depreciation and amortization expense), depreciation and amortization expense associated with our cost of sales, and other operating expenses of $219 million, $50 million, and $41 million, respectively. These changes resulted in a decrease in operating income of $94 million, from $3.1 billion in the first nine months of 2016 to $3.0 billion in the first nine months of 2017.
Excluding the $41 million of damages associated with Hurricane Harvey, which are reflected in other operating expenses, from 2017, operating income and the $697 million benefit from the lower of cost or market inventory valuation adjustment and the $56 million asset impairment loss related to our Aruba Terminal from 2016 operating income, adjusted operating income for the first nine months of 2017 increased $588 million. The reasons for this increase are described below.
As previously noted, refining segment margin increased $857 million in the first nine months of 2017 compared to the first nine months of 2016, primarily due to the following:
Increase in distillate margins. We experienced improved distillate margins throughout all our regions forduring the first nine months of 20172018 compared to the first nine months of 2016.2017. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $13.72 per barrel for the first nine months of 2018 compared to $12.67 per barrel for the first nine months of 2017, compared to $9.34representing a favorable increase of $1.05 per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel, which was $21.54 per barrel for the first nine months of 2016, representing a favorable increase of $3.33 per barrel. Another example is the Brent-based benchmark reference margin for North Atlantic ultra-low-sulfur diesel, which was $13.782018 compared to $16.86 per barrel for the first nine months of 2017, compared to $10.74 per barrel for the first nine months of 2016, representing a favorable increase of $3.04$4.68 per barrel. We estimate that the increase in distillate margins per barrel in the first nine months of 20172018 compared to the first nine months of 20162017 had a positivefavorable impact to our refining segment margin of approximately $833 million.
Increase in gasoline margins. We also experienced improved gasoline margins throughout all our regions for the first nine months of 2017 compared to the first nine months of 2016. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $11.17 per barrel for the first nine months of 2017 compared to $9.54 per barrel for the first nine months of 2016, representing a favorable increase of $1.63 per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline which was $15.38 per barrel for the first nine months of 2017 compared to $12.64 per barrel for the first nine months of 2016, representing a favorable increase of $2.74 per barrel. We estimate that the increase in gasoline margins per barrel in the first nine months of 2017 compared to the first nine months of 2016 had a positive impact to our refining segment margin of approximately $377$792 million.
Higher throughput volumes. Refining throughput volumes increased by 62,000 barrels per day in the first nine months of 2017. We estimate that the increase in refining throughput volumes had a positive impact on our refining segment margin of approximately $157 million.
Lower discounts on other feedstocks.feedstocks. In addition to crude oil, we utilize other feedstocks, such as natural gas and residuals, in certain of our refining processes. We benefit when we process these other feedstocks
that are priced at a discount to Brent crude oil when pricing terms are favorable. While weoil. We benefitted from processing these types of feedstocks induring the first nine months of 2017,2018 and that benefit declinedimproved compared to the first nine months of 2016.2017. We estimate that the reductionincrease in the discounts for the other feedstocks that we processed induring the first nine months of 2018 compared to the first nine months of 2017 had an unfavorablea favorable impact to our refining segment margin of approximately $227$315 million.
LowerHigher discounts on sour crude oils. The market prices offor refined petroleum products generally track the price of Brent crude oil, which is a benchmark crude oil, and we benefit when we process crude oils that are priced at a discount to Brent crude oil when pricing terms are favorable. While weoil. We benefitted from processing these sourtypes of crude oils induring the first nine months of 2017,2018 and that benefit declinedimproved compared to the first nine months of 2016.2017. For example, ASCIWTI crude oil, a light sweet crude oil processed in our U.S. Mid-Continent region, sold at a discount to Brent crude oil of $5.81 per barrel for the first nine months of 2018 compared to a discount of $3.18 per barrel for the first nine months of 2017, representing a favorable increase of $2.63 per barrel. Another example is Maya crude oil, a sour crude oil processed in our U.S. Gulf Coast region, which sold at a discount of $4.28$10.70 per barrel for the first nine months of 2018 compared to Brent crude oil ina discount of $7.54 per barrel for the first nine months of 2017, compared torepresenting a discountfavorable increase of $5.18 per barrel in the first nine months of 2016, representing an unfavorable decrease of $0.90 per barrel. Another example is Maya crude oil, which sold at a discount of $7.54 per barrel to Brent crude oil in the first nine months of 2017 compared to $8.73 per barrel in the first nine months of 2016, representing an unfavorable decrease of $1.19$3.16 per barrel. We estimate that the reductionincrease in the discounts for sour crude oils that we processed induring the first nine months of 2018 compared to the first nine months of 2017 had an unfavorablea favorable impact to our refining segment margin of $151approximately $282 million.
HigherLower costs of biofuel credits. As more fully described in Note 1315 of Condensed Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) decreased by $200 million from $631 million for the first nine months of 2017 to $431 million for the first nine months of 2018.
Higher throughput volumes. Refining throughput volumes increased by $99 million from $532 million60,000 BPD in the first nine months of 20162018 primarily due to $631 millioneffects of Hurricane Harvey in the first nine months of 2017. We estimate that the increase in refining throughput volumes had a positive impact on our refining segment margin of approximately $159 million.
Decrease in gasoline margins. We experienced a decrease in gasoline margins in most of our regions during the first nine months of 2018 compared to the first nine months of 2017. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $7.28 per barrel for the first nine months of 2018 compared to $11.17 per barrel for the first nine months of 2017, representing an unfavorable decrease of $3.89 per barrel. Another example is the ANS-based benchmark reference margin for U.S. West Coast CARBOB 87 gasoline, which was $15.05 per barrel for the first nine months of 2018 compared to $20.63 per barrel for the first nine months of 2017, representing an unfavorable decrease of $5.58 per barrel. We estimate that the decrease in gasoline margins per barrel in the first nine months of 2017.2018 compared to the first nine months of 2017 had an unfavorable impact to our refining segment margin of approximately $724 million.
Decrease in other products margins. We experienced a decrease in the margins of other products (such as petroleum coke and sulfur) relative to Brent crude oil during the first nine months of 2018 compared to the first nine months of 2017 due to an increase in the cost of crude oils between the periods. Because the market prices for our other products remain relatively stable, our margins decline when the cost of crude oils that we process increases. For example, the benchmark price of Brent crude oil was $72.67 per barrel for the first nine months of 2018 compared to $52.59 per barrel for the first nine months of 2017, representing an unfavorable increase of $20.08 per barrel. We estimate that the decrease in other products margins for the first nine months of 2018 compared to the first nine months of 2017 had an unfavorable impact to our refining segment margin of approximately $405 million.
Increase in charges from VLP. Charges from the VLP segment for transportation and terminaling services increased $68$81 million in the first nine months of 20172018 compared to the first nine months of 20162017 primarily due to new charges from businessesadditional services provided by a terminal and a product pipeline system acquired by VLP in 2016.November 2017 that were formerly a part of the refining segment. Details regarding the increase in charges from VLP are discussed in the VLP segment analysis below.
The increase of $219 million in refiningRefining segment operating expenses (excluding depreciation and amortization expense) wasincreased $47 million primarily due to an increase in energy costs driven by higher natural gas prices ($3.00 per MMBtu in the first nine months of 2017 compared to $2.27 per MMBtu in the first nine months of 2016).employee-related expenses.
The increase of $50 million inRefining segment depreciation and amortization expense associated with our cost of sales wasincreased $27 million primarily due to an increase in refinery turnaround and catalyst amortization expense primarily due to costs incurred in the latter partfirst nine months of 2016 in connection with significant turnaround projects at our Port Arthur and Texas City Refineries.2018 compared to the first nine months of 2017.
Ethanol Segment Results
Ethanol segment operating revenues decreased $86 million and cost of materials and other decreased $97increased $87 million in the first nine months of 20172018 compared to the first nine months of 2016,2017 primarily due to decreasesan increase in ethanol sales volumes and increases in corn related co-product prices, and corn prices, respectively. The resulting $11 million increasepartially offset by lower ethanol prices. This improvement in ethanol segment marginrevenue was more than offset by higher cost of sales between the negative effect from the $50periods resulting in a decrease in ethanol segment operating income of $26 million lower of cost or market inventory valuation adjustment in the first nine months of 2016,2018 compared to the first nine months of 2017. This decrease is due to lower ethanol segment margins as well as increases in operating expenses (excluding depreciation and amortization expense) and depreciation and amortization expense associated with our cost of sales of $25 million and $15 million, respectively, resulting in a decrease inoutlined below.
operating income of $79 million, from $214Ethanol segment margin, as defined in note (g) to the accompanying tables (see page 60), decreased $26 million in the first nine months of 2016 to $135 million in the first nine months of 2017. The reasons for this decrease are described below.
As previously noted, ethanol segment margin increased $11 million in the first nine months of 20172018 compared to the first nine months of 20162017, primarily due to the following:
HigherLower ethanol prices. Ethanol prices were slightly higherlower in the first nine months of 20172018 compared to the first nine months of 20162017 primarily due to an increase in ethanol export demand.domestic production. For example, the New York Harbor ethanol price was $1.51 per gallon for the first nine months of 2018 compared to $1.60 per gallon infor the first nine months of 2017, representing an unfavorable decrease of $0.09 per gallon. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of $121 million.
Higher co-product prices. An increase in protein values, as compared to $1.55 per gallon insoybean meal, had a favorable effect on the first nine months of 2016.prices received for the corn related co-products that we produced. We estimate that the increase in the price of ethanolcorn related co-product prices had a favorable impact to our ethanol segment margin of $30approximately $87 million.
Higher production volumes. Ethanol segment margin was favorably impacted by increased production volumes of 155,000112,000 gallons per day in the first nine months of 20172018 compared to the first nine months of 20162017 primarily due to reliability improvements. We estimate that the increase in production volumes had a positive impact to our ethanol segment margin of $25 million.
Lower corn prices. Despite an increase in the CBOT corn price from $3.62 per bushel in the first nine months of 2016 to $3.64 per bushel in the first nine months of 2017, we acquired corn at lower prices due to favorable location differentials, resulting in a decrease in the price we paid for corn in the first nine months of 2017 compared to the first nine months of 2016. We estimate that the decrease in the price we paid for corn had a favorable impact to our ethanol segment margin of $18$13 million.
Lower co-product prices. A decrease in export demand for corn related co-products, primarily distillers grains, had an unfavorable effect on the prices we received. We estimate that the decrease in corn related co-product prices had an unfavorable impact to our ethanol segment margin of $62 million.
The increase of $25 million in ethanol segment operating expenses (excluding depreciation and amortization expense) was primarily due to an increase in energy costs driven by higher natural gas prices ($3.00 per MMBtu in the first nine months of 2017 compared to $2.27 per MMBtu in the first nine months of 2016).
The increase of $15 million in ethanol segment depreciation and amortization expense associated with our cost of sales was primarily due to the write-off of assets that were idled in the first nine months of 2017.
VLP Segment Results
VLP segment operating revenues increased $68$81 million in the first nine months of 20172018 compared to the first nine months of 20162017 primarily due to $67 million of incremental revenues generated from transportation and terminaling services provided toassociated with the Port Arthur terminal and the Parkway pipeline acquired by VLP in November 2017 that were formerly a part of the refining segment associated with businesses and assets acquiredsegment. The increase in 2016 and early 2017, as discussed below. This $68 million increase inVLP segment revenues was partially offset by higher operating expenses (excluding depreciation and amortization expense), other operating expenses, and depreciation and amortization expense associated with our cost of sales, of $3 million, $3 million, and $1 million, respectively, resulting in an increase in VLP segment operating income of $61 million. Excluding$45 million in the $3 millionfirst nine months of damages associated with Hurricane Harvey, which are reflected in other operating expenses, adjusted operating income increased by $64 million2018 compared to the first nine months of 2016.2017. Excluding the adjustment reflected in the table on page 56, VLP adjusted operating income increased $42 million.
Corporate and Eliminations
Corporate and eliminations, which consists primarily of general and administrative expenses and related depreciation and amortization expense, increased by $100 million in the first nine months of 2018 compared to the first nine months of 2017. Excluding the environmental reserve adjustments of $108 million for the first nine months of 2018 reflected in the table on page 56, adjusted corporate and eliminations decreased by $8 million primarily due to expenses incurred in the first nine months of 2017 associated with the termination of the acquisition of certain assets from Plains.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We believe that we have sufficient funds from operations and from borrowings under our credit facilities to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.
VLP segment operating revenues increased $68Our liquidity consisted of the following as of September 30, 2018 (in millions):
|
| | | | |
Available borrowing capacity from committed facilities: | | |
Valero Revolver | | $ | 2,940 |
|
Canadian Revolver | | 55 |
|
Accounts receivable sales facility | | 1,200 |
|
Letter of credit facility | | 100 |
|
Total available borrowing capacity | | 4,295 |
|
Cash and cash equivalents(a) | | 3,324 |
|
Total liquidity | | $ | 7,619 |
|
___________________
| |
(a) | Excludes $227 million of cash and cash equivalents related to our VIEs that is available for use only by our VIEs. |
Information about our outstanding borrowings, letters of credit issued, and availability under our credit facilities is reflected in the first nine monthsNote 5 of 2017 comparedCondensed Notes to the first nine months of 2016, primarily due to the following:Consolidated Financial Statements.
Cash Flows Summary
Incremental terminaling throughput from acquired businesses. VLP experienced an 18 percent increase in terminaling revenues in the first nine monthsComponents of 2017 compared to the first nine months of 2016 generated by contributions from the McKee Terminal Services Business and the Meraux and Three Rivers Terminal Services Business, which were acquired by VLP in the second and third quarters of 2016, respectively. The incremental throughput volumes generated by these businesses had a favorable impact to VLP’s operating revenues of $47 million.our cash flows are set forth below (in millions):
Incremental operating revenues from acquired undivided interest in crude system assets. Incremental throughput volumes related to the acquisition of an undivided interest in crude system assets in January 2017 had a favorable impact to VLP’s operating revenues of $7 million.
LIQUIDITY AND CAPITAL RESOURCES |
| | | | | | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 |
Cash flows provided by (used in): | | | |
Operating activities | $ | 2,693 |
| | $ | 3,822 |
|
Investing activities | (2,768 | ) | | (1,740 | ) |
Financing activities | (2,181 | ) | | (1,943 | ) |
Effect of foreign exchange rate changes on cash | (43 | ) | | 221 |
|
Net increase (decrease) in cash and cash equivalents | $ | (2,299 | ) | | $ | 360 |
|
Cash Flows for the Nine Months Ended September 30, 2018
Our operations generated $2.7 billion of cash in the first nine months of 2018, driven primarily by net income of $2.3 billion and noncash charges to income for depreciation and amortization expense of $1.5 billion, partially offset by a negative change in working capital of $1.2 billion. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is further detailed in Note 13 of Condensed Notes to Consolidated Financial Statements. The use of cash resulting from the $1.2 billion change in working capital was mainly due to:
an increase in receivables, primarily as a result of increasing commodity prices;
an increasein inventory due to higher inventory levels combined with higher commodity prices;
a decrease in income taxes payable resulting from the $400 million payment of our fourth quarter 2017 estimated taxes in January 2018; and
a decrease in accrued expenses mainly due to the timing of payments on our environmental compliance program obligations; partially offset by
an increase in accounts payable due to higher commodity prices and higher purchases.
The $2.7 billion of cash generated by our operations, along with (i) $1.3 billion in proceeds from debt issuances and borrowings (as further discussed in Note 5 of Condensed Notes to Consolidated Financial Statements) and (ii) $2.3 billion from available cash on hand, were used mainly to:
fund $2.0 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;
fund $554 million for the Peru Acquisition and other minor acquisitions;
acquire undivided interests in pipeline and terminal assets for $181 million;
redeem our 9.375 percent Senior Notes for $787 million (or 104.9 percent of stated value);
make payments on debt and capital lease obligations of $428 million, of which $410 million related to the repayment of all outstanding borrowings under the VLP Revolver;
retire $137 millionof debt assumed in connection with the Peru Acquisition;
purchase common stock for treasury of $1.1 billion;
pay common stock dividends of $1.0 billion; and
pay distributions to noncontrolling interests of $63 million.
Cash Flows for the Nine Months Ended September 30, 2017
Our operations generated $3.8 billion of cash in the first nine months of 2017, driven primarily by net income of $1.8 billion, noncash charges to income of $1.6 billion, and a positive change in working capital of $544 million. Noncash charges included $1.5 billion of depreciation and amortization expense and $80 million of deferred income tax expense. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is further detailed in Note 1113 of Condensed Notes to Consolidated Financial Statements. ThisThe source of cash resulting from the $544 million change in working capital was mainly resulted from:due to:
an increase in accounts payable primarily as a result of an increase in commodity prices;
an increase in income taxes payable resulting from higher income tax expense in the third quarter of 2017;
an increase in accrued expenses mainly due to the timing of payments on our environmental compliance program obligations; and
a decrease in prepaid expenses and other mainly due to the utilization of purchased RINs to satisfy our biofuel blending obligation; andpartially offset by
an increase in inventory volumes held.
The $3.8 billion of cash generated by our operations, along with (i) net proceeds of $36 million from VLP’s sale of common units representing limited partner interests to the public and (ii) $221 million from the effects of a favorable change in foreign exchange rate change on cash,rates, were used mainly to:
fund $1.7 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;
acquire an undivided interest in crude system assets for $72 million;
purchase common stock for treasury of $951 million;
pay common stock dividends of $936 million;
pay distributions to noncontrolling interests of $56 million; and
increase available cash on hand by $360 million.
Cash Flows for the Nine Months Ended September 30, 2016
Our operations generated $3.8 billion of cash in the first nine months of 2016, driven primarily by net income of $2.0 billion, noncash charges to income of $928 million, and a positive change in working capital of $953 million. Noncash charges included $1.4 billion of depreciation and amortization expense, $56 million
for the asset impairment loss associated with our Aruba Terminal,Other Matters Impacting Liquidity and $193 million of deferred income tax expense, partially offset by a benefit of $747 million from a lower of cost or market inventory valuation adjustment. See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in our working capital is further detailed in Note 11 of Condensed Notes to Consolidated Financial Statements. This source of cash mainly resulted from:
an increase in accounts payable, partially offset by an increase in receivables, primarily as a result of increasing commodity prices; and
the temporary reduction of our inventories.
The $3.8 billion of cash generated by our operations, along with $1.65 billion in proceeds from the issuance of debt (primarily $1.25 billion of 3.4 percent senior notes due September 15, 2026 and borrowings under the VLP Revolver of $349 million as discussed in Note 4 of Condensed Notes to Consolidated Financial Statements), were used mainly to:
fund $1.4 billion in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;
pay a long-term liability of $137 million owed to a joint venture partner for an owner-method joint venture investment;
purchase common stock for treasury of $1.2 billion;
pay common stock dividends of $840 million;
pay distributions to noncontrolling interests of $54 million; and
increase available cash on hand by $1.8 billion.Capital Resources
Capital Investments
ForOur anticipated capital investments for 2018 have not changed from the amounts previously disclosed in our Form 10-K for the year ended December 31, 2017 as we expect to incur approximately $2.7 billion for capital investments, includingwhich includes capital expenditures, deferred turnaround and catalyst costs, equity-methodand investments in joint venture investments, owner-method joint venture investments,ventures. Capital expenditures include the capital expenditures of our consolidated subsidiaries and undivided interestsconsolidated VIEs in capital assets.which we hold an ownership interest. This consists of approximately $1.6$1.7 billion for stay-in-business capital and $1.1$1.0 billion for growth strategies, including our investments described below.strategies. This capital investment estimate excludes potential strategic acquisitions.acquisitions, including acquisitions of undivided interests. We continuously evaluate our capital budget and make changes as conditions warrant.
In addition to our capital investments noted above, we separately reflect in our statements of cash flows the capital expenditures of certain VIEs that we consolidate even though we do not hold an ownership interest in them. These expenditures are not included in our $2.7 billion estimate of capital investments for 2018. See Note 8 of Condensed Notes to Consolidated Financial Statements for a description of our VIEs.
Pending Acquisition of Ethanol Plants
On October 8, 2018, we entered into an agreement to acquire three ethanol plants from two subsidiaries of Green Plains Inc. for total cash consideration of $300 million plus working capital of approximately $28 million. The ethanol plants are located in Bluffton, Indiana; Lakota, Iowa; and Riga, Michigan with a combined ethanol production capacity of 280 million gallons per year. We make investmentsexpect the acquisition will be completed in equity-method joint ventures, owner-method joint venture investments, undivided intereststhe fourth quarter of 2018.
Pending Merger with VLP
On October 18, 2018, we entered into the Merger Agreement with VLP pursuant to which we have agreed to acquire, for cash, all of the outstanding publicly held common units of VLP at a price of $42.25 per common unit, for an aggregate transaction value of approximately $950 million. See Note 2 of Condensed Notes to Consolidated Financial Statements for further discussion of the Merger Transaction.
Stock Purchase Program
On January 23, 2018, our board of directors authorized our purchase of up to an additional $2.5 billion of our outstanding common stock (the 2018 program) with no expiration date. This authorization was in certain assets, and new construction projects in orderaddition to enhance our operations.the remaining amount available under a $2.5 billion program authorized on September 21, 2016 (the 2016 program). As of September 30, 2017, capital commitments related2018, we had approximately $2.8 billion of authorization remaining available under our programs. We have no obligation to make purchases under these investments included the following:programs.
Pension Plan Funding
We have a 50 percent interest in Diamond Pipeline LLC (Diamond Pipeline), which was formed by Plains to construct and operate a 440-mile, 20-inch crude oil pipeline with a capacity of up to 200,000 barrels per day. The pipeline will deliver domestic sweet crude oil from the Plains’ Cushing, Oklahoma terminalcontributed $132 million to our Memphis Refinerypension plans and will have$15 million to our other postretirement benefit plans during the abilitynine months ended September 30, 2018. During the fourth quarter of 2018, we plan to connectcontribute approximately $9 million to our pension plans and $4 million to our other postretirement benefit plans.
Environmental Matters
Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the Capline Pipeline. The pipeline is expected to be completedenvironment, waste management, pollution prevention measures, GHG emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in December 2017 for an estimated costthe future. In addition, any major upgrades in any of $925 million. We have made cumulative cash contributions of $420 million into Diamond Pipeline through September 2017 and expect to contribute $43 million during the remainder of 2017.
We have a 50 percent interest in MVP, which was formed by Magellan and us to construct, own, and operate the MVP Terminal located adjacent to the Houston Ship Channel in Pasadena, Texas. The MVP Terminal will contain (i) approximately 5 million barrels of storage capacity, (ii) a dock with two ship berths, and (iii) a three-bay truck rack facility. The MVP Terminal will handle refined petroleum products and will be completed in two phases. The MVP Terminal will be connected viaour operating facilities could require
pipelinematerial additional expenditures to comply with environmental laws and regulations. See Note 6 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.
Tax Matters
The IRS has ongoing audits related to our Houston and Texas City Refineries, the Colonial and Explorer pipelines, and Magellan’s Galena Park terminal facility. Magellan is the construction manager and will operate the completed terminal,U.S. federal income tax returns from 2010 through 2015. We have received Revenue Agent Reports in connection with the completion of phase one2010 and phase two expected2011 combined audit. We have made significant progress in early 2019 and early 2020, respectively. The terminal is estimated to cost $840 million for phases one and two of the project andresolving this audit, which we believe will be funded equally by Magellansettled within the next 12 months. Upon settlement, we anticipate receiving a refund; therefore, we have a receivable associated with this audit as of September 30, 2018. We do not expect to have a significant change to our uncertain tax positions upon the settlement of our ongoing audits, and us. The project could expand upwe believe that the ultimate settlement of our audits will not be material to four phases with total project costour financial position, results of approximately $1.4 billion if warranted by additional demand and agreed to by Magellan and us. We have contributed $77 million to MVP through September 2017; no further contributions are required to be made during the remainder of 2017.operations, or liquidity.
We continue to evaluate both provisional and incomplete estimates due to Tax Reform related to our 2017 tax provision. As discussed in Note 10 of Condensed Notes to Consolidated Financial Statements, there have a 40 percent undivided interest in a project with a subsidiarybeen no updates to these amounts as of Magellan to jointly build a 135-mile, 16-inch refined petroleum products pipeline with a capacity of up to 150,000 barrels per day from Houston to Hearne, Texas. The pipeline is expected to be completed in mid-2019. Our estimated cost for our 40 percent undivided interest in this pipeline is $170 million. We expect to make capital expenditures of $11 million during the remainder of 2017.September 30, 2018.
Cash Held by Our International Subsidiaries
In addition,conjunction with our implementation of the provisions under Tax Reform, which was enacted on December 22, 2017 and described in Note 10 of Condensed Notes to Consolidated Financial Statements, we recorded a liability in 2017 for the estimated U.S. federal tax due on the deemed repatriation of the accumulated earnings and profits of our international subsidiaries not previously distributed to us, and we will separately build, own,pay this liability over the eight-year period permitted by the provisions under Tax Reform. Because of the deemed repatriation of these accumulated earnings and operateprofits, there are no longer any U.S. federal income tax consequences associated with the repatriation of any of the $2.3 billion of cash and cash equivalents held by our international subsidiaries as of September 30, 2018. However, certain countries in which our international subsidiaries are organized impose withholding taxes on cash distributed outside of those countries. We have accrued for withholding taxes on the portion of the cash held by one of our international subsidiaries that we have deemed not to be permanently reinvested in our operations in that country. The remaining cash held by that subsidiary as well as our other international subsidiaries will be permanently reinvested in our operations in those countries.
Cash provided by operating activities in the U.S. continues to be our primary source of funds to finance our U.S. operations and capital expenditures, as well as our dividends and share repurchases.
Concentration of Customers
Our operations have a terminalconcentration of customers in Hearne, a terminal in Williamson County, Texas,the refining industry and a 70-mile, 12-inchcustomers who are refined petroleum products pipeline connectingproduct wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the two terminals. The new pipeline and terminals are expectedextent necessary to supply up to 60,000 barrels per day into the central Texas area. Our estimated cost for these projects is $210 million with expected completion in mid-2019. Weminimize potential credit risk. Historically, we have spent $5 million related to these projects through September 2017 and expect to spend $29 million during the remainder of 2017.not had any significant problems collecting our accounts receivable.
CONTRACTUAL OBLIGATIONS
As of September 30, 2017,2018, our contractual obligations included debt, capital lease obligations, operating leases,lease obligations, purchase obligations, and other long-term liabilities. There were no material changes outside the ordinary course of business with respect to theseour contractual obligations during the nine months ended September 30, 2017.2018. However, in the ordinary course of business, we recognized capital lease assets and related obligations totaling approximately $490 millionhad various debt-related activities
during the nine months ended September 30, 2018 as described in January 2017 for the leaseNote 5 of storage tanks located at three of our refineries. These lease agreements have initial terms of 10 years each with successive 10-year automatic renewals.Condensed Notes to Consolidated Financial Statements.
Our debt and financing agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt by the ratings agencies, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. All of our ratings on our senior unsecured debt are at or above investment grade level as follows:
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| | | | |
| | Rating |
Rating Agency | | Valero | | VLP |
Moody’s Investors Service | | Baa2 (stable outlook) | | Baa3 (stable outlook) |
Standard & Poor’s Ratings Services | | BBB (stable outlook) | | BBB- (stable outlook) |
Fitch Ratings | | BBB (stable outlook) | | BBB- (stable outlook) |
We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction below investment grade or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.
Summary of Credit Facilities
Information about our outstanding borrowings, letters of credit issued, and availability under our credit facilities is reflected in Note 4 of Condensed Notes to Consolidated Financial Statements.
Other Matters Impacting Liquidity and Capital Resources
Stock Purchase Program
On September 21, 2016, our board of directors authorized our purchase of up to an additional $2.5 billion of our outstanding common stock (the 2016 program) with no expiration date. This authorization was in addition to the remaining amount available under a $2.5 billion program authorized on July 13, 2015 (the 2015 program). During the first quarter of 2017, we completed our purchases under the 2015 program. As of September 30, 2017, we had approximately $1.6 billion remaining available under the 2016 program. We have no obligation to make purchases under this program.
Pension Plan Funding
We contributed $104 million to our pension plans and $17 million to our other postretirement benefit plans during the nine months ended September 30, 2017. During the fourth quarter of 2017, we plan to contribute approximately $4 million to our pension plans and $2 million to our other postretirement benefit plans.
Environmental Matters
Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, GHG emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future as previously discussed above in “OUTLOOK.” In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 5 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.
Tax Matters
The Internal Revenue Service (IRS) has ongoing audits related to our U.S. federal income tax returns from 2010 through 2015, and we have received Revenue Agent Reports (RARs) in connection with the 2010 and 2011 audit. We are contesting certain tax positions and assertions included in the RARs and continue to make progress in resolving certain of these matters with the IRS. We believe that the ultimate settlement of these audits will not be material to our financial position, results of operations, or liquidity.
Cash Held by Our International Subsidiaries
As of September 30, 2017, $3.3 billion of our cash and temporary cash investments was held by our international subsidiaries. A large portion of this cash can be returned to the U.S. without significant tax consequences, but the remaining amount would be subject to U.S. and certain foreign withholding taxes if it were returned to the U.S. The earnings of our international subsidiaries are taxed by the countries in which they are incorporated, and we intend to reinvest those earnings indefinitely in our international operations.
As a result, we have not accrued for U.S. taxes on those earnings. Cash provided by operating activities in the U.S. continues to be our primary source of funds to finance our U.S. operations and capital expenditures, as well as our dividends and share repurchases.
Concentration of Customers
Our operations have a concentration of customers in the refining industry and customers who are refined petroleum product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.
Sources of Liquidity
We believe that we have sufficient funds from operations and, to the extent necessary, from borrowings under our credit facilities, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates. As of September 30, 20172018, there were no significant changes to our critical accounting policies since the date our annual report on Form 10‑K for the year ended December 31, 20162017 was filed.
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ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
COMMODITY PRICE RISK
We are exposed to market risks related to the volatility in the price of crude oil, refined petroleum products (primarily gasoline and distillate), grain (primarily corn), soybean oil, and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including swaps, futures, and options to manage the volatility of:
inventories and firm commitments to purchase inventories generally for amounts by which our current year inventory levels (determined on a LIFO basis) differ from our previous year-end LIFO inventory levels, and
forecasted feedstock and refined petroleum product purchases, refined petroleum product sales, natural gas purchases, and corn purchases to lock in the price of those forecasted transactions at existing market prices that we deem favorable.
We use the futures markets for the available liquidity, which provides greater flexibility in transacting our price risk activities. We use swaps primarily to manage our price exposure. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to future results of operations and cash flows.
Our positions in commodity derivative instruments are monitored and managed on a daily basis by our risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.
The following sensitivity analysis includes all positions at the end of the reporting period with which we have market risk (in millions):
| | | Derivative Instruments Held For | Derivative Instruments Held For |
| Non-Trading Purposes | | Trading Purposes | Non-Trading Purposes | | Trading Purposes |
September 30, 2017: | | | | |
September 30, 2018: | | | | |
Gain (loss) in fair value resulting from: | | | | | | |
10% increase in underlying commodity prices | $ | (60 | ) | | $ | 3 |
| $ | (171 | ) | | $ | — |
|
10% decrease in underlying commodity prices | 60 |
| | (1 | ) | 171 |
| | (1 | ) |
| | | | |
December 31, 2016: | | | | |
December 31, 2017: | | | | |
Gain (loss) in fair value resulting from: | | | | | | |
10% increase in underlying commodity prices | 61 |
| | (22 | ) | (47 | ) | | 4 |
|
10% decrease in underlying commodity prices | (61 | ) | | 11 |
| 47 |
| | (2 | ) |
See Note 1315 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of September 30, 2017.
COMPLIANCE PROGRAM PRICE RISK
We are exposed to market risk related to the volatility in the price of biofuel credits and GHG emission credits needed to comply with various governmental and regulatory programs. To manage these risks, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are
derivative instruments; however, we elect the normal purchase exception and do not record these contracts at their fair values. As of September 30, 20172018, there was an immaterial and December 31, 2017, the amount of gain or loss in the fair value of derivative instruments that would resulthave resulted from a 10 percent increase or decrease in the underlying price of the contracts.contracts was not material. See Note 1315 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs.
INTEREST RATE RISK
The following table provides information about our debt instruments (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented.
| | | September 30, 2017 | September 30, 2018 |
| Expected Maturity Dates | | | | | Expected Maturity Dates | | | | |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | There- after | | Total (a) | | Fair Value | Remainder of 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | There- after | | Total (a) | | Fair Value |
Fixed rate | $ | — |
| | $ | — |
| | $ | 750 |
| | $ | 850 |
| | $ | — |
| | $ | 6,224 |
| | $ | 7,824 |
| | $ | 9,014 |
| $ | — |
| | $ | — |
| | $ | 850 |
| | $ | 10 |
| | $ | — |
| | $ | 7,474 |
| | $ | 8,334 |
| | $ | 9,113 |
|
Average interest rate | — | % | | — | % | | 9.4 | % | | 6.1 | % | | — | % | | 5.6 | % | | 6.0 | % | | | — | % | | — | % | | 6.1 | % | | 5.0 | % | | — | % | | 5.4 | % | | 5.5 | % | | |
Floating rate (b) | $ | 1 |
| | $ | 106 |
| | $ | 6 |
| | $ | 36 |
| | $ | 6 |
| | $ | 26 |
| | $ | 181 |
| | $ | 181 |
| $ | 73 |
| | $ | 106 |
| | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 18 |
| | $ | 215 |
| | $ | 215 |
|
Average interest rate | 3.8 | % | | 2.0 | % | | 3.8 | % | | 2.9 | % | | 3.8 | % | | 3.8 | % | | 2.6 | % | | | 6.0 | % | | 2.9 | % | | 4.3 | % | | 4.3 | % | | 4.3 | % | | 4.3 | % | | 4.2 | % | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2016 | December 31, 2017 |
| Expected Maturity Dates | | | | | Expected Maturity Dates | | | | |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | There- after | | Total (a) | | Fair Value | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | There- after | | Total (a) | | Fair Value |
Fixed rate | $ | — |
| | $ | — |
| | $ | 750 |
| | $ | 850 |
| | $ | — |
| | $ | 6,224 |
| | $ | 7,824 |
| | $ | 8,701 |
| $ | — |
| | $ | 750 |
| | $ | 850 |
| | $ | — |
| | $ | — |
| | $ | 6,224 |
| | $ | 7,824 |
| | $ | 9,236 |
|
Average interest rate | — | % | | — | % | | 9.4 | % | | 6.1 | % | | — | % | | 5.6 | % | | 6.0 | % | | | — | % | | 9.4 | % | | 6.1 | % | | — | % | | — | % | | 5.6 | % | | 6.0 | % | | |
Floating rate (b) | $ | 105 |
| | $ | 5 |
| | $ | 5 |
| | $ | 35 |
| | $ | 5 |
| | $ | 26 |
| | $ | 181 |
| | $ | 181 |
| $ | 106 |
| | $ | 6 |
| | $ | 416 |
| | $ | 6 |
| | $ | 6 |
| | $ | 19 |
| | $ | 559 |
| | $ | 559 |
|
Average interest rate | 1.4 | % | | 3.4 | % | | 3.4 | % | | 2.5 | % | | 3.4 | % | | 3.4 | % | | 2.1 | % | | | 2.1 | % | | 3.8 | % | | 2.9 | % | | 3.8 | % | | 3.8 | % | | 3.8 | % | | 2.8 | % | | |
____________________________________________
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(a) | Excludes unamortized discounts and debt issuance costs. |
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(b) | As of September 30, 20172018 and December 31, 2016,2017, we had an interest rate swap associated with $51$43 million and $49 million, respectively, of our floating rate debt resulting in an effective interest rate of 3.85 percent as of each of those reporting dates. The fair value of the swap was immaterial for all periods presented. |
FOREIGN CURRENCY RISK
As of September 30, 20172018, we had commitments to purchase $514$569 million of U.S. dollars. Our market risk was minimal on these contracts, as all of them matured on or before October 31, 2017.2018.
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ITEM 4. | CONTROLS AND PROCEDURES |
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(a) | Evaluation of disclosure controls and procedures. |
Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of September 30, 2017.2018.
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(b) | Changes in internal control over financial reporting. |
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
We continue the implementation process to prepare for the adoption of Topic 842, which we discuss in Note 1 of Condensed Notes to Consolidated Financial Statements. We expect that there will be changes affecting our internal control over financial reporting in conjunction with adopting this standard. The most significant changes we expect relate to the implementation of a lease evaluation system and a lease accounting system, including the integration of our lease accounting system with our general ledger and modifications to the related procurement and payment processes.
PART II – OTHER INFORMATION
The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2016.2017.
Litigation
We incorporate by reference into this Item our disclosures made in Part I, Item 1 of this report included in Note 56 of Condensed Notes to Consolidated Financial Statements under the caption “Environmental Matters” and “Litigation Matters.”
Environmental Enforcement Matters
While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position, results of operations, or liquidity. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In our Form 10-K for the year ended December 31, 2016, we reported that we had multiple Notices of Violations (NOVs) issued by the SCAQMD. These NOVs are for alleged reporting violations and excess emissions at our Wilmington Refinery. We recently entered into a Settlement Agreement with the SCAQMD to resolve three NOVs, and we continue to work with the SCAQMD to resolve the remaining NOVs.
U.S. EPA (Ardmore Refinery). In our Form 10-K for the year ended December 31, 2016, we reported that we had received a penalty demand in the amount of $730,820 from the U.S. EPA for alleged reporting violations at our Ardmore Refinery. We have resolved this matter with the U.S. EPA.
People of the State of Illinois, ex rel. v. The Premcor Refining Group Inc., et al., Third Judicial Circuit Court, Madison County (Case No. 03-CH-00459, filed May 29, 2003) (Hartford Refinery and terminal). In our quarterly report on Form 10-K10-Q for the yearquarter ended December 31, 2016,June 30, 2018, we reported that the Illinois EPA had filed suit against The Premcor Refining Group Inc. alleging violations of air and waste regulations at Premcor’s Hartford, Illinois terminal and closed refinery. We recentlyrefinery, and that we had entered into a Partial Consent Order resolving various air and permitting violations. Our litigationconsent order with other potentially responsible parties (PRPs) and the Illinois EPA continues. Weresolving all outstanding issues pending with the state. This consent order was lodged with the Court, and was approved on July 26, 2018.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). In our annual report on Form 10-K for the year ended December 31, 2017, we reported that we had multiple outstanding Violation Notices (VNs) issued by the BAAQMD. These VNs are for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. In the third quarter of 2018, we entered into an agreement with BAAQMD to resolve various VNs and continue to assertwork with the BAAQMD to resolve the remaining VNs.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). In our quarterly report on Form 10-Q for the quarter ended March 31, 2018, we reported that we had multiple Notices of Violation (NOVs) issued by the SCAQMD. These NOVs are for alleged reporting violations and excess emissions at our Wilmington Refinery. In the third quarter of 2018, we entered into an agreement with SCAQMD to resolve various defenses, limitationsNOVs and potential rights for contribution fromcontinue to work with the other PRPs.BAAQMD to resolve the remaining NOVs.
There have been no changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2016.2017.
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ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
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(a) | Unregistered Sales of Equity Securities. Not applicable. |
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(b) | Use of Proceeds. Not applicable. |
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(c) | Issuer Purchases of Equity Securities. The following table discloses purchases of shares of our common stock made by us or on our behalf during the third quarter of 2017.2018. |
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Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a) | | 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 (b) |
July 2017 | | 361,208 |
| | $ | 67.43 |
| | 5,508 |
| | 355,700 |
| | $1.9 billion |
August 2017 | | 1,826,381 |
| | $ | 66.79 |
| | 781 |
| | 1,825,600 |
| | $1.7 billion |
September 2017 | | 2,040,515 |
| | $ | 70.53 |
| | 115 |
| | 2,040,400 |
| | $1.6 billion |
Total | | 4,228,104 |
| | $ | 68.65 |
| | 6,404 |
| | 4,221,700 |
| | $1.6 billion |
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Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a) | | 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 (b) |
July 2018 | | 1,029,340 |
| | $ | 108.84 |
| | 334,238 |
| | 695,102 |
| | $3.1 billion |
August 2018 | | 1,538,156 |
| | $ | 116.36 |
| | 1,300 |
| | 1,536,856 |
| | $3.0 billion |
September 2018 | | 1,227,357 |
| | $ | 116.04 |
| | 6,156 |
| | 1,221,201 |
| | $2.8 billion |
Total | | 3,794,853 |
| | $ | 114.22 |
| | 341,694 |
| | 3,453,159 |
| | $2.8 billion |
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(a) | The shares reported in this column represent purchases settled in the third quarter of 20172018 relating to (i) our purchases of shares in open-market transactions to meet our obligations under stock-based compensation plans and (ii) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our stock-based compensation plans. |
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(b) | On September 21, 2016,January 23, 2018, we announced that our board of directors authorized our purchase of up to $2.5 billion of our outstanding common stock, (the 2016 program) with no expiration date, which was in addition to the remaining amount available under oura $2.5 billion program previously authorized on July 13, 2015 (the 2015 program). During the first quarter of 2017, we completed our purchases under the 2015 program.September 21, 2016. As of September 30, 2017, we had $1.6 billion remaining available for purchase2018, the approximate dollar value of shares that may yet be purchased under the 2016 program is $317 million and no purchases have been made under the 2018 program. |
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Exhibit No. | | Description |
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***101 | | Interactive Data Files |
___________________
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*** | Submitted electronically herewith. |
Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10 percent of our total consolidated assets. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | VALERO ENERGY CORPORATION (Registrant) |
| By: | /s/ Michael S. CiskowskiDonna M. Titzman |
| | Michael S. CiskowskiDonna M. Titzman |
| | Executive Vice President and |
| | Chief Financial Officer |
| | (Duly Authorized Officer and Principal |
| | Financial and Accounting Officer) |
Date: November 7, 20176, 2018