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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Valero Energy Corporation | NYSE:VLO | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
-0.50 | -0.32% | 156.84 | 158.885 | 154.785 | 157.86 | 2,356,804 | 01:00:00 |
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
For the transition period from _______________ to _______________
|
Delaware
|
74-1828067
|
(State or other jurisdiction of
|
(I.R.S. Employer
|
incorporation or organization)
|
Identification No.)
|
Large accelerated filer
þ
Accelerated filer
o
Non-accelerated filer
o
|
Smaller reporting company
o
Emerging growth company
o
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Page
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June 30,
2018 |
|
December 31,
2017 |
||||
|
(unaudited)
|
|
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
4,451
|
|
|
$
|
5,850
|
|
Receivables, net
|
7,535
|
|
|
6,922
|
|
||
Inventories
|
6,420
|
|
|
6,384
|
|
||
Prepaid expenses and other
|
542
|
|
|
156
|
|
||
Total current assets
|
18,948
|
|
|
19,312
|
|
||
Property, plant, and equipment, at cost
|
41,266
|
|
|
40,010
|
|
||
Accumulated depreciation
|
(13,086
|
)
|
|
(12,530
|
)
|
||
Property, plant, and equipment, net
|
28,180
|
|
|
27,480
|
|
||
Deferred charges and other assets, net
|
3,550
|
|
|
3,366
|
|
||
Total assets
|
$
|
50,678
|
|
|
$
|
50,158
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Current portion of debt and capital lease obligations
|
$
|
183
|
|
|
$
|
122
|
|
Accounts payable
|
8,963
|
|
|
8,348
|
|
||
Accrued expenses
|
641
|
|
|
712
|
|
||
Taxes other than income taxes payable
|
1,334
|
|
|
1,321
|
|
||
Income taxes payable
|
220
|
|
|
568
|
|
||
Total current liabilities
|
11,341
|
|
|
11,071
|
|
||
Debt and capital lease obligations, less current portion
|
8,876
|
|
|
8,750
|
|
||
Deferred income tax liabilities
|
4,760
|
|
|
4,708
|
|
||
Other long-term liabilities
|
2,897
|
|
|
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
|
|
||
Additional paid-in capital
|
7,032
|
|
|
7,039
|
|
||
Treasury stock, at cost;
245,078,683 and 239,603,534 common shares
|
(13,923
|
)
|
|
(13,315
|
)
|
||
Retained earnings
|
29,915
|
|
|
29,200
|
|
||
Accumulated other comprehensive loss
|
(1,262
|
)
|
|
(940
|
)
|
||
Total Valero Energy Corporation stockholders’ equity
|
21,769
|
|
|
21,991
|
|
||
Noncontrolling interests
|
1,035
|
|
|
909
|
|
||
Total equity
|
22,804
|
|
|
22,900
|
|
||
Total liabilities and equity
|
$
|
50,678
|
|
|
$
|
50,158
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Revenues (a)
|
$
|
31,015
|
|
|
$
|
22,254
|
|
|
$
|
57,454
|
|
|
$
|
44,026
|
|
Cost of sales:
|
|
|
|
|
|
|
|
||||||||
Cost of materials and other
|
27,860
|
|
|
19,609
|
|
|
51,616
|
|
|
39,037
|
|
||||
Operating expenses (excluding depreciation and amortization
expense reflected below)
|
1,110
|
|
|
1,111
|
|
|
2,246
|
|
|
2,235
|
|
||||
Depreciation and amortization expense
|
510
|
|
|
485
|
|
|
995
|
|
|
973
|
|
||||
Total cost of sales
|
29,480
|
|
|
21,205
|
|
|
54,857
|
|
|
42,245
|
|
||||
Other operating expenses
|
21
|
|
|
—
|
|
|
31
|
|
|
—
|
|
||||
General and administrative expenses (excluding depreciation and
amortization expense reflected below)
|
248
|
|
|
175
|
|
|
486
|
|
|
367
|
|
||||
Depreciation and amortization expense
|
13
|
|
|
14
|
|
|
26
|
|
|
26
|
|
||||
Operating income
|
1,253
|
|
|
860
|
|
|
2,054
|
|
|
1,388
|
|
||||
Other income (expense), net
|
(5
|
)
|
|
27
|
|
|
46
|
|
|
53
|
|
||||
Interest and debt expense, net of capitalized interest
|
(124
|
)
|
|
(119
|
)
|
|
(245
|
)
|
|
(240
|
)
|
||||
Income before income tax expense
|
1,124
|
|
|
768
|
|
|
1,855
|
|
|
1,201
|
|
||||
Income tax expense
|
249
|
|
|
196
|
|
|
398
|
|
|
308
|
|
||||
Net income
|
875
|
|
|
572
|
|
|
1,457
|
|
|
893
|
|
||||
Less: Net income attributable to noncontrolling interests
|
30
|
|
|
24
|
|
|
143
|
|
|
40
|
|
||||
Net income attributable to Valero Energy Corporation stockholders
|
$
|
845
|
|
|
$
|
548
|
|
|
$
|
1,314
|
|
|
$
|
853
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings per common share
|
$
|
1.96
|
|
|
$
|
1.23
|
|
|
$
|
3.05
|
|
|
$
|
1.90
|
|
Weighted-average common shares outstanding (in millions)
|
429
|
|
|
444
|
|
|
430
|
|
|
446
|
|
||||
Earnings per common share – assuming dilution
|
$
|
1.96
|
|
|
$
|
1.23
|
|
|
$
|
3.04
|
|
|
$
|
1.90
|
|
Weighted-average common shares outstanding –
assuming dilution (in millions)
|
431
|
|
|
446
|
|
|
432
|
|
|
448
|
|
||||
Dividends per common share
|
$
|
0.80
|
|
|
$
|
0.70
|
|
|
$
|
1.60
|
|
|
$
|
1.40
|
|
_______________________________________________
|
|
|
|
|
|
|
|
||||||||
Supplemental information:
|
|
|
|
|
|
|
|
||||||||
(a) Includes excise taxes on sales by certain of our international
operations
|
$
|
1,470
|
|
|
$
|
1,384
|
|
|
$
|
2,934
|
|
|
$
|
2,656
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net income
|
$
|
875
|
|
|
$
|
572
|
|
|
$
|
1,457
|
|
|
$
|
893
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
||||||||
Foreign currency translation adjustment
|
(291
|
)
|
|
208
|
|
|
(246
|
)
|
|
282
|
|
||||
Net gain on pension and other postretirement
benefits
|
9
|
|
|
4
|
|
|
17
|
|
|
7
|
|
||||
Other comprehensive income (loss) before
income tax expense
|
(282
|
)
|
|
212
|
|
|
(229
|
)
|
|
289
|
|
||||
Income tax expense related to items of
other comprehensive income (loss)
|
2
|
|
|
1
|
|
|
4
|
|
|
2
|
|
||||
Other comprehensive income (loss)
|
(284
|
)
|
|
211
|
|
|
(233
|
)
|
|
287
|
|
||||
Comprehensive income
|
591
|
|
|
783
|
|
|
1,224
|
|
|
1,180
|
|
||||
Less: Comprehensive income attributable
to noncontrolling interests
|
25
|
|
|
24
|
|
|
141
|
|
|
40
|
|
||||
Comprehensive income attributable to
Valero Energy Corporation stockholders
|
$
|
566
|
|
|
$
|
759
|
|
|
$
|
1,083
|
|
|
$
|
1,140
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Cash flows from operating activities:
|
|
|
|
||||
Net income
|
$
|
1,457
|
|
|
$
|
893
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
||||
Depreciation and amortization expense
|
1,021
|
|
|
999
|
|
||
Deferred income tax expense (benefit)
|
(24
|
)
|
|
24
|
|
||
Changes in current assets and current liabilities
|
(445
|
)
|
|
859
|
|
||
Changes in deferred charges and credits and
other operating activities, net
|
188
|
|
|
10
|
|
||
Net cash provided by operating activities
|
2,197
|
|
|
2,785
|
|
||
Cash flows from investing activities:
|
|
|
|
||||
Capital expenditures
|
(740
|
)
|
|
(572
|
)
|
||
Deferred turnaround and catalyst costs
|
(490
|
)
|
|
(308
|
)
|
||
Investments in joint ventures
|
(119
|
)
|
|
(222
|
)
|
||
Capital expenditures of certain variable interest entities
|
(78
|
)
|
|
—
|
|
||
Peru Acquisition, net of cash acquired
|
(471
|
)
|
|
—
|
|
||
Acquisitions of undivided interests
|
(145
|
)
|
|
(72
|
)
|
||
Minor acquisitions
|
(91
|
)
|
|
—
|
|
||
Other investing activities, net
|
2
|
|
|
—
|
|
||
Net cash used in investing activities
|
(2,132
|
)
|
|
(1,174
|
)
|
||
Cash flows from financing activities:
|
|
|
|
||||
Proceeds from debt issuances and borrowings
|
1,314
|
|
|
—
|
|
||
Repayments of debt and capital lease obligations
|
(1,345
|
)
|
|
(11
|
)
|
||
Purchase of common stock for treasury
|
(647
|
)
|
|
(660
|
)
|
||
Common stock dividends
|
(690
|
)
|
|
(627
|
)
|
||
Proceeds from issuance of Valero Energy Partners LP common units
|
—
|
|
|
36
|
|
||
Contribution from noncontrolling interest
|
32
|
|
|
—
|
|
||
Distributions to noncontrolling interests
|
(50
|
)
|
|
(45
|
)
|
||
Other financing activities, net
|
(16
|
)
|
|
(21
|
)
|
||
Net cash used in financing activities
|
(1,402
|
)
|
|
(1,328
|
)
|
||
Effect of foreign exchange rate changes on cash
|
(62
|
)
|
|
108
|
|
||
Net increase (decrease) in cash and cash equivalents
|
(1,399
|
)
|
|
391
|
|
||
Cash and cash equivalents at beginning of period
|
5,850
|
|
|
4,816
|
|
||
Cash and cash equivalents at end of period
|
$
|
4,451
|
|
|
$
|
5,207
|
|
1.
|
BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
|
2.
|
ACQUISITION
|
Current assets, net of cash acquired
|
$
|
147
|
|
Property, plant, and equipment
|
137
|
|
|
Deferred charges and other assets
|
451
|
|
|
Current liabilities, excluding current portion of debt
|
(25
|
)
|
|
Debt assumed, including current portion
|
(137
|
)
|
|
Deferred income tax liabilities
|
(81
|
)
|
|
Other long-term liabilities
|
(21
|
)
|
|
Total consideration, net of cash acquired
|
$
|
471
|
|
3.
|
INVENTORIES
|
|
June 30,
2018 |
|
December 31,
2017 |
||||
Refinery feedstocks
|
$
|
2,213
|
|
|
$
|
2,427
|
|
Refined petroleum products and blendstocks
|
3,717
|
|
|
3,459
|
|
||
Ethanol feedstocks and products
|
231
|
|
|
242
|
|
||
Materials and supplies
|
259
|
|
|
256
|
|
||
Inventories
|
$
|
6,420
|
|
|
$
|
6,384
|
|
4.
|
DEBT AND CAPITAL LEASE OBLIGATIONS
|
•
|
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 (expense), net.
|
•
|
VLP issued 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 other 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
on 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 consolidation.
|
•
|
Central Mexico Terminals, which is the name used by us to refer to one of our consolidated variable interest entities (VIEs) and which is further described and defined in Note 7, entered into a combined
$340 million
unsecured revolving credit facility (IEnova Revolver) with IEnova (defined in Note 7). Central Mexico Terminals borrowed
$56 million
and had
no
repayments under the IEnova Revolver.
|
•
|
We retired
$137 million
of debt assumed in connection with the Peru Acquisition with available cash on hand.
|
|
|
|
|
|
|
June 30, 2018
|
||||||||||||
|
|
Facility
Amount |
|
Maturity Date
|
|
Outstanding
Borrowings |
|
Letters of
Credit Issued |
|
Availability
|
||||||||
Committed facilities:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Valero Revolver
|
|
$
|
3,000
|
|
|
November 2020
|
|
$
|
—
|
|
|
$
|
119
|
|
|
$
|
2,881
|
|
VLP Revolver
|
|
750
|
|
|
November 2020
|
|
—
|
|
|
—
|
|
|
750
|
|
||||
IEnova Revolver
|
|
340
|
|
|
February 2028
|
|
56
|
|
|
n/a
|
|
|
284
|
|
||||
Canadian Revolver
|
|
C$
|
75
|
|
|
November 2018
|
|
C$
|
—
|
|
|
C$
|
6
|
|
|
C$
|
69
|
|
Accounts receivable
sales facility (a)
|
|
1,300
|
|
|
July 2018
|
|
100
|
|
|
n/a
|
|
|
1,200
|
|
||||
Letter of credit facility
|
|
100
|
|
|
November 2018
|
|
n/a
|
|
|
—
|
|
|
100
|
|
||||
Uncommitted facilities:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Letter of credit facilities
|
|
n/a
|
|
|
n/a
|
|
n/a
|
|
|
301
|
|
|
n/a
|
|
(a)
|
In July 2018, we amended this facility to extend the maturity date from
July 2018
to
July 2019
.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Interest and debt expense
|
$
|
144
|
|
|
$
|
134
|
|
|
$
|
283
|
|
|
$
|
268
|
|
Less capitalized interest
|
20
|
|
|
15
|
|
|
38
|
|
|
28
|
|
||||
Interest and debt expense, net of
capitalized interest
|
$
|
124
|
|
|
$
|
119
|
|
|
$
|
245
|
|
|
$
|
240
|
|
5.
|
COMMITMENTS AND CONTINGENCIES
|
6.
|
EQUITY
|
|
Six Months Ended June 30,
|
||||||||||||||||||||||
|
2018
|
|
2017
|
||||||||||||||||||||
|
Valero
Stockholders’
Equity
|
|
Non-
controlling
Interests (a)
|
|
Total
Equity
|
|
Valero
Stockholders’
Equity
|
|
Non-
controlling
Interests (a)
|
|
Total
Equity
|
||||||||||||
Balance as of
beginning of period
|
$
|
21,991
|
|
|
$
|
909
|
|
|
$
|
22,900
|
|
|
$
|
20,024
|
|
|
$
|
830
|
|
|
$
|
20,854
|
|
Net income
|
1,314
|
|
|
143
|
|
|
1,457
|
|
|
853
|
|
|
40
|
|
|
893
|
|
||||||
Dividends
|
(690
|
)
|
|
—
|
|
|
(690
|
)
|
|
(627
|
)
|
|
—
|
|
|
(627
|
)
|
||||||
Stock-based
compensation expense
|
29
|
|
|
—
|
|
|
29
|
|
|
25
|
|
|
—
|
|
|
25
|
|
||||||
Transactions in connection
with stock-based
compensation plans
|
(134
|
)
|
|
—
|
|
|
(134
|
)
|
|
(13
|
)
|
|
—
|
|
|
(13
|
)
|
||||||
Stock purchases under
purchase programs
|
(508
|
)
|
|
—
|
|
|
(508
|
)
|
|
(649
|
)
|
|
—
|
|
|
(649
|
)
|
||||||
Contribution from
noncontrolling interest
|
—
|
|
|
32
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Distributions to
noncontrolling interests
|
—
|
|
|
(50
|
)
|
|
(50
|
)
|
|
—
|
|
|
(45
|
)
|
|
(45
|
)
|
||||||
Other
|
(2
|
)
|
|
3
|
|
|
1
|
|
|
23
|
|
|
17
|
|
|
40
|
|
||||||
Other comprehensive
income (loss)
|
(231
|
)
|
|
(2
|
)
|
|
(233
|
)
|
|
287
|
|
|
—
|
|
|
287
|
|
||||||
Balance as of end of period
|
$
|
21,769
|
|
|
$
|
1,035
|
|
|
$
|
22,804
|
|
|
$
|
19,923
|
|
|
$
|
842
|
|
|
$
|
20,765
|
|
(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.
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 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
|
(244
|
)
|
|
—
|
|
|
(244
|
)
|
|
282
|
|
|
—
|
|
|
282
|
|
||||||
Amounts reclassified from
accumulated other
comprehensive loss
|
—
|
|
|
13
|
|
|
13
|
|
|
—
|
|
|
5
|
|
|
5
|
|
||||||
Other comprehensive income (loss)
|
(244
|
)
|
|
13
|
|
|
(231
|
)
|
|
282
|
|
|
5
|
|
|
287
|
|
||||||
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
|
$
|
(751
|
)
|
|
$
|
(511
|
)
|
|
$
|
(1,262
|
)
|
|
$
|
(739
|
)
|
|
$
|
(384
|
)
|
|
$
|
(1,123
|
)
|
7.
|
VARIABLE INTEREST ENTITIES
|
•
|
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;
|
•
|
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; 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.
|
|
June 30, 2018
|
||||||||||||||||||
|
VLP
|
|
DGD
|
|
Central
Mexico
Terminals |
|
Other
|
|
Total
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
100
|
|
|
$
|
167
|
|
|
$
|
2
|
|
|
$
|
14
|
|
|
$
|
283
|
|
Other current assets
|
1
|
|
|
50
|
|
|
13
|
|
|
—
|
|
|
64
|
|
|||||
Property, plant, and equipment, net
|
1,413
|
|
|
529
|
|
|
107
|
|
|
119
|
|
|
2,168
|
|
|||||
Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
27
|
|
|
$
|
29
|
|
|
$
|
63
|
|
|
$
|
6
|
|
|
$
|
125
|
|
Debt and capital lease obligations,
less current portion
|
989
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|
1,027
|
|
|
December 31, 2017
|
||||||||||||||||||
|
VLP
|
|
DGD
|
|
Central
Mexico
Terminals |
|
Other
|
|
Total
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
42
|
|
|
$
|
123
|
|
|
$
|
1
|
|
|
$
|
13
|
|
|
$
|
179
|
|
Other current assets
|
2
|
|
|
66
|
|
|
4
|
|
|
—
|
|
|
72
|
|
|||||
Property, plant, and equipment, net
|
1,416
|
|
|
435
|
|
|
51
|
|
|
127
|
|
|
2,029
|
|
|||||
Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
$
|
27
|
|
|
$
|
33
|
|
|
$
|
26
|
|
|
$
|
9
|
|
|
$
|
95
|
|
Debt and capital lease obligations,
less current portion
|
905
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
948
|
|
8.
|
EMPLOYEE BENEFIT PLANS
|
|
Pension Plans
|
|
Other Postretirement
Benefit Plans
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Three months ended June 30:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
33
|
|
|
$
|
30
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Interest cost
|
23
|
|
|
22
|
|
|
3
|
|
|
2
|
|
||||
Expected return on plan assets
|
(41
|
)
|
|
(38
|
)
|
|
—
|
|
|
—
|
|
||||
Amortization of:
|
|
|
|
|
|
|
|
||||||||
Net actuarial (gain) loss
|
17
|
|
|
14
|
|
|
(1
|
)
|
|
(1
|
)
|
||||
Prior service credit
|
(4
|
)
|
|
(5
|
)
|
|
(3
|
)
|
|
(4
|
)
|
||||
Special charges
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Net periodic benefit cost (credit)
|
$
|
31
|
|
|
$
|
23
|
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
|
|
|
|
|
|
|
||||||||
Six months ended June 30:
|
|
|
|
|
|
|
|
||||||||
Service cost
|
$
|
67
|
|
|
$
|
61
|
|
|
$
|
3
|
|
|
$
|
3
|
|
Interest cost
|
46
|
|
|
43
|
|
|
5
|
|
|
5
|
|
||||
Expected return on plan assets
|
(82
|
)
|
|
(75
|
)
|
|
—
|
|
|
—
|
|
||||
Amortization of:
|
|
|
|
|
|
|
|
||||||||
Net actuarial (gain)
loss
|
33
|
|
|
27
|
|
|
(1
|
)
|
|
(2
|
)
|
||||
Prior service credit
|
(9
|
)
|
|
(10
|
)
|
|
(6
|
)
|
|
(8
|
)
|
||||
Special charges
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Net periodic benefit cost
(credit)
|
$
|
60
|
|
|
$
|
46
|
|
|
$
|
1
|
|
|
$
|
(2
|
)
|
9.
|
INCOME TAXES
|
10.
|
EARNINGS PER COMMON SHARE
|
|
Three Months Ended June 30,
|
||||||||||||||
|
2018
|
|
2017
|
||||||||||||
|
Participating
Securities
|
|
Common
Stock
|
|
Participating
Securities
|
|
Common
Stock
|
||||||||
Earnings per common share:
|
|
|
|
|
|
|
|
||||||||
Net income attributable to Valero stockholders
|
|
|
$
|
845
|
|
|
|
|
$
|
548
|
|
||||
Less dividends paid:
|
|
|
|
|
|
|
|
||||||||
Common stock
|
|
|
344
|
|
|
|
|
311
|
|
||||||
Participating securities
|
|
|
1
|
|
|
|
|
1
|
|
||||||
Undistributed earnings
|
|
|
$
|
500
|
|
|
|
|
$
|
236
|
|
||||
Weighted-average common shares outstanding
|
1
|
|
|
429
|
|
|
2
|
|
|
444
|
|
||||
Earnings per common share:
|
|
|
|
|
|
|
|
||||||||
Distributed earnings
|
$
|
0.80
|
|
|
$
|
0.80
|
|
|
$
|
0.70
|
|
|
$
|
0.70
|
|
Undistributed earnings
|
1.16
|
|
|
1.16
|
|
|
0.53
|
|
|
0.53
|
|
||||
Total earnings per common share
|
$
|
1.96
|
|
|
$
|
1.96
|
|
|
$
|
1.23
|
|
|
$
|
1.23
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings per common share –
assuming dilution:
|
|
|
|
|
|
|
|
||||||||
Net income attributable to Valero stockholders
|
|
|
$
|
845
|
|
|
|
|
$
|
548
|
|
||||
Weighted-average common shares outstanding
|
|
|
429
|
|
|
|
|
444
|
|
||||||
Common equivalent shares
|
|
|
2
|
|
|
|
|
2
|
|
||||||
Weighted-average common shares outstanding –
assuming dilution
|
|
|
431
|
|
|
|
|
446
|
|
||||||
Earnings per common share – assuming dilution
|
|
|
$
|
1.96
|
|
|
|
|
$
|
1.23
|
|
|
Six Months Ended June 30,
|
||||||||||||||
|
2018
|
|
2017
|
||||||||||||
|
Participating
Securities
|
|
Common
Stock
|
|
Participating
Securities
|
|
Common
Stock
|
||||||||
Earnings per common share:
|
|
|
|
|
|
|
|
||||||||
Net income attributable to Valero stockholders
|
|
|
$
|
1,314
|
|
|
|
|
$
|
853
|
|
||||
Less dividends paid:
|
|
|
|
|
|
|
|
||||||||
Common stock
|
|
|
688
|
|
|
|
|
625
|
|
||||||
Participating securities
|
|
|
2
|
|
|
|
|
2
|
|
||||||
Undistributed
earnings
|
|
|
$
|
624
|
|
|
|
|
$
|
226
|
|
||||
Weighted-average common shares outstanding
|
1
|
|
|
430
|
|
|
2
|
|
|
446
|
|
||||
Earnings per common share:
|
|
|
|
|
|
|
|
||||||||
Distributed earnings
|
$
|
1.60
|
|
|
$
|
1.60
|
|
|
$
|
1.40
|
|
|
$
|
1.40
|
|
Undistributed earnings
|
1.45
|
|
|
1.45
|
|
|
0.50
|
|
|
0.50
|
|
||||
Total earnings per common share
|
$
|
3.05
|
|
|
$
|
3.05
|
|
|
$
|
1.90
|
|
|
$
|
1.90
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings per common share –
assuming dilution:
|
|
|
|
|
|
|
|
||||||||
Net income attributable to Valero stockholders
|
|
|
$
|
1,314
|
|
|
|
|
$
|
853
|
|
||||
Weighted-average common shares outstanding
|
|
|
430
|
|
|
|
|
446
|
|
||||||
Common equivalent shares
|
|
|
2
|
|
|
|
|
2
|
|
||||||
Weighted-average common shares outstanding –
assuming dilution
|
|
|
432
|
|
|
|
|
448
|
|
||||||
Earnings per common share – assuming dilution
|
|
|
$
|
3.04
|
|
|
|
|
$
|
1.90
|
|
11.
|
REVENUES AND SEGMENT INFORMATION
|
•
|
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.
|
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and
Eliminations
|
|
Total
|
||||||||||
Three months ended June 30, 2018:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
30,130
|
|
|
$
|
884
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
31,015
|
|
Intersegment revenues
|
1
|
|
|
42
|
|
|
135
|
|
|
(178
|
)
|
|
—
|
|
|||||
Total revenues
|
30,131
|
|
|
926
|
|
|
135
|
|
|
(177
|
)
|
|
31,015
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
27,283
|
|
|
754
|
|
|
—
|
|
|
(177
|
)
|
|
27,860
|
|
|||||
Operating expenses (excluding depreciation
and amortization expense reflected below)
|
969
|
|
|
109
|
|
|
33
|
|
|
(1
|
)
|
|
1,110
|
|
|||||
Depreciation and amortization expense
|
471
|
|
|
20
|
|
|
19
|
|
|
—
|
|
|
510
|
|
|||||
Total cost of sales
|
28,723
|
|
|
883
|
|
|
52
|
|
|
(178
|
)
|
|
29,480
|
|
|||||
Other operating expenses
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
248
|
|
|
248
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
|||||
Operating income by segment
|
$
|
1,387
|
|
|
$
|
43
|
|
|
$
|
83
|
|
|
$
|
(260
|
)
|
|
$
|
1,253
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Three months ended June 30, 2017:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
21,415
|
|
|
$
|
839
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
22,254
|
|
Intersegment revenues
|
—
|
|
|
28
|
|
|
110
|
|
|
(138
|
)
|
|
—
|
|
|||||
Total revenues
|
21,415
|
|
|
867
|
|
|
110
|
|
|
(138
|
)
|
|
22,254
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
19,037
|
|
|
710
|
|
|
—
|
|
|
(138
|
)
|
|
19,609
|
|
|||||
Operating expenses (excluding depreciation
and amortization expense reflected below)
|
979
|
|
|
107
|
|
|
27
|
|
|
(2
|
)
|
|
1,111
|
|
|||||
Depreciation and amortization expense
|
454
|
|
|
19
|
|
|
12
|
|
|
—
|
|
|
485
|
|
|||||
Total cost of sales
|
20,470
|
|
|
836
|
|
|
39
|
|
|
(140
|
)
|
|
21,205
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
175
|
|
|
175
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
14
|
|
|||||
Operating income by segment
|
$
|
945
|
|
|
$
|
31
|
|
|
$
|
71
|
|
|
$
|
(187
|
)
|
|
$
|
860
|
|
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and
Eliminations
|
|
Total
|
||||||||||
Six months ended June 30, 2018:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
55,691
|
|
|
$
|
1,761
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
57,454
|
|
Intersegment revenues
|
5
|
|
|
88
|
|
|
267
|
|
|
(360
|
)
|
|
—
|
|
|||||
Total revenues
|
55,696
|
|
|
1,849
|
|
|
267
|
|
|
(358
|
)
|
|
57,454
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
50,471
|
|
|
1,503
|
|
|
—
|
|
|
(358
|
)
|
|
51,616
|
|
|||||
Operating expenses (excluding depreciation
and amortization expense reflected below)
|
1,966
|
|
|
220
|
|
|
62
|
|
|
(2
|
)
|
|
2,246
|
|
|||||
Depreciation and amortization expense
|
919
|
|
|
38
|
|
|
38
|
|
|
—
|
|
|
995
|
|
|||||
Total cost of sales
|
53,356
|
|
|
1,761
|
|
|
100
|
|
|
(360
|
)
|
|
54,857
|
|
|||||
Other operating expenses
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
486
|
|
|
486
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
26
|
|
|||||
Operating income by segment
|
$
|
2,309
|
|
|
$
|
88
|
|
|
$
|
167
|
|
|
$
|
(510
|
)
|
|
$
|
2,054
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Six months ended June 30, 2017:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
42,302
|
|
|
$
|
1,724
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44,026
|
|
Intersegment revenues
|
—
|
|
|
88
|
|
|
216
|
|
|
(304
|
)
|
|
—
|
|
|||||
Total revenues
|
42,302
|
|
|
1,812
|
|
|
216
|
|
|
(304
|
)
|
|
44,026
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
37,844
|
|
|
1,497
|
|
|
—
|
|
|
(304
|
)
|
|
39,037
|
|
|||||
Operating expenses (excluding depreciation
and amortization expense reflected below)
|
1,970
|
|
|
216
|
|
|
51
|
|
|
(2
|
)
|
|
2,235
|
|
|||||
Depreciation and amortization expense
|
903
|
|
|
46
|
|
|
24
|
|
|
—
|
|
|
973
|
|
|||||
Total cost of sales
|
40,717
|
|
|
1,759
|
|
|
75
|
|
|
(306
|
)
|
|
42,245
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below)
|
—
|
|
|
—
|
|
|
—
|
|
|
367
|
|
|
367
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
26
|
|
|||||
Operating income by segment
|
$
|
1,585
|
|
|
$
|
53
|
|
|
$
|
141
|
|
|
$
|
(391
|
)
|
|
$
|
1,388
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Refining:
|
|
|
|
|
|
|
|
||||||||
Gasolines and blendstocks
|
$
|
12,514
|
|
|
$
|
9,723
|
|
|
$
|
23,143
|
|
|
$
|
19,058
|
|
Distillates
|
14,459
|
|
|
9,736
|
|
|
27,117
|
|
|
19,432
|
|
||||
Other product revenues
|
3,157
|
|
|
1,956
|
|
|
5,431
|
|
|
3,812
|
|
||||
Total refining revenues
|
30,130
|
|
|
21,415
|
|
|
55,691
|
|
|
42,302
|
|
||||
Ethanol:
|
|
|
|
|
|
|
|
||||||||
Ethanol
|
696
|
|
|
712
|
|
|
1,397
|
|
|
1,462
|
|
||||
Distillers grains
|
188
|
|
|
127
|
|
|
364
|
|
|
262
|
|
||||
Total ethanol revenues
|
884
|
|
|
839
|
|
|
1,761
|
|
|
1,724
|
|
||||
VLP:
|
|
|
|
|
|
|
|
||||||||
Pipeline transportation
|
31
|
|
|
25
|
|
|
62
|
|
|
48
|
|
||||
Terminaling
|
103
|
|
|
84
|
|
|
202
|
|
|
167
|
|
||||
Storage and other
|
1
|
|
|
1
|
|
|
3
|
|
|
1
|
|
||||
Total VLP revenues
|
135
|
|
|
110
|
|
|
267
|
|
|
216
|
|
||||
Corporate – other revenues
|
1
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||
Elimination of intersegment revenues
|
(135
|
)
|
|
(110
|
)
|
|
(267
|
)
|
|
(216
|
)
|
||||
Revenues
|
$
|
31,015
|
|
|
$
|
22,254
|
|
|
$
|
57,454
|
|
|
$
|
44,026
|
|
|
June 30,
2018 |
|
December 31,
2017 |
||||
Refining
|
$
|
42,107
|
|
|
$
|
40,382
|
|
Ethanol
|
1,332
|
|
|
1,344
|
|
||
VLP
|
1,569
|
|
|
1,517
|
|
||
Corporate and eliminations
|
5,670
|
|
|
6,915
|
|
||
Total assets
|
$
|
50,678
|
|
|
$
|
50,158
|
|
12.
|
SUPPLEMENTAL CASH FLOW INFORMATION
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Decrease (increase) in current assets:
|
|
|
|
||||
Receivables, net
|
$
|
(595
|
)
|
|
$
|
1,396
|
|
Inventories
|
(46
|
)
|
|
123
|
|
||
Prepaid expenses and other
|
(35
|
)
|
|
86
|
|
||
Increase (decrease) in current liabilities:
|
|
|
|
||||
Accounts payable
|
661
|
|
|
(942
|
)
|
||
Accrued expenses
|
(83
|
)
|
|
262
|
|
||
Taxes other than income taxes payable
|
28
|
|
|
(41
|
)
|
||
Income taxes payable
|
(375
|
)
|
|
(25
|
)
|
||
Changes in current assets and current liabilities
|
$
|
(445
|
)
|
|
$
|
859
|
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Interest paid in excess of amount capitalized
|
$
|
248
|
|
|
$
|
235
|
|
Income taxes paid, net
|
817
|
|
|
263
|
|
13.
|
FAIR VALUE MEASUREMENTS
|
|
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
|
||||||||||||||||||||
|
Fair Value Hierarchy
|
|
|
|
|
|
|||||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
|
|
|||||||||||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity derivative
contracts
|
$
|
875
|
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
894
|
|
|
$
|
(893
|
)
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
Investments of certain
benefit plans
|
65
|
|
|
—
|
|
|
8
|
|
|
73
|
|
|
n/a
|
|
|
n/a
|
|
|
73
|
|
|
n/a
|
|
||||||||
Total
|
$
|
940
|
|
|
$
|
19
|
|
|
$
|
8
|
|
|
$
|
967
|
|
|
$
|
(893
|
)
|
|
$
|
—
|
|
|
$
|
74
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity derivative
contracts
|
$
|
955
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
969
|
|
|
$
|
(893
|
)
|
|
$
|
(76
|
)
|
|
$
|
—
|
|
|
$
|
(102
|
)
|
Environmental credit
obligations
|
—
|
|
|
104
|
|
|
—
|
|
|
104
|
|
|
n/a
|
|
|
n/a
|
|
|
104
|
|
|
n/a
|
|
||||||||
Physical purchase
contracts
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|
n/a
|
|
|
n/a
|
|
|
6
|
|
|
n/a
|
|
||||||||
Foreign currency
contracts
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
n/a
|
|
|
n/a
|
|
|
7
|
|
|
n/a
|
|
||||||||
Total
|
$
|
962
|
|
|
$
|
124
|
|
|
$
|
—
|
|
|
$
|
1,086
|
|
|
$
|
(893
|
)
|
|
$
|
(76
|
)
|
|
$
|
117
|
|
|
|
|
•
|
Commodity derivative contracts consist primarily of exchange-traded futures and 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.
|
•
|
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 Renewable 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), (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 14
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.
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
Hierarchy
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Financial assets:
|
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
Level 1
|
|
$
|
4,451
|
|
|
$
|
4,451
|
|
|
$
|
5,850
|
|
|
$
|
5,850
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||
Debt (excluding capital leases)
|
Level 2
|
|
8,451
|
|
|
9,310
|
|
|
8,310
|
|
|
9,795
|
|
14.
|
PRICE RISK MANAGEMENT ACTIVITIES
|
•
|
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.
|
|
|
Notional Contract Volumes by
Year of Maturity
|
||||
Derivative Instrument
|
|
2018
|
|
2019
|
||
Crude oil and refined petroleum products:
|
|
|
|
|
||
Swaps – long
|
|
9,892
|
|
|
135
|
|
Swaps – short
|
|
10,115
|
|
|
—
|
|
Futures – long
|
|
93,569
|
|
|
—
|
|
Futures – short
|
|
95,354
|
|
|
6
|
|
Corn:
|
|
|
|
|
||
Futures – long
|
|
48,500
|
|
|
150
|
|
Futures – short
|
|
86,310
|
|
|
8,415
|
|
Physical contracts – long
|
|
41,029
|
|
|
8,264
|
|
Soybean oil:
|
|
|
|
|
||
Futures – long
|
|
65,519
|
|
|
—
|
|
Futures – short
|
|
169,018
|
|
|
—
|
|
•
|
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.
|
|
|
Notional Contract Volumes by
Year of Maturity
|
||||
Derivative Instrument
|
|
2018
|
|
2019
|
||
Crude oil and refined
petroleum
products:
|
|
|
|
|
||
Swaps – long
|
|
300
|
|
|
—
|
|
Swaps – short
|
|
300
|
|
|
—
|
|
Futures – long
|
|
55,504
|
|
|
7,701
|
|
Futures – short
|
|
55,402
|
|
|
7,751
|
|
Options – long
|
|
75,800
|
|
|
—
|
|
Options – short
|
|
75,400
|
|
|
—
|
|
Corn:
|
|
|
|
|
||
Futures – long
|
|
150
|
|
|
—
|
|
|
Balance Sheet
Location
|
|
June 30, 2018
|
||||||
|
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|||||
Derivatives not designated as
hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
1,398
|
|
|
$
|
1,426
|
|
Swaps
|
Receivables, net
|
|
11
|
|
|
11
|
|
||
Swaps
|
Accounts payable
|
|
—
|
|
|
1
|
|
||
Options
|
Receivables, net
|
|
27
|
|
|
29
|
|
||
Physical purchase contracts
|
Inventories
|
|
—
|
|
|
13
|
|
||
Foreign currency contracts
|
Receivables, net
|
|
2
|
|
|
—
|
|
||
Total
|
|
|
$
|
1,438
|
|
|
$
|
1,480
|
|
|
Balance Sheet
Location
|
|
December 31, 2017
|
||||||
|
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|||||
Derivatives not designated as
hedging instruments
|
|
|
|
|
|
||||
Commodity contracts:
|
|
|
|
|
|
||||
Futures
|
Receivables, net
|
|
$
|
875
|
|
|
$
|
955
|
|
Swaps
|
Receivables, net
|
|
11
|
|
|
11
|
|
||
Options
|
Receivables, net
|
|
8
|
|
|
3
|
|
||
Physical purchase contracts
|
Inventories
|
|
—
|
|
|
6
|
|
||
Foreign currency contracts
|
Accrued expenses
|
|
—
|
|
|
7
|
|
||
Total
|
|
|
$
|
894
|
|
|
$
|
982
|
|
Derivatives Designated as
Economic Hedges
|
|
Location of Gain (Loss)
Recognized in Income on Derivatives |
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
2018
|
|
2017
|
2018
|
|
2017
|
|||||||||||||
Commodity contracts
|
|
Cost of materials and other
|
|
$
|
(66
|
)
|
|
$
|
25
|
|
|
$
|
(114
|
)
|
|
$
|
(72
|
)
|
Foreign currency contracts
|
|
Cost of materials and other
|
|
17
|
|
|
(20
|
)
|
|
14
|
|
|
(26
|
)
|
Trading Derivatives
|
|
Location of Gain (Loss)
Recognized in Income on Derivatives |
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
2018
|
|
2017
|
2018
|
|
2017
|
|||||||||||||
Commodity contracts
|
|
Cost of materials and other
|
|
$
|
51
|
|
|
$
|
(3
|
)
|
|
$
|
87
|
|
|
$
|
(2
|
)
|
•
|
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.
|
•
|
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 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 Peruvian 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, 2017
that is incorporated by reference herein.
|
•
|
Refining segment.
Refining segment adjusted operating income increased by $463 million primarily due to improved distillate margins and stronger crude oil discounts, partially offset by lower gasoline margins and lower throughput volumes. This is more fully described on pages
44
through
46
.
|
•
|
Ethanol segment.
Ethanol segment operating income increased by
$12 million
primarily due to higher corn related co-product prices, partially offset by lower ethanol prices. This is more fully described on page
46
.
|
•
|
VLP segment.
VLP segment operating income increased by
$12 million
primarily due to incremental revenues, partially offset by higher cost of sales, 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 page
47
.
|
•
|
Corporate and eliminations.
Adjusted corporate and eliminations increased by $17 million primarily due to an increase in employee related expenses. This is more fully described on page
47
.
|
•
|
Refining segment.
Refining segment adjusted operating income increased by $585 million primarily due to improved distillate margins and stronger discounts on crude oils and other feedstocks, partially offset by lower gasoline and other products margins. This is more fully described on pages
56
through
58
.
|
•
|
Ethanol segment.
Ethanol segment operating income increased by
$35 million
primarily due to higher corn related co-product prices, partially offset by lower ethanol prices. This is more fully described on pages
58
and
59
.
|
•
|
VLP segment.
VLP segment operating income increased by
$26 million
primarily due to incremental revenues, partially offset by higher cost of sales, 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 page
59
.
|
•
|
Corporate and eliminations.
Adjusted corporate and eliminations increased by $11 million primarily due to an increase in employee related expenses. This is more fully described on page
59
.
|
•
|
Refined product margins are expected to remain near current levels as domestic and export demand remains strong.
|
•
|
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 remain near current levels as export demand remains strong and increased supplies from the Permian Basin are delivered into U.S. Gulf Coast markets.
|
•
|
Ethanol margins are expected to remain near current levels.
|
|
Three Months Ended June 30, 2018
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and
Eliminations
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
30,130
|
|
|
$
|
884
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
31,015
|
|
Intersegment revenues
|
1
|
|
|
42
|
|
|
135
|
|
|
(178
|
)
|
|
—
|
|
|||||
Total revenues
|
30,131
|
|
|
926
|
|
|
135
|
|
|
(177
|
)
|
|
31,015
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
27,283
|
|
|
754
|
|
|
—
|
|
|
(177
|
)
|
|
27,860
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below)
|
969
|
|
|
109
|
|
|
33
|
|
|
(1
|
)
|
|
1,110
|
|
|||||
Depreciation and amortization expense
|
471
|
|
|
20
|
|
|
19
|
|
|
—
|
|
|
510
|
|
|||||
Total cost of sales
|
28,723
|
|
|
883
|
|
|
52
|
|
|
(178
|
)
|
|
29,480
|
|
|||||
Other operating expenses (c)
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below) (d)
|
—
|
|
|
—
|
|
|
—
|
|
|
248
|
|
|
248
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
|||||
Operating income by segment
|
$
|
1,387
|
|
|
$
|
43
|
|
|
$
|
83
|
|
|
$
|
(260
|
)
|
|
1,253
|
|
|
Other income (expense), net (e)
|
|
|
|
|
|
|
|
|
(5
|
)
|
|||||||||
Interest and debt expense, net of capitalized interest
|
|
|
|
|
|
|
|
|
(124
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
1,124
|
|
|||||||||
Income tax expense (f)
|
|
|
|
|
|
|
|
|
249
|
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
875
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests
|
|
|
|
|
|
|
|
|
30
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
845
|
|
|
Three Months Ended June 30, 2017
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and
Eliminations
|
|
Total
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
21,415
|
|
|
$
|
839
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
22,254
|
|
Intersegment revenues
|
—
|
|
|
28
|
|
|
110
|
|
|
(138
|
)
|
|
—
|
|
|||||
Total revenues
|
21,415
|
|
|
867
|
|
|
110
|
|
|
(138
|
)
|
|
22,254
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
19,037
|
|
|
710
|
|
|
—
|
|
|
(138
|
)
|
|
19,609
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below) (b)
|
979
|
|
|
107
|
|
|
27
|
|
|
(2
|
)
|
|
1,111
|
|
|||||
Depreciation and amortization expense
|
454
|
|
|
19
|
|
|
12
|
|
|
—
|
|
|
485
|
|
|||||
Total cost of sales
|
20,470
|
|
|
836
|
|
|
39
|
|
|
(140
|
)
|
|
21,205
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below) (b)
|
—
|
|
|
—
|
|
|
—
|
|
|
175
|
|
|
175
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
14
|
|
|||||
Operating income by segment
|
$
|
945
|
|
|
$
|
31
|
|
|
$
|
71
|
|
|
$
|
(187
|
)
|
|
860
|
|
|
Other income, net (b)
|
|
|
|
|
|
|
|
|
27
|
|
|||||||||
Interest and debt expense, net of capitalized interest
|
|
|
|
|
|
|
|
|
(119
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
768
|
|
|||||||||
Income tax expense
|
|
|
|
|
|
|
|
|
196
|
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
572
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests
|
|
|
|
|
|
|
|
|
24
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
548
|
|
|
Three Months Ended June 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
|
$
|
845
|
|
|
$
|
548
|
|
Exclude adjustments:
|
|
|
|
||||
Texas City Refinery fire expenses (c)
|
(14
|
)
|
|
—
|
|
||
Income tax benefit related to Texas City Refinery fire expenses
|
3
|
|
|
—
|
|
||
Texas City Refinery fire expenses, net of taxes
|
(11
|
)
|
|
—
|
|
||
Environmental reserve adjustment (d)
|
(56
|
)
|
|
—
|
|
||
Income tax benefit related to the environmental reserve adjustment
|
13
|
|
|
—
|
|
||
Environmental reserve adjustment, net of taxes
|
(43
|
)
|
|
—
|
|
||
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
|
(83
|
)
|
|
—
|
|
||
Adjusted net income attributable to
Valero Energy Corporation stockholders
|
$
|
928
|
|
|
$
|
548
|
|
|
Three Months Ended June 30, 2018
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and
Eliminations
|
|
Total
|
||||||||||
Reconciliation of operating income to adjusted
operating income (g)
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating income by segment (see page 38)
|
$
|
1,387
|
|
|
$
|
43
|
|
|
$
|
83
|
|
|
$
|
(260
|
)
|
|
$
|
1,253
|
|
Exclude:
|
|
|
|
|
|
|
|
|
|
||||||||||
Other operating expenses (c)
|
(21
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|||||
Environmental reserve adjustment (d)
|
—
|
|
|
—
|
|
|
—
|
|
|
(56
|
)
|
|
(56
|
)
|
|||||
Adjusted operating income
|
$
|
1,408
|
|
|
$
|
43
|
|
|
$
|
83
|
|
|
$
|
(204
|
)
|
|
$
|
1,330
|
|
|
Three Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Throughput volumes (thousand barrels per day (BPD))
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude oil
|
482
|
|
|
517
|
|
|
(35
|
)
|
|||
Medium/light sour crude oil
|
434
|
|
|
508
|
|
|
(74
|
)
|
|||
Sweet crude oil
|
1,303
|
|
|
1,308
|
|
|
(5
|
)
|
|||
Residuals
|
231
|
|
|
228
|
|
|
3
|
|
|||
Other feedstocks
|
121
|
|
|
142
|
|
|
(21
|
)
|
|||
Total feedstocks
|
2,571
|
|
|
2,703
|
|
|
(132
|
)
|
|||
Blendstocks and other
|
327
|
|
|
316
|
|
|
11
|
|
|||
Total throughput volumes
|
2,898
|
|
|
3,019
|
|
|
(121
|
)
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD)
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,407
|
|
|
1,458
|
|
|
(51
|
)
|
|||
Distillates
|
1,096
|
|
|
1,167
|
|
|
(71
|
)
|
|||
Other products (h)
|
434
|
|
|
434
|
|
|
—
|
|
|||
Total yields
|
2,937
|
|
|
3,059
|
|
|
(122
|
)
|
|||
|
|
|
|
|
|
||||||
Operating statistics (i)
|
|
|
|
|
|
||||||
Refining margin (g)
|
$
|
2,848
|
|
|
$
|
2,378
|
|
|
$
|
470
|
|
Adjusted refining operating income
(see page 40) (g)
|
$
|
1,408
|
|
|
$
|
945
|
|
|
$
|
463
|
|
Throughput volumes (thousand BPD)
|
2,898
|
|
|
3,019
|
|
|
(121
|
)
|
|||
|
|
|
|
|
|
||||||
Refining margin per barrel of throughput
|
$
|
10.80
|
|
|
$
|
8.66
|
|
|
$
|
2.14
|
|
Less:
|
|
|
|
|
|
||||||
Operating expenses (excluding depreciation and
amortization expense reflected below) per barrel of
throughput (b)
|
3.67
|
|
|
3.56
|
|
|
0.11
|
|
|||
Depreciation and amortization expense per barrel of
throughput
|
1.79
|
|
|
1.66
|
|
|
0.13
|
|
|||
Adjusted refining operating income per barrel of throughput
|
$
|
5.34
|
|
|
$
|
3.44
|
|
|
$
|
1.90
|
|
|
Three Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Operating statistics (i)
|
|
|
|
|
|
||||||
Ethanol margin (g)
|
$
|
172
|
|
|
$
|
157
|
|
|
$
|
15
|
|
Ethanol operating income
|
$
|
43
|
|
|
$
|
31
|
|
|
$
|
12
|
|
Production volumes (thousand gallons per day)
|
4,002
|
|
|
3,775
|
|
|
227
|
|
|||
|
|
|
|
|
|
||||||
Ethanol margin per gallon of production
|
$
|
0.47
|
|
|
$
|
0.46
|
|
|
$
|
0.01
|
|
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
|
|
|
0.06
|
|
|
(0.01
|
)
|
|||
Ethanol operating income per gallon of
production
|
$
|
0.12
|
|
|
$
|
0.09
|
|
|
$
|
0.03
|
|
|
Three Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Operating statistics (i)
|
|
|
|
|
|
||||||
Pipeline transportation revenue
|
$
|
31
|
|
|
$
|
25
|
|
|
$
|
6
|
|
Terminaling revenue
|
103
|
|
|
84
|
|
|
19
|
|
|||
Storage and other revenue
|
1
|
|
|
1
|
|
|
—
|
|
|||
Total VLP revenues
|
$
|
135
|
|
|
$
|
110
|
|
|
$
|
25
|
|
|
|
|
|
|
|
||||||
Pipeline transportation throughput (thousand BPD)
|
1,033
|
|
|
1,003
|
|
|
30
|
|
|||
Pipeline transportation revenue per barrel of throughput
|
$
|
0.32
|
|
|
$
|
0.27
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
||||||
Terminaling throughput (thousand BPD)
|
3,562
|
|
|
2,853
|
|
|
709
|
|
|||
Terminaling revenue per barrel of throughput
|
$
|
0.32
|
|
|
$
|
0.33
|
|
|
$
|
(0.01
|
)
|
|
Three Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Feedstocks (dollars per barrel)
|
|
|
|
|
|
||||||
Brent crude oil
|
$
|
74.93
|
|
|
$
|
50.91
|
|
|
$
|
24.02
|
|
Brent less West Texas Intermediate (WTI) crude oil
|
6.93
|
|
|
2.67
|
|
|
4.26
|
|
|||
Brent less Alaska North Slope (ANS) crude oil
|
0.83
|
|
|
0.22
|
|
|
0.61
|
|
|||
Brent less Louisiana Light Sweet (LLS) crude oil
|
1.93
|
|
|
0.60
|
|
|
1.33
|
|
|||
Brent less Argus Sour Crude Index (ASCI) crude oil
|
5.63
|
|
|
3.94
|
|
|
1.69
|
|
|||
Brent less Maya crude oil
|
12.90
|
|
|
7.03
|
|
|
5.87
|
|
|||
LLS crude oil
|
73.00
|
|
|
50.31
|
|
|
22.69
|
|
|||
LLS less ASCI crude oil
|
3.70
|
|
|
3.34
|
|
|
0.36
|
|
|||
LLS less Maya crude oil
|
10.97
|
|
|
6.43
|
|
|
4.54
|
|
|||
WTI crude oil
|
68.00
|
|
|
48.24
|
|
|
19.76
|
|
|||
|
|
|
|
|
|
||||||
Natural gas (dollars per million British Thermal Units
(MMBtu))
|
2.89
|
|
|
3.14
|
|
|
(0.25
|
)
|
|||
|
|
|
|
|
|
||||||
Products (dollars per barrel, unless otherwise noted)
|
|
|
|
|
|
||||||
U.S. Gulf Coast:
|
|
|
|
|
|
||||||
Conventional Blendstock of Oxygenate Blending (CBOB)
gasoline less Brent
|
7.47
|
|
|
10.38
|
|
|
(2.91
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
13.46
|
|
|
10.99
|
|
|
2.47
|
|
|||
Propylene less Brent
|
(6.54
|
)
|
|
0.04
|
|
|
(6.58
|
)
|
|||
CBOB gasoline less LLS
|
9.40
|
|
|
10.98
|
|
|
(1.58
|
)
|
|||
Ultra-low-sulfur diesel less LLS
|
15.39
|
|
|
11.59
|
|
|
3.80
|
|
|||
Propylene less LLS
|
(4.61
|
)
|
|
0.64
|
|
|
(5.25
|
)
|
|||
U.S. Mid-Continent:
|
|
|
|
|
|
||||||
CBOB gasoline less WTI
|
16.05
|
|
|
14.16
|
|
|
1.89
|
|
|||
Ultra-low-sulfur diesel less WTI
|
22.02
|
|
|
14.60
|
|
|
7.42
|
|
|||
North Atlantic:
|
|
|
|
|
|
||||||
CBOB gasoline less Brent
|
10.37
|
|
|
12.57
|
|
|
(2.20
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
15.25
|
|
|
12.21
|
|
|
3.04
|
|
|||
U.S. West Coast:
|
|
|
|
|
|
||||||
California Reformulated Gasoline Blendstock of Oxygenate
Blending (CARBOB) 87 gasoline less ANS
|
18.36
|
|
|
23.01
|
|
|
(4.65
|
)
|
|||
CARB diesel less ANS
|
18.70
|
|
|
14.32
|
|
|
4.38
|
|
|||
CARBOB 87 gasoline less WTI
|
24.46
|
|
|
25.46
|
|
|
(1.00
|
)
|
|||
CARB diesel less WTI
|
24.80
|
|
|
16.77
|
|
|
8.03
|
|
|||
New York Harbor corn crush (dollars per gallon)
|
0.17
|
|
|
0.26
|
|
|
(0.09
|
)
|
•
|
Increase in distillate margins.
We experienced improved distillate margins throughout all of our regions during the
second quarter
of
2018
compared to the
second quarter
of
2017
. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was
$13.46
per barrel for the
second quarter
of
2018
compared to
$10.99
per barrel for the
second quarter
of
2017
, representing a favorable increase of
$2.47
per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel which was
$22.02
per barrel for the
second quarter
of
2018
compared to
$14.60
per barrel for the
second quarter
of
2017
, representing a favorable increase of
$7.42
per barrel. We estimate that the increase in distillate
|
•
|
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
second quarter
of
2018
and that benefit improved compared to the
second quarter
of
2017
. For example, Maya crude oil, a sour crude oil processed in our U.S. Gulf Coast region, sold at a discount to Brent crude oil of
$12.90
per barrel for the
second quarter
of
2018
compared to a discount of
$7.03
per barrel for the
second quarter
of
2017
, representing a favorable increase of
$5.87
per barrel. Another example is WTI crude oil, a light sweet crude oil processed in our U.S. Mid-Continent region, which sold at a discount of
$6.93
per barrel for the
second quarter
of
2018
compared to a discount of
$2.67
per barrel for the
second quarter
of
2017
, representing a favorable increase of
$4.26
per barrel. We estimate that the increase in the discounts for the crude oils we processed during the
second quarter
of
2018
compared to the
second quarter
of
2017
had a favorable impact to our refining segment margin of approximately $325 million.
|
•
|
Higher 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. We benefitted from processing these types of feedstocks during the
second quarter
of
2018
and that benefit improved compared to the
second quarter
of
2017
. We estimate that the increase in the discounts for the other feedstocks we processed during the
second quarter
of
2018
compared to the
second quarter
of
2017
had a favorable impact to our refining segment margin of approximately $181 million.
|
•
|
Lower costs of biofuel credits.
As more fully described in
Note 14
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
$124 million
to
$131 million
for the
second quarter
of
2018
compared to
$255 million
for the
second quarter
of
2017
.
|
•
|
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
second quarter
of
2018
compared to the
second 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
$74.93
per barrel for the
second quarter
of
2018
compared to
$50.91
per barrel for the
second quarter
of
2017
, representing an unfavorable increase of
$24.02
per barrel. We estimate that the decrease in other products margins in the
second quarter
of
2018
compared to the
second quarter
of
2017
had an unfavorable impact to our refining segment margin of approximately $259 million.
|
•
|
Decrease in gasoline margins.
We experienced a decrease in gasoline margins during the
second quarter
of
2018
compared to the
second quarter
of
2017
. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was
$7.47
per barrel for the
second quarter
of
2018
compared to
$10.38
per barrel for the
second quarter
of
2017
, representing an unfavorable decrease of
$2.91
per barrel. Another example is the ANS-based benchmark reference margin for U.S. West Coast CARBOB 87 gasoline which was
$18.36
per barrel for the
second quarter
of
2018
compared to
$23.01
per barrel for the
second quarter
of
2017
, representing an unfavorable decrease
|
•
|
Lower throughput volumes.
Refining throughput volumes decreased by
121,000
BPD in the
second quarter
of
2018
primarily due to maintenance in the U.S. Gulf Coast and North Atlantic regions. We estimate that the decrease in refining throughput volumes had a negative impact on our refining segment margin of approximately $119 million.
|
•
|
Increase in charges from VLP.
Charges from the VLP segment for transportation and terminaling services increased
$25 million
in the
second quarter
of
2018
compared to the
second 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 co-product prices.
An increase in export demand for corn related co-products, primarily distillers grains, had a favorable effect on the prices we received. We estimate that the increase in corn related co-product prices had a favorable impact to our ethanol segment margin of approximately $41 million.
|
•
|
Higher production volumes.
Ethanol segment margin was favorably impacted by increased production volumes of 227,000 gallons per day in the
second quarter
of
2018
compared to the
second quarter
of
2017
primarily due to reliability improvements. We estimate that the increase in production volumes had a favorable impact to our ethanol segment margin of approximately $9 million.
|
•
|
Lower ethanol prices
. Ethanol prices were lower in the
second quarter
of
2018
compared to the
second quarter
of
2017
primarily due to a decrease in both export and domestic demand.
For example, the New York Harbor ethanol price was $1.56 per gallon for the
second quarter
of
2018
compared to $1.59 per gallon for the
second quarter
of
2017
, representing an unfavorable decrease of $0.03 per gallon. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of approximately $25 million.
|
•
|
Higher corn prices
. Corn prices were higher in the
second quarter
of
2018
compared to the
second quarter
of
2017
.
For example, the Chicago Board of Trade (CBOT) corn price was $3.83 per bushel for the
second quarter
of
2018
compared to $3.68 per bushel for the
second quarter
of
2017
, representing an unfavorable increase of $0.15 per bushel. We estimate that the increase in the price of corn had an unfavorable impact to our ethanol segment margin of approximately $10 million.
|
|
Six Months Ended June 30, 2018
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
Company |
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
55,691
|
|
|
$
|
1,761
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
57,454
|
|
Intersegment revenues
|
5
|
|
|
88
|
|
|
267
|
|
|
(360
|
)
|
|
—
|
|
|||||
Total revenues
|
55,696
|
|
|
1,849
|
|
|
267
|
|
|
(358
|
)
|
|
57,454
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other (a)
|
50,471
|
|
|
1,503
|
|
|
—
|
|
|
(358
|
)
|
|
51,616
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below)
|
1,966
|
|
|
220
|
|
|
62
|
|
|
(2
|
)
|
|
2,246
|
|
|||||
Depreciation and amortization expense
|
919
|
|
|
38
|
|
|
38
|
|
|
—
|
|
|
995
|
|
|||||
Total cost of sales
|
53,356
|
|
|
1,761
|
|
|
100
|
|
|
(360
|
)
|
|
54,857
|
|
|||||
Other operating expenses (c)
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below) (d)
|
—
|
|
|
—
|
|
|
—
|
|
|
486
|
|
|
486
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
26
|
|
|||||
Operating income by segment
|
$
|
2,309
|
|
|
$
|
88
|
|
|
$
|
167
|
|
|
$
|
(510
|
)
|
|
2,054
|
|
|
Other income, net (e)
|
|
|
|
|
|
|
|
|
46
|
|
|||||||||
Interest and debt expense, net of capitalized interest
|
|
|
|
|
|
|
|
|
(245
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
1,855
|
|
|||||||||
Income tax expense (f)
|
|
|
|
|
|
|
|
|
398
|
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
1,457
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests (a)
|
|
|
|
|
|
|
|
|
143
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
1,314
|
|
|
Six Months Ended June 30, 2017
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
Company |
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from external customers
|
$
|
42,302
|
|
|
$
|
1,724
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44,026
|
|
Intersegment revenues
|
—
|
|
|
88
|
|
|
216
|
|
|
(304
|
)
|
|
—
|
|
|||||
Total revenues
|
42,302
|
|
|
1,812
|
|
|
216
|
|
|
(304
|
)
|
|
44,026
|
|
|||||
Cost of sales:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
37,844
|
|
|
1,497
|
|
|
—
|
|
|
(304
|
)
|
|
39,037
|
|
|||||
Operating expenses (excluding depreciation and
amortization expense reflected below) (b)
|
1,970
|
|
|
216
|
|
|
51
|
|
|
(2
|
)
|
|
2,235
|
|
|||||
Depreciation and amortization expense
|
903
|
|
|
46
|
|
|
24
|
|
|
—
|
|
|
973
|
|
|||||
Total cost of sales
|
40,717
|
|
|
1,759
|
|
|
75
|
|
|
(306
|
)
|
|
42,245
|
|
|||||
General and administrative expenses (excluding
depreciation and amortization expense reflected
below) (b)
|
—
|
|
|
—
|
|
|
—
|
|
|
367
|
|
|
367
|
|
|||||
Depreciation and amortization expense
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
26
|
|
|||||
Operating income by segment
|
$
|
1,585
|
|
|
$
|
53
|
|
|
$
|
141
|
|
|
$
|
(391
|
)
|
|
1,388
|
|
|
Other income, net (b)
|
|
|
|
|
|
|
|
|
53
|
|
|||||||||
Interest and debt expense, net of capitalized interest
|
|
|
|
|
|
|
|
|
(240
|
)
|
|||||||||
Income before income tax expense
|
|
|
|
|
|
|
|
|
1,201
|
|
|||||||||
Income tax expense
|
|
|
|
|
|
|
|
|
308
|
|
|||||||||
Net income
|
|
|
|
|
|
|
|
|
893
|
|
|||||||||
Less: Net income attributable to noncontrolling
interests
|
|
|
|
|
|
|
|
|
40
|
|
|||||||||
Net income attributable to
Valero Energy Corporation stockholders
|
|
|
|
|
|
|
|
|
$
|
853
|
|
|
Six Months Ended June 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
|
$
|
1,314
|
|
|
$
|
853
|
|
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 (c)
|
(14
|
)
|
|
—
|
|
||
Income tax benefit related to Texas City Refinery fire expenses
|
3
|
|
|
—
|
|
||
Texas City Refinery fire expenses, net of taxes
|
(11
|
)
|
|
—
|
|
||
Environmental reserve adjustment (d)
|
(108
|
)
|
|
—
|
|
||
Income tax benefit related to the environmental reserve adjustment
|
24
|
|
|
—
|
|
||
Environmental reserve adjustment, 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
|
$
|
1,359
|
|
|
$
|
853
|
|
|
Six Months Ended June 30, 2018
|
||||||||||||||||||
|
Refining
|
|
Ethanol
|
|
VLP
|
|
Corporate
and Eliminations |
|
Total
Company |
||||||||||
Reconciliation of operating income to adjusted
operating income (g)
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating income by segment (see page 48)
|
$
|
2,309
|
|
|
$
|
88
|
|
|
$
|
167
|
|
|
$
|
(510
|
)
|
|
$
|
2,054
|
|
Exclude:
|
|
|
|
|
|
|
|
|
|
||||||||||
Blender’s tax credit (a)
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
170
|
|
|||||
Other operating expenses (c)
|
(31
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
|||||
Environmental reserve adjustment (d)
|
—
|
|
|
—
|
|
|
—
|
|
|
(108
|
)
|
|
(108
|
)
|
|||||
Adjusted operating income
|
$
|
2,170
|
|
|
$
|
88
|
|
|
$
|
167
|
|
|
$
|
(402
|
)
|
|
$
|
2,023
|
|
|
Six Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Throughput volumes (thousand BPD)
|
|
|
|
|
|
||||||
Feedstocks:
|
|
|
|
|
|
||||||
Heavy sour crude oil
|
482
|
|
|
483
|
|
|
(1
|
)
|
|||
Medium/light sour crude oil
|
421
|
|
|
482
|
|
|
(61
|
)
|
|||
Sweet crude oil
|
1,323
|
|
|
1,277
|
|
|
46
|
|
|||
Residuals
|
226
|
|
|
231
|
|
|
(5
|
)
|
|||
Other feedstocks
|
121
|
|
|
145
|
|
|
(24
|
)
|
|||
Total feedstocks
|
2,573
|
|
|
2,618
|
|
|
(45
|
)
|
|||
Blendstocks and other
|
342
|
|
|
311
|
|
|
31
|
|
|||
Total throughput volumes
|
2,915
|
|
|
2,929
|
|
|
(14
|
)
|
|||
|
|
|
|
|
|
||||||
Yields (thousand BPD)
|
|
|
|
|
|
||||||
Gasolines and blendstocks
|
1,404
|
|
|
1,409
|
|
|
(5
|
)
|
|||
Distillates
|
1,102
|
|
|
1,129
|
|
|
(27
|
)
|
|||
Other products (h)
|
446
|
|
|
429
|
|
|
17
|
|
|||
Total yields
|
2,952
|
|
|
2,967
|
|
|
(15
|
)
|
|||
|
|
|
|
|
|
||||||
Operating statistics (i)
|
|
|
|
|
|
||||||
Refining margin (g)
|
$
|
5,055
|
|
|
$
|
4,458
|
|
|
$
|
597
|
|
Adjusted refining operating income (see page 50) (g)
|
$
|
2,170
|
|
|
$
|
1,585
|
|
|
$
|
585
|
|
Throughput volumes (thousand BPD)
|
2,915
|
|
|
2,929
|
|
|
(14
|
)
|
|||
|
|
|
|
|
|
||||||
Refining margin per barrel of throughput
|
$
|
9.58
|
|
|
$
|
8.41
|
|
|
$
|
1.17
|
|
Less:
|
|
|
|
|
|
||||||
Operating expenses (excluding depreciation and
amortization expense reflected below) per barrel of throughput (b)
|
3.73
|
|
|
3.72
|
|
|
0.01
|
|
|||
Depreciation and amortization expense per barrel of
throughput
|
1.74
|
|
|
1.70
|
|
|
0.04
|
|
|||
Adjusted refining operating income per barrel of throughput
|
$
|
4.11
|
|
|
$
|
2.99
|
|
|
$
|
1.12
|
|
|
Six Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Operating statistics (i)
|
|
|
|
|
|
||||||
Ethanol margin (g)
|
$
|
346
|
|
|
$
|
315
|
|
|
$
|
31
|
|
Ethanol operating income
|
$
|
88
|
|
|
$
|
53
|
|
|
$
|
35
|
|
Production volumes (thousand gallons per day)
|
4,057
|
|
|
3,908
|
|
|
149
|
|
|||
|
|
|
|
|
|
||||||
Ethanol margin per gallon of production
|
$
|
0.47
|
|
|
$
|
0.45
|
|
|
$
|
0.02
|
|
Less:
|
|
|
|
|
|
||||||
Operating expenses (excluding depreciation and
amortization reflected below) per gallon of production
|
0.30
|
|
|
0.31
|
|
|
(0.01
|
)
|
|||
Depreciation and amortization expense per gallon of
production
|
0.05
|
|
|
0.06
|
|
|
(0.01
|
)
|
|||
Ethanol operating income per gallon of production
|
$
|
0.12
|
|
|
$
|
0.08
|
|
|
$
|
0.04
|
|
|
Six Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Operating statistics (i)
|
|
|
|
|
|
||||||
Pipeline transportation revenue
|
62
|
|
|
48
|
|
|
$
|
14
|
|
||
Terminaling revenue
|
202
|
|
|
167
|
|
|
35
|
|
|||
Storage and other revenue
|
3
|
|
|
1
|
|
|
2
|
|
|||
Total VLP revenues
|
$
|
267
|
|
|
$
|
216
|
|
|
$
|
51
|
|
|
|
|
|
|
|
||||||
Pipeline transportation throughput (thousand BPD)
|
1,047
|
|
|
983
|
|
|
64
|
|
|||
Pipeline transportation revenue per barrel of throughput
|
$
|
0.33
|
|
|
$
|
0.27
|
|
|
$
|
0.06
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
||||||
Terminaling throughput (thousand BPD)
|
3,479
|
|
|
2,794
|
|
|
685
|
|
|||
Terminaling revenue per barrel of throughput
|
$
|
0.32
|
|
|
$
|
0.33
|
|
|
$
|
(0.01
|
)
|
|
Six Months Ended June 30,
|
||||||||||
|
2018
|
|
2017
|
|
Change
|
||||||
Feedstocks (dollars per barrel)
|
|
|
|
|
|
||||||
Brent crude oil
|
$
|
71.05
|
|
|
$
|
52.78
|
|
|
$
|
18.27
|
|
Brent less WTI crude oil
|
5.61
|
|
|
2.74
|
|
|
2.87
|
|
|||
Brent less ANS crude oil
|
0.52
|
|
|
0.52
|
|
|
—
|
|
|||
Brent less LLS crude oil
|
1.66
|
|
|
0.86
|
|
|
0.80
|
|
|||
Brent less ASCI crude oil
|
5.26
|
|
|
4.50
|
|
|
0.76
|
|
|||
Brent less Maya crude oil
|
11.18
|
|
|
8.48
|
|
|
2.70
|
|
|||
LLS crude oil
|
69.39
|
|
|
51.92
|
|
|
17.47
|
|
|||
LLS less ASCI crude oil
|
3.60
|
|
|
3.64
|
|
|
(0.04
|
)
|
|||
LLS less Maya crude oil
|
9.52
|
|
|
7.62
|
|
|
1.90
|
|
|||
WTI crude oil
|
65.44
|
|
|
50.04
|
|
|
15.40
|
|
|||
|
|
|
|
|
|
|
|||||
Natural gas (dollars per MMBtu)
|
3.04
|
|
|
3.05
|
|
|
(0.01
|
)
|
|||
|
|
|
|
|
|
|
|||||
Products (dollars per barrel, unless otherwise noted)
|
|
|
|
|
|
|
|||||
U.S. Gulf Coast:
|
|
|
|
|
|
|
|||||
CBOB gasoline less Brent
|
7.38
|
|
|
9.58
|
|
|
(2.20
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
13.62
|
|
|
11.06
|
|
|
2.56
|
|
|||
Propylene less Brent
|
(6.68
|
)
|
|
0.63
|
|
|
(7.31
|
)
|
|||
CBOB gasoline less LLS
|
9.04
|
|
|
10.44
|
|
|
(1.40
|
)
|
|||
Ultra-low-sulfur diesel less LLS
|
15.28
|
|
|
11.92
|
|
|
3.36
|
|
|||
Propylene less LLS
|
(5.02
|
)
|
|
1.49
|
|
|
(6.51
|
)
|
|||
U.S. Mid-Continent:
|
|
|
|
|
|
|
|||||
CBOB gasoline less WTI
|
14.76
|
|
|
13.44
|
|
|
1.32
|
|
|||
Ultra-low-sulfur diesel less WTI
|
20.93
|
|
|
14.30
|
|
|
6.63
|
|
|||
North Atlantic:
|
|
|
|
|
|
|
|||||
CBOB gasoline less Brent
|
9.63
|
|
|
10.63
|
|
|
(1.00
|
)
|
|||
Ultra-low-sulfur diesel less Brent
|
15.60
|
|
|
12.14
|
|
|
3.46
|
|
|||
U.S. West Coast:
|
|
|
|
|
|
|
|||||
CARBOB 87 gasoline less ANS
|
15.82
|
|
|
19.89
|
|
|
(4.07
|
)
|
|||
CARB diesel less ANS
|
17.99
|
|
|
14.58
|
|
|
3.41
|
|
|||
CARBOB 87 gasoline less WTI
|
20.91
|
|
|
22.11
|
|
|
(1.20
|
)
|
|||
CARB diesel less WTI
|
23.08
|
|
|
16.80
|
|
|
6.28
|
|
|||
New York Harbor corn crush (dollars per gallon)
|
0.18
|
|
|
0.26
|
|
|
(0.08
|
)
|
(a)
|
Cost of materials and other for the six months ended June 30, 2018 includes a benefit of $170 million for 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 includes $80 million attributable to noncontrolling interest and $90 million attributable to Valero Energy Corporation stockholders.
|
(b)
|
Effective January 1, 2018, we adopted the provisions of ASU No. 2017-07 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 (expense), net. This resulted in an increase of $14 million and $21 million in operating expenses (excluding depreciation and amortization expense) and a decrease of $3 million and $1 million in general and administrative expenses (excluding depreciation and amortization expense) for the three and six months ended June 30, 2017, respectively.
|
(c)
|
Other operating expenses reflects expenses that are not associated with our cost of sales. Other operating expenses for the three and six months ended June 30, 2018 includes $14 million of costs to respond to and assess the damage caused by a fire in the alkylation unit at our Texas City Refinery on April 19, 2018. In addition, other operating expenses for the three and six months ended June 30, 2018 includes repair costs incurred at certain of our refineries due to damage associated with inclement weather events in 2018 and Hurricane Harvey in 2017.
|
(d)
|
General and administrative expenses (excluding depreciation and amortization expense) for the three and six months ended June 30, 2018 includes a charge of $56 million and $108 million, respectively, for an environmental reserve adjustment associated with certain non-operating sites.
|
(e)
|
Other income (expense), net for the three and six months ended June 30, 2018 includes a $38 million charge composed of the early redemption fee of $37 million on our 9.375 percent Senior Notes and the write-off of $1 million of unamortized debt issuance costs.
|
(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 six months ended June 30, 2018 are now taxed at 21 percent, resulting in a lower effective tax rate compared to the three and six months ended June 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.
|
◦
|
Adjusted net income attributable to Valero Energy Corporation stockholders
is defined as net 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
|
▪
|
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 (see note (c)) are specific to that event and are not ongoing costs incurred in our operations.
|
▪
|
Environmental reserve adjustment –
The environmental reserve adjustment is 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 9.375
percent Senior Notes (see note (e)) are not associated with the ongoing costs of our borrowing and financing activities.
|
◦
|
Refining margin
is defined as refining operating income excluding the blender’s tax credit (see note (a)), operating expenses (excluding depreciation and amortization expense), other operating expenses, and depreciation and amortization expense, as reflected below.
|
◦
|
Ethanol margin
is defined as ethanol operating income excluding operating expenses (excluding depreciation and amortization expense) and depreciation and amortization expense, as reflected below.
|
|
Three Months Ended June 30,
|
||||||||||||||
|
2018
|
|
2017
|
||||||||||||
|
Refining
|
|
Ethanol
|
|
Refining
|
|
Ethanol
|
||||||||
Reconciliation of operating income
to segment margin
|
|
|
|
|
|
|
|
||||||||
Operating income
|
$
|
1,387
|
|
|
$
|
43
|
|
|
$
|
945
|
|
|
$
|
31
|
|
Exclude:
|
|
|
|
|
|
|
|
||||||||
Operating expenses (excluding depreciation
and amortization expense reflected below) (b)
|
(969
|
)
|
|
(109
|
)
|
|
(979
|
)
|
|
(107
|
)
|
||||
Depreciation and amortization expense
|
(471
|
)
|
|
(20
|
)
|
|
(454
|
)
|
|
(19
|
)
|
||||
Other operating expenses (c)
|
(21
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Segment margin
|
$
|
2,848
|
|
|
$
|
172
|
|
|
$
|
2,378
|
|
|
$
|
157
|
|
|
Six Months Ended June 30,
|
||||||||||||||
|
2018
|
|
2017
|
||||||||||||
|
Refining
|
|
Ethanol
|
|
Refining
|
|
Ethanol
|
||||||||
Reconciliation of operating income
to segment margin
|
|
|
|
|
|
|
|
||||||||
Operating income
|
$
|
2,309
|
|
|
$
|
88
|
|
|
$
|
1,585
|
|
|
$
|
53
|
|
Exclude:
|
|
|
|
|
|
|
|
||||||||
Blender’s tax credit (a)
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Operating expenses (excluding depreciation
and amortization expense reflected below) (b)
|
(1,966
|
)
|
|
(220
|
)
|
|
(1,970
|
)
|
|
(216
|
)
|
||||
Depreciation and amortization expense
|
(919
|
)
|
|
(38
|
)
|
|
(903
|
)
|
|
(46
|
)
|
||||
Other operating expenses (c)
|
(31
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Segment margin
|
$
|
5,055
|
|
|
$
|
346
|
|
|
$
|
4,458
|
|
|
$
|
315
|
|
◦
|
Adjusted refining operating income
is defined as refining operating income excluding the 2017 blender’s tax credit received in 2018 (see note (a)) and other operating expenses.
|
◦
|
Adjusted corporate and eliminations
is defined as corporate and eliminations excluding the environmental reserve adjustment associated with certain non-operating sites (see note (d)).
|
(h)
|
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.
|
(i)
|
Valero uses certain operating statistics (as noted below) to evaluate performance between comparable periods. Different companies may calculate them in different ways.
|
•
|
Increase in distillate margins
. We experienced improved distillate margins throughout all our regions during the first
six
months of
2018
compared to the first
six
months of
2017
. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was
$13.62
per barrel for the first
six
months of
2018
compared to
$11.06
per barrel for the first
six
months of
2017
, representing a favorable increase of
$2.56
per barrel. Another example is the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel, which was
$20.93
per barrel for the first
six
months of
2018
compared to
$14.30
per barrel for the first
six
months of
2017
, representing a favorable increase of
$6.63
per barrel. We estimate that the increase in distillate margins per barrel in the first
six
months of
2018
compared to the first
six
months of
2017
had a favorable impact to our refining segment margin of approximately $817 million.
|
•
|
Higher 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. We benefitted from processing these types of feedstocks during the first
six
months of
2018
and that benefit improved compared to the first
six
months of
2017
. We estimate that the increase in the discounts for the other feedstocks that we processed during the first
six
months of
2018
compared to the first
six
months of
2017
had a favorable impact to our refining segment margin of approximately $160 million.
|
•
|
Lower costs of biofuel credits.
As more fully described in
Note 14
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 $64 million from
$401 million
for the first
six
months of
2017
to
$337 million
for the first
six
months of
2018
.
|
•
|
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 first
six
months of
2018
and that benefit improved compared to the first
six
months of
2017
. For example, WTI crude oil, a light sweet crude oil processed in our U.S. Mid-Continent region, sold at a discount to Brent crude oil of
$5.61
per barrel for the first six months of 2018 compared to a discount of
$2.74
per barrel for the first six months of 2017, representing a favorable increase of
$2.87
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
$11.18
per barrel for the first six months of 2018 compared to a discount of
$8.48
per barrel for the first six months of 2017, representing a favorable increase of
$2.70
per barrel. We estimate that the increase in the discounts for crude oils
|
•
|
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
six
months of
2018
compared to the first
six
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
$71.05
per barrel for the first
six
months of
2018
compared to
$52.78
per barrel for the first
six
months of
2017
, representing an unfavorable increase of
$18.27
per barrel. We estimate that the decrease in other products margins for the first
six
months of
2018
compared to the first
six
months of
2017
had an unfavorable impact to our refining segment margin of approximately $384 million.
|
•
|
Decrease in gasoline margins.
We experienced a decrease in gasoline margins during the first
six
months of
2018
compared to the first
six
months of
2017
. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was
$7.38
per barrel for the first
six
months of
2018
compared to
$9.58
per barrel for the first
six
months of
2017
, representing an unfavorable decrease of
$2.20
per barrel. Another example is the ANS-based benchmark reference margin for U.S. West Coast CARBOB 87 gasoline, which was
$15.82
per barrel for the first
six
months of
2018
compared to
$19.89
per barrel for the first
six
months of
2017
, representing an unfavorable decrease of
$4.07
per barrel. We estimate that the decrease in gasoline margins per barrel in the first
six
months of
2018
compared to the first
six
months of
2017
had an unfavorable impact to our refining segment margin of approximately $145 million.
|
•
|
Increase in charges from VLP.
Charges from the VLP segment for transportation and terminaling services increased $51 million in the first
six
months of
2018
compared to the first
six
months 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. Details regarding the increase in charges from VLP are discussed in the VLP segment analysis below.
|
•
|
Higher co-product prices.
An increase in export demand for corn related co-products, primarily distillers grains, had a favorable effect on the prices received. We estimate that the increase in corn
|
•
|
Higher production volumes.
Ethanol segment margin was favorably impacted by increased production volumes of
149,000
gallons per day in the first
six
months of
2018
compared to the first
six
months of
2017
primarily due to reliability improvements. We estimate that the increase in production volumes had a favorable impact to our ethanol segment margin of $14 million.
|
•
|
Lower ethanol prices.
Ethanol prices were lower in the first
six
months of
2018
compared to the first
six
months of
2017
primarily due to a decrease in both export and domestic demand. For example, the New York Harbor ethanol price was $1.54 per gallon for the first
six
months of
2018
compared to $1.59 per gallon for the first
six
months of
2017
, representing an unfavorable decrease of $0.05 per gallon. We estimate that the decrease in the price of ethanol had an unfavorable impact to our ethanol segment margin of $45 million.
|
•
|
Higher corn prices.
Corn prices were higher in the first
six
months of 2018 compared to the first
six
months of
2017
. For example, the CBOT corn price was $3.75 per bushel for the first
six
months of
2018
compared to $3.66 per bushel for the first
six
months of
2017
, representing an unfavorable increase of $0.09 per bushel. We estimate that the increase in the price of corn had an unfavorable impact to our ethanol segment margin of $13 million.
|
(a)
|
Excludes
$283 million
of cash and cash equivalents related to our VIEs that is available for use only by our VIEs.
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Cash flows provided by (used in):
|
|
|
|
||||
Operating activities
|
$
|
2,197
|
|
|
$
|
2,785
|
|
Investing activities
|
(2,132
|
)
|
|
(1,174
|
)
|
||
Financing activities
|
(1,402
|
)
|
|
(1,328
|
)
|
||
Effect of foreign exchange rate changes on cash
|
(62
|
)
|
|
108
|
|
||
Net increase (decrease) in cash and cash equivalents
|
$
|
(1,399
|
)
|
|
$
|
391
|
|
•
|
fund
$1.3 billion
in capital investments, which include capital expenditures, deferred turnaround and catalyst costs, and investments in joint ventures;
|
•
|
fund
$562 million
for the Peru Acquisition and other minor acquisitions;
|
•
|
acquire undivided interests in pipeline and terminal assets for
$145 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 $421 million, of which
$410 million
related to the repayment of all outstanding borrowings under the VLP Revolver;
|
•
|
retire $137 million of debt assumed in connection with the Peru Acquisition;
|
•
|
purchase common stock for treasury of
$647 million
; and
|
•
|
pay common stock dividends of
$690 million
.
|
•
|
a decrease in receivables, partially offset by a decrease in accounts payable, primarily as a result of the timing of collections of receivables and payments of invoices, respectively, combined with a decrease in commodity prices;
|
•
|
an increase in accrued expenses mainly due to the timing of payments on our environmental compliance program obligations; and
|
•
|
a decrease in inventory volumes held.
|
•
|
fund
$1.1 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
$660 million
;
|
•
|
pay common stock dividends of
$627 million
;
|
•
|
pay distributions to noncontrolling interests of
$45 million
; and
|
•
|
increase available cash on hand by
$391 million
.
|
|
|
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)
|
ITEM 3.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
•
|
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.
|
|
June 30, 2018
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
There-
after
|
|
Total (a)
|
|
Fair
Value
|
||||||||||||||||
Fixed rate
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
850
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
7,474
|
|
|
$
|
8,334
|
|
|
$
|
9,110
|
|
Average interest rate
|
—
|
%
|
|
—
|
%
|
|
6.1
|
%
|
|
5.0
|
%
|
|
—
|
%
|
|
5.4
|
%
|
|
5.5
|
%
|
|
|
|||||||||
Floating rate (b)
|
$
|
159
|
|
|
$
|
5
|
|
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
6
|
|
|
$
|
19
|
|
|
$
|
200
|
|
|
$
|
200
|
|
Average interest rate
|
3.9
|
%
|
|
4.2
|
%
|
|
4.2
|
%
|
|
4.2
|
%
|
|
4.2
|
%
|
|
4.2
|
%
|
|
3.9
|
%
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
|
December 31, 2017
|
||||||||||||||||||||||||||||||
|
Expected Maturity Dates
|
|
|
|
|
||||||||||||||||||||||||||
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
There-
after
|
|
Total (a)
|
|
Fair
Value
|
||||||||||||||||
Fixed rate
|
$
|
—
|
|
|
$
|
750
|
|
|
$
|
850
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,224
|
|
|
$
|
7,824
|
|
|
$
|
9,236
|
|
Average interest rate
|
—
|
%
|
|
9.4
|
%
|
|
6.1
|
%
|
|
—
|
%
|
|
—
|
%
|
|
5.6
|
%
|
|
6.0
|
%
|
|
|
|||||||||
Floating rate (b)
|
$
|
106
|
|
|
$
|
6
|
|
|
$
|
416
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
19
|
|
|
$
|
559
|
|
|
$
|
559
|
|
Average interest rate
|
2.1
|
%
|
|
3.8
|
%
|
|
2.9
|
%
|
|
3.8
|
%
|
|
3.8
|
%
|
|
3.8
|
%
|
|
2.8
|
%
|
|
|
(a)
|
Excludes unamortized discounts and debt issuance costs.
|
(b)
|
As of
June 30, 2018
and
December 31, 2017
, we had an interest rate swap associated with $44 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.
|
ITEM 4.
|
CONTROLS AND PROCEDURES
|
(a)
|
Evaluation of disclosure controls and procedures.
|
(b)
|
Changes in internal control over financial reporting.
|
ITEM 1.
|
LEGAL PROCEEDINGS
|
ITEM 1A.
|
RISK FACTORS
|
ITEM 2.
|
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
|
(a)
|
Unregistered Sales of Equity Securities
. Not applicable.
|
(b)
|
Use of Proceeds
. Not applicable.
|
(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
second quarter
of
2018
.
|
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)
|
|||||
April 2018
|
|
46,946
|
|
|
$
|
108.23
|
|
|
46,946
|
|
|
—
|
|
|
$3.5 billion
|
May 2018
|
|
779,733
|
|
|
$
|
116.23
|
|
|
601,552
|
|
|
178,181
|
|
|
$3.4 billion
|
June 2018
|
|
1,969,635
|
|
|
$
|
117.34
|
|
|
1,176
|
|
|
1,968,459
|
|
|
$3.2 billion
|
Total
|
|
2,796,314
|
|
|
$
|
116.88
|
|
|
649,674
|
|
|
2,146,640
|
|
|
$3.2 billion
|
(a)
|
The shares reported in this column represent purchases settled in the
second quarter
of
2018
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.
|
(b)
|
On
January 23, 2018
, we announced that our board of directors authorized our purchase of up to
$2.5 billion
of our outstanding common stock, with no expiration date, which was in addition to the remaining amount available under a
$2.5 billion
program authorized on
September 21, 2016
. As of
June 30, 2018
, the approximate dollar value of shares that may yet be purchased under the 2016 program is
$712 million
and no purchases have been made under the 2018 program.
|
ITEM 6.
|
EXHIBITS
|
Exhibit
No.
|
|
Description
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
***101
|
|
Interactive Data Files
|
*
|
Filed herewith.
|
**
|
Furnished herewith.
|
***
|
Submitted electronically herewith.
|
|
|
|
|
|
|
VALERO ENERGY CORPORATION
(Registrant)
|
|
|
By:
|
/s/ Donna M. Titzman
|
|
|
|
Donna M. Titzman
|
|
|
|
Executive Vice President and
|
|
|
|
Chief Financial Officer
|
|
|
|
(Duly Authorized Officer and Principal
|
|
|
|
Financial and Accounting Officer)
|
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