Delek US Holdings, Inc. (Form: 10-Q, Received: 11/08/2019 06:09:28)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)



☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the quarterly period ended	September 30, 2019



☐		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to

Commission file number 001-38142

DELEK US HOLDINGS, INC.

(Exact name of registrant as specified in its charter)



Delaware			35-2581557
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

7102 Commerce Way	Brentwood	Tennessee	37027
(Address of principal executive offices)			(Zip Code)

(615) 771-6701

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer	☑	Accelerated filer	☐	Non-accelerated filer	☐	Smaller reporting company	☐	Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, par value $0.01	DK	New York Stock Exchange

At November 1, 2019, there were 74,235,210 shares of common stock, $0.01 par value, outstanding (excluding securities held by, or for the account of, the Company or its subsidiaries).

Table of Contents

Delek US Holdings, Inc.

Quarterly Report on Form 10-Q

For the Quarterly Period Ended September 30, 2019



PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)	3
Condensed Consolidated Balance Sheets	3
Condensed Consolidated Statements of Income	4
Condensed Consolidated Statements of Comprehensive Income	5
Condensed Consolidated Statement of Changes in Stockholders' Equity	6
Condensed Consolidated Statements of Cash Flows	10
Notes to Condensed Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3. Quantitative and Qualitative Disclosures about Market Risk	74
Item 4. Controls and Procedures	76

PART II. OTHER INFORMATION
Item 1. Legal Proceedings	77
Item 1A. Risk Factors	77
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	77
Item 5. Other Information	77
Item 6. Exhibits	78
Signatures	79



2 \|

Financial Statements

Part I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Delek US Holdings, Inc.

Condensed Consolidated Balance Sheets (Unaudited)

(In millions, except share and per share data)



	September 30, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	1,006.4		$	1,079.3
Accounts receivable, net	834.3			514.4
Inventories, net of inventory valuation reserves	908.6			690.9
Other current assets	115.1			135.7
Total current assets	2,864.4			2,420.3
Property, plant and equipment:
Property, plant and equipment	3,309.9			2,999.6
Less: accumulated depreciation	(944.7		)	(804.7		)
Property, plant and equipment, net	2,365.2			2,194.9
Operating lease right-of-use assets	187.6			—
Goodwill	856.6			857.8
Other intangibles, net	92.9			104.4
Equity method investments	360.2			130.3
Other non-current assets	66.4			52.9
Total assets	$	6,793.3		$	5,760.6
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,364.5		$	1,011.2
Current portion of long-term debt	64.5			32.0
Obligation under Supply and Offtake Agreements	265.0			312.6
Current portion of operating lease liabilities	45.1			—
Accrued expenses and other current liabilities	487.6			307.7
Total current liabilities	2,226.7			1,663.5
Non-current liabilities:
Long-term debt, net of current portion	1,935.4			1,751.3
Obligation under Supply and Offtake Agreements	143.6			49.6
Environmental liabilities, net of current portion	139.1			139.5
Asset retirement obligations	70.3			75.5
Deferred tax liabilities	232.1			210.2
Operating lease liabilities, net of current portion	144.2			—
Other non-current liabilities	38.5			62.9
Total non-current liabilities	2,703.2			2,289.0
Stockholders’ equity:
Preferred stock, $0.01 par value, 10,000,000 shares authorized, no shares issued and outstanding	—			—
Common stock, $0.01 par value, 110,000,000 shares authorized, 90,940,393 shares and 90,478,075 shares issued at September 30, 2019 and December 31, 2018, respectively	0.9			0.9
Additional paid-in capital	1,146.1			1,135.4
Accumulated other comprehensive income	10.7			28.6
Treasury stock, 16,653,356 shares and 12,477,780 shares, at cost, as of September 30, 2019 and December 31, 2018, respectively	(661.9		)	(514.1		)
Retained earnings	1,195.3			981.8
Non-controlling interests in subsidiaries	172.3			175.5
Total stockholders’ equity	1,863.4			1,808.1
Total liabilities and stockholders’ equity	$	6,793.3		$	5,760.6

See accompanying notes to condensed consolidated financial statements



3 \|

Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Income (Unaudited)

(In millions, except share and per share)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018 ⁽¹⁾			2019			2018 ^(1),(2)
Net revenues	$	2,334.3		$	2,768.9		$	7,014.5		$	7,759.0
Cost of sales:
Cost of materials and other	1,964.1			2,244.2			5,731.2			6,537.2
Operating expenses (excluding depreciation and amortization presented below)	141.7			136.4			418.4			400.7
Depreciation and amortization	43.8			41.2			125.7			119.3
Total cost of sales	2,149.6			2,421.8			6,275.3			7,057.2
Operating expenses related to retail and wholesale business (excluding depreciation and amortization presented below)	25.2			27.6			77.5			78.9
General and administrative expenses	65.6			58.0			197.3			176.1
Depreciation and amortization	6.0			8.0			21.0			27.1
Other operating expense (income), net	0.5			(1.7		)	(0.7		)	(9.4		)
Total operating costs and expenses	2,246.9			2,513.7			6,570.4			7,329.9
Operating income	87.4			255.2			444.1			429.1
Interest expense	33.9			31.2			95.4			95.2
Interest income	(3.2		)	(1.4		)	(9.0		)	(3.0		)
Income from equity method investments	(16.5		)	(4.0		)	(28.4		)	(6.9		)
Gain on sale of business	—			—			—			(13.2		)
Impairment loss on assets held for sale	—			—			—			27.5
Loss on extinguishment of debt	—			0.1			—			9.1
Other (income) expense, net	(0.2		)	(7.5		)	3.3			(7.9		)
Total non-operating expenses, net	14.0			18.4			61.3			100.8
Income from continuing operations before income tax expense	73.4			236.8			382.8			328.3
Income tax expense	13.4			51.0			83.8			72.3
Income from continuing operations, net of tax	60.0			185.8			299.0			256.0
Discontinued operations:
Income (loss) from discontinued operations, including gain (loss) on sale of discontinued operations	—			0.8			(1.0		)	(10.7		)
Income tax expense (benefit)	—			0.3			(0.2		)	(2.2		)
Income (loss) from discontinued operations, net of tax	—			0.5			(0.8		)	(8.5		)
Net income	60.0			186.3			298.2			247.5
Net income attributed to non-controlling interests	8.7			6.5			20.3			29.0
Net income attributable to Delek	$	51.3		$	179.8		$	277.9		$	218.5
Basic income (loss) per share:
Income from continuing operations	$	0.68		$	2.15		$	3.64		$	2.82
Income (loss) from discontinued operations	—			$	0.01		(0.01		)	(0.20		)
Total basic income per share	$	0.68		$	2.16		$	3.63		$	2.62
Diluted income (loss) per share:
Income from continuing operations	$	0.68		$	2.02		$	3.61		$	2.69
Income (loss) from discontinued operations	—			0.01			(0.01		)	(0.19		)
Total diluted income per share	$	0.68		$	2.03		$	3.60		$	2.50
Dividends declared per common share outstanding	$	0.29		$	0.25		$	0.84		$	0.70

⁽¹⁾

Net revenues and cost of materials and other for the three and nine months ended September 30, 2018 reflect a correction of an intercompany elimination which resulted in an increase in those accounts of $273.7 million and $347.1 million, respectively, not previously reflected on the unaudited consolidated financial statements in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 9, 2018. Such amounts are not considered material to the financial statements and had no impact to operating income or net income for those periods. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.

⁽²⁾

Income tax expense for the nine months ended September 30, 2018 reflects a correction made in our 2018 Annual Report on Form 10-K (as originally filed on March 1, 2019) to record additional deferred tax expense totaling $5.5 million related to the recognition of a valuation allowance on deferred tax assets recognized in connection with the Big Spring Logistic Assets Acquisition (see Note 5) not previously reported in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 09, 2018. Such amount is not considered material to the financial statements or the trend of earnings for that period. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.

See accompanying notes to condensed consolidated financial statements



4 \|

Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

(In millions)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018 ⁽¹⁾
Net income attributable to Delek	$	51.3		$	179.8		$	277.9		$	218.5
Other comprehensive income (loss):
Commodity contracts designated as cash flow hedges:
Net (losses) gains related to commodity cash flow hedges	(19.8		)	52.7			(23.2		)	(10.5		)
Income tax benefit (expense)	4.1			(11.0		)	4.8			2.3
Net comprehensive (loss) income on commodity contracts designated as cash flow hedges	(15.7		)	41.7			(18.4		)	(8.2		)

Loss on interest rate contracts designated as cash flow hedges, net of taxes	—			—			—			(0.5		)

Foreign currency translation gain (loss), net of taxes	—			0.2			0.1			(0.4		)

Postretirement benefit plans:
Unrealized gain arising during the year related to:
Net actuarial gain	—			8.9			—			9.0
Curtailment and settlement gains	—			2.4			—			2.5
Reclassified to other expense (income), net:
Gain recognized due to curtailment and settlement	—			(2.4		)	—			(2.5		)
Amortization of net actuarial loss	0.2			—			0.5			—
Gains related to postretirement benefit plans, net	0.2			8.9			0.5			9.0
Income tax expense	(0.1		)	(2.0		)	(0.1		)	(2.0		)
Net comprehensive income on postretirement benefit plans, net of taxes	0.1			6.9			0.4			7.0
Total other comprehensive (loss) income	(15.6		)	48.8			(17.9		)	(2.1		)
Comprehensive income attributable to Delek	$	35.7		$	228.6		$	260.0		$	216.4

⁽¹⁾

Net income attributable to Delek and Comprehensive income attributable to Delek for the nine months ended September 30, 2018 reflects a correction made in our 2018 Annual Report on Form 10-K (as originally filed on March 1, 2019) to reduce both amounts for additional deferred tax expense totaling $5.5 million related to the recognition of a valuation allowance on deferred tax assets recognized in connection with the Big Spring Logistic Assets Acquisition (see Note 5) not previously reported in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 09, 2018. Such amount is not considered material to the financial statements or the trend of earnings for that period. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.

See accompanying notes to condensed consolidated financial statements



5 \|

Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Changes in Stockholders' Equity (Unaudited)

(In millions, except share and per share data)



		Three Months Ended September 30, 2019
		Common Stock			Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Treasury Stock					Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
		Shares	Amount		Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Shares		Amount			Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
Balance at	June 30, 2019	90,861,698	$	0.9	$	1,140.3		$	26.3		$	1,165.9		(15,416,502	)	$	(618.9	)	$	171.7		$	1,886.2
Net income		—	—		—			—			51.3			—		—			8.7			60.0
Other comprehensive loss related to commodity contracts, net		—	—		—			(15.7		)	—			—		—			—			(15.7		)
Other comprehensive income related to postretirement benefit plans, net		—	—		—			0.1			—			—		—			—			0.1
Common stock dividends ($0.29 per share)		—	—		—			—			(21.8		)	—		—			—			(21.8		)
Distributions to non-controlling interests		—	—		—			—			—			—		—			(8.2		)	(8.2		)
Equity-based compensation expense		—	—		7.3			—			—			—		—			0.1			7.4
Repurchase of common stock		—	—		—			—			—			(1,236,854	)	(43.0		)	—			(43.0		)
Taxes paid due to the net settlement of equity-based compensation		—	—		(1.5		)	—			—			—		—			—			(1.5		)
Exercise of equity-based awards		78,695	—		—			—			—			—		—			—			—
Other		—	—		—			—			(0.1		)	—		—			—			(0.1		)
Balance at	September 30, 2019	90,940,393	$	0.9	$	1,146.1		$	10.7		$	1,195.3		(16,653,356	)	$	(661.9	)	$	172.3		$	1,863.4



6 \|

Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Changes in Stockholders' Equity (Unaudited)

(In millions, except share and per share data)



		Three Months Ended September 30, 2018
		Common Stock			Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Treasury Stock					Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
		Shares	Amount		Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Shares		Amount			Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
Balance at	June 30, 2018	87,631,115	$	0.9	$	1,041.8		$	(42.4	)	$	722.8		(3,703,826	)	$	(140.3	)	$	176.5		$	1,759.3
Net income		—	—		—			—			179.8			—		—			6.5			186.3
Other comprehensive income related to commodity contracts, net		—	—		—			41.7			—			—		—			—			41.7
Other comprehensive income related to postretirement benefit plans, net		—	—		—			6.9			—			—		—			—			6.9
Foreign currency translation gain, net		—	—		—			0.2			—			—		—			—			0.2
Common stock dividends ($0.25 per share)		—	—		—			—			(21.0		)	—		—			—			(21.0		)
Distribution to non-controlling interest		—	—		—			—			—			—		—			(7.4		)	(7.4		)
Equity-based compensation expense		—	—		5.1			—			—			—		—			0.1			5.2
Shares issued in connection with settlement of Convertible Notes		2,692,218	—		(0.3		)	—			—			—		—			—			(0.3		)
Shares received in connection with exercise of Call Options		—	—		124.2			—			—			(2,692,771	)	(123.9		)	—			0.3
Repurchase of common stock		—	—		—			—			—			(1,906,308	)	(92.1		)	—			(92.1		)
Taxes paid due to the net settlement of equity-based compensation		—	—		(2.0		)	—			—			—		—			—			(2.0		)
Exercise of equity-based awards		109,159	—		—			—			—			—		—			—			—
Other		—	—		—			—			(0.1		)	—		—			0.1			—
Balance at	September 30, 2018	90,432,492	$	0.9	$	1,168.8		$	6.4		$	881.5		(8,302,905	)	$	(356.3	)	$	175.8		$	1,877.1



7 \|

Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Changes in Stockholders' Equity (Unaudited)

(In millions, except share and per share data)



		Nine Months Ended September 30, 2019
		Common Stock			Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Treasury Stock					Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
		Shares	Amount		Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Shares		Amount			Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
Balance at	December 31, 2018	90,478,075	$	0.9	$	1,135.4		$	28.6		$	981.8		(12,477,780	)	$	(514.1	)	$	175.5		$	1,808.1
Net income		—	—		—			—			277.9			—		—			20.3			298.2
Other comprehensive loss related to commodity contracts, net		—	—		—			(18.4		)	—			—		—			—			(18.4		)
Other comprehensive income related to postretirement benefit plans, net		—	—		—			0.4			—			—		—			—			0.4
Foreign currency translation gain, net		—	—		—			0.1			—			—		—			—			0.1
Common stock dividends ($0.84 per share)		—	—		—			—			(64.3		)	—		—			—			(64.3		)
Distributions to non-controlling interests		—	—		—			—			—			—		—			(23.8		)	(23.8		)
Equity-based compensation expense		—	—		18.9			—			—			—		—			0.3			19.2
Repurchase of common stock		—	—		—			—			—			(4,175,576	)	(147.8		)	—			(147.8		)
Taxes paid due to the net settlement of equity-based compensation		—	—		(8.4		)	—			—			—		—			—			(8.4		)
Exercise of equity-based awards		462,318	—		—			—			—			—		—			—			—
Other		—	—		0.2			—			(0.1		)	—		—			—			0.1
Balance at	September 30, 2019	90,940,393	$	0.9	$	1,146.1		$	10.7		$	1,195.3		(16,653,356	)	$	(661.9	)	$	172.3		$	1,863.4



8 \|

Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Changes in Stockholders' Equity (Unaudited) (Continued)

(In millions, except share and per share data)



		Nine Months Ended September 30, 2018
		Common Stock			Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Treasury Stock					Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
		Shares	Amount		Additional Paid-in Capital			Accumulated Other Comprehensive Income			Retained Earnings			Shares		Amount			Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
Balance at	December 31, 2017	81,533,548	$	0.8	$	900.1		$	6.9		$	767.8		(762,623	)	$	(25.0	)	$	313.6		$	1,964.2
Net income		—	—		—			—			218.5			—		—			29.0			247.5
Other comprehensive loss related to commodity contracts, net		—	—		—			(8.2		)	—			—		—			—			(8.2		)
Other comprehensive income related to postretirement benefit plans, net		—	—		—			7.0			—			—		—			—			7.0
Other comprehensive loss related to interest rate contracts, net		—	—		—			(0.4		)	—			—		—			—			(0.4		)
Foreign currency translation loss, net		—	—		—			(0.4		)	—			—		—			—			(0.4		)
Common stock dividends ($0.70 per share)		—	—		—			—			(58.8		)	—		—			—			(58.8		)
Distribution to non-controlling interest		—	—		—			—			—			—		—			(21.5		)	(21.5		)
Equity-based compensation expense		—	—		15.3			—			—			—		—			0.3			15.6
Issuance of stock for non-controlling interest repurchase, net of tax		5,649,373	0.1		140.4			—			—			—		—			(127.0		)	13.5
De-recognition of non-controlling interest		—	—		—			—			—			—		—			(18.7		)	(18.7		)
Reclassification for stranded tax effects resulting from the the Tax Reform Act		—	—		—			1.6			(1.6		)	—		—			—			—
Cumulative effect of adopting accounting principle regarding income tax effect of intra-equity transfers		—	—		—			—			(44.4		)	—		—			—			(44.4		)
Shares issued in connection with settlement of Convertible Notes		2,692,218	—		(0.3		)	—			—			—		—			—			(0.3		)
Shares received in connection with exercise of Call Options		—	—		124.2			—			—			(2,692,771	)	(123.9		)	—			0.3
Repurchase of common stock		—	—		—			—			—			(4,847,511	)	(207.4		)	—			(207.4		)
Taxes paid due to the net settlement of equity-based compensation		—	—		(10.8		)	—			—			—		—			—			(10.8		)
Exercise of equity-based awards		556,564	—		—			—			—			—		—			—			—
Other		789	—		(0.1		)	(0.1		)	—			—		—			0.1			(0.1		)
Balance at	September 30, 2018	90,432,492	$	0.9	$	1,168.8		$	6.4		$	881.5		(8,302,905	)	$	(356.3	)	$	175.8		$	1,877.1

See accompanying notes to condensed consolidated financial statements



9 \|

Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In millions)



	Nine Months Ended September 30,
	2019			2018 ⁽¹⁾
Cash flows from operating activities:
Net income	$	298.2		$	247.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	146.7			146.4
Other amortization/accretion	7.1			6.7
Non-cash lease expense	29.6			—
Deferred income taxes	26.3			(29.2		)
Income from equity method investments	(28.4		)	(6.9		)
Dividends from equity method investments	11.7			5.2
Loss on disposal of assets	3.8			1.3
Loss on extinguishment of debt	—			9.1
Gain on sale of business	—			(13.2		)
Impairment of assets held for sale	—			27.5
Equity-based compensation expense	19.2			15.6
Income tax benefit of equity-based compensation	(2.0		)	—
Loss from discontinued operations	0.8			8.5
Changes in assets and liabilities, net of acquisitions:
Accounts receivable	(319.4		)	(112.7		)
Inventories and other current assets	(211.5		)	(78.7		)
Fair value of derivatives	(12.8		)	(64.1		)
Accounts payable and other current liabilities	474.3			50.5
Obligation under Supply and Offtake Agreement	46.4			32.2
Non-current assets and liabilities, net	(41.6		)	(14.4		)
Cash provided by operating activities - continuing operations	448.4			231.3
Cash used in operating activities - discontinued operations	—			(30.1		)
Net cash provided by operating activities	448.4			201.2
Cash flows from investing activities:
Equity method investment contributions	(214.0		)	(0.2		)
Distributions from equity method investments	0.8			1.0
Purchases of property, plant and equipment	(305.7		)	(228.0		)
Purchase of intangible assets	(0.8		)	(1.7		)
Proceeds from sale of property, plant and equipment	0.3			5.4
Proceeds from sale of retail stores	9.9			—
Proceeds from sale of business	—			110.8
Proceeds from sales of discontinued operations	—			55.5
Cash used in investing activities - continuing operations	(509.5		)	(57.2		)
Cash provided by investing activities - discontinued operations	—			20.0
Net cash used in investing activities	(509.5		)	(37.2		)

Delek US Holdings, Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited) (continued)

(In millions)



	Nine Months Ended September 30,
	2019			2018 ⁽¹⁾
Cash flows from financing activities:
Proceeds from long-term revolvers	$	1,278.4		$	1,749.1
Payments on long-term revolvers	(1,278.9		)	(1,227.8		)
Proceeds from term debt	246.8			690.6
Payments on term debt	(31.5		)	(824.6		)
Proceeds from product financing agreements	40.8			—
Repayments of product financing agreements	(22.2		)	(72.4		)
Taxes paid due to the net settlement of equity-based compensation	(8.4		)	(10.8		)
Repurchase of common stock	(147.8		)	(207.4		)
Distribution to non-controlling interest	(23.8		)	(21.5		)
Dividends paid	(64.3		)	(58.8		)
Deferred financing costs paid	(0.9		)	(13.2		)
Cash (used in) provided by financing activities - continuing operations	(11.8		)	3.2
Cash provided by (used in) financing activities - discontinued operations	—			—
Net cash (used in) provided by financing activities	(11.8		)	3.2
Net (decrease) increase in cash and cash equivalents	(72.9		)	167.2
Cash and cash equivalents at the beginning of the period	1,079.3			941.9
Cash and cash equivalents of continuing operations at the end of the period	$	1,006.4		$	1,109.1



Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest, net of capitalized interest of $1.2 million and $0.6 million in the 2019 and 2018 periods, respectively	$	88.3	$	87.2
Income taxes	$	73.3	$	53.3
Non-cash investing activities:
Common stock issued in connection with the buyout of Alon Partnership non-controlling interest	$	—	$	127.0
Increase (decrease) in accrued capital expenditures	$	19.1	$	(17.1	)
Non-cash financing activities:
Non-cash lease liability arising from recognition of right of use assets upon adoption of ASU 2016-02	$	211.0	$	—
Non-cash lease liability arising from obtaining right of use assets during the period	$	9.6	$	—
Common stock issued in connection with settlement of Convertible Notes	$	—	$	123.9
Treasury shares received in connection with exercise of Call Options	$	—	$	(123.9	)

⁽¹⁾

Net income and deferred income taxes for the nine months ended September 30, 2018 reflects a correction made in our 2018 Annual Report on Form 10-K (as originally filed on March 1, 2019) to record additional deferred tax expense totaling $5.5 million related to the recognition of a valuation allowance on deferred tax assets recognized in connection with the Big Spring Logistic Assets Acquisition (see Note 5) not previously reported in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 09, 2018. Such amount is not considered material to the financial statements or the trend of earnings for that period. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.

See accompanying notes to condensed consolidated financial statements



10 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

Note 1 - Organization and Basis of Presentation

Delek US Holdings, Inc. operates through its consolidated subsidiaries, which include Delek US Energy, Inc. (and its subsidiaries) and Alon USA Energy, Inc. ("Alon") (and its subsidiaries). The terms "we," "our," "us," "Delek" and the "Company" are used in this report to refer to Delek and its consolidated subsidiaries. Delek's Common Stock is listed on the NYSE under the symbol "DK."

Our condensed consolidated financial statements include the accounts of Delek and its subsidiaries. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. Generally Accepted Accounting Principles ("GAAP") have been condensed or omitted, although management believes that the disclosures herein are adequate to make the financial information presented not misleading. Our unaudited condensed consolidated financial statements have been prepared in conformity with GAAP applied on a consistent basis with those of the annual audited consolidated financial statements included in our Annual Report on Form 10-K as amended and filed with the Securities and Exchange Commission ("SEC") on June 27, 2019 (the "Annual Report on Form 10-K") and in accordance with the rules and regulations of the SEC. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto for the year ended December 31, 2018 included in our Annual Report on Form 10-K.

Our condensed consolidated financial statements include Delek Logistics Partners, LP ("Delek Logistics"), which is a variable interest entity. As the indirect owner of the general partner of Delek Logistics, we have the ability to direct the activities of this entity that most significantly impact its economic performance. We are also considered to be the primary beneficiary for accounting purposes for this entity and are Delek Logistics' primary customer. As Delek Logistics does not derive an amount of gross margin material to us from third parties, there is limited risk to Delek associated with Delek Logistics' operations. However, in the event that Delek Logistics incurs a loss, our operating results will reflect such loss, net of intercompany eliminations, to the extent of our ownership interest in this entity.

In the opinion of management, all adjustments necessary for a fair presentation of the financial condition and the results of operations for the interim periods have been included. All significant intercompany transactions and account balances have been eliminated in consolidation. All adjustments are of a normal, recurring nature. Operating results for the interim period should not be viewed as representative of results that may be expected for any future interim period or for the full year.

Reclassifications

Certain prior period amounts have been reclassified in order to conform to the current period presentation.

New Accounting Pronouncements Adopted During 2019

Accounting Standards Update ("ASU") 2016-02, Leases

In February 2016, the Financial Accounting Standards Board (the "FASB") issued guidance that requires the recognition of a lease liability and a right-of-use asset, initially measured at the present value of the lease payments, in the statement of financial condition for all leases with terms longer than one year. The guidance was subsequently amended to consider the impact of practical expedients and provide additional clarifications. This guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We adopted the new lease standard on January 1, 2019. We elected the package of practical expedients which, among other things, allows us to carry forward the historical lease classification. For certain lease classes, we have elected the practical expedient not to separate lease and non-lease components, which allows us to combine the components if certain criteria are met. Further, we elected the optional transition method, which allows us to recognize a cumulative-effect adjustment to the opening balance sheet of retained earnings at the date of adoption and to not recast our comparative periods. We have not elected the hindsight practical expedient, which would have allowed us to use hindsight in determining the reasonably certain lease term. The adoption of the lease accounting guidance had no impact on January 1, 2019 retained earnings and resulted in the recognition of a $211.0 million lease liability and a corresponding right-of-use asset on our consolidated balance sheet. The adoption did not have a material impact on our consolidated income statement. See Note 20 for further information.

ASU 2017-12, Derivatives and Hedging - Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued guidance to better align financial reporting for hedging activities with the economic objectives of those activities for both financial (e.g., interest rate) and commodity risks. The guidance was intended to create more transparency in the presentation of financial results, both on the face of the financial statements and in the footnotes, and simplify the application of hedge accounting guidance. This guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Companies are required to apply the guidance on a modified retrospective transition method in which the cumulative effect of the change is recognized within equity in the consolidated balance sheet as of the date of adoption. We adopted this guidance on January 1, 2019 and the adoption did not have a material impact on our business, financial condition or results of operations. See Note 11 for further information.



11 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

Accounting Pronouncements Not Yet Adopted

ASU 2018-15, Intangible - Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract

In August 2018, the FASB issued guidance related to customers’ accounting for implementation costs incurred in a cloud computing arrangement that is considered a service contract. This pronouncement aligns the requirements for capitalizing implementation costs in such arrangements with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. Entities can choose to adopt the new guidance prospectively or retrospectively. We expect to adopt this guidance on the effective date and are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations.

ASU 2018-14, Compensation - Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, the FASB issued guidance related to disclosure requirements for defined benefit plans. The pronouncement eliminates, modifies and adds disclosure requirements for defined benefit plans. The pronouncement is effective for fiscal years ending after December 15, 2020, and early adoption is permitted. We expect to adopt this guidance on the effective date and do not expect adopting this new guidance will have a material impact on our business, financial condition or results of operations.

ASU 2018-13, Fair Value Measurement - Changes to the Disclosure Requirements for Fair Value Measurement

In August 2018, the FASB issued guidance related to disclosure requirements for fair value measurements. The pronouncement eliminates, modifies and adds disclosure requirements for fair value measurements. The pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We expect to adopt this guidance on the effective date and do not expect adopting this new guidance will have a material impact on our business, financial condition or results of operations.

ASU 2016-13, Financial Instruments - Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued guidance requiring the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. Organizations will now use forward-looking information to better inform their credit loss estimates. We are currently evaluating the impact that adopting this new guidance will have on our business, financial condition and results of operations, which includes scoping, accounting, and disclosure considerations and historical analysis of applicable assets. This guidance is effective for interim and annual periods beginning after December 15, 2019. We expect to adopt this guidance on the effective date.

Note 2 - Acquisitions

In January 2017, we announced that Delek (and various related entities) ("Old Delek") entered into a merger agreement with Alon, as amended (the "Merger Agreement"). The related Merger (the "Delek/Alon Merger") was effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed as Delek US Holdings, Inc. (“New Delek”, or "Delek"), with Alon and Old Delek surviving as wholly-owned subsidiaries of New Delek. New Delek is the successor issuer to Old Delek and Alon pursuant to Rule 12g-3(c) under the Exchange Act, as amended. In addition, as a result of the Delek/Alon Merger, the shares of common stock of Old Delek and Alon were delisted from the NYSE in July 2017, and their respective reporting obligations under the Exchange Act were terminated.

In connection with the Delek/Alon Merger, Alon, New Delek and U.S. Bank National Association, as trustee (the “Trustee”) entered into a First Supplemental Indenture (the “Supplemental Indenture”), effective as of July 1, 2017, which provided for Alon's 3.00% Convertible Senior Notes due 2018, which were previously convertible into Alon Common Stock, to thereafter be convertible into New Delek Common Stock based on the exchange rate applied in the Delek/Alon Merger (the “Convertible Notes”). Additionally, in connection with the Convertible Notes, Alon also entered into equity instruments, including call options (the "Call Options") and warrants (the "Warrants"), designed, in combination, to hedge a portion of the risk associated with the potential exercise of the conversion feature of the Convertible Notes and to mitigate the dilutive effect of such potential conversion. These instruments were also exchanged in connection with the Delek/Alon Merger into instruments that were indexed to New Delek Common Stock. See Note 10 for further discussion of these instruments and subsequent activity.

The Delek/Alon Merger was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Transaction costs incurred by the Company in connection with the Delek/Alon Merger totaled $6.6 million for the nine months ended September 30, 2018 (none were incurred during the three months then ended). Such costs were included in general and administrative expenses in the accompanying condensed consolidated statements of income.

The final allocation of the aggregate purchase price (which was finalized as of June 30, 2018) is summarized as follows (in millions), and is inclusive of our discontinued Paramount and Long Beach, California refinery and California renewable fuels facility operations (collectively, the "California Discontinued Entities," discussed in Note 7):



12 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)



Delek common stock issued	19,250,795
Ending price per share of Delek Common Stock immediately before the Effective Time	$	26.44
Total value of common stock consideration			$	509.0
Additional consideration⁽¹⁾			21.7
Fair value of Delek's pre-existing equity method investment in Alon ⁽²⁾			449.0
			979.7
Less: Fair value of net assets acquired			109.0
Goodwill (excess of purchase price over fair value of net assets acquired)			$	870.7


⁽¹⁾	Additional consideration includes the fair value of certain equity instruments originally indexed to Alon stock that were exchanged for instruments indexed to New Delek's stock, as well as the fair value of certain share-based payments that were required to be exchanged for awards indexed to New Delek's stock in connection with the Delek/Alon Merger.

⁽²⁾The fair value of Delek's pre-existing equity method investment in Alon was based on the quoted market price of shares of Alon.

During the nine months ended September 30, 2018, certain immaterial purchase price accounting adjustments were recorded related to accretion of environmental liabilities and amortization of leasehold intangibles identified and valued during the final months of the measurement period (none were made during the three months then ended).

Note 3 - Segment Data

We aggregate our operating units into three reportable segments: Refining, Logistics, and Retail.

Operations that are not specifically included in the reportable segments are included in Corporate, Other and Eliminations, which consist of the following:


•	our corporate activities;


•	results of certain immaterial operating segments, including our Canadian crude trading operations (as discussed in Note 11);


•	Alon's asphalt terminal operations acquired as part of the Delek/Alon Merger and subsequently substantially disposed in the second quarter of 2018 (see Note 7 for further discussion);


•	the California Discontinued Entities which were acquired as part of the Delek/Alon Merger and subsequently disposed over the first seven months of 2018 (see Note 7 for further discussion); and


•	intercompany eliminations.

Decisions concerning the allocation of resources and assessment of operating performance are made based on this segmentation. Management measures the operating performance of each of the reportable segments based on the segment contribution margin. Segment contribution margin is defined as net revenues less cost of materials and other and operating expenses, excluding depreciation and amortization. All inter-segment transactions have been eliminated in consolidation.

Refining Segment


•	75,000 bpd Tyler, Texas refinery (the "Tyler refinery");


•	80,000 bpd El Dorado, Arkansas refinery (the "El Dorado refinery");


•	73,000 bpd Big Spring, Texas refinery (the "Big Spring refinery");


•	74,000 bpd Krotz Springs, Louisiana refinery (the "Krotz Springs refinery"); and


•	a non-operating refinery located in Bakersfield, California

As of September 30, 2019, the refining segment also owns and operates two biodiesel facilities involved in the production of biodiesel fuels and related activities, located in Crossett, Arkansas and Cleburne, Texas. The refining segment's petroleum-based products are marketed primarily in the south central, southwestern and western regions of the United States, and the refining segment also ships and sells gasoline into wholesale markets in the southern and eastern United States. Motor fuels are sold under the Alon or Delek brand through various terminals to supply Alon or Delek branded retail sites. In addition, we sell motor fuels through our wholesale distribution network on an unbranded basis.



13 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

Logistics Segment

Our logistics segment owns and operates crude oil and refined products logistics and marketing assets. The logistics segment generates revenue by charging fees for gathering, transporting and storing crude oil and for marketing, distributing, transporting and storing intermediate and refined products in select regions of the southeastern United States and west Texas for our refining segment and third parties, and sales of wholesale products in the west Texas market.

Retail Segment

Our retail segment consists of 263 owned and leased convenience store sites as of September 30, 2019, located primarily in central and west Texas and New Mexico. These convenience stores typically offer various grades of gasoline and diesel primarily under the Alon or Delek brand name and food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the public, primarily under the 7-Eleven and Alon brand names. Substantially all of the motor fuel sold through our retail segment is supplied by our Big Spring refinery, which is transferred to the retail segment at prices substantially determined by reference to published commodity pricing information. In November 2018, we terminated the license agreement with 7-Eleven, Inc. and the terms of such termination require the removal of all 7-Eleven branding on a store-by-store basis by the earlier of December 31, 2021 or the date upon which our last 7-Eleven store is de-identified or closed. Merchandise sales at our convenience store sites will continue to be sold under the 7-Eleven brand name until 7-Eleven branding is removed at such convenience store sites pursuant to the termination. In connection with certain strategic initiatives, we closed or sold 20 under-performing or non-strategic store locations during the nine months ended September 30, 2019 for total proceeds of $9.9 million.

Significant Inter-segment Transactions

Inter-segment transactions consist primarily of the following:


•	refining segment refined product sales to the retail segment to be sold through the store locations;


•	refining segment sales of asphalt and refined product to entities included in corporate, other and eliminations;


•	logistics segment service fee revenue under service agreements with the refining segment based on the number of gallons sold and to share a portion of the margin achieved in return for providing marketing, sales and customer services;


•	logistics segment sales of wholesale finished product to our refining segment; and


•	logistics segment crude transportation, terminalling and storage fee revenue from our refining segment for the utilization of pipeline, terminal and storage assets.

Business Segment Operating Performance

The following is a summary of business segment operating performance as measured by contribution margin for the period indicated (in millions):



	Three Months Ended September 30, 2019
(In millions)	Refining		Logistics		Retail		Corporate, Other and Eliminations			Consolidated
Net revenues (excluding inter-segment fees and revenues)	$	2,036.9	$	71.4	$	218.5	$	7.5		$	2,334.3
Inter-segment fees and revenues	139.9		66.2		—		(206.1		)	—
Operating costs and expenses:
Cost of materials and other	1,928.6		72.6		176.4		(213.5		)	1,964.1
Operating expenses (excluding depreciation and amortization presented below)	120.7		18.4		23.5		4.3			166.9
Segment contribution margin	$	127.5	$	46.6	$	18.6	$	10.6		203.3
Depreciation and amortization	34.6		6.6		3.0		5.6			49.8
General and administrative expenses										65.6
Other operating expense, net										0.5
Operating income										$	87.4
Capital spending (excluding business combinations)	$	63.3	$	4.0	$	3.8	$	39.4		$	110.5



14 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)



	Three Months Ended September 30, 2018
	Refining ⁽¹⁾		Logistics		Retail		Corporate, Other and Eliminations			Consolidated ⁽¹⁾
Net revenues (excluding inter-segment fees and revenues)	$	2,420.5	$	100.3	$	246.4	$	1.7		$	2,768.9
Inter-segment fees and revenues	228.8		63.8		—		(292.6		)	—
Operating costs and expenses:
Cost of materials and other	2,211.0		105.6		204.4		(276.8		)	2,244.2
Operating expenses (excluding depreciation and amortization presented below)	118.8		15.4		26.7		3.1			164.0
Segment contribution margin	$	319.5	$	43.1	$	15.3	$	(17.2	)	360.7
Depreciation and amortization	33.8		6.7		5.3		3.4			49.2
General and administrative expenses										58.0
Other operating income, net										(1.7		)
Operating income										$	255.2
Capital spending (excluding business combinations)	$	51.1	$	2.9	$	1.9	$	30.2		$	86.1



	Nine Months Ended September 30, 2019
(In millions)	Refining		Logistics		Retail		Corporate, Other and Eliminations			Consolidated
Net revenues (excluding inter-segment fees and revenues)	$	6,096.7	$	254.3	$	640.2	$	23.3		$	7,014.5
Inter-segment fees and revenues	539.9		191.1		—		(731.0		)	—
Operating costs and expenses:
Cost of materials and other	5,679.8		262.7		521.9		(733.2		)	5,731.2
Operating expenses (excluding depreciation and amortization presented below)	356.7		51.8		71.9		15.5			495.9
Segment contribution margin	$	600.1	$	130.9	$	46.4	$	10.0		787.4
Depreciation and amortization	98.9		19.8		11.5		16.5			146.7
General and administrative expenses										197.3
Other operating income, net										(0.7		)
Operating income										$	444.1
Capital spending (excluding business combinations)	$	193.8	$	6.2	$	14.3	$	110.5		$	324.8



	Nine Months Ended September 30, 2018
	Refining ⁽¹⁾		Logistics		Retail		Corporate, Other and Eliminations ⁽⁴⁾			Consolidated ⁽¹⁾
Net revenues (excluding inter-segment fees and revenues)	$	6,678.2	$	319.8	$	700.8	$	60.2		$	7,759.0
Inter-segment fees and revenues	640.2		178.5		—		(818.7		)	—
Operating costs and expenses:
Cost of materials and other	6,341.9		330.6		578.5		(713.8		)	6,537.2
Operating expenses (excluding depreciation and amortization presented below)	346.7		42.9		76.5		13.5			479.6
Segment contribution margin	$	629.8	$	124.8	$	45.8	$	(58.2	)	742.2
Depreciation and amortization	99.1		19.7		16.8		10.8			146.4
General and administrative expenses										176.1
Other operating income, net										(9.4		)
Operating income										$	429.1
Capital spending (excluding business combinations)	$	136.3	$	7.4	$	6.0	$	61.2		$	210.9

⁽¹⁾

Refining segment and consolidated net revenues and cost of materials and other for the three and nine months ended September 30, 2018 reflect a correction of an intercompany elimination which resulted in an increase in those accounts of $273.7 million and $347.1 million, respectively, not previously reflected on the unaudited consolidated financial statements in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 9, 2018. Such amounts are not considered material to the financial statements and had no impact to operating income or segment contribution margin for those periods. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.



15 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

Other Segment Information

Total assets by segment were as follows as of September 30, 2019:



	Refining			Logistics		Retail		Corporate, Other and Eliminations			Consolidated
Total assets	$	7,036.8		$	767.8	$	354.2	$	(1,365.5	)	$	6,793.3
Less:
Inter-segment notes receivable	(1,731.0		)	—		—		1,731.0			—
Inter-segment right of use lease assets	(387.8		)	—		—		387.8			—
Total assets, excluding inter-segment notes receivable and right of use assets	$	4,918.0		$	767.8	$	354.2	$	753.3		$	6,793.3

Property, plant and equipment and accumulated depreciation as of September 30, 2019 and depreciation expense by reporting segment for the three and nine months ended September 30, 2019 are as follows (in millions):



	Refining			Logistics			Retail			Corporate, Other and Eliminations			Consolidated
Property, plant and equipment	$	2,417.9		$	457.7		$	154.3		$	280.0		$	3,309.9
Less: Accumulated depreciation	(679.0		)	(159.6		)	(38.7		)	(67.4		)	(944.7		)
Property, plant and equipment, net	$	1,738.9		$	298.1		$	115.6		$	212.6		$	2,365.2
Depreciation expense for the three months ended September 30, 2019	$	34.1		$	6.6		$	2.8		$	5.6		$	49.1
Depreciation expense for the nine months ended September 30, 2019	$	95.0		$	19.8		$	10.9		$	16.5		$	142.2

In accordance with Accounting Standards Codification ("ASC") 360, Property, Plant and Equipment ("ASC 360"), Delek evaluates the realizability of property, plant and equipment as events occur that might indicate potential impairment. There were no indicators of impairment related to our property, plant and equipment as of September 30, 2019.

Note 4 - Earnings (Loss) Per Share

Basic earnings per share (or "EPS") is computed by dividing net income (loss) by the weighted average common shares outstanding. Diluted earnings per share is computed by dividing net income (loss), as adjusted for changes to income that would result from the assumed settlement of the dilutive equity instruments included in diluted weighted average common shares outstanding, by the diluted weighted average common shares outstanding. For all periods presented, we have outstanding various equity-based compensation awards that are considered in our diluted EPS calculation (when to do so would be dilutive), and is inclusive of awards disclosed in Note 17 to these condensed consolidated financial statements. For those instruments that are indexed to our common stock, they are generally dilutive when the market price of the underlying indexed share of common stock is in excess of the exercise price. Additionally, in connection with the Delek/Alon Merger, we assumed certain equity instruments, including conversion options (associated with the Convertible Notes) and Warrants, that were dilutive in certain periods (see discussion of these instruments in Note 10). The Convertible Notes conversion options were dilutive during the period they were outstanding when the incremental EPS calculated by dividing the increase in income associated with the elimination of interest expense on the convertible debt, net of tax, by the number of shares that would be issued upon conversion using the treasury stock method (which is applicable because of the cash settlement feature associated with the underlying principal) is dilutive to the overall diluted EPS calculation. The Warrants were generally dilutive during the period they were outstanding when the market price of the underlying indexed share of common stock is in excess of the exercise price. All such instruments that may otherwise be dilutive may not be dilutive when there is a net loss for the period. On September 17, 2018, Delek settled the Convertible Notes for a combination of cash and shares of New Delek Common Stock (See Note 10) and in November 2018, Delek entered into Warrant Unwind Agreements (the "Unwind Agreements" - See Note 10) with the holders of our outstanding common stock warrants; therefore, these instruments were only potentially dilutive for EPS for the three and nine months ended September 30, 2018.



16 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

The following table sets forth the computation of basic and diluted earnings per share.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019			2018
Numerator:
Numerator for EPS - continuing operations
Income from continuing operations	$	60.0	$	185.8	$	299.0		$	256.0
Less: Income from continuing operations attributed to non-controlling interest	8.7		6.5		20.3			20.9
Income from continuing operations attributable to Delek (numerator for basic EPS - continuing operations attributable to Delek)	51.3		179.3		278.7			235.1
Interest on convertible debt, net of tax	—		0.7		—			2.5
Numerator for diluted EPS - continuing operations attributable to Delek	$	51.3	$	180.0	$	278.7		$	237.6

Numerator for EPS - discontinued operations
Income (loss) from discontinued operations	$	—	$	0.5	$	(0.8	)	$	(8.5	)
Less: Loss from discontinued operations attributed to non-controlling interest	—		—		—			8.1
Income (loss) from discontinued operations attributable to Delek	$	—	$	0.5	$	(0.8	)	$	(16.6	)

Denominator:
Weighted average common shares outstanding (denominator for basic EPS)	75,028,562		83,575,122		76,463,435			83,294,473
Dilutive effect of convertible debt	—		2,176,140		—			2,183,186
Dilutive effect of warrants	—		1,683,722		—			1,291,156
Dilutive effect of stock-based awards	673,749		1,586,276		704,399			1,600,298
Weighted average common shares outstanding, assuming dilution (denominator for diluted EPS)	75,702,311		89,021,260		77,167,834			88,369,113

EPS:
Basic income (loss) per share:
Income from continuing operations	$	0.68	$	2.15	$	3.64		$	2.82
Income (loss) from discontinued operations	$	—	0.01		$	(0.01	)	(0.20		)
Total basic income per share	$	0.68	$	2.16	$	3.63		$	2.62
Diluted income (loss) per share:
Income from continuing operations	$	0.68	$	2.02	$	3.61		$	2.69
Income (loss) from discontinued operations	$	—	0.01		$	(0.01	)	(0.19		)
Total diluted income per share	$	0.68	$	2.03	$	3.60		$	2.50

The following equity instruments were excluded from the diluted weighted average common shares outstanding because their effect would be antidilutive:
Antidilutive stock-based compensation (because average share price is less than exercise price)	1,846,919		1,014,057		2,003,283			1,208,648

Note 5 - Delek Logistics and the Alon Partnership

Delek Logistics

Delek Logistics is a publicly traded limited partnership that was formed by Delek in 2012 to own, operate, acquire and construct crude oil and refined products logistics and marketing assets. A substantial majority of Delek Logistics' assets are integral to Delek’s refining and marketing operations. As of September 30, 2019, we owned a 61.4% limited partner interest in Delek Logistics, consisting of 15,294,046 common units, and a 94.6% interest in Delek Logistics GP, LLC, which owns the entire 2.0% general partner interest, consisting of 498,312 general partner units, in Delek Logistics and all of the incentive distribution rights.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

The limited partner interests in Delek Logistics not owned by us are reflected in net income attributable to non-controlling interest in the accompanying condensed consolidated statements of income and in non-controlling interest in subsidiaries in the accompanying condensed consolidated balance sheets.

In March 2018, a subsidiary of Delek Logistics completed the acquisition from a subsidiary of Delek (the "Alon Partnership") of storage tanks and terminals that support the Big Spring refinery (the "Big Spring Logistic Assets Acquisition"), which included the execution of related commercial agreements. In addition, a new marketing agreement was entered into between the subsidiary of Delek Logistics and the Alon Partnership pursuant to which the subsidiary of Delek Logistics provides marketing services for product sales from the Big Spring refinery. The cash paid for the transferred assets was $170.8 million, subject to certain post-closing adjustments, and the cash paid for the marketing agreement was $144.2 million. The transactions were financed with borrowings under the 2014 Facility revolving credit agreement (as defined in Note 10). Additionally, the transaction resulted in the creation of a deferred tax asset related to the tax-book basis difference in the sold assets totaling $98.8 million, against which we have recorded a valuation allowance totaling $5.5 million for the portion of the deferred tax asset that relates to basis difference attributable to the non-controlling interest and therefore may not be realizable. Prior periods have not been recast in our Segment Data Note 3, as these assets did not constitute a business in accordance with ASU 2017-01, Clarifying the Definition of a Business, and were accounted for as acquisitions of assets between entities under common control.

We have agreements with Delek Logistics that, among other things, establish fees for certain administrative and operational services provided by us and our subsidiaries to Delek Logistics, provide certain indemnification obligations and establish terms for fee-based commercial logistics and marketing services provided by Delek Logistics and its subsidiaries to us, including new agreements related to the Big Spring Logistic Assets Acquisition. The revenues and expenses associated with these agreements are eliminated in consolidation.

Delek Logistics is a variable interest entity, as defined under GAAP, and is consolidated into our condensed consolidated financial statements, representing our logistics segment. Exclusive of intercompany balances and the marketing agreement intangible asset between Delek Logistics and Delek which are eliminated in consolidation, the Delek Logistics condensed consolidated balance sheets as presented below are included in the condensed consolidated balance sheets of Delek (unaudited, in millions).



	September 30, 2019			December 31, 2018
	September 30, 2019			December 31, 2018
ASSETS
Cash and cash equivalents	$	6.4		$	4.5
Accounts receivable	20.0			21.6
Inventory	7.7			5.5
Other current assets	2.7			1.0
Property, plant and equipment, net	298.1			312.6
Equity method investments	247.0			104.8
Operating lease right-of-use assets	18.3			—
Goodwill	12.2			12.2
Intangible assets, net	132.8			138.2
Other non-current assets	22.7			24.2
Total assets	$	767.9		$	624.6
LIABILITIES AND DEFICIT
Accounts payable	$	12.5		$	14.2
Accounts payable to related parties	2.8			7.8
Current portion of operating lease liabilities	4.8			—
Accrued expenses and other current liabilities	12.2			14.5
Long-term debt	840.8			700.4
Asset retirement obligations	5.5			5.2
Operating lease liabilities, net of current portion	13.5			—
Other non-current liabilities	18.2			17.3
Deficit	(142.5		)	(134.8		)
Total liabilities and deficit	$	767.8		$	624.6



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Alon Partnership

As part of the Delek/Alon Merger, we acquired a majority interest in the Alon Partnership, which owns the assets and conducts the operations of the Big Spring refinery and the associated integrated wholesale marketing operations. On February 7, 2018 (the "Merger Date"), Delek acquired from the Alon Partnership all of the outstanding limited partner units that Delek did not already own in an all-equity transaction (the "Alon Partnership Merger"). Delek owned approximately 51.0 million limited partner units of the Alon Partnership, or approximately 81.6% of the outstanding units, immediately prior to the Merger Date. Under terms of the merger agreement, the owners of the remaining outstanding units in the Alon Partnership that Delek did not own immediately prior to the Merger Date received a fixed exchange ratio of 0.49 shares of New Delek common stock for each limited partner unit of the Alon Partnership, resulting in the issuance of approximately 5.6 million shares of New Delek common stock to the public unitholders of the Alon Partnership. Because the transaction represented a combination of ownership interests under common control, the transfer of equity from non-controlling interest to owned interest (additional paid-in capital) was recorded at carrying value and no gain or loss was recognized in connection with the transaction. Additionally, book-tax basis difference was created as a result of the transaction that resulted in a deferred tax asset of approximately $13.5 million, net of a valuation allowance on certain state income tax components, that also increased additional paid-in capital. Transaction costs incurred by the Company in connection with the Alon Partnership Merger totaled approximately $3.0 million for the nine months ended September 30, 2018, none of which were recorded in the third quarter of 2018. Such costs were included in general and administrative expenses in the accompanying condensed consolidated statements of income.

Prior to the Merger Date, the Alon Partnership was a variable interest entity for which Delek was the primary beneficiary. As of September 30, 2019 and December 31, 2018, the Alon Partnership is included in Delek's condensed consolidated balance sheet as a wholly-owned subsidiary.

Note 6 - Equity Method Investments

Wink to Webster Pipeline LLC ("WWP")

On July 30, 2019, we, through our wholly-owned direct subsidiary Delek US Energy, Inc. (“Delek Energy”), entered into a limited liability company agreement (the “LLCA”) and related agreements with multiple joint venture members of Wink to Webster Pipeline LLC (“WWP”). Pursuant to the LLCA, Delek Energy acquired a 15% ownership interest in WWP. WWP intends to construct and operate a crude oil pipeline system from Wink, Texas to Webster, Texas along with certain pipelines from Webster, Texas to other destinations in the Gulf Coast area. Pursuant to the LLCA, Delek Energy will be required to contribute its percentage interest of the applicable construction costs (including certain costs previously incurred by WWP) and it is anticipated that Delek Energy’s capital contributions will total approximately $340 million to $380 million over the course of construction (expected to be two to three years). During the three and nine months ended September 30, 2019, we made capital contributions totaling $75.3 million. Subsequent to September 30, 2019, we made additional capital contributions totaling $46.2 million based on capital calls received.

As of September 30, 2019, Delek's investment balance in WWP totaled $75.3 million, and we recognized nominal income on the investment for the three and nine months then ended. This investment is accounted for using the equity method and is included as part of total assets in corporate, other and eliminations in our segment disclosure.

Red River Pipeline Company LLC ("Red River")

In May 2019, Delek Logistics, through its wholly owned indirect subsidiary Delek Logistics Pipeline, LLC (“Delek Logistics Pipeline”), entered into a Contribution and Subscription Agreement (the “Contribution Agreement”) with Plains Pipeline, L.P. (“Plains”) and Red River Pipeline Company LLC (“Red River”). Pursuant to the Contribution Agreement, Delek Logistics Pipeline contributed $124.7 million, substantially all of which was financed under the Delek Logistics Credit Facility (as defined in Note 10), to Red River in exchange for a 33% membership interest in Red River and Delek Logistics Pipeline’s admission as a member of Red River. Red River owns a 16-inch crude oil pipeline running from Cushing, Oklahoma to Longview, Texas, with an expansion project planned to increase the pipeline capacity, which is expected to be completed during the first half of 2020. Delek Logistics contributed an additional $3.5 million related to such expansion project in May 2019. As of September 30, 2019, Delek's investment balance in Red River totaled $131.2 million, and we recognized income on the investment totaling $4.7 million and $7.0 million for the three and nine months then ended September 30, 2019, respectively. This investment is accounted for using the equity method and is included as part of total assets in our logistics segment.

Other Investments

Delek Logistics also has two joint ventures that own and operate logistics assets, and which serve third parties and subsidiaries of Delek. As of September 30, 2019 and December 31, 2018, Delek Logistics' investment balances in these joint ventures totaled $115.8 million and $104.8 million, respectively, and were accounted for using the equity method.

Delek Renewables, LLC, a wholly-owned subsidiary of Delek, has a joint venture that owns, operates and maintains a terminal consisting of an ethanol unit train facility with an ethanol tank in North Little Rock, Arkansas. As of September 30, 2019 and December 31, 2018, Delek Renewables, LLC's investment balance in this joint venture was $4.2 million and $2.4 million, respectively, and was accounted for using the equity method. The investment in this joint venture is reflected in the refining segment.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Effective with the Delek/Alon Merger, we acquired a 50% interest in two joint ventures that own asphalt terminals located in Fernley, Nevada, and Brownwood, Texas. On May 21, 2018, Delek sold its 50% interest in the asphalt terminal located in Fernley, Nevada. See Note 7 for further discussion. As of September 30, 2019 and December 31, 2018, Delek's investment balance in the Brownwood, Texas joint venture was $33.7 million and $23.1 million, respectively. This investment is accounted for using the equity method and is included as part of total assets in corporate, other and eliminations in our segment disclosure.

Note 7 - Discontinued Operations and Assets Held for Sale

Asphalt Terminals

On February 12, 2018, Delek announced it had reached a definitive agreement to sell certain assets and operations of four asphalt terminals (included in corporate, other and eliminations in our segment disclosure), as well as an equity method investment in an additional asphalt terminal located in Femley, Nevada, to an affiliate of Andeavor. On May 21, 2018, Delek completed the transaction and received net proceeds of approximately $110.8 million, inclusive of the $75.0 million base proceeds as well as certain working capital adjustments. The assets associated with the owned terminals met the definition of held for sale pursuant to ASC 360 as of February 1, 2018, but did not meet the definition of discontinued operations pursuant to ASC 205-20, Presentation of Financial Statements - Discontinued Operations ("ASC 205-20"), as the sale of these asphalt assets did not represent a strategic shift that would have a major effect on the entity's operations and financial results. Accordingly, depreciation ceased as of February 1, 2018, and the assets to be sold were reclassified to assets held for sale as of that date and were written down to the estimated fair value less costs to sell, resulting in an impairment loss on assets held for sale of $27.5 million for the nine months ended September 30, 2018 (none for the three months then ended). All goodwill associated with the asphalt operations sold was written off in connection with the impairment charge discussed above. In connection with the completion of the sale transaction in the second quarter of 2018, we recognized a gain of approximately $13.2 million, resulting primarily from the recognition of certain additional proceeds at closing associated with the asphalt terminals which were not previously determinable/probable and the recognition of the gain on the sale of the joint venture which was not previously recognized as held for sale (as it did not meet the criteria).

California Discontinued Entities

During the third quarter 2017, we committed to a plan to sell certain assets associated with our Paramount and Long Beach, California refineries and our California renewable fuels facility (as previously defined, the "California Discontinued Entities"). Such operations were designated and reported as discontinued operations.

Sale of Paramount Refinery Assets and Altair

On March 16, 2018, Delek sold to World Energy, LLC ("World Energy") (i) all of Delek’s membership interests in the California renewable fuels facility ("AltAir") (ii) certain refining assets and other related assets located in Paramount, California and (iii) certain associated tank farm and pipeline assets and other related assets located in California. Upon final settlement (excluding contingent components), Delek expects to receive net cash proceeds of approximately $85.2 million, which included a post-closing working capital settlement, Delek’s portion of the biodiesel tax credit (the "BTC") for 2017 and certain customary adjustments. The sale resulted in a loss on sale of discontinued operations totaling approximately $41.4 million of which $41.2 million was recorded during the nine months ended September 30, 2018 (none for the three months ended September 30, 2018). Of the total expected proceeds, $70.4 million was received during the nine months ended September 30, 2018 ($14.9 million of which were included in net cash flows from investing activities in discontinued operations). Prior to the agreement reached with World Energy in August 2019 (see below), we had a remaining receivable from the buyer totaling approximately $14.8 primarily related to the working capital settlement. Additionally, Delek is entitled to its pro rata portion of any tax credits relating to AltAir activities in 2018 earned through the sale date if the 2018 BTC is re-enacted. A receivable for such additional contingent proceeds will be recorded when the criteria for recognition are met, which is predicated upon reenactment of the tax credit and determination of the amounts earned by AltAir.

In August 2019, we reached an agreement with World Energy to offset amounts payable by Delek under our seller obligations for the Ten-Tex Litigation matter (defined and further discussed in Note 13) against the working capital settlement receivable referenced above, and to convert the net receivable to a promissory note in the amount of $12.3 million (the "World Energy Note Receivable" or the "Note Receivable"). The World Energy Note Receivable bears interest at a fixed rate of 6.0% per annum payable monthly, and requires monthly principal payments totaling approximately $0.5 million beginning in January 2020. The Note Receivable matures on December 31, 2021, subject to acceleration clauses if certain events occur. In the event that the BTC is re-enacted for 2018 and/or 2019 resulting in proceeds to World Energy for Altair's qualifying credits, pre-payment of the lesser of the remaining outstanding balance (and all accrued interest) or the amount of the BTC proceeds received will be payable to Delek within 15 days of such receipt.

Sale of Long Beach Refinery Net Assets

The transaction to dispose of certain assets and liabilities associated with our Long Beach, California refinery to Bridge Point Long Beach, LLC closed July 17, 2018 resulting in initial cash proceeds of approximately $14.5 million, net of expenses, and resulting in a gain on sale of discontinued operations of approximately $1.4 million during the third quarter of 2018.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Operating Results

The operating results, net of tax, from discontinued operations associated with the California Discontinued Entities are presented separately in Delek’s condensed consolidated statements of income and the notes to the condensed consolidated financial statements have been adjusted to exclude the discontinued operations. Components of amounts reflected in income (loss) from discontinued operations prior to their disposal are as follows (in millions):



	Three Months Ended			Nine Months Ended
	September 30, 2018				September 30, 2018
Net revenues	$	—			$	32.5
Cost of sales:
Cost of materials and other	—				3.8
Operating expenses (excluding depreciation and amortization)	(0.6		)		(9.4		)
Total cost of sales	(0.6		)		(5.6		)
General and administrative expenses	—				(1.1		)
Other operating income, net	—				0.3
Interest income	—				3.0
Loss on sale of California Discontinued Entities	1.4				(39.8		)
Loss from discontinued operations before taxes	0.8				(10.7		)
Income tax benefit	0.3				(2.2		)
Loss from discontinued operations, net of tax ⁽¹⁾	$	0.5			$	(8.5	)


⁽¹⁾	Included in loss from discontinued operations is net income attributable to non-controlling interest totaling $8.1 million related to AltAir for the nine months ended September 30, 2018 (none for the three months ended September 30, 2018).

Related to the California Discontinued Entities, all of which were disposed of by December 31, 2018, we retained certain obligations associated with various matters, including (but not necessarily limited to) California emissions credits requirements that were attributable to operations of the California Discontinued Entities for periods prior to disposition, litigations, claims or assessments related to matters/events that occurred prior to disposition, or indemnification of certain liabilities that related to the California Discontinued Entities and arose prior to disposition. Related to these matters, we recorded liabilities of $3.4 million and $5.0 million as of September 30, 2019 and December 31, 2018, respectively based on amounts that were deemed probable and could be reasonably estimated as of those dates. During the nine months ended September 30, 2019, we recorded an additional accrual for California emission credit obligation based upon our revised estimates totaling $3.4 million, none of which was recorded in the third quarter. Additionally, in July 2019, we resolved a pending litigation matter (the Ten-Tex Litigation -- see Note 13) that resulted in a decrease in our accrual totaling $2.4 million during the nine months ended September 30, 2019. Such adjustments are included in loss from discontinued operations on the accompanying condensed consolidated statements of income for those periods.

Note 8 - Inventory

Crude oil, work in process, refined products, blendstocks and asphalt inventory for all of our operations, excluding the Tyler refinery and merchandise inventory in our retail segment, are stated at the lower of cost determined using the first-in, first-out (“FIFO”) basis or net realizable value. Cost of all inventory at the Tyler refinery is determined using the last-in, first-out ("LIFO") inventory valuation method and inventory is stated at the lower of cost or market. Retail merchandise inventory consists of cigarettes, beer, convenience merchandise and food service merchandise and is stated at estimated cost as determined by the retail inventory method.

Carrying value of inventories consisted of the following (in millions):



	September 30, 2019		December 31, 2018
Refinery raw materials and supplies	$	432.8	$	289.0
Refinery work in process	94.4		58.9
Refinery finished goods	342.4		304.1
Retail fuel	5.6		8.0
Retail merchandise	25.7		25.4
Logistics refined products	7.7		5.5
Total inventories	$	908.6	$	690.9



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Notes to Condensed Consolidated Financial Statements (Unaudited)

At September 30, 2019, we recorded a pre-tax inventory valuation reserve of $23.9 million, $12.4 million of which related to LIFO inventory, due to a market price decline below our cost of certain inventory products. At December 31, 2018, we recorded a pre-tax inventory valuation reserve of $54.0 million, $39.4 million of which related to LIFO inventory, which reversed in the first quarter of 2019 due to the sale of inventory quantities that gave rise to the December 31, 2018 reserve. We recognized a net (increase) reduction in cost of materials and other in the accompanying condensed consolidated statements of income related to the change in pre-tax inventory valuation of $(21.4) million and $30.1 million for the three and nine months ended September 30, 2019, respectively, and $(0.1) million and $1.9 million for the three and nine months ended September 30, 2018, respectively.

Note 9 - Crude Oil Supply and Inventory Purchase Agreements

Delek has Supply and Offtake Agreements with J. Aron & Company ("J. Aron") in connection with its El Dorado, Big Spring and Krotz Spring refineries (collectively, the "Supply and Offtake Agreements"). Pursuant to the Supply and Offtake Agreements, (i) J. Aron agrees to sell to us, and we agree to buy from J. Aron, at market prices, crude oil for processing at these refineries and (ii) we agree to sell, and J. Aron agrees to buy, at market prices, certain refined products produced at these refineries. The Supply and Offtake Agreements also provide for the lease to J. Aron of crude oil and refined product storage facilities, and the identification of prospective purchasers of refined products on J. Aron’s behalf. At the inception of the Supply and Offtake Agreements, we transferred title to a certain number of barrels of crude and other inventories to J. Aron (the "Step-In"), and the Supply and Offtake Agreements require the repurchase of remaining inventory (including certain "Baseline Volumes") at the termination of those Agreements (the "Step-Out"). The Supply and Offtake Agreements are accounted for as product financing arrangements under the fair value election provided by ASC 815 Derivatives and Hedging ("ASC 815") and ASC 825, Financial Instruments ("ASC 825").

Barrels subject to the Supply and Offtake Agreements are as follows:



(in millions)	El Dorado	Big Spring	Krotz Springs
Baseline Volumes pursuant to the respective Supply and Offtake Agreements	1.9	0.8	1.3
Barrels of inventory consigned under the respective Supply and Offtake Agreements as of September 30, 2019 ⁽¹⁾	3.4	1.5	1.6
Barrels of inventory consigned under the respective Supply and Offtake Agreements as of December 31, 2018 ⁽¹⁾	2.8	1.7	1.8


⁽¹⁾	Includes Baseline Volumes plus/minus over/short quantities.

The El Dorado Supply and Offtake Agreement has a maturity date of April 30, 2020. The Big Spring and Krotz Springs Supply and Offtake Agreements have initial terms that expire in May 2021. J. Aron or Delek may elect to terminate the agreements at the Big Spring and Krotz Springs refineries in May 2020 on six months' prior notice. The Supply and Offtake Agreements have certain termination provisions, which may include requirements to negotiate with third parties for the assignment to us of certain contracts, commitments and arrangements, including procurement contracts, commitments for the sale of product, and pipeline, terminalling, storage and shipping arrangements.

The Supply and Offtake Agreements were amended in December 2018 for Big Spring and in January 2019 for El Dorado and Krotz Springs so that the repurchase of Baseline Volumes at the end of the Supply and Offtake Agreement term (representing the "Baseline Step-Out Liability" or, collectively, the "Baseline Step-Out Liabilities") will be based upon a fixed price. Prior to those amendments, the Baseline Step-Out Liabilities were based on market-indexed pricing. The amendments resulted in Baseline Step-Out Liabilities that are no longer subject to commodity price volatility, but for which its fair value is now subject to interest rate risk. As a result, we recorded gains on the change in fair value resulting from the modification of the instruments from commodities-based risk to interest rate risk in cost of materials and other in the periods in which the amendments occurred, including $7.6 million of which were recognized in the first quarter of 2019. Subsequent to these amendments, such Baseline Step-Out Liabilities will continue to be recorded at fair value, where the fair value will reflect changes in interest rate risk rather than commodity price risk under the fair value election provided by ASC 815 and ASC 825. Prior to the amendments, the Obligations under the Supply and Offtake Agreements were all classified as current based on the market-indexed nature of the liabilities. Subsequent to the amendments, the Baseline Step-Out Liabilities are reflected as non-current liabilities on our consolidated balance sheet to the extent that they are not contractually due within twelve months. Monthly activity resulting in over and short volumes continue to be valued using market-indexed pricing, and are included in current liabilities (or receivables) on our consolidated balance sheet. Net balances payable (receivable) under the Supply and Offtake Agreements were as follows as of the balance sheet dates:



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(in millions)	El Dorado			Big Spring			Krotz Springs			Total
Balances as of September 30, 2019:
Baseline Step-Out Liability	$	124.1		$	56.5		$	87.1		$	267.7
Revolving over/short product financing liability	80.4			32.8			27.7			140.9
Total Obligations Under Supply and Offtake Agreements	204.5			89.3			114.8			408.6
Less: Current portion	204.5			32.8			27.7			265.0
Obligations Under Supply and Offtake Agreements - Noncurrent portion	$	—		$	56.5		$	87.1		$	143.6
Other receivable for monthly activity true-up (included in current receivables)	$	(6.9	)	$	(2.4	)	$	(3.1	)	$	(12.4	)



(in millions)	El Dorado			Big Spring			Krotz Springs		Total
Balances as of December 31, 2018:
Baseline Step-Out Liability	$	—		$	49.6		$	—	$	49.6
Revolving over/short product financing liability	—			46.9			—		46.9
Revolving Step-Out Liability (prior to January 2019 amendments)	152.6			—			113.1		265.7
Total Obligations Under Supply and Offtake Agreements	152.6			96.5			113.1		362.2
Less: Current portion	152.6			46.9			113.1		312.6
Obligations Under Supply and Offtake Agreements - Noncurrent portion	$	—		$	49.6		$	—	$	49.6
Other (receivable) payable for monthly activity true-up (included in current payables (receivables))	$	(7.8	)	$	(0.4	)	$	1.4	$	(6.8	)

In September 2019, we amended the Supply and Offtake Agreements to increase the fixed Step-Out price on Baseline Volumes. As a result of the change in the contractual terms, we received cash, net of estimated fees paid, totaling approximately $38.9 million. No gain or loss was recognized as a result of these September 2019 amendments. As of September 30, 2019, the effective interest rates related to the Supply and Offtake Agreements, as amended, were as follows:



	El Dorado		Big Spring		Krotz Springs
Effective interest rate as of September 30, 2019	8.6	%	9.5	%	8.0	%

The Supply and Offtake Agreements require payments of fees which are factored into the interest rate yield under the fair value accounting model. Recurring cash fees paid during the periods presented were as follows:



(in millions)	El Dorado		Big Spring		Krotz Springs		Total
Recurring cash fees paid during the three months ended September 30, 2019	$	2.9	$	1.5	$	2.5	$	6.9
Recurring cash fees paid during the three months ended September 30, 2018	$	2.7	$	1.8	$	1.8	$	6.3
Recurring cash fees paid during the nine months ended September 30, 2019	$	8.5	$	4.4	$	7.6	$	20.5
Recurring cash fees paid during the nine months ended September 30, 2018	$	8.3	$	5.4	$	5.0	$	18.7

Interest expense recognized under the Supply and Offtake Agreements includes the yield attributable to recurring cash fees, one-time cash fees (e.g., in connection with amendments), as well as other changes in fair value, which may increase or decrease interest expense. Total interest expense incurred during the periods presented was as follows:



(in millions)	El Dorado		Big Spring		Krotz Springs		Total
Interest expense for the three months ended September 30, 2019	$	3.7	$	2.0	$	2.7	$	8.4
Interest expense for the three months ended September 30, 2018	$	2.7	$	1.8	$	1.8	$	6.3
Interest expense for the nine months ended September 30, 2019	$	10.9	$	3.6	$	8.8	$	23.3
Interest expense for the nine months ended September 30, 2018	$	8.3	$	5.4	$	5.0	$	18.7

Reflected in interest expense are gains totaling $7.7 million and $11.4 million for the three and nine months September 30, 2019, respectively,



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related to the changes in fair value in the Baseline Step-Out Liabilities component of Obligations Under Supply and Offtake Agreements.

We maintained letters of credit under the Supply and Offtake Agreements as follows:



(in millions)	El Dorado		Big Spring and Krotz Springs
Letters of credit outstanding as of September 30, 2019	$	180.0	$	44.0
Letters of credit outstanding as of December 31, 2018	$	120.0	$	24.0

In connection with the Krotz Springs Supply and Offtake Agreement, prior to September 30, 2019, we granted a security interest to J. Aron in certain assets (including all of its accounts receivable and inventory) to secure our obligations to J. Aron. Pursuant to an amendment to the security agreement effective September 30, 2019, no cash, deposit accounts or accounts receivable constitute collateral.

Note 10 - Long-Term Obligations and Notes Payable

Outstanding borrowings, net of unamortized debt discounts and certain deferred financing costs, under Delek’s existing debt instruments are as follows (in millions):



	September 30, 2019		December 31, 2018
Revolving Credit Facility	$	160.0	$	300.0
Term LoanCredit Facility ⁽¹⁾	924.1		682.9
Delek Logistics Credit Facility	596.3		456.7
Delek Logistics Notes ⁽²⁾	244.5		243.7
Reliant Bank Revolver	30.0		30.0
Promissory Notes	45.0		70.0
	1,999.9		1,783.3
Less: Current portion of long-term debt and notes payable	64.5		32.0
	$	1,935.4	$	1,751.3


⁽¹⁾	Net of deferred financing costs of $3.7 million and $3.5 million and debt discount of $10.4 million and $8.4 million at September 30, 2019 and December 31, 2018, respectively.


⁽²⁾	Net of deferred financing costs of $4.2 million and $4.8 million and debt discount of $1.3 million and $1.5 million at September 30, 2019 and December 31, 2018, respectively.

Outstanding Obligations/Facilities as of the Balance Sheet Dates

Delek Revolver and Term Loan

On March 30, 2018, (the "Closing Date"), Delek entered into (i) a new term loan credit agreement with Wells Fargo Bank, National Association, as administrative agent (the "Term Administrative Agent"), Delek, as borrower, certain subsidiaries of Delek, as guarantors, and the lenders from time to time party thereto, providing for a senior secured term loan facility in an amount of $700.0 million (the "Term Loan Credit Facility") and (ii) a second amended and restated credit agreement with Wells Fargo Bank, National Association, as administrative agent (the "Revolver Administrative Agent"), Delek, as borrower, certain subsidiaries of Delek, as guarantors, and the other lenders party thereto, providing for a senior secured asset-based revolving credit facility with commitments of $1.0 billion (the "Revolving Credit Facility" and, together with the Term Loan Credit Facility, the "New Credit Facilities").

The Revolving Credit Facility permits borrowings in Canadian dollars of up to $50.0 million. The Revolving Credit Facility also permits the issuance of letters of credit of up to $300.0 million, including letters of credit denominated in Canadian dollars of up to $10.0 million. Delek may designate restricted subsidiaries as additional borrowers under the Revolving Credit Facility.

The Term Loan Credit Facility was drawn in full for $700.0 million on the Closing Date at an original issue discount of 0.50%. Proceeds under the Term Loan Credit Facility, as well as proceeds of approximately $300.0 million in borrowings under the Revolving Credit Facility on the Closing Date, were used to repay certain indebtedness of Delek and its subsidiaries (the “Refinancing”), as well as certain fees, costs and expenses in connection with the closing of the New Credit Facilities, with any remaining proceeds held in cash. Proceeds of future borrowings under the Revolving Credit Facility will be used for working capital and general corporate purposes of Delek and its subsidiaries.

In connection with the Refinancing, we recorded a loss on extinguishment of debt totaling approximately $9.1 million all of which was recorded in the first quarter of 2018.



24 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

On May 22, 2019 (the "First Incremental Effective Date"), we amended the Term Loan Credit Facility agreement pursuant to the terms of the First Incremental Amendment to Term Loan Credit Agreement (the "Incremental Amendment"). Pursuant to the Incremental Amendment, the Company borrowed $250.0 million in aggregate principal amount of incremental term loans (the “Incremental Term Loans”) at an original issue discount of 0.75%, increasing the aggregate principal amount of loans outstanding under the Term Loan Credit Facility on the First Incremental Effective Date to $943.0 million. The terms of the Incremental Term Loans are substantially identical to the terms applicable to the initial term loans under the Term Loan Credit Facility borrowed in March 2018. There are no restrictions on the Company's use of the proceeds of the Incremental Term Loans, and the proceeds may be used for (i) reducing utilizations under the Revolving Credit Facility, (ii) general corporate purposes and (iii) paying transaction fees and expenses associated with the Incremental Amendment.

Interest and Unused Line Fees

The interest rates applicable to borrowings under the Term Loan Credit Facility and the Revolving Credit Facility are based on a fluctuating rate of interest measured by reference to either, at Delek’s option, (i) a base rate, plus an applicable margin, or (ii) a reserve-adjusted London Interbank Offered Rate ("LIBOR"), plus an applicable margin (or, in the case of Revolving Credit Facility borrowings denominated in Canadian dollars, the Canadian dollar bankers' acceptances rate ("CDOR")). The initial applicable margin for all Term Loan Credit Facility borrowings was 1.50% per annum with respect to base rate borrowings and 2.50% per annum with respect to LIBOR borrowings.

On October 26, 2018, Delek entered into an amendment to the Term Loan Credit Facility (the “First Amendment”) to reduce the margin on certain borrowings under the Term Loan Credit Facility and incorporate certain other changes. The First Amendment decreased the applicable margins for borrowings under (i) Base Rate Loans from 1.50% to 1.25% and (ii) LIBOR Rate Loans from 2.50% to 2.25%, as such terms are defined in the Term Loan Credit Facility.

The initial applicable margin for Revolving Credit Facility borrowings was 0.25% per annum with respect to base rate borrowings and 1.25% per annum with respect to LIBOR and CDOR borrowings, and the applicable margin for such borrowings after September 30, 2018 is based on Delek’s excess availability as determined by reference to a borrowing base, ranging from 0.25% to 0.75% per annum with respect to base rate borrowings and from 1.25% to 1.75% per annum with respect to LIBOR and CDOR borrowings.

In addition, the Revolving Credit Facility requires Delek to pay an unused line fee on the average amount of unused commitments thereunder in each quarter, where the fee is at a rate of 0.25% or 0.375% per annum, depending on average commitment usage for such quarter. As of September 30, 2019, the unused line fee was 0.375% per annum.

Maturity and Repayments

The Revolving Credit Facility will mature and the commitments thereunder will terminate on March 30, 2023. The Term Loan Credit Facility requires scheduled quarterly principal payments (which pursuant to the Incremental Amendment increased from $1.750 million to $2.375 million commencing with the quarterly principal payment due on June 28, 2019), with the balance of the principal due at maturity on March 30, 2025. Additionally, the Term Loan Credit Facility requires prepayments by Delek with the net cash proceeds from certain debt incurrences, asset dispositions and insurance or condemnation events with respect to Delek’s assets, subject to certain exceptions, thresholds and reinvestment rights. The Term Loan Credit Facility also requires annual prepayments with a variable percentage of Delek’s excess cash flow, ranging from 50.0% to 0% depending on Delek’s consolidated fiscal year end secured net leverage ratio. Delek may also make voluntarily prepayments under the Term Loan Credit Facility at any time, subject to a prepayment premium of 1.0% in connection with certain customary repricing events that may occur within six months after the First Incremental Effective Date, with no such premium applied after six months.

Guarantee and Security

The obligations of the borrowers under the New Credit Facilities are guaranteed by Delek and each of its direct and indirect, existing and future, wholly-owned domestic subsidiaries, subject to customary exceptions and limitations, and excluding Delek Logistics Partners, LP, Delek Logistics GP, LLC, and each subsidiary of the foregoing (collectively, the "MLP Subsidiaries"). Borrowings under the New Credit Facilities are also guaranteed by DK Canada Energy ULC, a British Columbia unlimited liability company and a wholly-owned restricted subsidiary of Delek.

The Revolving Credit Facility is secured by a first priority lien over substantially all of Delek’s and each guarantor's receivables, inventory, renewable identification numbers, instruments, intercompany loan receivables, deposit and securities accounts and related books and records and certain other personal property, subject to certain customary exceptions (the "Revolving Priority Collateral"), and a second priority lien over substantially all of Delek's and each guarantor's other assets, including all of the equity interests of any subsidiary held by Delek or any guarantor (other than equity interests in certain MLP Subsidiaries) subject to certain customary exceptions, but excluding real property (such real property and equity interests, the "Term Priority Collateral").

The Term Loan Credit Facility is secured by a first priority lien on the Term Priority Collateral and a second priority lien on the Revolving Priority Collateral, all in accordance with an intercreditor agreement between the Term Administrative Agent and the Revolver Administrative Agent and acknowledged by Delek and the subsidiary guarantors. Certain excluded assets are not included in the Term Priority Collateral and the Revolving Priority Collateral.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Additional Information

At September 30, 2019, the weighted average borrowing rate under the Revolving Credit Facility was 5.25% and was comprised entirely of a base rate borrowing, and the principal amount outstanding thereunder was $160.0 million. Additionally, there were letters of credit issued of approximately $293.5 million as of September 30, 2019 under the Revolving Credit Facility. Unused credit commitments under the Revolving Credit Facility, as of September 30, 2019, were approximately $546.5 million.

At September 30, 2019, the weighted average borrowing rate under the Term Loan Credit Facility was approximately 4.29% comprised entirely of a LIBOR borrowing, and the principal amount outstanding thereunder was $938.2 million. As of September 30, 2019, the effective interest rate related to the Term Loan Credit Facility was 4.61%.

Delek Logistics Credit Facility

Prior to its amendment and restatement on September 28, 2018, Delek Logistics had a $700.0 million senior secured revolving credit agreement with Fifth Third Bank ("Fifth Third"), as administrative agent, and a syndicate of lenders (the "2014 Facility") with a $100.0 million accordion feature, bearing interest at either a U.S. dollar prime rate, Canadian dollar prime rate, LIBOR, or a CDOR rate, in each case plus applicable margins, at the election of the borrowers and as a function of draw down currency. On September 28, 2018, Delek Logistics and all of its subsidiaries entered into a third amended and restated senior secured revolving credit agreement with Fifth Third as administrative agent and a syndicate of lenders (hereafter, the "Delek Logistics Credit Facility"). Under the terms of the Delek Logistics Credit Facility, among other things, the lender commitments were increased from $700.0 million to $850.0 million. The Delek Logistics Credit Facility also contains an accordion feature whereby Delek Logistics can increase the size of the credit facility to an aggregate of $1.0 billion, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent.

The obligations under the Delek Logistics Credit Facility remain secured by first priority liens on substantially all of Delek Logistics' tangible and intangible assets. Additionally, a subsidiary of Delek continues to provide a limited guaranty of Delek Logistics' obligations under the Delek Logistics Credit Facility. The guaranty is (i) limited to an amount equal to the principal amount, plus unpaid and accrued interest, of a promissory note made by Delek in favor of the subsidiary guarantor (the "Holdings Note") and (ii) secured by the subsidiary guarantor's pledge of the Holdings Note to the Delek Logistics Credit Facility lenders. As of both September 30, 2019 and December 31, 2018, the principal amount of the Holdings Note was $102.0 million.

The Delek Logistics Credit Facility has a maturity date of September 28, 2023. Borrowings under the Delek Logistics Credit Facility bear interest at either a U.S. dollar prime rate, Canadian dollar prime rate, LIBOR, or a CDOR rate, in each case plus applicable margins, at the election of the borrowers and as a function of draw down currency. The applicable margin in each case and the fee payable for the unused revolving commitments vary based upon Delek Logistics' most recent total leverage ratio calculation delivered to the lenders, as called for and defined under the terms of the Delek Logistics Credit Facility. At September 30, 2019, the weighted average borrowing rate was approximately 4.89%. Additionally, the Delek Logistics Credit Facility requires Delek Logistics to pay a leverage ratio dependent quarterly fee on the average unused revolving commitment. As of September 30, 2019, this fee was 0.50% per year.

As of September 30, 2019, Delek Logistics had $596.3 million of outstanding borrowings under the Delek Logistics Credit Facility, with no letters of credit in place. Unused credit commitments under the Delek Logistics Credit Facility, as of September 30, 2019, were $253.7 million.

Delek Logistics Notes

On May 23, 2017, Delek Logistics and Delek Logistics Finance Corp. (collectively, the “Issuers”) issued $250.0 million in aggregate principal amount of 6.75% senior notes due 2025 (the “Delek Logistics Notes”) at a discount. The Delek Logistics Notes are general unsecured senior obligations of the Issuers. The Delek Logistics Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by Delek Logistics' existing subsidiaries (other than Delek Logistics Finance Corp., the "Guarantors") and will be unconditionally guaranteed on the same basis by certain of Delek Logistics' future subsidiaries. The Delek Logistics Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. Interest on the Delek Logistics Notes is payable semi-annually in arrears on each May 15 and November 15, commencing November 15, 2017.

At any time prior to May 15, 2020, the Issuers may redeem up to 35% of the aggregate principal amount of the Delek Logistics Notes with the net cash proceeds of one or more equity offerings by Delek Logistics at a redemption price of 106.750% of the redeemed principal amount, plus accrued and unpaid interest, if any, subject to certain conditions and limitations. Prior to May 15, 2020, the Issuers may redeem all or part of the Delek Logistics Notes at a redemption price of the principal amount plus accrued and unpaid interest, if any, plus a "make whole" premium, subject to certain conditions and limitations. In addition, beginning on May 15, 2020, the Issuers may, subject to certain conditions and limitations, redeem all or part of the Delek Logistics Notes, at a redemption price of 105.063% of the redeemed principal for the twelve-month period beginning on May 15, 2020, 103.375% for the twelve-month period beginning on May 15, 2021, 101.688% for the twelve-month period beginning on May 15, 2022 and 100.00% beginning on May 15, 2023 and thereafter, plus accrued and unpaid interest, if any.

In the event of a change of control, accompanied or followed by a ratings downgrade within a certain period of time, subject to certain conditions and limitations, the Issuers will be obligated to make an offer for the purchase of the Delek Logistics Notes from holders at a price equal to 101.00% of the principal amount thereof, plus accrued and unpaid interest.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

In May 2018, the Delek Logistics Notes were exchanged for new notes with terms substantially identical in all material respects with the 2025 Notes except the new notes do not contain terms with respect to transfer restrictions.

As of September 30, 2019, we had $250.0 million in outstanding principal amount under the Delek Logistics Notes. As of September 30, 2019, the effective interest rate related to the Delek Logistics Notes was 7.24%.

Reliant Bank Revolver

Delek has an unsecured revolving credit agreement with Reliant Bank (the "Reliant Bank Revolver") that provides for unsecured loans of up to $30.0 million. The Reliant Bank Revolver matures June 28, 2020, bears interest at fixed rate of 4.75% per annum and requires us to pay a quarterly fee of 0.50% per year on the average unused revolving commitment. As of September 30, 2019, we had $30.0 million outstanding and had no unused credit commitments under the Reliant Bank Revolver.

Promissory Notes

Delek has four notes payable (the "Promissory Notes") with various assignees of Alon Israel Oil Company, Ltd., the holder of a predecessor consolidated promissory note, which bear interest at a fixed rate of 5.50% per annum and which, collectively, require annual principal amortization payments of $25.0 million through 2020 followed by a final principal amortization payment of $20.0 million at maturity on January 4, 2021. As of September 30, 2019, a total principal amount of $45.0 million was outstanding under the Promissory Notes.

Restrictive Covenants

Under the terms of our Revolving Credit Facility, Term Loan Credit Facility, Delek Logistics Credit Facility, Delek Logistics Notes and Reliant Bank Revolver, we are required to comply with certain usual and customary financial and non-financial covenants. The terms and conditions of the Revolving Credit Facility include periodic compliance with a springing minimum fixed charge coverage ratio financial covenant if excess availability under the revolver borrowing base is below certain thresholds, as defined in the credit agreement. The Term Loan Credit Facility does not have any financial maintenance covenants. We believe we were in compliance with all covenant requirements under each of our credit facilities as of September 30, 2019.

Certain of our debt facilities contain limitations on the incurrence of additional indebtedness, making of investments, creation of liens, dispositions and acquisitions of assets, and making of restricted payments and transactions with affiliates. Specifically, these covenants may limit the payment, in the form of cash or other assets, of dividends or other distributions, or the repurchase of shares with respect to the equity of the Company or certain of our subsidiaries. Additionally, certain of our debt facilities limit our ability to make investments, including extensions of loans or advances to, or acquisitions of equity interests in, or guarantees of obligations of, any other entities.

Instruments Outstanding as of September 30, 2018

Alon Convertible Senior Notes

In connection with the Delek/Alon Merger, Alon, New Delek and U.S. Bank National Association, as trustee (the “Trustee”) entered into a First Supplemental Indenture (the “Supplemental Indenture”), effective as of July 1, 2017, which provided that Alon's 3.00% Convertible Senior Notes due September 2018, which were previously convertible into Alon Common Stock, to thereafter be convertible into New Delek Common Stock based on the exchange rate applied in the Delek/Alon Merger (as previously defined, the “Convertible Notes”). Additionally, in connection with the Convertible Notes, Alon entered into equity instruments, including call options (as previously defined, the "Call Options") and warrants (as previously defined, the "Warrants"), designed, in combination, to hedge a portion of the economic risk associated with the potential exercise of the conversion feature of the Convertible Notes and to mitigate the dilutive effect of such potential conversion. The aggregate principal amount of the Convertible Notes was $150.0 million, and the effective interest rate as of September 30, 2018 was 5.92%, resulting in recognition of total interest expense during the three and nine months then ended of approximately $2.2 million and $6.6 million, respectively.

The Convertible Notes could be converted into shares of Delek Common Stock, into cash, or into a combination of cash and shares of New Delek Common Stock, at our election. In May 2018, we made the election and notified holders of our intention to satisfy the principal amount outstanding with cash and the incremental value of the conversion options with shares at maturity. The conversion rate of the Convertible Notes was subject to adjustment upon the occurrence of certain events, including cash dividend adjustments. On September 17, 2018, Delek settled the Convertible Notes for a combination of cash and shares of New Delek Common Stock. The maturity settlement in respect of the Convertible Notes consisted of (i) cash payments totaling approximately $152.5 million which included a cash payment for outstanding principal of $150.0 million, a cash payment for accrued interest of approximately $2.2 million, a cash payment for dividends of approximately $0.3 million and a nominal cash payment in lieu of fractional shares, and (ii) the issuance of approximately 2.7 million shares of New Delek Common Stock to holders of the Convertible Notes (the “Conversion Shares”). The issuance of the Conversion Shares was made in exchange for the Convertible Notes pursuant to an exemption from the registration requirements provided by Section 3(a)(9) of the Securities Act of 1933, as amended. Prior to the conversion, the conversion feature met the definition for recognition as a bifurcated equity instrument.

Convertible Note Hedge Transactions

In connection with the Convertible Notes offering, Alon entered into convertible note hedge transactions with respect to Alon Common Stock (as previously defined, the “Call Options”) with the initial purchasers of the Convertible Notes (the “Hedge Counterparties”). In connection



27 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

with the Delek/Alon Merger, Alon, Delek and the Hedge Counterparties entered into amended and restated Call Options permitting us to purchase up to approximately 5.7 million shares of New Delek Common Stock, subject to customary anti-dilution adjustments, that underlie the Convertible Notes sold in the offering.

On September 17, 2018, we exercised the Call Options in connection with the settlement of the Convertible Notes and received approximately 2.7 million shares of our common stock from the Call Option counterparties, a cash payment for dividends of approximately $0.3 million and a nominal cash payment in lieu of fractional shares. On a net basis, the settlement of the Convertible Notes and the exercise of the Call Options resulted in no net dilution to our common stock. Prior to their exercise, the Call Options totaling $23.3 million were included as a reduction of additional paid-in capital on the condensed consolidated balance sheets.

Warrant Transactions

In connection with the Convertible Notes offering, Alon also entered into warrant transactions (as previously defined, the “Warrants”) whereby warrants to acquire Alon common stock were sold to the Hedge Counterparties. In connection with the Delek/Alon Merger, Alon, Delek and the Hedge Counterparties entered into amended and restated Warrants which allow the Hedge Counterparties to purchase up to approximately 5.7 million shares of New Delek Common Stock, subject to customary anti-dilution adjustments. In November 2018, Delek entered into Warrant Unwind Agreements (as previously defined, the "Unwind Agreements") with the holders of our outstanding common stock Warrants. Pursuant to the terms of the Unwind Agreements, we settled for cash all outstanding Warrants with the holders at various prices per Warrant as provided in the Unwind Agreements. The settlement amount was based on the volume-weighted average market price of our common stock taking into account an adjustment for the exercise price of the Warrants over a period of sixteen trading days beginning November 9, 2018 (the “Unwind Period”). Following the Unwind Period and upon the satisfaction of the payment obligation, the Warrants were canceled and the associated rights and obligations terminated. Based on the provisions of the Unwind Agreements, the amount paid to warrant holders in satisfaction of the payment obligation totaled approximately $36.0 million.

Obligations Extinguished in Connection with the March 2018 Refinancing

During the first quarter 2018, Delek had outstanding various credit facilities/debt instruments as follows, all of which were extinguished in connection with the March 2018 Refinancing:

Wells ABL

Our subsidiary, Delek Refining, Ltd., had an asset-based loan credit facility with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders, which was previously amended and restated on September 29, 2016 (the "Wells ABL"). The Wells ABL consisted of (i) a $450.0 million revolving loan (the "Wells Revolving Loan") and (ii) a $70 million term loan ("Wells Term Loan"). Borrowings under the Wells Revolving Loan and Wells Term Loan bore interest based on separate predetermined pricing grids that allowed us to choose between base rate loans or LIBOR rate loans. Additionally, the Wells ABL required us to pay a quarterly unused credit commitment fee. This facility was amended and restated on March 30, 2018 in connection with the Refinancing and replaced by the New Credit Facilities, as previously defined.

Lion Term Loan

Our subsidiary, Lion Oil, had a term loan credit facility with Fifth Third Bank, as administrative agent, and a syndicate of lenders, with a total loan size of $275.0 million (the "Lion Term Loan"). For the period(s) it was outstanding, interest on the unpaid balance of the Lion Term Loan was computed at a rate per annum equal to LIBOR or a base rate, at our election, plus the applicable margins, subject in each case to an all-in interest rate floor of 5.50% per annum.

Alon Partnership Facilities

Revolving Credit Facility

Alon USA, LP, a wholly-owned subsidiary of the Alon Partnership had a $240.0 million asset-based revolving credit facility with Israel Discount Bank of New York, as administrative agent (the “Alon Partnership Credit Facility”). Borrowings under the Alon Partnership Credit Facility bore interest at LIBOR or base rate, at our election, plus the applicable margins.

Partnership Term Loan Credit Facility

The Alon Partnership had a $250.0 million term loan with Credit Suisse AG, as administrative agent (the “Alon Partnership Term Loan”). The Alon Partnership Term Loan bore interest at a rate per annum equal to LIBOR (subject to a floor of 1.25%) or a base rate plus the applicable margins.

Alon Term Loan Credit Facilities

Alon Energy Term Loan

Alon had a promissory note to Bank Hapoalim B.M. in an original principal amount of $38.0 million ("New Alon Energy Term Loan"). The New Alon Energy Term Loan incurred interest at an annual rate equal to LIBOR plus an applicable margin.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Alon Asphalt Term Loan

Alon had a term loan owed to Export Development Canada secured by liens on certain of our asphalt terminals (“Alon Asphalt Term Loan”) in an original principal amount of $35.0 million. The Alon Asphalt Term Loan bore interest at a rate equal to LIBOR plus an applicable margin.

Alon Retail Credit Agreement

Alon wholly-owned subsidiaries Southwest Convenience Stores, LLC and Skinny’s LLC, (collectively, “Alon Retail”), had a credit agreement (“Alon Retail Credit Agreement”), that was to mature in March 2019, with Wells Fargo Bank, National Association, as administrative agent. The Alon Retail Credit Agreement included a term loan in an original principal amount of $110.0 million and a $10.0 million revolving credit facility. Borrowings under the Alon Retail Credit Agreement bore interest at LIBOR or base rate, at our election, plus an applicable margin, determined quarterly based upon Alon Retail’s leverage ratio.

Total Amounts Outstanding and Repaid

Principal amounts outstanding and repaid in connection with the March 2018 Refinancing with respect to these credit facilities/debt instruments were as follows:



(in millions)	Amount Outstanding/Repaid at March 30, 2018
Wells ABL	$	40.8
Lion Term Loan	206.3
Alon Partnership Facilities	236.9
Alon Term Loan Credit Facilities	38.0
Alon Retail Credit Agreement	86.4
Total	$	608.4

Additionally, on March 29, 2018, in anticipation of the March 2018 Refinancing, we also repaid $35 million of principal on the Alon Asphalt Term Loan.

Note 11 - Derivative Instruments

We use the majority of our derivatives to reduce normal operating and market risks with the primary objective of reducing the impact of market price volatility on our results of operations. As such, our use of derivative contracts is aimed at:


•	limiting the exposure to price fluctuations of commodity inventory above or below target levels at each of our segments;


•	managing our exposure to commodity price risk associated with the purchase or sale of crude oil, feedstocks and finished grade fuel products at each of our segments;


•	managing the cost of our credits for commitments required by the U.S. Environmental Protection Agency ("EPA") to blend biofuels into fuel products ("RINs Obligation") using future commitments to purchase or sell renewable identification numbers ("RINs") at fixed prices and quantities; and


•	limiting the exposure to interest rate fluctuations on our floating rate borrowings.

We primarily utilize commodity swaps, futures, forward contracts and options contracts, generally with maturity dates of three years or less, and from time to time interest rate swap agreements, to achieve these objectives. Futures contracts are standardized agreements, traded on a futures exchange, to buy or sell the commodity at a predetermined price at a specified future date. Options provide the right, but not the obligation to buy or sell the commodity at a specified price in the future. Commodity swap and futures contracts require cash settlement for the commodity based on the difference between a fixed or floating price and the market price on the settlement date, and options require payment of an upfront premium. Because these derivatives are entered into to achieve objectives specifically related to our inventory and production risks, such gains and losses (to the extent not designated as accounting hedges and recognized on an unrealized basis in other comprehensive income) are recognized in cost of materials and other.

During the first quarter of 2018, we utilized interest rate swap agreements to hedge floating rate debt by exchanging interest rate cash flows, based on a notional amount from a floating rate to a fixed rate. Effective with the Delek/Alon Merger, we had four interest rate swap agreements (that had maturities in March 2019) which effectively fixed the variable LIBOR interest component of the term loan within the Alon Retail Credit Agreement. The aggregate notional amount under these agreements were to cover approximately 77% of the outstanding principal of these term loans throughout the duration of the interest rate swaps. These interest rate swap agreements were terminated due to the extinguishment of the Alon Retail Credit Agreement in connection with the Refinancing on March 30, 2018, resulting in a reclassification of unrealized loss of $0.6 million from accumulated other comprehensive income to interest expense on the condensed consolidated statements of income during



29 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

the nine months ended September 30, 2018.

Forward contracts are agreements to buy or sell a commodity at a predetermined price at a specified future date, and for our transactions, generally require physical delivery. Forward contracts where the underlying commodity will be used or sold in the normal course of business qualify as normal purchases and normal sales pursuant to ASC 815 and are not accounted for as derivative instruments. Rather, such forward contracts are accounted for under other applicable GAAP. Forward contracts entered into for trading purposes that do not meet the normal purchases, normal sales exception are accounted for as derivative instruments at fair value with changes in fair value recognized in earnings in the period of change. As of September 30, 2019 and December 31, 2018, and for the three and nine months ended September 30, 2019 and September 30, 2018, our forward contracts that were accounted for as derivative instruments primarily consisted of contracts related to our Canadian crude trading operations. Since Canadian crude trading activity is not related to managing supply or pricing risk of the actual inventory that will be used in production, such unrealized and realized gains and losses are recognized in other operating income, net rather than cost of materials and other on the accompanying condensed consolidated statements of income.

Futures, swaps or other commodity related derivative instruments that are utilized to specifically provide economic hedges on our Canadian forward contract or investment positions are recognized in other operating income, net because that is where the related underlying transactions are reflected.

From time to time, we also enter into future commitments to purchase or sell RINs at fixed prices and quantities, which are used to manage the costs associated with our RINs Obligation. These future RIN commitment contracts meet the definition of derivative instruments under ASC 815, and are recorded at estimated fair value in accordance with the provisions of ASC 815. Changes in the fair value of these future RIN commitment contracts are recorded in cost of materials and other on the condensed consolidated statements of income.

At this time, we do not believe there is any material credit risk with respect to the counterparties to any of our derivative contracts.

In accordance with ASC 815, certain of our commodity swap contracts and our interest rate agreements have been designated as cash flow hedges and the change in fair value between the execution date and the end of period (or early termination date in regards to the four Alon retail interest rate swaps discussed above) has been recorded in other comprehensive income. The fair value of these contracts is recognized in income in the same financial statement line item as hedged transaction at the time the positions are closed and the hedged transactions are recognized in income.

The following table presents the fair value of our derivative instruments as of September 30, 2019 and December 31, 2018. The fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under our master netting arrangements, including cash collateral on deposit with our counterparties. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements. As a result, the asset and liability amounts below differ from the amounts presented in our condensed consolidated balance sheets. See Note 12 for further information regarding the fair value of derivative instruments (in millions).



		September 30, 2019					December 31, 2018
Derivative Type	Balance Sheet Location	Assets		Liabilities			Assets		Liabilities
Derivatives not designated as hedging instruments:
Commodity derivatives⁽¹⁾	Other current assets	$	272.5	$	(278.1	)	$	158.3	$	(142.4	)
Commodity derivatives⁽¹⁾	Other current liabilities	14.0		(16.4		)	—		(8.4		)
Commodity derivatives⁽¹⁾	Other long-term assets	29.8		(29.6		)	2.1		(2.4		)
Commodity derivatives⁽¹⁾	Other long-term liabilities	34.8		(38.6		)	93.0		(94.0		)
RIN commitment contracts⁽²⁾	Other current assets	5.9		—			2.0		—
RIN commitment contracts⁽²⁾	Other current liabilities	—		(3.5		)	—		(6.7		)

Derivatives designated as hedging instruments:
Commodity derivatives ⁽¹⁾	Other current assets	18.1		(3.2		)	200.3		(157.0		)
Commodity derivatives⁽¹⁾	Other current liabilities	1.7		(1.3		)	—		—
Commodity derivatives⁽¹⁾	Other long-term assets	1.7		(1.3		)	6.1		(4.8		)
Total gross fair value of derivatives		$	378.5	$	(372.0	)	$	461.8	$	(415.7	)
Less: Counterparty netting and cash collateral⁽³⁾		329.2		(358.0		)	399.9		(399.5		)
Total net fair value of derivatives		$	49.3	$	(14.0	)	$	61.9	$	(16.2	)

⁽¹⁾

As of September 30, 2019 and December 31, 2018, we had open derivative positions representing 95,410,250 and 39,277,822 barrels, respectively, of crude oil and refined petroleum products. Additionally, as of September 30, 2019, we had open derivative positions representing 76,510,000 MMBTU of natural gas products. Of these open positions, contracts representing 2,752,000 and 16,461,000 barrels were designated as cash flow hedging instruments as of September 30, 2019 and December 31, 2018, respectively.


⁽²⁾	As of September 30, 2019 and December 31, 2018, we had open RIN commitment contracts representing 283,381,000 and 137,750,000 RINs, respectively.


⁽³⁾	As of September 30, 2019 and December 31, 2018, $28.8 million and $(0.4) million, respectively, of cash collateral (obligation) held by counterparties has been netted with the derivatives with each counterparty.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Total gains (losses) on our hedging derivatives and RIN commitment contracts recorded in the condensed consolidated statements of income are as follows (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019		2018
Gains (losses) on commodity derivatives not designated as hedging instruments recognized in cost of materials and other ⁽¹⁾	$	(8.0	)	$	(9.3	)	$	8.5	$	(23.7	)
Gains (losses) on commodity derivatives not designated as hedging instruments recognized in other operating income, net ^{(1) (2)}	(0.3		)	(0.6		)	0.2		(3.5		)
Realized gains (losses) reclassified out of AOCI and into cost of materials and other on commodity derivatives designated as cash flow hedging instruments	21.1			(9.6		)	55.0		(18.4		)
Gains (losses) recognized in cost of materials and other due to cash flow hedging ineffectiveness on commodity derivatives designated as hedging instruments	—			—			—		0.7
Total gains (losses)	$	12.8		$	(19.5	)	$	63.7	$	(44.9	)

⁽¹⁾

Gains (losses) on commodity derivatives that are economic hedges but not designated as hedging instruments include unrealized gains (losses) of $0.5 million and $(30.1) million for the three and nine months ended September 30, 2019, respectively, and $13.0 million and $2.8 million for the three and nine months ended September 30, 2018, respectively. Of these amounts, approximately $(12.2) million and $(21.1) million for the three and nine months ended September 30, 2019, respectively, and $20.6 million and $1.4 million for the three and nine months ended September 30, 2018, respectively, represent unrealized gains (losses) where the instrument has matured but where it has not cash settled as of period end, including the reversal of prior period settlement timing differences. Derivative instruments that have matured but not cash settled at the balance sheet date continue to be reflected in derivative assets or liabilities on our balance sheet.


⁽²⁾	See separate table below for disclosures about "trading derivatives."

The effect of cash flow hedge accounting on the consolidated statements of income is as follows (in millions):



	Three Months Ended September 30,			Nine Months Ended September 30,
	2019			2019
Gain (loss) on cash flow hedging relationships recognized in cost of materials and other:
Commodity contracts:
Hedged items	$	(21.1	)	$	(55.0	)
Derivative designated as hedging instruments	21.1			55.0
Total	$	—		$	—

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2019 or 2018. As of September 30, 2019, we estimate that $21.4 million of deferred gains related to commodity cash flow hedges will be reclassified into cost of materials and other over the next 12 months as a result of hedged transactions that are forecasted to occur.

Total gains on our trading physical forward contract derivatives (none of which were designated as hedging instruments) recorded in other operating income (expense), net on the condensed consolidated statements of income are as follows (in millions):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019		2018
Realized (losses) gains	$	(1.4	)	$	1.7	$	3.3	$	10.5
Unrealized gains	4.5			3.8		6.6		6.7
Total	$	3.1		$	5.5	$	9.9	$	17.2

Note 12 - Fair Value Measurements

Delek applies the provisions of ASC 820, Fair Value Measurements ("ASC 820"), which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. ASC 820 requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1



31 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting our assumptions about pricing by market participants.

Commodity swaps, exchange-traded futures, options, physical commodity forward purchase and sale contracts (that do not qualify as normal purchases or normal sales), and interest rate swaps are generally valued using industry-standard models that consider various assumptions, including quoted forward prices, spot prices, interest rates, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines the classification as Level 2 or 3. Our contracts are valued based on exchange pricing and/or price index developers such as Platts or Argus and are, therefore, classified as Level 2. Commodity investments are valued using published market prices of the commodity on the applicable exchange and are, therefore, classified as Level 1.

Our Environmental Credits Obligation surplus or deficit is based on the amount of RINs or other emissions credits we must purchase, net of amounts internally generated and purchased and the price of those RINs or other emissions credits as of the balance sheet date, by refinery/obligor. The Environmental Credits Obligation surplus or deficit is categorized as Level 2, and is measured at fair value either directly through observable inputs or indirectly through market-corroborated inputs.

During the third quarter of 2019, the Tyler, El Dorado and Krotz Springs refineries received approval from the EPA for a small refinery exemption from the requirements of the renewable fuel standard ("RIN Waivers") for the 2018 calendar year, which resulted in a reduction of our RINs Obligation and related cost of materials and other of approximately $20.7 million for the three and nine months ended September 30, 2019. During the first quarter 2019, the Tyler and Big Spring refineries received RIN Waivers for the 2017 calendar year, which had an immaterial impact on our results of operations, while the 2017 RIN Waivers for the El Dorado and Krotz Springs refineries received in March 2018 resulted in a reduction of our RINs Obligation and related cost of materials and other of approximately $90.9 million for the nine months ended September 30, 2018.

Our RIN commitment contracts are future commitments to purchase or sell RINs at fixed prices and quantities, which are used to manage the costs associated with our RINs Obligation. These RIN commitment contracts are categorized as Level 2, and are measured at fair value based on quoted prices from an independent pricing service. Changes in the fair value of these future RIN commitment contracts are recorded in cost of materials and other on the condensed consolidated statements of income.

The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of Delek's assets and liabilities that fall under the scope of ASC 825. As of and for the nine months ended September 30, 2019 and 2018, we elected to account for our J. Aron step-out liability at fair value in accordance with ASC 825, as it pertains to the fair value option. This standard permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. Our J. Aron step-out liability was categorized as Level 2, and measured at fair value using market prices for the consigned crude oil and refined products we were required to repurchase from J. Aron at the end of the term of the Supply and Offtake Agreement prior to the December 2018/January 2019 amendments to each of the Supply and Offtake Agreements. The J. Aron step-out liability was presented in the Obligation under Supply and Offtake Agreement line item of our condensed consolidated balance sheets. Gains (losses) related to the change in fair value was recorded as a component of cost of materials and other in the condensed consolidated statements of income. With respect to the amended Supply and Offtake Agreements, such amendments being effective December 2018 for our Big Spring Agreement and January 2019 for our El Dorado and Krotz Springs Agreements and as all subsequently amended on September 19, 2019, we apply fair value measurement as follows: (1) we determine fair value for our amended fixed-price step-out liability based on changes in fair value related to interest rate risk where such obligation is categorized as Level 2 and is presented in the current or long-term portion, based on maturity of the agreement, of the Obligation under Supply and Offtake Agreements on our condensed consolidated balance sheets, and where gains (losses) related to changes in fair value are recorded as a component of interest expense in the condensed consolidated statements of income; and (2) we determine fair value of the short-term commodity-indexed financing facility based on the market prices for the consigned crude oil and refined products collateralizing the financing/funding where such obligation is categorized as Level 2 and is presented in the current portion of the Obligation under Supply and Offtake Agreements on our condensed consolidated balance sheets, and where gains (losses) related to the change in fair value are recorded as a component of cost of materials and other in the condensed consolidated statements of income.

Commodity investments represent those commodities (generally crude oil) physically on hand as a result of trading activities with physical forward contracts. Such investment stores, included in other current assets on the condensed consolidated balance sheets, are maintained on a weighted average cost basis for determining realized gains and losses on physical sales under forward contracts, and ending balances are adjusted to fair value at each reporting date. The unrealized gain (loss) on commodity investments for the three and nine months ended September 30, 2019 totaled $0.1 million and $(1.9) million, respectively.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis was as follows (in millions):



	September 30, 2019
	Level 1		Level 2			Level 3		Total
Assets
Commodity derivatives	$	—	$	372.6		$	—	$	372.6
Commodity investments	6.0		—			—		6.0
RIN commitment contracts	—		5.9			—		5.9
Environmental Credits Obligation surplus	—		20.2			—		20.2
Total assets	6.0		398.7			—		404.7
Liabilities
Commodity derivatives	—		(368.5		)	—		(368.5		)
RIN commitment contracts	—		(3.5		)	—		(3.5		)
Environmental Credits Obligation deficit	—		(16.7		)	—		(16.7		)
J. Aron step-out liability	—		(408.6		)	—		(408.6		)
Total liabilities	—		(797.3		)	—		(797.3		)
Net assets (liabilities)	$	6.0	$	(398.6	)	$	—	$	(392.6	)



	December 31, 2018
	Level 1		Level 2			Level 3		Total
Assets
Commodity derivatives	$	—	$	459.8		$	—	$	459.8
Commodity investments	15.8		—			—		15.8
RIN commitment contracts	—		2.0			—		2.0
Environmental Credits Obligation surplus	—		10.3			—		10.3
Total assets	15.8		472.1			—		487.9
Liabilities
Commodity derivatives	—		(409.0		)	—		(409.0		)
RIN commitment contracts	—		(6.7		)	—		(6.7		)
Environmental Credits Obligation deficit	—		(11.8		)	—		(11.8		)
J. Aron step-out liability	—		(362.2		)	—		(362.2		)
Total liabilities	—		(789.7		)	—		(789.7		)
Net assets (liabilities)	$	15.8	$	(317.6	)	$	—	$	(301.8	)

The derivative values above are based on analysis of each contract as the fundamental unit of account as required by ASC 820. In the table above, derivative assets and liabilities with the same counterparty are not netted where the legal right of offset exists. This differs from the presentation in the financial statements which reflects our policy, wherein we have elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty and where the legal right of offset exists. As of September 30, 2019 and December 31, 2018, $28.8 million and $(0.4) million, respectively, of cash collateral (obligation) was held by counterparty brokerage firms and has been netted with the net derivative positions with each counterparty. See Note 11 for further information regarding derivative instruments.

Note 13 - Commitments and Contingencies

Litigation

In the ordinary conduct of our business, we are from time to time subject to lawsuits, investigations and claims, including environmental claims and employee-related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, including civil penalties or other enforcement actions, we do not believe that any currently pending legal proceeding or



33 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

proceedings to which we are a party will have a material adverse effect on our financial statements. Certain environmental matters that have or may result in penalties or assessments are discussed below in the "Environmental, Health and Safety" section of this Note.

One of our Alon subsidiaries was the defendant in a legal action related to an easement dispute arising from a purchase of property that occurred in October 2013, prior to the Delek/Alon Merger. In June 2019, the court found in favor of the plaintiffs and assessed damages against such subsidiary totaling $6.7 million, which is included as of September 30, 2019 in accrued expenses and other current liabilities on the accompanying condensed consolidated balance sheet, and which reflects a $5.7 million increase in the accrual recorded during the nine months ended September 30, 2019, none of which was recorded for the third quarter. Additionally, through September 30, 2019, we have incurred $1.2 million of related legal expenses, of which none and $1.1 million was incurred during the three and nine months ended September 30, 2019, respectively, and has been recorded in general and administrative expenses in the accompanying condensed consolidated statements of income.

As of September 30, 2019 and December 31, 2018, AltAir (one of the California Discontinued Entities) was the party to a lawsuit whereby the plaintiff alleged breach of contract relating to a supply agreement during the period prior to the Delek/Alon Merger. We recorded a contingent liability associated with this matter (the "Ten-Tex Litigation") totaling $5.0 million as part of the purchase price allocation, which was finalized in June 2018. In July 2019, we reached a settlement with the plaintiff, whereby we were obligated for $2.3 million of the judgment against AltAir plus expected legal fees of approximately $0.3 million. Related to this obligation, we reduced our litigation accrual by $2.4 million during the nine months ended September 30, 2019, which was recorded in discontinued operations. In August 2019, we reached an agreement with World Energy to offset amounts payable by Delek under our seller obligations for the Ten-Tex Litigation matter against the working capital settlement receivable, and to convert the net receivable into the World Energy Note Receivable . As a result, this obligation is no longer reflected in our liabilities on the condensed consolidated balance sheet as of September 30, 2019. See Note 7 for further discussion of these matters.

Self-insurance

Delek records a self-insurance accrual for workers’ compensation claims up to a $4.0 million deductible on a per accident basis, general liability claims up to $4.0 million on a per occurrence basis and medical claims for eligible full-time employees up to $0.3 million per covered individual per calendar year. We also record a self-insurance accrual for auto liability up to a $4.0 million deductible on a per accident basis.

We have umbrella liability insurance available to each of our segments in an amount determined reasonable by management.

Environmental, Health and Safety

We are subject to extensive federal, state and local environmental and safety laws and regulations enforced by various agencies, including the EPA, the United States Department of Transportation, the Occupational Safety and Health Administration, as well as numerous state, regional and local environmental, safety and pipeline agencies. These laws and regulations govern the discharge of materials into the environment, waste management practices, pollution prevention measures and the composition of the fuels we produce, as well as the safe operation of our plants and pipelines and the safety of our workers and the public. Numerous permits or other authorizations are required under these laws and regulations for the operation of our refineries, renewable fuels facilities, terminals, pipelines, underground storage tanks, trucks, rail cars and related operations, and may be subject to revocation, modification and renewal.

These laws and permits raise potential exposure to future claims and lawsuits involving environmental and safety matters which could include soil and water contamination, air pollution, personal injury and property damage allegedly caused by substances which we manufactured, handled, used, released or disposed of, transported, or that relate to pre-existing conditions for which we have assumed responsibility. We believe that our current operations are in substantial compliance with existing environmental and safety requirements. However, there have been and will continue to be ongoing discussions about environmental and safety matters between us and federal and state authorities, including notices of violations, citations and other enforcement actions, some of which have resulted or may result in changes to operating procedures and in capital expenditures. While it is often difficult to quantify future environmental or safety related expenditures, we anticipate that continuing capital investments and changes in operating procedures will be required for the foreseeable future to comply with existing and new requirements, as well as evolving interpretations and more strict enforcement of existing laws and regulations.

The Big Spring refinery has been negotiating an agreement with the EPA for over 10 years under the EPA’s National Petroleum Refinery Initiative regarding alleged historical violations of the federal Clean Air Act related to emissions and emissions control equipment. A Consent Decree resolving these alleged historical violations for the Big Spring refinery was lodged with the United States District Court for the Northern District of Texas on June 6, 2017. An amendment to the Consent Decree was agreed upon by Delek and the EPA/ United States Department of Justice (the "DOJ"), in late 2018 and was executed by Delek. The amended Consent Decree was lodged during the first quarter of 2019, and was entered by the Court on June 5, 2019. The civil penalty of $0.5 million was paid on June 18, 2019. Per the Consent Decree, the Company will be required to expend capital for pollution control equipment that may be significant over the next 10 years.

As of September 30, 2019, we have recorded an environmental liability of approximately $142.8 million, primarily related to the estimated probable costs of remediating or otherwise addressing certain environmental issues of a non-capital nature at our refineries, as well as terminals, some of which we no longer own. This liability includes estimated costs for ongoing investigation and remediation efforts, which were already being performed by the former operators of the refineries and terminals prior to our acquisition of those facilities, for known



34 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

contamination of soil and groundwater, as well as estimated costs for additional issues which have been identified subsequent to the acquisitions. Approximately $3.7 million of the total liability is expected to be expended over the next 12 months, with most of the balance expended by 2032, although some costs may extend up to 30 years. In the future, we could be required to extend the expected remediation period or undertake additional investigations of our refineries, pipelines and terminal facilities, which could result in the recognition of additional remediation liabilities.

Crude Oil and Other Releases

We have experienced several crude oil and other releases involving our assets, including five releases that occurred in 2019 and six releases that occurred in 2018. Cleanup operations and site maintenance and remediation efforts on these and other releases are at various stages of completion. The majority of the remediation efforts for these releases have been substantially completed or have received regulatory closure. Boom maintenance and confirmatory sampling is currently underway at some sites. We expect regulatory closure by the end of 2019 for some release sites that have not yet received it, with closure on a few remaining sites occurring in 2020.

Many of the releases have occurred on the SALA Gathering System. During the nine months ended September 30, 2019, we decommissioned certain sections of the SALA Gathering System in an effort to improve the safety and integrity of the system. The decommissioning of these sections was completed in August 2019. The decommissioning project did not have a material effect on the operational capabilities of the system.

On October 3, 2019, a finished product release involving one of our pipelines occurred near Sulphur Springs, Texas (the "Sulphur Springs Release"). Cleanup operations and site maintenance and remediation on this release are expected to be completed in the fourth quarter of 2019. We currently estimate the maintenance and remediation efforts to cost between $4.0 million and $6.0 million, excluding any fines or penalties assessed by regulatory agencies. We anticipate that we will incur certain fines or penalties but we cannot currently estimate those costs. No accrual is recorded for the Sulphur Springs Release as of September 30, 2019, as the release occurred subsequent to that date. We are evaluating whether there may be potential recoveries or indemnification of the costs incurred for the Sulphur Springs Release.

The DOJ, on behalf of the EPA, and the State of Arkansas, on behalf of the Arkansas Department of Environmental Quality, have been pursuing an enforcement action against Delek Logistics with regard to potential violations of the Clean Water Act and certain state laws arising from the release of crude oil from a pumping facility at its Magnolia Station near the El Dorado Refinery ( the "Magnolia Release") since June 2015. On July 13, 2018, the DOJ and the State of Arkansas filed a civil action against two of Delek Logistics’ wholly-owned subsidiaries, Delek Logistics Operating LLC and SALA Gathering Systems LLC, in the United States District Court for the Western District of Arkansas.

In December 2018, Delek, the United States and the state of Arkansas reached an agreement to settle the claims related to the Magnolia Release for $2.2 million and the claims against Delek Logistics were resolved and an additional demand for a compliance audit at the Magnolia terminal was abandoned pursuant to payment of monetary penalties and other relief. In July 2019, Delek signed and submitted to the DOJ, a consent decree (the "Magnolia Consent Decree") to settle the release, and on August 30, 2019, the Magnolia Consent Decree was lodged with the Court. We expect the Magnolia Consent Decree to be finalized and to settle the payable in the fourth quarter of 2019. As of September 30, 2019, $2.2 million for the Magnolia Release is recorded in accounts payable in our condensed consolidated balance sheet.

Letters of Credit

As of September 30, 2019, we had in place letters of credit totaling approximately $293.5 million with various financial institutions securing obligations primarily with respect to our commodity purchases for the refining segment and certain of our insurance programs. There were no amounts drawn by beneficiaries of these letters of credit at September 30, 2019.

Note 14 - Income Taxes

Under ASC 740, Income Taxes (“ASC 740”), companies are required to apply an estimated annual tax rate to interim period results on a year-to-date basis; however, the estimated annual tax rate should not be applied to interim financial results if a reliable estimate cannot be made. In this situation, the interim tax rate should be based on actual year-to-date results. We used an estimated annual tax rate to record income taxes for the three and nine months ended September 30, 2019 and September 30, 2018.

Our effective tax rate was 18.3% and 21.9% for the three and nine months ended September 30, 2019, respectively, compared to 21.5% and 22.0% for the three and nine months ended September 30, 2018, respectively. The difference between the effective tax rate and the statutory rate is generally attributable to permanent differences and discrete items. The change in our effective tax rate was primarily due to the reversal of a reserve for uncertain tax positions, net of an increase in a valuation allowance related to state net operating loss carryforwards, reflected in the three months ended September 30, 2019 as compared to the three months ended September 30, 2018.



35 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

Note 15 - Related Party Transactions

Our related party transactions consist primarily of transactions with our equity method investees (See Note 6 ). Transactions with our related parties were as follows for the periods presented:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Revenues ⁽¹⁾	$	45.1	$	9.0	$	73.3	$	31.7
Cost of materials and other ⁽²⁾	$	20.3	$	4.8	$	33.7	$	15.7


⁽¹⁾	Consists primarily of asphalt sales which are recorded in corporate, other and eliminations segment.


⁽²⁾	Consists primarily of pipeline throughput fees paid by the refining segment and asphalt purchases.

Note 16 - Other Assets and Liabilities

The detail of other current assets is as follows (in millions):



Other Current Assets	September 30, 2019		December 31, 2018
Short-term derivative assets (see Note 11)	$	48.7	$	61.9
Prepaid expenses	21.0		15.8
Environmental Credits Obligation surplus (see Note 12)	20.2		10.3
Income and other tax receivables	7.8		24.3
Commodity investments	6.0		15.6
Note receivable - current portion (see Note 7)	4.6		—
Other	6.8		7.8
Total	$	115.1	$	135.7

The detail of other non-current assets is as follows (in millions):



Other Non-Current Assets	September 30, 2019		December 31, 2018
Supply and Offtake receivable	$	32.7	$	32.7
Note receivable - non-current portion (see Note 7)	7.7		—
Deferred financing costs	8.7		10.6
Other equity Investments	6.9		—
Long-term derivative assets (see Note 11)	0.6		1.0
Other	9.8		8.6
Total	$	66.4	$	52.9



36 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

The detail of accrued expenses and other current liabilities is as follows (in millions):



Accrued Expenses and Other Current Liabilities	September 30, 2019		December 31, 2018
Crude liabilities	$	223.5	$	42.3
Income and other taxes payable	105.8		126.0
Employee costs	38.7		46.5
Product financing agreements	21.0		—
Environmental Credits Obligation deficit (see Note 12)	16.7		11.8
Interest payable	12.4		10.2
Short-term derivative liabilities (see Note 11)	10.2		16.2
Tank inspection liabilities	6.5		7.0
Accrued utilities	4.9		10.6
Environmental liabilities (see Note 13)	3.7		3.8
Other	44.2		33.3
Total	$	487.6	$	307.7

The detail of other non-current liabilities is as follows (in millions):



Other Non-Current Liabilities	September 30, 2019		December 31, 2018
Pension and other postemployment benefit liabilities, net	$	16.2	$	17.6
Tank inspection liabilities	9.9		9.9
Liability for unrecognized tax benefits	7.2		19.2
Long-term derivative liabilities (see Note 11)	3.8		1.0
Above-market leases	—		9.2
Other	1.4		6.0
Total	$	38.5	$	62.9

Note 17 - Equity-Based Compensation

Delek US Holdings, Inc. 2006 and 2016 and Alon USA Energy, Inc. 2005 Long-Term Incentive Plans (collectively, the "Incentive Plans")

Compensation expense related to equity-based awards granted under the Incentive Plans amounted to $7.3 million ($5.8 million, net of taxes) and $18.7 million ($14.8 million, net of taxes) for the three and nine months ended September 30, 2019, respectively, and $5.4 million ($4.3 million, net of taxes) and $15.6 million ($12.3 million, net of taxes) for the three and nine months ended September 30, 2018, respectively. These amounts are included in general and administrative expenses in the accompanying condensed consolidated statements of income.

As of September 30, 2019, there was $51.3 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements, which is expected to be recognized over a weighted-average period of 2.3 years.

We issued 78,695 and 462,318 shares of common stock as a result of exercised or vested equity-based awards during the three and nine months ended September 30, 2019, respectively, and 90,552 and 535,613 shares for the three and nine months ended September 30, 2018, respectively. These amounts are net of 146,148 and 470,232 shares withheld to satisfy employee tax obligations related to the exercises and vestings during the three and nine months ended September 30, 2019, respectively, and 146,193 and 980,954 shares during the three and nine months ended September 30, 2018, respectively.

Delek Logistics GP, LLC 2012 Long-Term Incentive Plan

The Delek Logistics GP, LLC 2012 Long-Term Incentive Plan (the "LTIP") was adopted by the Delek Logistics GP, LLC board of directors in connection with the completion of Delek Logistics' initial public offering in November 2012. The LTIP is administered by the Conflicts Committee of the board of directors of Delek Logistics' general partner.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Note 18 - Stockholders' Equity

Dividends

During the nine months ended September 30, 2019, our Board of Directors declared the following dividends:



Approval Date	Dividend Amount Per Share	Record Date	Payment Date
February 19, 2019	$0.27	March 5, 2019	March 19, 2019
April 30, 2019	$0.28	May 20, 2019	June 3, 2019
July 29, 2019	$0.29	August 19, 2019	September 3, 2019

Stock Repurchase Program

On November 6, 2018, our Board of Directors authorized a share repurchase program for up to $500.0 million of Delek common stock. Any share repurchases under the repurchase program may be implemented through open market transactions or in privately negotiated transactions, in accordance with applicable securities laws. The timing, price and size of repurchases are made at the discretion of management and will depend on prevailing market prices, general economic and market conditions and other considerations. The repurchase program does not obligate us to acquire any particular amount of stock and does not expire. During the three and nine months ended September 30, 2019, 1,236,854 and 4,175,576 shares of our common stock were repurchased for a total of $43.0 million and $147.8 million, respectively, compared to repurchases of 1,906,308 and 4,847,511 shares during the three and nine months ended September 30, 2018 for a total of $92.1 million and $207.4 million, respectively. As of September 30, 2019, there was $261.9 million of authorization remaining under Delek's aggregate stock repurchase program.

Note 19 - Employees

Postretirement Benefits

The net periodic (benefit) cost for our postretirement benefit plans was not material for the three and nine months ended September 30, 2019 or 2018. Additionally, our estimated contributions to our pension plans during 2019 have not changed significantly from amounts previously disclosed in the notes to the consolidated financial statements for the year ended December 31, 2018.

Note 20 - Leases

We lease certain retail stores, land, building and various equipment from others. Leases with an initial term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 15 years or more. The exercise of existing lease renewal options is at our sole discretion. Certain leases also include options to purchase the leased property. The depreciable life of assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise.

Some of our lease agreements include a rate based on equipment usage and others include a rate with fixed increases or inflationary indices based increase. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants.

We rent or sublease certain real estate and equipment to third parties. Our sublease portfolio consists primarily of operating leases within our stores and crude storage equipment.

As of September 30, 2019, $30.0 million of our net property, plant, and equipment balance is subject to an operating lease. This agreement does not include options for the lessee to purchase our leasing equipment, nor does it include any material residual value guarantees or material restrictive covenants.



38 \|

Notes to Condensed Consolidated Financial Statements (Unaudited)

The following table presents additional information related to our operating leases in accordance ASC 842, Leases ("ASC 842"):



(in millions)	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Lease Cost
Operating lease costs	$	13.5		$	44.1
Short-term lease costs ⁽¹⁾	4.0			11.3
Sublease income	(1.9		)	(6.4		)
Net lease costs	$	15.6		$	49.0

Other Information
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(13.5	)	$	(44.1	)
Leased assets obtained in exchange for new operating lease liabilities	$	1.5		$	9.6

				September 30, 2019
Weighted-average remaining lease term (years) operating leases				6.69
Weighted-average discount rate operating leases ⁽²⁾				6.2		%

⁽¹⁾Includes an immaterial amount of variable lease cost.

⁽²⁾ Our discount rate is primarily based on our incremental borrowing rate in accordance with ASC 842.

The following is an estimate of the maturity of our lease liabilities for operating leases having remaining noncancelable terms in excess of one year as of September 30, 2019 (in millions) under the new lease guidance ASC 842:



Maturity of Lease Liabilities	Total
October 1 to December 31, 2019	$	14.7
2020	52.1
2021	40.6
2022	27.4
2023	21.7
Thereafter	76.4
Total future lease payments	232.9
Less: Interest	43.6
Present Value of Lease Liabilities	$	189.3

The following is an estimate of our future minimum lease payments for operating leases having remaining noncancelable terms in excess of one year as of December 31, 2018 (in millions) under the legacy lease guidance ASC 840, Leases:



Minimum Lease Payments
2019	$	48.1
2020	42.1
2021	39.5
2022	28.5
2023	23.4
Thereafter	77.9
Total future minimum lease payments	$	259.5

Note 21 - Subsequent Events

Dividend Declaration

On November 4, 2019, our Board of Directors voted to declare a quarterly cash dividend of $0.30 per share of our common stock, payable on December 2, 2019 to shareholders of record on November 18, 2019.



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Notes to Condensed Consolidated Financial Statements (Unaudited)

Purchase of Biofuel Production Assets



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Management's Discussion and Analysis

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is management’s analysis of our financial performance and of significant trends that may affect our future performance. The MD&A should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K as amended and filed with the Securities and Exchange Commission ("SEC") on June 27, 2019 (the "Annual Report on Form 10-K"). Those statements in the MD&A that are not historical in nature should be deemed forward-looking statements that are inherently uncertain.

In January 2017, Delek US Holdings, Inc. ("Old Delek") (and various related entities) entered into an Agreement and Plan of Merger with Alon USA Energy, Inc. (NYSE: ALJ) ("Alon") (as amended, the "Merger Agreement"). The related merger (the "Delek/Alon Merger") was effective July 1, 2017 (the “Effective Time”), resulting in a new post-combination consolidated registrant renamed Delek US Holdings, Inc. (“New Delek”), with Alon and Old Delek surviving as wholly-owned subsidiaries. New Delek is the successor issuer to Old Delek and Alon USA pursuant to Rule 12g-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act").

Unless otherwise noted or the context requires otherwise, the terms "we," "our," "us," "Delek" and the "Company" are used in this report to refer to Old Delek and its consolidated subsidiaries for the periods prior to July 1, 2017, and New Delek and its consolidated subsidiaries for the periods on or after July 1, 2017 - see Note 1 of the condensed consolidated financial statements in Item 1, Financial Statements, for additional information.

You should read the following discussion of our financial condition and results of operations in conjunction with our historical condensed consolidated financial statements and notes thereto.

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. These forward-looking statements reflect our current estimates, expectations and projections about our future results, performance, prospects and opportunities. Forward-looking statements include, among other things, the information concerning our possible future results of operations, business and growth strategies, financing plans, expectations that regulatory developments or other matters will or will not have a material adverse effect on our business or financial condition, our competitive position and the effects of competition, the projected growth of the industry in which we operate, and the benefits and synergies to be obtained from our completed and any future acquisitions, statements of management’s goals and objectives, and other similar expressions concerning matters that are not historical facts. Words such as "may," "will," "should," "could," "would," "predicts," "potential," "continue," "expects," "anticipates," "future," "intends," "plans," "believes," "estimates," "appears," "projects" and similar expressions, as well as statements in future tense, identify forward-looking statements.

Forward-looking statements should not be read as a guarantee of future performance or results, and will not necessarily be accurate indications of the times at, or by, which such performance or results will be achieved. Forward-looking information is based on information available at the time and/or management’s good faith belief with respect to future events, and is subject to risks and uncertainties that could cause actual performance or results to differ materially from those expressed in the statements. Important factors that, individually or in the aggregate, could cause such differences include, but are not limited to:


•	volatility in our refining margins or fuel gross profit as a result of changes in the prices of crude oil, other feedstocks and refined petroleum products;


•	reliability of our operating assets;


•	actions of our competitors and customers;


•	changes in, or the failure to comply with, the extensive government regulations applicable to our industry segments;


•	our ability to execute our strategy of growth through acquisitions and capital projects and changes in the expected value of and benefits derived therefrom, including any ability to successfully integrate acquisitions, realize expected synergies or achieve operational efficiency and effectiveness;


•	diminishment in value of long-lived assets may result in an impairment in the carrying value of the assets on our balance sheet and a resultant loss recognized in the statement of operations;


•	general economic and business conditions affecting the southern, southwestern and western United States, particularly levels of spending related to travel and tourism;


•	volatility under our derivative instruments;


•	deterioration of creditworthiness or overall financial condition of a material counterparty (or counterparties);


•	unanticipated increases in cost or scope of, or significant delays in the completion of, our capital improvement and periodic turnaround projects;


•	risks and uncertainties with respect to the quantities and costs of refined petroleum products supplied to our pipelines and/or held in our terminals;


•	operating hazards, natural disasters, casualty losses and other matters beyond our control;


•	increases in our debt levels or costs;


•	changes in our ability to continue to access the credit markets;



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Management's Discussion and Analysis


•	compliance, or failure to comply, with restrictive and financial covenants in our various debt agreements;


•	the inability of our subsidiaries to freely make dividends, loans or other cash distributions to us;


•	seasonality;


•	acts of terrorism (including cyber-terrorism) aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;


•	disruption, failure, or cybersecurity breaches affecting or targeting our IT systems and controls, our infrastructure, or the infrastructure of our cloud-based IT service providers;


•	changes in the cost or availability of transportation for feedstocks and refined products; and


•	other factors discussed under the headings "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors" and in our other filings with the SEC.

In light of these risks, uncertainties and assumptions, our actual results of operations and execution of our business strategy could differ materially from those expressed in, or implied by, the forward-looking statements, and you should not place undue reliance upon them. In addition, past financial and/or operating performance is not necessarily a reliable indicator of future performance, and you should not use our historical performance to anticipate future results or period trends. We can give no assurances that any of the events anticipated by any forward-looking statements will occur or, if any of them do, what impact they will have on our results of operations and financial condition.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

Executive Summary

Business Overview

We are an integrated downstream energy business focused on petroleum refining, the transportation, storage and wholesale distribution of crude oil, intermediate and refined products and convenience store retailing. Effective July 1, 2017, we acquired through the Delek/Alon Merger the operations and net assets of Alon. The Delek/Alon Merger continues to have a significant impact on our revenue and profitability as well as earnings per share, our net asset position, our purchasing position in the marketplace, our footprint in the refining industry, especially in the Gulf Coast Region/Permian Basin, and our ability to go to market and secure financing.

The refining segment processes crude oil and other feedstocks for the manufacture of transportation motor fuels, including various grades of gasoline, diesel fuel and aviation fuel, asphalt and other petroleum-based products that are distributed through owned and third-party product terminals. The refining segment has a combined nameplate capacity of 302,000 bpd, including the 75,000 bpd Tyler, Texas refinery (the "Tyler refinery"), the 80,000 bpd El Dorado, Arkansas refinery (the "El Dorado refinery"), the 73,000 bpd Big Spring, Texas refinery (the "Big Spring refinery"), and the 74,000 bpd Krotz Springs, Louisiana refinery (the "Krotz Springs refinery"), as well as a non-operating refinery located in Bakersfield, California. The refining segment also owns and operates two biodiesel facilities involved in the production of biodiesel fuels and related activities, located in Crossett, Arkansas and Cleburn, Texas. The refining segment's petroleum-based products are marketed primarily in the south central, southwestern and western regions of the United States, and the refining segment also ships and sells gasoline into wholesale markets in the southern and eastern United States. Motor fuels are sold under the Alon or Delek brand through various terminals to supply Alon or Delek branded retail sites. In addition, we sell motor fuels through our wholesale distribution network on an unbranded basis.

Our profitability in the refining segment is substantially determined by the difference between the cost of the crude oil feedstocks we purchase and the price of the refined products we sell, referred to as the "crack spread", "refining margin" or "refined product margin". Refining margin is used as a metric to assess a refinery's product margins against market crack spread trends, where "crack spread" is a measure of the difference between market prices for crude oil and refined products and is a commonly used proxy within the industry to estimate or identify trends in refining margins. The cost to acquire feedstocks and the price of the refined petroleum products we ultimately sell from our refineries depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions such as hurricanes or tornadoes, local, domestic and foreign political affairs, global conflict, production levels, the availability of imports, the marketing of competitive fuels and government regulation. Other significant factors that influence our results in the refining segment include operating costs (particularly the cost of natural gas used for fuel and the cost of electricity), seasonal factors, refinery utilization rates and planned or unplanned maintenance activities or turnarounds. Demand for gasoline and asphalt products is generally higher during the summer months than during the winter months due to seasonal increases in motor vehicle traffic and road and home construction. Varying vapor pressure requirements between the summer and winter months also tighten summer gasoline supply. As a result, our operating results are generally lower for the first and fourth quarters of the calendar year. Moreover, while the fluctuations in the cost of crude oil are typically reflected in the prices of light refined products, such as gasoline and diesel fuel, the price of other residual products, such as asphalt, coke, carbon black oil and liquefied petroleum gas ("LPG"), are less likely to move in parallel with crude cost. This could cause additional pressure on our realized margin during periods of rising or falling crude oil prices. Additionally, our margins are impacted by the pricing differentials of the various types and sources of crude oil we use at our refineries and their relation to product pricing, such as the differentials between West Texas Intermediate ("WTI") Midland and WTI Cushing or WTI Midland and Brent crude oil.



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Management's Discussion and Analysis

With respect to measuring our refining margins at our refineries, we consider the following:

•

For our Tyler refinery, we compare our per barrel refined product margin to the U.S.Gulf Coast ("Gulf Coast") 5-3-2 crack spread. The Gulf Coast 5-3-2 crack spread is calculated assuming one barrel of crude oil is converted into three-fifths barrel of U.S. Gulf Coast CBOB gasoline and two-fifths barrel of Gulf Coast No. 2 heating oil (high sulfur diesel). The crack spread is used as a benchmark for predicting/evaluating a refinery's product margins by measuring the difference between the market price of light products and crude oil.

•

For our Big Spring refinery, we compare our per barrel refined product margin to the Gulf Coast 3-2-1 crack spread. The Gulf Coast 3-2-1 crack spread is calculated assuming that one barrel of WTI Cushing crude oil is converted into two-thirds barrel of Gulf Coast 87 conventional gasoline and one-third barrel of Gulf Coast ultra-low sulfur diesel. Our Big Spring refinery is capable of processing substantial volumes of sour crude oil, which has historically cost less than intermediate, and/or substantial volumes of sweet crude oils, and therefore the WTI Cushing/WTS price differential, taking into account differences in production yield, is an important measure for helping us make strategic, market-respondent production decisions.

•

For our Krotz Springs refinery, we compare our per barrel refined product margin to the Gulf Coast 2-1-1 high sulfur diesel crack spread which is calculated assuming that one barrel of Light Louisiana Sweet (“LLS”) crude oil is converted into one-half barrel of Gulf Coast 87 conventional gasoline and one-half barrel of Gulf Coast high sulfur diesel. The Krotz Springs refinery has the capability to process substantial volumes of light sweet, crude oils to produce a high percentage of refined light products.

•

The crude oil and product slate flexibility of the El Dorado refinery allows us to take advantage of changes in the crude oil and product markets; therefore, we anticipate that the quantities and varieties of crude oil processed and products manufactured at the El Dorado refinery by processing a variety of feedstocks into a number of refined product types will continue to vary. While there is variability in the crude slate and the product output at the El Dorado refinery, we compare our per barrel refined product margin to the Gulf Coast 5-3-2 crack spread because we believe it to be the most closely aligned benchmark.

A widening of the WTI Cushing less WTI Midland spread will favorably influence the operating margin for our refineries. Alternatively, a narrowing of this differential will have an adverse effect on our operating margins. Global product prices are influenced by the price of Brent crude which is a global benchmark crude. Global product prices influence product prices in the U.S. As a result, our refineries are influenced by the spread between Brent crude and WTI Midland. The Brent less WTI Midland spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of WTI Midland crude oil. A widening of the spread between Brent and WTI Midland will favorably influence our refineries' operating margins. Also, the Krotz Springs refinery is influenced by the spread between Brent crude and LLS. The Brent less LLS spread represents the differential between the average per barrel price of Brent crude oil and the average per barrel price of LLS crude oil. A discount in LLS relative to Brent will favorably influence the Krotz Springs refinery operating margin.

Our logistics segment gathers, transports and stores crude oil and markets, distributes, transports and stores refined products in select regions of the southeastern United States and west Texas for our refining segment and third parties. It is comprised of the consolidated balance sheet and results of operations of Delek Logistics Partners, LP ("Delek Logistics", NYSE:DKL), where we owned a 61.4% limited partner interest (at September 30, 2019) in Delek Logistics and a 94.6% interest in the entity that owns the entire 2.0% general partner interest in Delek Logistics and all of the incentive distribution rights. Delek Logistics was formed by Delek in 2012 to own, operate, acquire and construct crude oil and refined products logistics and marketing assets. A substantial majority of Delek Logistics' assets are currently integral to our refining and marketing operations. The logistics segment's pipelines and transportation business owns or leases capacity on approximately 400 miles of crude oil transportation pipelines, approximately 450 miles of refined product pipelines, an approximately 600-mile crude oil gathering system and associated crude oil storage tanks with an aggregate of approximately 9.6 million barrels of active shell capacity. Our logistics segment owns and operates nine light product terminals and markets light products using third-party terminals.

Our retail segment at September 30, 2019 includes the operations of 263 owned and leased convenience store sites located primarily in central and west Texas and New Mexico which were acquired in connection with the Delek/Alon Merger. Our convenience stores typically offer various grades of gasoline and diesel under the DK or Alon brand name and food products, food service, tobacco products, non-alcoholic and alcoholic beverages, general merchandise as well as money orders to the public, primarily under the 7-Eleven and DK or Alon brand names pursuant to a license agreement with 7-Eleven, Inc. which gives us a perpetual license to use the 7-Eleven trademark, service name and trade name in west Texas and a majority of the counties in New Mexico in connection with our retail store operations. In November 2018, we terminated the license agreement with 7-Eleven, Inc. and the terms of such termination require the removal of all 7-Eleven branding on a store-by-store basis by the earlier of December 31, 2021 or the date upon which our last 7-Eleven store is de-identified or closed. Merchandise sales at our convenience store sites will continue to be sold under the 7-Eleven brand name until 7-Eleven branding is removed pursuant to the termination. Substantially all of the motor fuel sold through our retail segment is supplied by our Big Spring refinery, which is transferred to the retail segment at prices substantially determined by reference to published commodity pricing information. In connection with our retail strategic initiatives, we closed or sold 20 under-performing or non-strategic store locations during the nine months ended September 30, 2019 and have plans to close 10 additional stores during the remainder of 2019.

The cost to acquire the refined fuel products we sell to our wholesale customers in our logistics segment and at our convenience stores in our retail segment depends on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions,



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Management's Discussion and Analysis

domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. Our retail merchandise sales are driven by convenience, customer service, competitive pricing and branding. Motor fuel margin is sales less the delivered cost of fuel and motor fuel taxes, measured on a cents per gallon basis. Our motor fuel margins are impacted by local supply, demand, weather, competitor pricing and product brand.

Our corporate activities, results of certain immaterial operating segments (including Alon's asphalt terminal operations effective with the Delek/Alon Merger), results and assets of discontinued operations and intercompany eliminations are reported in corporate, other and eliminations in our segment disclosure.

As part of our overall business strategy, we regularly evaluate opportunities to expand our portfolio of businesses and may at any time be discussing or negotiating a transaction that, if consummated, could have a material effect on our business, financial condition, liquidity or results of operations.

2019 Developments

Transactions designed to maximize shareholder return

Dividend Declaration

On November 4, 2019, Delek's Board of Directors voted to declare a quarterly cash dividend of $0.30 per share, payable on December 2, 2019, to stockholders of record on November 18, 2019. Our previous quarterly cash dividend amounts ranged between $0.20 to $0.26 per share throughout 2018 and between $0.27 and $0.29 per share through the third quarter of 2019.

Share Repurchases

During the three and nine months ended September 30, 2019, Delek repurchased 1,236,854 and 4,175,576 shares for an aggregate purchase price of $43.0 million and $147.8 million, respectively, under the most recent share repurchase plan which provided for repurchases up to $500.0 million and was approved by the board on November 6, 2018. As of September 30, 2019, there remained $261.9 million available for repurchases under the most recent repurchase plan.

Transactions designed to maximize return on assets

Alkylation Project Completed

The alkylation unit at the Krotz Springs refinery was completed in early April providing additional flexibility to the refinery. The total cost was approximately $138.0 million. This unit should improve the ability to convert low value products into gasoline, enable the refinery to produce multiple summer gasoline grades and increase octane, allowing the refinery to produce premium gasoline. Because of the conversion improvement at the refinery from this project, its returns are expected to be less dependent on the crack spread environment over time.

Investment in Pipeline Joint Ventures

On July 30, 2019, we, through our wholly-owned direct subsidiary Delek US Energy, Inc. (“Delek Energy”), entered into a limited liability company agreement (the "LLCA") and related agreements with multiple joint venture members of Wink to Webster Pipeline LLC (“WWP”). Pursuant to the LLCA, Delek Energy acquired a 15% ownership interest in WWP. WWP intends to construct and operate a crude oil pipeline system from Wink, Texas to Webster, Texas along with certain pipelines from Webster, Texas to other destinations in the Gulf Coast area. It is expected to span approximately 650 miles at completion. Pursuant to the LLCA, Delek Energy will be required to contribute its percentage interest of the applicable construction costs (including certain costs previously incurred by WWP) and it is anticipated that Delek Energy’s capital contributions will total approximately $340 million to $380 million over the course of construction (expected to be two to three years). During the three months ended September 30, 2019, we made capital contributions totaling $75.3 million. Subsequent to September 30, 2019, we made additional capital contributions totaling $46.2 million.

In May 2019, Delek Logistics, through its wholly owned indirect subsidiary Delek Logistics Pipeline, LLC (“Delek Logistics Pipeline”), entered into a Contribution and Subscription Agreement (the “Contribution Agreement”) with Plains Pipeline, L.P. (“Plains”) and Red River Pipeline Company LLC (“Red River”). Pursuant to the Contribution Agreement, Delek Logistics Pipeline contributed approximately $124.7 million, substantially all of which was financed under the Delek Logistics Credit Facility, to Red River in exchange for a 33% membership interest in Red River and Delek Logistics Pipeline’s admission as a member of Red River ("Red River Pipeline Joint Venture"). Red River intends to proceed with an expansion project to increase the capacity of the pipeline from 150,000 barrels per day to 235,000 barrels per day and, pursuant to the Contribution Agreement, in May 2019 we contributed an additional $3.5 million for such expansion project. This investment was also made to advance our long-term strategic objectives to expand our midstream investments and network/pipeline access.

In September 2018, Delek announced plans for a joint venture with Energy Transfer, Magellan, and MPLX to construct a 600-mile common carrier pipeline to transport crude oil from the Permian Basin to the Texas Gulf Coast region (the "Proposed PGC Partnership"). During the first quarter 2019, we elected not to move forward with the Proposed PGC Partnership which allowed us to explore other options to participate in a long-haul crude oil pipeline, including the joint ventures discussed above.



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Management's Discussion and Analysis

Purchase of Biofuel Production Assets

Effective October 1, 2019, we acquired certain assets of JNS Biofuel, LLC, a biodiesel facility located in New Albany, Mississippi for a total purchase price of $8.0 million. The assets acquired consisted primarily of real property and integral equipment. This acquisition allows us to bring assets in-house for a facility where we were previously the sole tolling customer, and utilize those assets to leverage across our renewables activities.

Transactions designed to minimize the cost of capital/manage financial risk exposures

2019 Amendments to Supply and Offtake Agreements

During January 2019, we amended the El Dorado refinery and the Krotz Springs refinery Supply and Offtake Agreements with J. Aron & Company ("J. Aron") so that the repurchase of baseline volumes at the end of the applicable Supply and Offtake Agreement term (representing the "Baseline Step-Out Liabilities") will be based upon a fixed price instead of a market-indexed price and therefore subject to changes in fair value that reflect changes in interest rate risk rather than commodity price risk. The modified arrangement results in a Baseline Step-Out Liability that is no longer subject to commodity volatility, but for which its fair value is subject to interest rate risk. As a result, we recorded a gain on the change in fair value resulting from the modification of the instruments from commodities-based risk to interest rate risk in cost of materials and other in the first quarter of 2019. Such Baseline Step-Out Liabilities will continue to be recorded at fair value, where the fair value will reflect changes in interest rate risk rather than commodity price risk.

In September 2019, we amended the Supply and Offtake Agreements to increase the fixed Step-Out price on Baseline Volumes. As a result of the change in the contract terms, we received cash, net of estimated fees paid, totaling approximately $38.9 million. No gain or loss was recognized as a result of these September 2019 amendments.

See further discussion in Note 9 of our condensed consolidated financial statements included in Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

2019 Amendment to the Term Loan Credit Facility Agreement

On May 22, 2019 (the "First Incremental Effective Date"), we amended the Term Loan Credit Facility agreement pursuant to the terms of the First Incremental Amendment to Term Loan Credit Agreement (the "Incremental Amendment"). Pursuant to the Incremental Amendment, the Company borrowed $250.0 million in aggregate principal amount of incremental term loans (the “Incremental Term Loans”) at an original issue discount of 0.75%, increasing the aggregate principal amount of loans outstanding under the Term Loan Credit Facility on the First Incremental Effective Date to $943.0 million. Per the Incremental Amendment, the required scheduled quarterly principal payments under the Term Loan Credit Facility increased from $1.750 million to $2.375 million commencing with the quarterly principal payment due on June 28, 2019. The terms of the Incremental Term Loans are substantially identical to the terms applicable to the initial term loans under the Term Loan Credit Facility borrowed in March 2018. There are no restrictions on the Company's use of the proceeds of the Incremental Term Loans, and the proceeds may be used to (i) to reduce utilizations under the Revolving Credit Facility, (ii) for general corporate purposes and (iii) to pay transaction fees and expenses associated with the Incremental Amendment.



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Management's Discussion and Analysis

Market Trends

Our results of operations are significantly affected by fluctuations in the prices of certain commodities, including, but not limited to, crude oil, gasoline, distillate fuel, biofuels, natural gas and electricity. Historically, our profitability has been affected by commodity price volatility, specifically as it relates to the price of crude oil and refined products.

The chart reflects the quarterly high, low and average prices of WTI Midland crude oil for each of the quarterly periods in 2018 and for the three quarterly periods in 2019.

The chart reflects the quarterly high, low and average prices of WTI Cushing crude oil for each of the quarterly periods in 2018 and for the three quarterly periods in 2019.



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Management's Discussion and Analysis

Crack spreads are used as benchmarks for predicting and evaluating a refinery's product margins by measuring the difference between the market price of feedstocks and crude oil, and represents the approximate refining margin resulting from processing one barrel of crude oil into its outputs, generally gasoline and diesel fuel.

The Gulf Coast 5-3-2 crack spread represents the approximate refining margin resulting from processing one barrel of crude oil into three-fifths barrel of gasoline and two-fifths barrel of high-sulfur diesel. The chart reflects the quarterly high, low and average Gulf Coast 5-3-2 crack spread (Tyler benchmark) for each of the quarterly periods in 2018 and for the three quarterly periods in 2019.

The Gulf Coast 3-2-1 crack spread is calculated assuming that one barrel of WTI Cushing crude oil is converted into two-thirds barrel of Gulf Coast conventional gasoline and one-third barrel of Gulf Coast ultra-low sulfur diesel. The chart reflects the quarterly high, low and average Gulf Coast 3-2-1 crack spread (Big Spring benchmark) for each of the quarterly periods in 2018 and for the three quarterly periods in 2019.

The Gulf Coast 2-1-1 high sulfur diesel crack spread is calculated assuming that one barrel of Light Louisiana Sweet (“LLS”) crude oil is converted into one-half barrel of Gulf Coast conventional gasoline and one-half barrel of Gulf Coast high sulfur diesel. The chart reflects the quarterly high, low and average Gulf Coast 2-1-1 crack spread (Krotz Springs benchmark) for each of the quarterly periods in 2018 and for the three quarterly periods in 2019.



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Management's Discussion and Analysis

Crack spreads are impacted by the price of refined products as compared to the price of crude oil and therefore may narrow or widen based on different trends in those market prices, or lags in one commodity pricing change versus the other. The average Gulf Coast 5-3-2 crack spread increased to $14.25 during the first nine months of 2019 from $13.44 during the first nine months of 2018 despite decreases in the Gulf Coast price of gasoline (CBOB) of 13.6%, from an average of $1.91 per gallon in the first nine months of 2018 to $1.65 per gallon in the first nine months of 2019 and decreases in the Gulf Coast price of High Sulfur Diesel of 7.8%, from an average of $1.92 per gallon in the first nine months of 2018 to $1.77 per gallon in the first nine months of 2019.

The next three charts illustrate the quarterly high, low and average prices of Gulf Coast Gasoline, U.S. Gulf Coast High Sulfur Diesel and Ultra Low Sulfur Diesel ("ULSD") for each of the quarterly periods in 2018 and for the three quarterly periods in 2019.



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Management's Discussion and Analysis

As U.S. crude oil production has increased, we have seen the discount for WTI Cushing compared to Brent widen. This generally leads to higher margins in our refineries, as refined product prices are influenced by Brent crude prices and the majority of our crude supply is WTI-linked. The average discount for WTI Cushing compared to Brent increased to $7.70 during the first nine months of 2019 from $5.81 during the first nine months of 2018. We note similar historical trends when reviewing the discount for WTI Cushing compared to LLS, where the average discount increased to $6.29 during the first nine months of 2019 from $4.16 during the first nine months of 2018. Additionally, our refineries continue to have relatively greater access to WTI Midland and WTI Midland-linked crude feedstocks compared to certain of our competitors. The average discount for WTI Midland compared to WTI Cushing decreased to $1.22 during the first nine months of 2019 from a discount of $7.69 during the first nine months of 2018. When these price discounts increase, so does our competitive advantage, created by our access to WTI Midland-linked crude oil pricing.

The chart illustrates the differentials of both Brent crude oil, WTI Midland crude oil, and LLS as compared to WTI Cushing crude oil for each of the quarterly periods in 2018 and for the three quarterly periods in 2019.

Environmental regulations continue to affect our margins in the form of volatility in the cost of renewable identification number ("RINs"). On a consolidated basis, we work to balance the cost of our credits for commitments required by the EPA to blend biofuels into fuel products ("RINs Obligation") in order to minimize the effect of RINs on our results. While we generate RINs in both our refining and logistics segments through our ethanol blending and biodiesel production, our refining segment needs to purchase additional RINs to satisfy its obligations. As a result, increases in the price of RINs generally adversely affect our results of operations. It is not possible at this time to predict with certainty what future volumes or costs may be, but given the volatile price of RINs, the cost of purchasing sufficient RINs could have an adverse impact on our results of operations if we are unable to recover those costs in the price of our refined products.

The chart illustrates the volatility in RINs prices over several quarterly periods, beginning with the first quarter of 2018 through the third quarter of 2019.



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Management's Discussion and Analysis

Contractual Obligations

There have been no material changes to our contractual obligations and commercial commitments during the nine months ended September 30, 2019, from those disclosed in our Annual Report on Form 10-K.

Critical Accounting Policies

The preparation of our consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. The SEC has defined critical accounting policies as those that are both most important to the portrayal of our financial condition and results of operations, and require our most difficult, subjective or complex judgments or estimates. Based on this definition and as further described in our 2018 Annual Report on Form 10-K, we believe our critical accounting policies include the following: (i) estimating our quarterly inventory adjustments using the last-in, first-out valuation method for the Tyler refinery, (ii) evaluating impairment for property, plant and equipment and definite life intangibles, (iii) evaluating potential impairment of goodwill, (iv) estimating environmental expenditures, and (v) estimating asset retirement obligations. For all financial statement periods presented, there have been no material modifications to the application of these critical accounting policies or estimates since our most recently filed Annual Report on Form 10-K. See Note 1 of the condensed consolidated financial statements in Item 1, Financial Statements for discussion of updates to our accounting policies.

Non-GAAP Measures

Our management uses certain “non-GAAP” operational measures to evaluate our operating segment performance and non-GAAP financial measures to evaluate past performance and prospects for the future to supplement our GAAP financial information presented in accordance with U.S. GAAP. These financial and operational non-GAAP measures are important factors in assessing our operating results and profitability and include:


•	Refining margin - calculated as the difference between net refining revenues and total cost of materials and other;


•	Refined product margin - calculated as the difference between net revenues attributable to refined products (produced and purchased) and related cost of materials and other (which is applicable to both the refining segment and the west Texas wholesale marketing activities within our logistics segment); and


•	Refining margin per barrels sold - calculated as refining margin divided by our average refining sales in barrels per day (excluding purchased barrels) multiplied by 1,000 and multiplied by the number of days in the period.

We believe these non-GAAP operational and financial measures are useful to investors, lenders, ratings agencies and analysts to assess our ongoing performance because, when reconciled to their most comparable GAAP financial measure, they provide improved comparability between periods through the exclusion of certain items that we believe are not indicative of our core operating performance and they may obscure our underlying results and trends.

Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings and operating income. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures.

Non-GAAP Reconciliations

The following table provides a reconciliation of refining margin to the most directly comparable U.S.GAAP measure, gross margin:

Reconciliation of refining margin to gross margin



Refining Segment
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018 ⁽¹⁾		2019		2018 ⁽¹⁾
Net revenues	$	2,176.8	$	2,649.3	$	6,636.6	$	7,318.4
Cost of sales	2,083.9		2,363.6		6,135.4		6,787.7
Gross margin	92.9		285.7		501.2		530.7
Add back (items included in cost of sales):
Operating expenses (excluding depreciation and amortization)	120.7		118.8		356.7		346.7
Depreciation and amortization	34.6		33.8		98.9		99.1
Refining margin	$	248.2	$	438.3	$	956.8	$	976.5

⁽¹⁾

Refining segment net revenues and cost of sales for the three and nine months ended September 30, 2018 reflect a correction of an intercompany elimination which resulted in an increase in those accounts of $273.7 million and $347.1 million, respectively, not previously reflected on the unaudited consolidated financial statements in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 9, 2018. Such amounts are not considered material to the financial statements and had no impact to gross margin or refining margin for those periods. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.



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Management's Discussion and Analysis

Summary Financial and Other Information

The following table provides summary financial data for Delek:

Statement of Operations Data (in millions)



Consolidated
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018 ⁽¹⁾		2019			2018 ^(1),(2)
Net revenues	$	2,334.3	$	2,768.9	$	7,014.5		$	7,759.0
Total operating costs and expenses	2,246.9		2,513.7		6,570.4			7,329.9
Operating income	87.4		255.2		444.1			429.1
Total non-operating expenses, net	14.0		18.4		61.3			100.8
Income from continuing operations before income tax expense	73.4		236.8		382.8			328.3
Income tax expense	13.4		51.0		83.8			72.3
Income from continuing operations, net of tax	60.0		185.8		299.0			256.0
Income (loss) from discontinued operations, net of tax	—		0.5		(0.8		)	(8.5		)
Net income	60.0		186.3		298.2			247.5
Net income attributed to non-controlling interests	8.7		6.5		20.3			29.0
Net income attributable to Delek	$	51.3	$	179.8	$	277.9		$	218.5

⁽¹⁾

Net revenues and cost of materials and other for the three and nine months ended September 30, 2018 reflect a correction of an intercompany elimination which resulted in an increase in those accounts of $273.7 million and $347.1 million, respectively, not previously reflected on the unaudited consolidated financial statements in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 9, 2018. Such amounts are not considered material to the financial statements and had no impact to operating income or segment contribution margin for those periods. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.

⁽²⁾

Income tax expense for the nine months ended September 30, 2018 reflects a correction made in our 2018 Annual Report on Form 10-K (as originally filed on March 1, 2019 ) to record additional deferred tax expense totaling $5.5 million related to the recognition of a valuation allowance on deferred tax assets recognized in connection with the Big Spring Logistic Assets Acquisition (see Note 5) not previously reported in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 9, 2018. Such amount is not considered material to the financial statements or the trend of earnings for that period. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.



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Management's Discussion and Analysis

Results of Operations

Consolidated Results of Operations — Comparison of the Three and Nine Months Ended September 30, 2019 versus the Three and Nine Months Ended September 30, 2018

Net Income

Q3 2019 vs. Q3 2018

Consolidated net income for the third quarter of 2019 was $60.0 million compared to a net income of $186.3 million for the third quarter of 2018. Consolidated net income attributable to Delek for the third quarter of September 30, 2019 was $51.3 million, or $0.68 per basic share, compared to a net income of $179.8 million, or $2.15 per basic share, for the third quarter 2018. Explanations for significant drivers impacting net income as compared to the comparable period of the prior year are discussed in the sections below.

YTD 2019 vs. YTD 2018

Consolidated net income for the nine months ended September 30, 2019 was $298.2 million compared to net income of $247.5 million for the nine months ended September 30, 2018. Consolidated net income attributable to Delek for the nine months ended September 30, 2019 was $277.9 million, or $3.63 per basic share, compared to net income of $218.5 million, or $2.62 per basic share, for the nine months ended September 30, 2018. Explanations for significant drivers impacting net income as compared to the comparable period of the prior year are discussed in the sections below.

Net Revenues

Q3 2019 vs. Q3 2018

In the third quarters of 2019 and 2018, we generated net revenues of $2,334.3 million and $2,768.9 million, respectively, a decrease of $434.6 million, or 15.7%. The decrease in net revenues was primarily driven by the following factors:


•	in our refining segment, decreased sales volumes and decreases in the average price of U.S. Gulf Coast gasoline of 17.0%, ULSD of 13.4%, and High-Sulfur diesel ("HSD") of 14.5%;


•	in our logistics segment, decreases in the average volume sold and sales prices per gallon of gasoline and diesel sold in our west Texas marketing operations, where the average sales prices per gallon of gasoline and diesel sold decreased $0.24 per gallon and $0.33 per gallon, respectively;


•	in our retail segment, decreases in fuel sales volumes and merchandise sales partially attributable to reduction in the average number of stores, as well as a $0.25 decrease in average price charged per gallon quarter over quarter.

Such decreases were partially offset by:


•	increased revenues in our logistics segment associated with our Paline Pipeline as a result of increased rates and a change in the fee structure.

YTD 2019 vs. YTD 2018

For the nine months ended September 30, 2019 and 2018, we generated net revenues of $7,014.5 million and $7,759.0 million, respectively, a decrease of $744.5 million, or 9.6%. The decrease in net revenues was primarily driven by the following factors:


•	in our refining segment, decreases in the average price of U.S. Gulf Coast gasoline of 13.6%, ULSD of 8.3%, and HSD of 7.8%; and


•	in our logistics segment, decreases in the average volume sold and sales prices per gallon of gasoline and diesel sold in our west Texas marketing operations, where the average sales prices per gallon of gasoline and diesel sold decreased $0.22 per gallon and $0.21 per gallon, respectively.

Such decreases were partially offset by:


•	increased revenues in our logistics segment associated with our Paline Pipeline as a result of increased rates and a change in the fee structure.

Cost of Materials and Other

Q3 2019 vs. Q3 2018

Cost of materials and other was $1,964.1 million for the third quarter of 2019 compared to $2,244.2 million for the third quarter of 2018, a decrease of $280.1 million, or 12.5%. The net decrease in cost of materials and other was primarily driven by the following:



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Management's Discussion and Analysis


•	decreases in the cost of crude oil feedstocks at the refineries, including a decrease in the cost of WTI Cushing crude oil from an average of $69.63 per barrel to an average of $56.40;


•	a decrease in RIN expense primarily due to impact of 2018 RIN Waivers which reduced our RINS Obligation by $20.7 million, in addition to the decrease in ethanol RIN prices which averaged $0.19 per RIN in third quarter 2019 compared to $0.21 per RIN in the prior year period;


•	decreases in the volume and cost of refined products in the logistics segment where the average cost per gallon of gasoline and diesel purchased decreased $0.26 per gallon and $0.31 per gallon, respectively;


•	a decrease in retail fuel cost of materials and other attributable to a decrease in average cost per gallon of $0.33; and


•	an increase in hedging gains to $13.1 million recognized during the third quarter of 2019 from a loss of $18.9 million recognized during the third quarter of 2018.

Such decreases were partially offset by the following:


•	a narrowing of crude oil differentials during the third quarter where the Midland WTI crude oil differential to Brent crude oil was an average discount of $5.91 per barrel compared to $20.48 per barrel in the prior year period, and the WTI Midland to WTI Cushing discount averaged $0.28 per barrel in the third quarter 2019 compared to a discount of $14.35 per barrel in the prior-year-period.

YTD 2019 vs. YTD 2018

Cost of materials and other was $5,731.2 million for the nine months ended September 30, 2019 compared to $6,537.2 million for the nine months ended September 30, 2018, a decrease of $806.0 million, or 12.3%. The net decrease in cost of materials and other was primarily driven by the following:


•	decreases in the cost of crude oil feedstocks at the refineries, including a decrease in the cost of WTI Cushing crude oil from an average of $66.90 per barrel to an average of $57.03 and a decrease in the cost of WTI Midland crude oil from an average of $59.21 per barrel to an average of $55.81 during the comparable periods;


•	a decrease in RIN expense where ethanol RIN prices averaged $0.18 per RIN in nine months ended September 30, 2019 compared to $0.37 per RIN in the prior year period;


•	decreases in the cost of refined products in the logistics segment where the average cost per gallon of gasoline and diesel purchased decreased $0.22 per gallon and $0.18 per gallon, respectively;


•	a decrease in retail fuel cost of materials and other attributable to a decrease in average cost per gallon of $0.24; and


•	an increase in hedging gains to $63.5 million recognized during the nine months ended September 30, 2019 from a loss of $42.1 million recognized during the nine months ended September 30, 2018.

Such decreases were partially offset by:


•	a prior period benefit of approximately $115.5 million related to a combination of the 2017 RINs waivers and a biodiesel tax credit recognized during the nine months ended September 30, 2018, whereas 2018 RIN Waivers provided a benefit of $20.7 million the same period in the nine months ended September 30, 2019.

Operating Expenses

Q3 2019 vs. Q3 2018

Operating expenses were $166.9 million for the third quarter of 2019 compared to $164.0 million for the third quarter of 2018, an increase of $2.9 million, or 1.8%. The increase in operating expenses was primarily driven by the following:


•	higher employee related costs primarily across our refining and logistics segment;


•	higher outside service costs in our refining segment; and


•	partially offset by decrease in retail operating expenses due to reduction in number of stores.

YTD 2019 vs. YTD 2018

Operating expenses were $495.9 million for the nine months ended September 30, 2019 compared to $479.6 million for the nine months ended September 30, 2018, an increase of $16.3 million, or 3.4%. The increase in operating expenses was primarily driven by the following:


•	higher employee related costs primarily in our refining and logistics segments;


•	higher contract services in our refining and logistics segments; and

Such increases were partially offset by:



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Management's Discussion and Analysis


•	reductions in maintenance expense and variable expenses in our refining segment; and


•	decrease in retail operating expenses due to reduction in number of stores.

General and Administrative Expenses

Q3 2019 vs. Q3 2018

General and administrative expenses were $65.6 million for the third quarter of 2019 compared to $58.0 million for the third quarter of 2018, an increase of $7.6 million, or 13.1%. The increase in general and administrative expense was primarily driven by the following:


•	an increase in employee costs driven by higher equity-based compensation and increased headcount in corporate and other; and


•	increase in property and other taxes.

YTD 2019 vs. YTD 2018

General and administrative expenses were $197.3 million and $176.1 million for the nine months ended September 30, 2019 and 2018, respectively, a increase of $21.2 million, or 12.0%. The increase in general and administrative expense was primarily driven by the following:


•	an increase in employee costs driven by higher equity based compensation and increased headcount;


•	increases in legal costs associated with various acquisition, investment, litigation and dispute matters;


•	increases in property and other taxes;


•	increases in supplies expenses for subscriptions and office related costs; and


•	increases for various outside service costs.

Depreciation and Amortization

Q3 2019 vs. Q3 2018

Depreciation and amortization (included in both cost of sales and other operating expenses) was $49.8 million for the third quarter of 2019 compared to $49.2 million for the third quarter of 2018, a increase of $0.6 million, or 1.2%.

YTD 2019 vs. YTD 2018

Depreciation and amortization (included in both cost of sales and other operating expenses) was $146.7 million compared to $146.4 million for the nine months ended September 30, 2019 and 2018, respectively, a increase of $0.3 million, or 0.2%.

Other Operating Income, Net

Q3 2019 vs. Q3 2018

Other operating income decreased by $2.2 million in the third quarter of 2019 to expense of $0.5 million compared to income of $1.7 million in the third quarter of 2018, partially due to lower net gains associated with our Canadian crude trading operations compared to the third quarter of 2018.

YTD 2019 vs. YTD 2018

Other operating income decreased by $8.7 million during the nine months ended September 30, 2019 to $0.7 million compared to income of $9.4 million during the nine months ended September 30, 2018, partially due to lower net gains associated with our Canadian crude trading operations compared to the third quarter of 2018.

Non-operating Expenses, Net

Interest Expense

Q3 2019 vs. Q3 2018

Interest expense increased by $2.7 million, or 8.7%, to $33.9 million in the third quarter of 2019 compared to $31.2 million in the third quarter of 2018, primarily driven by the following:

•

an increase in the average effective interest rate of 0.62% in the third quarter of 2019 compared to the third quarter of 2018 (where effective interest rate is calculated as interest expense divided by the net average borrowings/obligations outstanding), partially offset by a decrease in net average borrowings outstanding (including the obligations under the supply and offtake agreements which have an



54 \|

Management's Discussion and Analysis

associated interest charge) of approximately $74.4 million in the third quarter of 2019 (calculated as a simple average of beginning borrowings/obligations and ending borrowings/obligations for the period) compared to the third quarter of 2018.

YTD 2019 vs. YTD 2018

Interest expense increased by $0.2 million, or 0.2%, to $95.4 million during the nine months ended September 30, 2019 compared to $95.2 million during the nine months ended September 30, 2018.

Results from Equity Method Investments

Q3 2019 vs. Q3 2018

We recognized income of $16.5 million from equity method investments during the third quarter of 2019, compared to $4.0 million for the third quarter of 2018, an increase of $12.5 million. This increase was primarily driven by the following:


•	an increase in income from our asphalt joint venture from $2.1 million in the third quarter of 2018 to $7.9 million in the third quarter of 2019;


•	the addition of the Red River Joint Venture in May 2019 which contributed income of $4.7 million in the third quarter of 2019; and


•	an increase in income from our other logistics joint ventures from $1.9 million in the third quarter of 2018 to $3.7 million in the third quarter of 2019.

YTD 2019 vs. YTD 2018

During the nine months ended September 30, 2019, we recognized income of $28.4 million from equity method investments, compared to $6.9 million for the nine months ended September 30, 2018, an increase of $21.5 million. This increase was primarily driven by the following:


•	an increase in income from our asphalt joint venture from $2.3 million in the first nine months of 2018 to $13.1 million in the first nine months of 2019;


•	the addition of the Red River Joint Venture in May 2019 which contributed income of $7.0 million in the first nine months of 2019; and


•	an increase in income from our other logistics joint ventures from $4.7 million in the first nine months of 2018 to $7.9 in the first nine months of 2019.

Other

Q3 2019 vs. Q3 2018

Other income decreased $7.3 million, or 97.3% primarily due to income related pension curtailment and settlement of litigation resulting in a reversal of accrual in the third quarter of 2018; no comparable activity in the third quarter of 2019.

YTD 2019 vs. YTD 2018

During the nine months ended September 30, 2018, we incurred certain infrequently occurring expenses/charges that were not incurred during the nine months ended September 30, 2019. These included a $9.1 million loss on extinguishment of debt related to the Refinancing and an impairment loss on assets held for sale totaling approximately $27.5 million related to the asphalt assets held for sale. These charges were partially offset by a realized gain on the sale of certain asphalt assets totaling $13.2 million, including a gain on the sale of an asphalt equity method investment. See Notes 7 and 10 of the condensed consolidated financial statements in Item 1, Financial Statements, for additional information.

Income Taxes

Q3 2019 vs. Q3 2018

Income tax expense decreased by $37.6 million in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	pre-tax income of $73.4 million in the third quarter of 2019, as compared to pre-tax income of $236.8 million for the third quarter of 2018; and


•	a decrease in our effective tax rate which was 18.3% for the third quarter of 2019, compared to 21.5% for the third quarter of 2018 primarily due to the reversal of reserve for uncertain tax positions in the third quarter of 2019 net of an increase in valuation allowance related to state net operating loss carryforwards.

YTD 2019 vs. YTD 2018

Income tax expense increased by $11.5 million during the nine months ended September 30, 2019 compared to the same period for 2018, primarily driven by the following:



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Management's Discussion and Analysis


•	an increase attributable pre-tax income of $382.8 million for the nine months ended September 30, 2019, as compared to pre-tax income of $328.3 million for the nine months ended September 30, 2018.

Such increase was partially offset by a decrease in our effective tax rate which was 21.9% and 22.0% for the nine months ended September 30, 2019 and 2018, respectively, primarily due to the following:


•	the 2019 reversal of reserve for uncertain tax positions in the quarter, net of increase in state valuation allowance on net operating losses; and


•	the discrete adjustments that were reported in the first nine months of 2018 for the following:


◦	further adjustments to properly consider the impact of the Tax Reform Act (which reduced the US federal corporate tax rate from 35% to 21%) on previously recorded deferred taxes;


◦	tax benefit for federal tax credits attributable to the Company’s biodiesel blending operations for 2017 that have not been extended by Congress;


◦	tax expense associated with the impairment of assets held for sale; and


◦	changes in valuation allowance attributable to the book-tax basis differences from the Big Spring Logistic Asset Acquisition (See Note 5).



56 \|

Management's Discussion and Analysis

Operating Segments

We review operating results in the following reportable segments:


•	Refining


•	Logistics


•	Retail

Refining Segment

The tables and charts below set forth certain information concerning our refining segment operations ($ in millions, except per barrel amounts):



Refining Segment Margins
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018 ⁽¹⁾		2019 ⁽¹⁾		2018 ⁽¹⁾
Net revenues	$	2,176.8	$	2,649.3	$	6,636.6	$	7,318.4
Cost of materials and other	1,928.6		2,211.0		5,679.8		6,341.9
Refining margin	248.2		438.3		956.8		976.5
Operating expenses (excluding depreciation and amortization)	120.7		118.8		356.7		346.7
Contribution margin	$	127.5	$	319.5	$	600.1	$	629.8

⁽¹⁾

Refining segment net revenues and cost of materials and other for the nine months ended September 30, 2019 reflect a correction of an intercompany elimination which resulted in an increase in those accounts of $273.7 million and $347.1 million, respectively, not previously reflected on the unaudited consolidated financial statements in our September 30, 2018 Quarterly Report on Form 10-Q filed on November 9, 2018. Such amounts are not considered material to the financial statements and had no impact to operating income or segment contribution margin for those periods. See Note 23 to our annual audited consolidated financial statements included in Part II, Item 8 of our 2018 Annual Report on Form 10-K, as amended and filed on June 27, 2019, for further discussion.



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Management's Discussion and Analysis



Refinery Statistics
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Unaudited)						(Unaudited)
Tyler, TX Refinery
Days in period	92			92			273			273
Total sales volume - refined product (average barrels per day)⁽¹⁾	80,981			79,691			76,262			78,497
Products manufactured (average barrels per day):
Gasoline	41,480			40,663			40,281			41,417
Diesel/Jet	33,105			31,659			30,685			30,742
Petrochemicals, LPG, NGLs	3,992			3,199			3,129			2,722
Other	1,853			1,646			1,560			1,718
Total production	80,430			77,167			75,655			76,599
Throughput (average barrels per day):
Crude Oil	75,266			72,845			70,594			71,161
Other feedstocks	5,565			4,713			5,710			5,867
Total throughput	80,831			77,558			76,304			77,028
Per barrel of refined product sales:
Tyler refining margin	$	11.96		$	19.84		$	15.09		$	13.47
Direct operating expenses	$	3.11		$	3.57		$	3.77		$	3.45
Crude Slate: (% based on amount received in period)
WTI crude oil	94.6		%	82.2		%	91.3		%	80.7		%
East Texas crude oil	2.7		%	17.8		%	8.0		%	18.4		%
Other	2.8		%	—		%	0.7		%	0.9		%

El Dorado, AR Refinery
Days in period	92			92			273			273
Total sales volume - refined product (average barrels per day)⁽¹⁾	71,282			76,196			58,310			74,400
Products manufactured (average barrels per day):
Gasoline	30,766			30,522			24,396			33,948
Diesel	22,348			24,734			18,559			25,423
Petrochemicals, LPG, NGLs	834			1,012			731			1,236
Asphalt	5,886			5,313			5,894			5,036
Other	713			504			678			708
Total production	60,547			62,085			50,258			66,351
Throughput (average barrels per day):
Crude Oil	58,362			65,975			49,199			67,688
Other feedstocks	1,748			(2,197		)	1,431			237
Total throughput	60,110			63,778			50,631			67,925
Per barrel of refined product sales:
El Dorado refining margin	$	4.25		$	9.21		$	8.34		$	8.89
Direct operating expenses	$	5.27		$	4.79		$	5.88		$	4.92
Crude Slate: (% based on amount received in period)
WTI crude oil	72.0		%	68.3		%	53.8		%	66.2		%
Local Arkansas crude oil	20.7		%	20.2		%	25.4		%	20.6		%
Other	7.2		%	11.5		%	20.8		%	13.2		%



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Management's Discussion and Analysis



Refinery Statistics (continued)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(Unaudited)						(Unaudited)
Big Spring, TX Refinery
Days in period	92			92			273			273
Total sales volume - refined product (average barrels per day)⁽¹⁾	72,909			78,062			77,712			72,669
Products manufactured (average barrels per day):
Gasoline	33,561			37,587			36,276			34,931
Diesel/Jet	28,391			29,177			27,796			25,864
Petrochemicals, LPG, NGLs	3,755			3,889			3,761			3,585
Asphalt	2,027			1,713			1,815			1,808
Other	1,423			1,504			1,339			1,366
Total production	69,157			73,870			70,986			67,554
Throughput (average barrels per day):
Crude oil	70,542			72,689			71,939			66,223
Other feedstocks	(1,282		)	828			(3		)	947
Total throughput	69,260			73,517			71,936			67,170
Per barrel of refined product sales:
Big Spring refining margin	$	12.21		$	22.20		$	14.78		$	16.73
Direct operating expenses	$	4.50		$	3.78		$	3.98		$	4.12
Crude Slate: (% based on amount received in period)
WTI crude oil	76.4		%	75.4		%	76.4		%	72.7		%
WTS crude oil	23.6		%	24.6		%	23.6		%	27.3		%

Krotz Springs, LA Refinery
Days in period	92			92			273			273
Total sales volume - refined product (average barrels per day) ⁽¹⁾	72,173			76,353			75,207			77,667
Products manufactured (average barrels per day):
Gasoline	34,757			33,103			35,760			36,028
Diesel/Jet	27,277			30,428			29,137			31,161
Heavy Oils	1,125			1,031			1,108			1,243
Petrochemicals, LPG, NGLs	3,814			6,531			5,103			7,188
Other	—			—			35			—
Total production	66,973			71,093			71,143			75,620
Throughput (average barrels per day):
Crude Oil	69,805			71,746			70,757			73,410
Other feedstocks	(3,553		)	(1,552		)	(596		)	1,072
Total throughput	66,252			70,194			70,161			74,482
Per barrel of refined product sales:
Krotz Springs refining margin	$	9.88		$	10.41		$	10.53		$	8.70
Direct operating expenses	$	4.27		$	3.98		$	4.18		$	3.80
Crude Slate: (% based on amount received in period)
WTI Crude	78.7		%	71.6		%	73.9		%	62.1		%
Gulf Coast Sweet Crude	21.3		%	28.4		%	26.1		%	37.9		%


⁽¹⁾	Includes inter-refinery sales and sales to other segments which are eliminated in consolidation. See tables below.



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Management's Discussion and Analysis

Included in the refinery statistics above are the following inter-refinery and sales to other segments:



Inter-refinery Sales
	Three Months Ended September 30,		Nine Months Ended September 30,
(in barrels per day)	2019	2018	2019	2018
	(Unaudited)		(Unaudited)

Tyler refined product sales to other Delek refineries	1,543	975	890	791
El Dorado refined product sales to other Delek refineries	39,885	48,071	38,614	29,331
Big Spring refined product sales to other Delek refineries	1,754	762	1,190	529
Krotz Springs refined product sales to other Delek refineries	15,189	41,123	8,785	33,538



Refinery Sales to Other Segments
	Three Months Ended September 30,		Nine Months Ended September 30,
(in barrels per day)	2019	2018	2019	2018
	(Unaudited)		(Unaudited)

Tyler refined product sales to other Delek segments	18	—	192	608
El Dorado refined product sales to other Delek segments	11	217	106	580
Big Spring refined product sales to other Delek segments	24,404	17,034	25,735	18,858



Pricing Statistics (average for the period presented)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(Unaudited)				(Unaudited)

WTI — Cushing crude oil (per barrel)	$	56.40	$	69.63	$	57.03	$	66.90
WTI — Midland crude oil (per barrel)	$	56.12	$	55.28	$	55.81	$	59.21
WTS -- Midland crude oil (per barrel) ⁽¹⁾	$	55.94	$	55.36	$	55.95	$	58.76
LLS (per barrel) ⁽¹⁾	$	60.58	$	74.14	$	63.32	$	71.06
Brent crude oil (per barrel)	$	62.03	$	75.76	$	64.73	$	72.71

U.S. Gulf Coast 5-3-2 crack spread (per barrel) ⁽¹⁾	$	14.18	$	14.33	$	14.25	$	13.44
U.S. Gulf Coast 3-2-1 crack spread (per barrel) ⁽¹⁾	$	17.55	$	17.43	$	17.34	$	17.02
U.S. Gulf Coast 2-1-1 crack spread (per barrel) ⁽¹⁾	$	12.03	$	11.20	$	9.73	$	10.59

U.S. Gulf Coast Unleaded Gasoline (per gallon)	$	1.64	$	1.98	$	1.65	$	1.91
Gulf Coast Ultra low sulfur diesel (per gallon)	$	1.85	$	2.14	$	1.89	$	2.06
U.S. Gulf Coast high sulfur diesel (per gallon)	$	1.74	$	2.03	$	1.77	$	1.92
Natural gas (per MMBTU)	$	2.33	$	2.86	$	2.56	$	2.85

⁽¹⁾

For our Tyler and El Dorado refineries, we compare our per barrel refining product margin to the Gulf Coast 5-3-2 crack spread consisting of WTI Cushing crude, U.S. Gulf Coast CBOB and U.S, Gulf Coast Pipeline No. 2 heating oil (high sulfur diesel). For our Big Spring refinery, we compare our per barrel refined product margin to the Gulf Coast 3-2-1 crack spread consisting of WTI Cushing crude, Gulf Coast 87 Conventional gasoline and Gulf Coast ultra low sulfur diesel, and for our Krotz Springs refinery, we compare our per barrel refined product margin to the Gulf Coast 2-1-1 crack spread consisting of LLS crude oil, Gulf Coast 87 Conventional gasoline and U.S, Gulf Coast Pipeline No. 2 heating oil (high sulfur diesel). The Tyler refinery's crude oil input is primarily WTI Midland and east Texas, while the El Dorado refinery's crude input is primarily a combination of WTI Midland, local Arkansas and other domestic inland crude oil. The Big Spring refinery’s crude oil input is primarily comprised of WTS and WTI Midland. The Krotz Springs refinery’s crude oil input is primarily comprised of LLS and WTI Midland.



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Management's Discussion and Analysis

Refining Segment Operational Comparison of the Three and Nine Months Ended September 30, 2019 versus the Three and Nine Months Ended September 30, 2018

Net Revenues

Q3 2019 vs. Q3 2018

Net revenues for the refining segment decreased by $472.5 million, or 17.8%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	decreases in the average price of U.S. Gulf Coast gasoline of 17.0%, ULSD of 13.4%, and HSD of 14.5%; and


•	decreases in sales volume of refined product totaling 1.6 million barrels partially due to vacuum unit outage at our El Dorado refinery and decreased throughput at our Big Spring refinery, offset by a 0.2 million barrel increase in purchased product sales across all four refineries primarily to compensate for production shortfalls.

Net revenues included sales to our retail segment of $97.3 million and $122.4 million, and sales to our logistics segment of $66.6 million and $83.9 million. Also included was a reduction in sales to our other segment of $23.9 million and sales of $22.5 million for the three months ended September 30, 2019 and September 30, 2018, respectively. We eliminate this intercompany revenue in consolidation.

YTD 2019 vs. YTD 2018

Net revenues for the refining segment decreased by $681.8 million, or 9.3%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	decreases in the average price of U.S. Gulf Coast gasoline of 13.6%, ULSD of 8.3%, and HSD of 7.8%; and

•

decreases in sales volume of refined product totaling 4.9 million barrels consisting of decreases in sales volumes at our El Dorado refinery primarily resulting from vaccum unit outage and scheduled turnaround activities and decreases in sales volumes at the Tyler refinery related to unit outages or maintenance stoppages, offset by a 1.4 million barrel increase in sales volumes of refined product at our Big Spring refinery and a 5.9 million barrel increase in purchased product sales across all four refineries primarily to compensate for production shortfalls.

Net revenues included sales to our retail segment of $289.2 million and $340.9 million, sales to our logistics segment of $219.2 million and $265.7 million and sales to our other segment of $31.5 million and $33.6 million for the nine months ended September 30, 2019 and 2018, respectively. We eliminate this intercompany revenue in consolidation.

Cost of Materials and Other

Q3 2019 vs. Q3 2018

Cost of materials and other decreased by $282.4 million, or 12.8%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	a decrease in the cost of WTI Cushing crude oil, from an average of $69.63 per barrel to an average of $56.40, or 19.0%;



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Management's Discussion and Analysis


•	a decrease in RIN expense primarily due to 2018 RIN Waivers received in the third quarter of 2019, which resulted in a reduction of our RINs Obligation and related cost of materials and other of approximately $20.7 million. Additionally, ethanol RIN prices averaged $0.19 per RIN in third quarter 2019 compared to $0.21 per RIN in the prior year period; and


•	partially offset by an increase in the cost of WTI Midland crude oil, from an average of $55.28 per barrel to an average of $56.12, or 1.5%.

YTD 2019 vs. YTD 2018

Cost of materials and other decreased by $662.1 million, or 10.4%, during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	a decrease in the cost of WTI Cushing crude oil, from an average of $66.90 per barrel to an average of $57.03, or 14.8%;


•	a decrease in the cost of WTI Midland crude oil, from an average of $59.21 per barrel to an average of $55.81, or 5.7%; and


•	the net reversal benefit of $30.1 million related to inventory valuation reserves recognized during the nine months ended September 30, 2019 compared to the net reversal benefit of $1.9 million recognized during the nine months ended September 30, 2018.

These decreases were partially offset by the following:


•	a prior period benefit of approximately $115.5 million related to a combination of the 2017 RIN Waivers and a biodiesel tax credit recognized during the nine months ended September 30, 2018, whereas 2018 RIN Waivers provided a benefit of $20.7 million the same period of 2019.

Our refining segment purchases finished product from our logistics segment and has multiple service agreements with our logistics segment which, among other things, require the refining segment to pay terminalling and storage fees based on the throughput volume of crude and finished product in the logistics segment pipelines and the volume of crude and finished product stored in the logistics segment storage tanks, subject to minimum volume commitments. These costs and fees were $55.4 million and $54.1 million during the third quarters of 2019 and 2018, respectively, and $159.8 million and $152.0 million during the nine months ended September 30, 2019 and 2018, respectively. We eliminate these intercompany fees in consolidation.

Refining Margin

Q3 2019 vs. Q3 2018

Refining margin decreased by $190.1 million, or 43.4%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	a narrowing of the average WTI Cushing crude oil differential to WTS crude oil to $0.46 per barrel during the third quarter of 2019 compared to $14.27 during the third quarter of 2018 and narrowing of the average WTI Midland crude oil differential to WTI Cushing crude oil to $0.28 per barrel during the third quarter of 2019 compared to $14.35 during the third quarter of 2018; and


•	a narrowing of the discount between WTI Midland crude oil and Brent crude oil where, during the third quarter of 2019, the WTI Midland crude oil differential to Brent crude oil was an average discount of $5.91 per barrel compared to $20.48 per barrel during the third quarter of 2018;



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Management's Discussion and Analysis


•	an inventory valuation reserve of $21.4 million recognized during the third quarter of 2019 compared to the reserve of $0.1 million recognized during the nine months of 2018; and


•	reduced performance at our El Dorado refinery due to vacuum unit outage, where the refining margin was $4.25 per barrel during the third quarter of 2019 as compared to $9.21 per barrel for the comparable prior year period, and operating expenses were $5.27 per barrel and $4.79 per barrel during the third quarter of 2019 and 2018, respectively.

These decreases were partially offset by the following:


•	a 1.0% improvement in the 5-3-2 crack spread (the primary measure for the Tyler refinery and El Dorado refinery);


•	a 0.7% improvement in the average Gulf Coast 3-2-1 crack spread (the primary measure for the Big Spring refinery); and


•	the benefit attributable to the decrease in RIN prices.

YTD 2019 vs. YTD 2018

Refining margin decreased by $19.7 million, or 2.0%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	a narrowing of the discount between WTI Midland crude oil compared to WTI Cushing where, during the nine months of 2019, the average WTI Midland crude oil differential to WTI Cushing crude oil was $1.22 per barrel compared to $7.69 during the nine months of 2018;



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Management's Discussion and Analysis


•	a narrowing of the discount between WTI Midland crude oil and Brent crude oil where, during the nine months of 2019, the WTI Midland crude oil differential to Brent crude oil was an average discount of $8.92 per barrel compared to $13.50 per barrel during the same period of 2018;


•	a narrowing of the average WTI Cushing crude oil differential to WTS crude oil to $1.08 per barrel during the nine months of 2019 compared to $8.14 during the nine months of 2018;


•	a 8.1% decline in the average Gulf Coast 2-1-1 crack spread (the primary measure for the Krotz Springs refinery); and


•	a prior period benefit of approximately $115.5 million related to a combination of the 2017 RIN Waivers and a biodiesel tax credit recognized during the nine months of 2018, whereas 2018 RIN Waivers provided a benefit of $20.7 million the same period of 2019.

These decreases were partially offset by the following:


•	a wider discount between WTI Cushing crude oil compared to Brent where, during the nine months of 2019, the average WTI Cushing crude oil differential to Brent crude oil was $7.70 per barrel compared to $5.81 during the nine months of 2018,


•	a 6.0% improvement in the 5-3-2 crack spread (the primary measure for the Tyler refinery and El Dorado refinery);


•	a 1.9% improvement in the average Gulf Coast 3-2-1 crack spread (the primary measure for the Big Spring refinery);


•	the net reversal benefit of $30.1 million related to inventory valuation reserves recognized during the nine months of 2019 compared to the net reversal benefit of $1.9 million recognized during the nine months of 2018; and


•	the benefit attributable to the decrease in RIN prices.



64 \|

Management's Discussion and Analysis

Operating Expenses

Q3 2019 vs. Q3 2018

Operating expenses increased by $1.9 million, or 1.6%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	increases in employee related costs and outside services at our El Dorado and Big Spring refineries; and


•	partially offsetting decreases in expenses at the Tyler and Krotz Springs refineries.

YTD 2019 vs. YTD 2018

Operating expenses increased by $10.0 million, or 2.9%, during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	an overall net increase of $13.3 million in outside services costs across the Tyler, Big Spring and Krotz Springs refineries primarily related to various unit outages and project studies;


•	an increase in employee related costs of $7.9 million across all four refineries;


•	an offsetting decrease of $4.3 million in variable expenses, primarily due to reduced production at our El Dorado and Big Spring refineries; and


•	offsetting reductions in repairs and maintenance expense at the El Dorado, Krotz Springs and Big Spring refineries.

Contribution Margin

Q3 2019 vs. Q3 2018

Contribution margin decreased by $192.0 million, or a 6.9% reduction in contribution margin percentage, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	the decline of the Midland WTI crude oil differential to Brent crude oil compared to the prior-year period;


•	reduced performance at our El Dorado refinery due to vacuum unit outage; and


•	a narrowing of the discount between WTI Cushing and WTS crude oil compared to the third quarter of 2018.

These decreases were partially offset by the following:


•	the impact of the addition of the alkylation unit at our Krotz Springs refinery in April 2019;


•	a 1.0% improvement in the 5-3-2 crack spread (the primary measure for the Tyler and El Dorado refineries), a 0.7% improvement in the average Gulf Coast 3-2-1 crack spread (the primary measure for the Big Spring refinery) and a 7.4% improvement in the average Gulf Coast 2-1-1 crack spread (the primary measure for the Krotz Springs refinery); and


•	the benefit attributable to the decrease in RIN prices and 2018 RIN Waivers received during the third quarter of 2019.

YTD 2019 vs. YTD 2018

Contribution margin decreased by $29.7 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	a 8.1% decline in the average Gulf Coast 2-1-1 crack spread (the primary measure for the Krotz Springs refinery);


•	a narrowing of the discount between WTI Cushing and WTS crude oil compared to the prior-year period;


•	a narrowing of the discount between WTI Midland and WTI Cushing compared to the prior-year period; and


•	a prior period benefit of approximately $115.5 million related to a combination of the 2017 RINs waivers and a biodiesel tax credit recognized during the nine months of 2018, whereas 2018 RIN Waivers provided a benefit of $20.7 million the same period of 2019.

These decreases were partially offset by the following:


•	a 6.0% improvement in the 5-3-2 crack spread (the primary measure for the Tyler and El Dorado refineries) and a 1.9% improvement in the average Gulf Coast 3-2-1 crack spread (the primary measure for the Big Spring refinery);


•	the net reversal benefit of $30.1 million related to inventory valuation reserves recognized during the nine months of 2019 compared to the net reversal benefit of $1.9 million recognized during the nine months of 2018; and


•	the benefit attributable to the decrease in RIN prices.



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Management's Discussion and Analysis

Logistics Segment

The table below sets forth certain information concerning our logistics segment operations ($ in millions, except per barrel amounts):



Logistics Segment Contribution
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net revenues	$	137.6	$	164.1	$	445.4	$	498.3
Cost of materials and other	72.6		105.6		262.7		330.6
Operating expenses (excluding depreciation and amortization)	18.4		15.4		51.8		42.9
Contribution margin	$	46.6	$	43.1	$	130.9	$	124.8

Operating Information
	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
East Texas - Tyler Refinery sales volumes (average bpd)⁽¹⁾	83,953		79,404		74,607		77,349
West Texas wholesale marketing throughputs (average bpd)	9,535		12,197		11,446		13,453
West Texas wholesale marketing margin per barrel	$	4.82	$	4.65	$	4.83	$	5.88
Big Spring wholesale marketing throughputs (average bpd) ⁽²⁾	80,203		80,687		83,608		79,819
Terminalling throughputs (average bpd) ⁽³⁾	170,727		167,491		160,621		159,457
Lion Pipeline System Throughputs (average bpd):
Crude pipelines (non-gathered)	49,477		59,150		43,446		56,672
Refined products pipelines to Enterprise Systems	43,518		43,762		32,242		47,154
SALA Gathering System Throughputs (average bpd)	21,632		16,704		21,143		16,705
East Texas Crude Logistics System Throughputs (average bpd)	25,391		14,284		21,045		16,402


⁽¹⁾	Excludes jet fuel and petroleum coke.


⁽²⁾	Throughputs for the nine months ended September 30, 2018 are for the 214 days we marketed certain finished products produced at or sold from the Big Spring Refinery following the execution of the Big Spring Marketing Agreement, effective March 1, 2018, as defined in Note 3 to our accompanying condensed consolidated financial statements.

⁽³⁾

Consists of terminalling throughputs at our Tyler, Big Spring, Big Sandy and Mount Pleasant, Texas, our El Dorado and North Little Rock, Arkansas and our Memphis and Nashville, Tennessee terminals. Throughputs for the nine months ended September 30, 2018 for the Big Spring terminal are for the 214 days we operated the terminal following its acquisition effective March 1, 2018. Barrels per day are calculated for only the days we operated each terminal. Total throughput barrels for the nine months ended September 30, 2018 was 41.4 million barrels, which averaged 151,646 bpd for the 273 day period.

Logistics Segment Operational Comparison of the Three and Nine Months Ended September 30, 2019 versus the Three and Nine Months Ended September 30, 2018

Net Revenues

Q3 2019 vs. Q3 2018

Net revenues decreased by $26.5 million, or 16.1%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	decreases in the average volumes sold and in the average sales prices per gallon of gasoline and diesel in our west Texas marketing operations.


◦	the average volumes of gasoline and diesel sold decreased 2.2 million gallons and 8.0 million gallons, respectively.


◦	the average sales prices per gallon of gasoline and diesel sold decreased $0.24 per gallon and $0.33 per gallon, respectively.

Such decreases were partially offset by the following:


•	increased revenues for marketing and terminalling services under the agreements associated with certain of our assets in Big Spring, Texas as a result of increased throughput;


•	increased revenues associated with our Paline Pipeline as a result of increased rates and a change in the fee structure from the third quarter of 2018, during which the capacity of the Paline Pipeline was contracted to separate parties for a monthly fee, compared to the third quarter of 2019, during which the pipeline was subject to a FERC tariff;



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Management's Discussion and Analysis


•	increased revenues from fees received by Delek Logistics related to the management of a long-term capital project for the construction of a gathering system in the Permian Basin ("Delek Permian Gathering Project") on behalf of Delek during the third quarter of 2019 for which there were no fees earned during the third quarter of 2018; and


•	increased revenues associated with our trucking assets.

Net revenues included sales to our refining segment of $65.4 million and $63.8 million for the three months ended September 30, 2019 and September 30, 2018, respectively, and sales to our other segment of $0.8 million for the three months ended September 30, 2019 . We eliminate this intercompany revenue in consolidation.

YTD 2019 vs. YTD 2018

Net revenues decreased by $52.9 million, or 10.6%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	decreases in the average volumes and in the average sales prices per gallon of gasoline and diesel sold in our west Texas marketing operations.


◦	the average volumes of gasoline and diesel sold decreased 8.5 million gallons and 15.2 million gallons, respectively.


◦	the average sales prices per gallon of gasoline and diesel sold decreased $0.22 per gallon and $0.21 per gallon, respectively.

Such decreases were partially offset by the following:


•	net revenues generated under the agreements executed in connection with the Big Spring Logistic Assets Acquisition, which were effective March 1, 2018. Refer to Note 3 to our accompanying condensed consolidated financial statements for additional information about the agreements executed in connection with the Big Spring Logistic Assets Acquisition;


•	increased revenues associated with our Paline Pipeline as a result of increased rates and a change in the fee structure from the nine months ended September 30, 2018, during which the capacity of the Paline Pipeline was contracted to separate parties for a monthly fee, compared to the nine months ended September 30, 2019, during which the pipeline was subject to a FERC tariff;


•	increased revenues from fees received by Delek Logistics related to the management of the Delek Permian Gathering Project during the nine months ended September 30, 2019 for which there were no fees earned during the nine months ended September 30, 2018; and


•	increased revenues associated with our trucking assets.

Net revenues included sales to our refining segment of $187.5 million and $178.5 million for the nine months ended September 30, 2019 and 2018, respectively, and sales to our other segment of $3.6 million for the nine months ended September 30, 2019 . We eliminate this intercompany revenue in consolidation.



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Management's Discussion and Analysis

Cost of Materials and Other

Q3 2019 vs. Q3 2018

Cost of materials and other for the logistics segment decreased $33.0 million, or 31.3%, in the third quarter of 2019 compared to the third quarter of 2018. This decrease was primarily driven by the following:


•	decreases in the average volumes sold and in the average cost per gallon of gasoline and diesel sold in our west Texas marketing operations.


◦	the average volumes of gasoline and diesel sold decreased 2.2 million gallons and 8.0 million gallons, respectively.


◦	the average cost per gallon of gasoline and diesel sold decreased $0.26 per gallon and $0.31 per gallon, respectively.

Our logistics segment purchased product from our refining segment of $66.6 million and $83.9 million for the three months ended September 30, 2019 and September 30, 2018, respectively. We eliminate these intercompany costs in consolidation.

YTD 2019 vs. YTD 2018

Cost of materials and other for the logistics segment decreased $67.9 million, or 20.5%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. This decrease was primarily driven by the following:


•	decreases in the average volumes sold and in the average cost per gallon of gasoline and diesel sold in our west Texas marketing operations.


◦	the average volumes of gasoline and diesel sold decreased 8.5 million gallons and 15.2 million gallons, respectively.


◦	the average cost per gallon of gasoline and diesel sold decreased $0.22 per gallon and $0.18 per gallon, respectively.

Our logistics segment purchased product from our refining segment of $219.2 million and $265.7 million for the nine months ended September 30, 2019 and September 30, 2018, respectively. We eliminate these intercompany costs in consolidation.

Operating Expenses

Q3 2019 vs. Q3 2018

Operating expenses increased by $3.0 million, or 19.5%, in the third quarter of 2019 compared to the third quarter of 2018, driven by the following:


•	higher operating costs associated with various logistics assets, including variable expenses such as utilities, contractor and materials costs; and


•	a reduction in expense associated with expenditures on certain of our assets during the third quarter of 2018, with no comparable reduction during the third quarter of 2019.

YTD 2019 vs. YTD 2018

Operating expenses increased by $8.9 million, or 20.7%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, driven by the following:


•	higher operating costs associated with allocated contract services pertaining to certain of our assets; and



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Management's Discussion and Analysis


•	higher employee costs allocated to Delek Logistics as a result of an increase in allocated employee headcount in various operational groups.

These increases were partially offset by:


•	decreases in variable expenses such as utilities, maintenance and materials costs.

Contribution Margin

Q3 2019 vs. Q3 2018

Contribution margin increased by $3.5 million, or 8.1%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	increases in revenues associated with Paline pipeline, trucking assets and fees from management of the Delek Permian Gathering Project; and


•	increase in gross margin of $0.17 per barrel of our gasoline and diesel sold in our west Texas marketing operations.

Such increases were partially offset by the following:


•	higher operating expenses; and


•	decreases in the volumes of gasoline and diesel sold in our west Texas marketing operations.

YTD 2019 vs. YTD 2018

Contribution margin increased by $6.1 million, or 4.9%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	increases in revenue generated under the agreements executed in connection with the Big Spring Logistic Assets Acquisition.

Such increases were partially offset by the following:


•	higher operating expenses; and


•	decreases in the volumes combined with a $1.05 decrease in gross margin per barrel of gasoline and diesel sold in our west Texas marketing operations.



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Management's Discussion and Analysis

Retail Segment

The table below sets forth certain information concerning our retail segment operations (gross sales $ in millions):



Retail Segment Contribution
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net revenues	$	218.5		$	246.4		$	640.2		$	700.8
Cost of materials and other	176.4			204.4			521.9			578.5
Operating expenses (excluding depreciation and amortization)	23.5			26.7			71.9			76.5
Contribution margin	$	18.6		$	15.3		$	46.4		$	45.8

Operating Information
Number of stores (end of period)	263			295			263			295
Average number of stores	263			295			263			295
Average number of fuel stores	255			286			255			286
Retail fuel sales	$	137.4		$	154.2		$	400.1		$	435.2
Retail fuel sales (thousands of gallons)	54,943			55,996			162,576			163,809
Average retail gallons sold per average number of fuel stores (in thousands)	215			196			638			573
Average retail sales price per gallon sold	$	2.50		$	2.75		$	2.46		$	2.66
Retail fuel margin ($ per gallon) ⁽¹⁾	$	0.315		$	0.231		$	0.269		$	0.219
Merchandise sales (in millions)	$	81.5		$	89.7		$	240.2		$	258.0
Merchandise sales per average number of stores (in millions)	$	0.3		$	0.3		$	0.9		$	0.9
Merchandise margin %	30.5		%	31.3		%	30.9		%	31.1		%



Same-Store Comparison ⁽²⁾
	Three Months Ended September 30, 2019		Three Months Ended September 30, 2018		Nine Months Ended September 30, 2019
Change in same-store fuel gallons sold	3.0	%	4.4	%	3.1	%
Change in same-store merchandise sales	(1.5	)%	3.7	%	(1.3	)%


⁽¹⁾	Retail fuel margin represents gross margin on fuel sales in the retail segment, and is calculated as retail fuel sales revenue less retail fuel cost of sales. The retail fuel margin per gallon calculation is derived by dividing retail fuel margin by the total retail fuel gallons sold for the period.


⁽²⁾	Same-store comparisons include period-over-period increases or decreases in specified metrics for stores that were in service at both the beginning of the earliest period and the end of the most recent period used in the comparison.

Retail Segment Operational Comparison of the Three and Nine Months Ended September 30, 2019 versus the Three and Nine Months Ended September 30, 2018

Net Revenues

Q3 2019 vs. Q3 2018

Net revenues for the retail segment decreased by $27.9 million, or 11.3%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	total fuel sales were $137.4 million in the third quarter of 2019 compared to $154.2 million in the third quarter of 2018, attributable to the following:


◦	$7.1 million decrease related to reduction in number of stores period over period;


◦	a $0.25 decrease in average price charged per gallon; and


◦	a slight decrease in total retail fuel gallons sold for the retail segment to 54,943 thousand gallons in the third quarter of 2019 compared to 55,996 thousand gallons in the third quarter of 2018 associated with the reduction in average number of stores period over period, where there was a same-store sales growth in fuel volumes of 3.0%;



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Management's Discussion and Analysis


•	merchandise sales were $81.5 million in the third quarter of 2019 compared to $89.7 million in the third quarter of 2018 attributable to the following:


◦	$7.0 million decrease related to reduction in number of stores; and


◦	same-store sales decrease of 1.5%.

YTD 2019 vs. YTD 2018

Net revenues for the retail segment decreased by $60.6 million, or 8.6%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	total fuel sales were $400.1 million in the nine months of 2019 compared to $435.2 million in the nine months of 2018, attributable to the following:


◦	$15.1 million decrease related to reduction in number of stores period over period;


◦	a $0.20 decrease in average price charged per gallon; and


◦	a slight decrease in total retail fuel gallons sold of 162,576 thousand gallons in the nine months of 2019 compared to 163,809 thousand gallons in the nine months of 2018, attributable to a decrease in volumes associated with the reduction in average number of stores period over period offset by same-store sales growth in fuel volumes of 3.1%.


•	merchandise sales were $240.2 million in the nine months of 2019 compared to $258.0 million in the nine months of 2018 primarily driven by the following:


◦	$14.7 million decrease related to reduction in number of stores period over period; and


◦	a same-store sales decrease of 1.3%.



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Management's Discussion and Analysis

Cost of Materials and Other

Q3 2019 vs. Q3 2018

Cost of materials and other for the retail segment decreased by $28.0 million, or 13.7%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven by the following:


•	$11.9 million decrease due to reduction in number of stores period over period;


•	a decrease in average cost per gallon of $0.33 or 13.2% applied to fuel sales volumes that decreased slightly period over period.

Our retail segment purchased finished product from our refining segment of $97.3 million and $122.4 million for the three months ended September 30, 2019 and September 30, 2018. We eliminate this intercompany cost in consolidation.

YTD 2019 vs. YTD 2018

Cost of materials and other for the retail segment decreased by $56.6 million, or 9.8%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by the following:


•	$26.4 million decrease due to reduction in number of stores period over period;


•	a decrease in average cost per gallon of $0.24 or 9.8% applied to fuel sales volumes that decreased slightly period over period.

Our retail segment purchased finished product from our refining segment of $289.2 million and $340.9 million for the nine months ended September 30, 2019 and September 30, 2018. We eliminate this intercompany cost in consolidation.

Operating Expenses

Q3 2019 vs. Q3 2018

Operating expenses for the retail segment decreased by $3.2 million, or 12.0% in the third quarter of 2019 compared to the third quarter of 2018. This decrease is primarily attributable to a decrease in operating costs associated with the reduction in the number of stores.

YTD 2019 vs. YTD 2018

Operating expenses for the retail segment decreased by $4.6 million, or 6.0% in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. This decrease is primarily attributable to a decrease in operating costs associated with the reduction in the number of stores.

Contribution Margin

Q3 2019 vs. Q3 2018

Contribution margin for the retail segment increased by $3.3 million, or 21.6%, in the third quarter of 2019 compared to the third quarter of 2018, primarily driven a $0.084 per gallon improvement in the retail fuel margin, partially offset by a reduction in merchandise margin.

YTD 2019 vs. YTD 2018

Contribution margin for the retail segment increased by $0.6 million, or 1.3%, in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily driven by a $0.050 per gallon improvement in the retail fuel margin, partially offset by a reduction in merchandise margin.



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Management's Discussion and Analysis

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are


•	cash generated from our operating activities;


•	borrowings under our debt facilities; and


•	potential issuances of additional equity and debt securities.

We believe that cash generated from these sources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations and capital expenditures for at least the next 12 months.

Cash Flows

The following table sets forth a summary of our consolidated cash flows (in millions):



Consolidated
	Nine Months Ended September 30,
	2019			2018
Cash Flow Data:
Operating activities	$	448.4		$	201.2
Investing activities	(509.5		)	(37.2		)
Financing activities	(11.8		)	3.2
Net (decrease) increase	$	(72.9	)	$	167.2

Cash Flows from Operating Activities

Net cash provided by operating activities was $448.4 million for the nine months ended September 30, 2019, compared to $201.2 million for the comparable period of 2018. The increase in cash flows from operations was partially due to an increase in net income, which for the nine months ended September 30, 2019 was $298.2 million, compared to $247.5 million in the same period of 2018. Additionally, net income for the nine months ended September 30, 2019 included non-cash net expenses of $202.0 million compared to $106.9 million in the prior year. The increase in non-cash expenses was primarily driven by an increase in deferred tax expense and an increase due to changes in fair value of derivatives; such increases were partially offset by increase in income from equity method investments. Changes in working capital, net of non-cash items, which resulted in cash used of $56.6 million during the nine months ended September 30, 2019 as compared to $140.9 million in the comparable prior year period, contributed $84.3 million to the increase in operating cash flows. Changes in our obligation under Supply and Offtake Agreement contributed $14.2 million to the increase in cash flows from operating activities. Partially offsetting these increases was a $27.2 million decrease due to changes in non-current assets and liabilities.

Cash Flows from Investing Activities

Net cash used in investing activities was $509.5 million for the first nine months of 2019, compared to $37.2 million in the comparable period of 2018. The increase in cash flows used in investing activities was primarily due to an increase in cash purchases of property, plant and equipment and capital expenditures related to turnaround activities, which increased from $228.0 million in 2018, to $305.7 million in 2019, and a $213.8 million increase in equity method investment contributions in the current year, $124.7 million of which related to our obtaining a 33% membership interest in Red River Red River Pipeline Joint Venture in May 2019 and $75.3 million of which related to our obtaining a 15% interest in the WWP in July 2019. Also contributing to this increase was the sale of asphalt assets and discontinued operations in 2018, for which we received proceeds of $110.8 million and $55.5 million, respectively.

Cash Flows from Financing Activities

Net cash used in financing activities was $11.8 million for the nine months ended September 30, 2019, compared to net cash provided of $3.2 million in the comparable 2018 period. The decrease in net cash provided by financing activities was partially due to the decrease in net proceeds received from long-term revolvers due to completion of the Refinancing transaction as well as the additional borrowings used to fund the Big Spring Logistic Assets Acquisition during the nine months ended September 30, 2018. We made net payments on long-term revolvers of $0.5 million during the nine months ended September 30, 2019 compared to net proceeds received of $521.3 million in the comparable 2018 period. Partially offsetting this decrease was a decrease in repurchase of common stock to $147.8 million for the nine months ended September 30, 2019 compared to $207.4 million in the comparable 2018 period, a decrease in repayments of product financing arrangements to $22.2 million for the nine months ended September 30, 2019 compared to $72.4 million in the comparable 2018 period, an increase in term loan net proceeds of $215.3 million for the nine months ended September 30, 2019 compared to term loan net payments of



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$134.0 million in the comparable 2018 period, as well as proceeds from product financing arrangements of $40.8 million during the nine months ended September 30, 2019; there were no such proceeds in the comparable 2018 period.

Cash Position and Indebtedness

As of September 30, 2019, our total cash and cash equivalents were $1,006.4 million and we had total indebtedness of approximately $1,999.9 million. Total unused credit commitments or borrowing base availability, as applicable, under our revolving credit facilities was approximately $800.2 million and we had letters of credit issued of approximately $293.5 million. We believe we were in compliance with our covenants in all debt facilities as of September 30, 2019. See Note 10 of the condensed consolidated financial statements in Item 1, Financial Statements, for additional information about our separate credit facilities.

Capital Spending

A key component of our long-term strategy is our capital expenditure program. Our capital expenditures for the nine months ended September 30, 2019 were $324.8 million, of which approximately $193.8 million was spent in our refining segment, $6.2 million in our logistics segment, $14.3 million in our retail segment and $110.5 million at the holding company level. The following table summarizes our actual capital expenditures for the nine months ended September 30, 2019 and planned capital expenditures for the full year 2019 by operating segment and major category (in millions):



	Full Year 2019 Forecast		Nine Months Ended September 30, 2019
Refining
Sustaining maintenance, including turnaround activities	$	149.1	$	120.5
Regulatory	61.8		37.3
Discretionary projects	35.9		36.0
Refining segment total	246.8		193.8

Logistics
Regulatory	2.5		2.1
Sustaining maintenance	5.8		3.2
Discretionary projects	1.5		0.9
Logistics segment total	9.8		6.2

Retail
Regulatory	—		—
Sustaining maintenance	3.6		3.3
Discretionary projects	17.7		11.0
Retail segment total	21.3		14.3

Other
Regulatory	1.0		0.5
Sustaining maintenance	1.8		0.9
Discretionary projects	134.2		109.1
Other total	137.0		110.5
Total capital spending	$	414.9	$	324.8

The amount of our capital expenditure budget is subject to change due to unanticipated increases in the cost, scope and completion time for our capital projects. For example, we may experience increases in the cost of and/or timing to obtain necessary equipment required for our continued compliance with government regulations or to complete improvement projects or scheduled maintenance activities. Additionally, the scope and cost of employee or contractor labor expense related to installation of that equipment could exceed our projections. Our capital expenditure budget may also be revised as management continues to evaluate projects for reliability or profitability.

We have no off-balance sheet arrangements through the date of the filing of this Quarterly Report on Form 10-Q.



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Management's Discussion and Analysis

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

These disclosures should be read in conjunction with the condensed consolidated financial statements, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and other information presented herein, as well as in the "Quantitative and Qualitative Disclosures About Market Risk" section contained in our Annual Report on Form 10-K, as amended and filed on June 27, 2019.

Price Risk Management Activities

At times, we enter into the following instruments/transactions in order to manage our market-indexed pricing risk: commodity derivative contracts which we use to manage our price exposure to our inventory positions, future purchases of crude oil and ethanol, future sales of refined products or to fix margins on future production; and future commitments to purchase or sell RINs at fixed prices and quantities, which are used to manage the costs associated with our RINs obligations and meet the definition of derivative instruments under ASC 815, Derivatives and Hedging ("ASC 815"). In accordance with ASC 815, all of these commodity contracts and future purchase commitments are recorded at fair value, and any change in fair value between periods has historically been recorded in the profit and loss section of our condensed consolidated financial statements. Occasionally, at inception, the Company will elect to designate the commodity derivative contracts as cash flow hedges under ASC 815. Gains or losses on commodity derivative contracts accounted for as cash flow hedges are recognized in other comprehensive income on the condensed consolidated balance sheets and, ultimately, when the forecasted transactions are completed, in net revenues or cost of materials and other in the condensed consolidated statements of income.

The following table sets forth information relating to our open commodity derivative contracts as of September 30, 2019 ($ in millions):



	Total Outstanding				Notional Contract Volume by Year of Maturity
Contract Description	Fair Value			Notional Contract Volume	2019	2020	2021
Contracts not designated as hedging instruments:
Crude oil price swaps - long⁽¹⁾	$	(6.3	)	27,763,000	12,565,000	11,218,000	3,980,000
Crude oil price swaps - short⁽¹⁾	2.3			29,231,000	12,896,000	12,355,000	3,980,000
Inventory, refined product and crack spread swaps - long⁽¹⁾	(29.4		)	15,539,000	10,863,000	4,411,000	265,000
Inventory, refined product and crack spread swaps - short⁽¹⁾	22.2			18,362,000	16,140,000	1,847,000	375,000
Natural gas swaps - long⁽²⁾	(9.4		)	34,652,500	31,050,000	3,602,500	—
Natural gas swaps - short⁽²⁾	5.4			41,857,500	41,625,000	232,500	—
RIN commitment contracts - long⁽³⁾	1.9			160,978,000	—	—	—
RIN commitment contracts - short⁽³⁾	0.5			122,403,000	—	—	—
Total	$	(12.8	)	450,786,000	125,139,000	33,666,000	8,600,000
Contracts designated as cash flow hedging instruments:
Crude oil price swaps - long⁽¹⁾	$	14.4		2,152,000	2,152,000	—	—
Crude oil price swaps - short⁽¹⁾	—			—	—	—	—
Inventory, refined product and crack spread swaps - long⁽¹⁾	(4.2		)	300,000	—	300,000	—
Inventory, refined product and crack spread swaps - short⁽¹⁾	5.5			300,000	—	300,000	—
Total	$	15.7		2,752,000	2,152,000	600,000	—

(1)Volume in barrels

(2)Volume in MMBTU

(3)Volume in RINs



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Management's Discussion and Analysis

Interest Risk Management Activities

We have market exposure to changes in interest rates relating to our outstanding floating rate borrowings, which totaled approximately $1,694.5 million as of September 30, 2019. The annualized impact of a hypothetical one percent change in interest rates on our floating rate debt as of September 30, 2019 would be to change interest expense by approximately $16.9 million.

Commodity Derivatives Trading Activities

In the first half of 2018, we began entering into active trading positions in a variety of commodity derivatives, which include forward physical contracts, swap contracts, and futures contracts. These contracts are classified as held for trading and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to create incremental gains by capitalizing on crude oil supply and pricing seasonality. These contracts had remaining durations of less than one year as of September 30, 2019.

The following table sets forth information relating to commodity derivative contracts held for trading purposes as of September 30, 2019:



Contract Description	Less than 1 year
Over the counter forward sales contracts
Notional contract volume ⁽¹⁾	960,461
Weighted-average market price (per barrel)	$	41.03
Contractual volume at fair value (in millions)	$	39.4
Over the counter forward purchase contracts
Notional contract volume ⁽¹⁾	802,788
Weighted-average market price (per barrel)	$	41.08
Contractual volume at fair value (in millions)	$	33.0


⁽¹⁾	Volume in barrels

ITEM 4. CONTROLS AND PROCEDURES

Our disclosure controls and procedures are designed to provide reasonable assurance that the information that we are required to disclose in reports we file under the Securities Exchange Act of 1934, as amended ("the Exchange Act"), is accumulated and appropriately communicated to management. We carried out an evaluation required by Rule 13a-15(b) of the Exchange Act, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures at the end of the reporting period. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the reporting period.

There have been no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during the third quarter of 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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Legal Proceedings, Risk Factors, Unregistered Sales of Equity Securities and Other Information

Part II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In the ordinary conduct of our business, we are from time to time subject to lawsuits, investigations and claims, including, environmental claims and employee-related matters. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, including civil penalties or other enforcement actions, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations. See Note 13 to our accompanying condensed consolidated financial statements, which is incorporated by reference in this Item1, for additional information. Aside from the disclosure in Note 13, there have been no material developments to the proceedings previously reported in our Annual Report on Form 10-K, as amended and filed on June 27, 2019.

ITEM 1A. RISK FACTORS

There have been no material changes in the risk factors previously disclosed in "Item 1A. Risk Factors" of our Annual Report on Form 10-K, as amended and filed on June 27, 2019.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On November 6, 2018, our Board of Directors authorized a share repurchase program for up to $500.0 million of Delek common stock. Any share repurchases under the repurchase program may be implemented through open market transactions or in privately negotiated transactions, in accordance with applicable securities laws. The timing, price, and size of repurchases will be made at the discretion of management and will depend on prevailing market prices, general economic and market conditions and other considerations. The repurchase program does not obligate us to acquire any particular amount of stock and does not expire. The following table sets forth information with respect to the purchase of shares of our common stock made during the three months ended September 30, 2019 by or on behalf of us or any “affiliated purchaser,” as defined by Rule 10b-18 of the Exchange Act (inclusive of all purchases that have settled as of September 30, 2019):



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2019	132,776	$	39.30	132,776	$	299,722,910
August 1 - August 31, 2019	484,667	32.09		484,667	284,167,582
September 1 - September 30, 2019	619,411	35.88		619,411	261,945,757
Total	1,236,854	$	34.76	1,236,854	N/A

ITEM 5. OTHER INFORMATION

Dividend Declaration



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Exhibits

ITEM 6. EXHIBITS



Exhibit No.		Description
10.1	#	First Amendment to Second Amended and Restated Credit Agreement, dated as of May 14, 2018, by and among Delek US Holdings, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent for each member of the Lender Group and the Bank Product Providers and the lenders from time to time party thereto.

10.2	#	Second Amendment to Second Amended and Restated Credit Agreement, dated as of July 13, 2018, by and among Delek US Holdings, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent for each member of the Lender Group and the Bank Product Providers and the lenders from time to time party thereto.

10.3	~ #	Amendment to Second Amended and Restated Supply and Offtake Agreement dated September 19, 2019, by and between Alon Refining Krotz Springs, Inc. and J. Aron & Company LLC.

10.4	~ #	Amendment to Second Amended and Restated Supply and Offtake Agreement dated September 19, 2019, by and between Alon USA, LP and J. Aron & Company LLC.

10.5	~ #	Amendment to Second Amended and Restated Supply and Offtake Agreement dated September 19, 2019, by and between Lion Oil Company and J. Aron & Company LLC.

10.6	#	First Amendment to Term Loan Credit Agreement, dated as of October 26, 2018 by and among Delek US Holdings, Inc., as borrower, the guarantors thereto, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent.

10.7		Third Amended and Restated Limited Liability Company Agreement of Wink to Webster Pipeline, LLC, a Delaware limited liability company, dated as of July 30, 2019, by and among Delek Us Energy, Inc., ExxonMobil Permian Logistics LLC, Plains Pipeline, L.P., MPLX W2W Pipeline Holdings, LLC, Centurion Permian Logistics, LLC, and Rattler Midstream Operating, LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K field on August 5, 2019, SEC File No. 001-38142).

31.1	#	Certification of the Company’s Chief Executive Officer pursuant to Rule 13a-14(a)/15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
31.2	#	Certification of the Company’s Chief Financial Officer pursuant to Rule 13a-14(a)/15(d)-14(a) under the Securities Exchange Act of 1934, as amended.
32.1	##	Certification of the Company’s Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	##	Certification of the Company’s Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101		The following materials from Delek US Holdings, Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2019, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018 (Unaudited), (ii) Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018 (Unaudited), (iii) Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2019 and 2018 (Unaudited), (iv) Condensed Consolidated Statements of Changes in Stockholders' Equity for the three and nine months ended September 30, 2019 and 2018 (Unaudited), (v) Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2019 and 2018 (Unaudited), and (v) Notes to Condensed Consolidated Financial Statements (Unaudited).
104		The cover page from Delek US Holdings, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, has been formatted in Inline XBRL.



#		Filed herewith
##		Furnished herewith
~		Certain confidential information contained in these exhibits has been omitted because it (i) is not material and (ii) would be competitively harmful if publicly disclosed.



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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



Delek US Holdings, Inc.

By:	/s/ Ezra Uzi Yemin
	Ezra Uzi Yemin
	Director (Chairman), President and Chief Executive Officer (Principal Executive Officer)

By:	/s/ Assaf Ginzburg
	Assaf Ginzburg
	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Dated: November 7, 2019



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Exhibit 10.1

EXECUTION COPY

AMENDMENT NO. 1 TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT

This AMENDMENT NO. 1 TO SECOND AMENDED AND RESTATED CREDIT

AGREEMENT (this “Amendment”) is entered into as of May 14, 2018, by and among (a) DELEK US HOLDINGS, INC., a Delaware corporation, as administrative borrower (in such capacity, “Administrative Borrower”) for itself and the other Borrowers party to the Credit Agreement referred to below, (b) WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent for each member of the Lender Group and the Bank Product Providers (in such capacity, “Agent”), and (c) the Issuing Banks party hereto (each, a “Consenting Issuing Bank” and collectively, the “Consenting Issuing Banks”). All terms used herein that are defined in the Credit Agreement (as defined below) and not otherwise defined herein shall have the respective meanings ascribed thereto in the Credit Agreement.

W I T N E S S E T H:

WHEREAS, Borrowers, Guarantors, Lenders, and Agent are parties to that certain Second Amended and Restated Credit Agreement, dated as of March 30, 2018 (as the same may now exists and may be amended, modified, supplemented, extended, renewed, restated, or replaced from time to time, the “Credit Agreement”);

WHEREAS, in accordance with the Credit Agreement, Lenders have made and continue to make Loans and other financial accommodations to and for the benefit of Borrowers, in each instance pursuant to, and upon the terms and subject to the conditions specified in, the Credit Agreement;

WHEREAS, Administrative Borrower has requested, and the Consenting Issuing Banks have agreed, to re-allocate such Consenting Issuing Banks’ Individual Letter of Credit Sublimits, as hereafter set forth; and

WHEREAS, Administrative Borrower, Agent, and the Consenting Issuing Banks are willing to amend the Credit Agreement on the First Amendment Effective Date (as defined below), as set forth herein, subject to the terms and conditions set forth in this Amendment.

NOW, THEREFORE, in consideration of the foregoing premises, which are hereby incorporated into and made a part of this Amendment, the covenants and agreements hereinafter set forth, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, each of the undersigned, intending to be legally bound, does hereby agree as follows:

AGREEMENT

1.Amendment. Schedule 1.2 to the Credit Agreement is hereby amended and restated in its entirety in the form appended to this Amendment as Exhibit A, and the respective Individual Letter of Credit Sublimits of the Consenting Issuing Banks are hereby re-allocated as set forth therein.

2.Representations and Warranties. Administrative Borrower, on behalf of itself and each other Loan Party, hereby represents and warrants to Agent and each other member of the Lender Group, that (i) the execution, delivery, and performance by such Loan Party of the Loan Documents to which it is a party (including, without limitation, this Amendment) have been duly authorized by all necessary action on the part of such Loan Party, and (ii) each Loan Document (including, without limitation, this Amendment) has been duly executed and delivered by each Loan Party that is a party thereto and is the legally valid and binding obligation of such Loan Party, enforceable against such Loan Party in accordance with its respective terms, except as enforcement may be limited by equitable principles or by bankruptcy, insolvency, reorganization, moratorium, or similar laws relating to or limiting creditors’

rights generally, and (iii) the execution, delivery, and performance by such Loan Party of the Loan Documents to which it is a party (including, without limitation, this Amendment) do not and will not (x) violate (A) any provision of federal, state, provincial, or local law or regulation applicable to any Loan Party or its Restricted Subsidiaries, where such violation could reasonably be expected to have a Material Adverse Effect, (B) the Governing Documents of any Loan Party, or (C) any order, judgment, or decree of any court or other Governmental Authority binding on any Loan Party where such violation could reasonably be expected to have a Material Adverse Effect, or (y) conflict with, result in a breach of, or constitute (with due notice or lapse of time or both) a default under (A) any Material Contract or any Intermediation Facility where any such conflict, breach or default could individually or in the aggregate reasonably be expected to have a Material Adverse Effect, or (B) any Term Loan Document of any Loan Party or its Restricted Subsidiaries.

3.Conditions to Effectiveness. This Amendment shall become effective only upon satisfaction in full, in a manner satisfactory to Agent, of the following conditions precedent (the first date upon which all such conditions shall have been satisfied being herein called the “First Amendment Effective Date”):

(a) After giving effect to this Amendment, no Default or Event of Default shall have

occurred and be continuing.

(b) The Agent shall have received counterparts of the signature pages to this Amendment, duly executed by Administrative Borrower and each Consenting Issuing Bank.

4.Continued Effectiveness of the Credit Agreement and other Loan Documents. Administrative Borrower, on behalf of itself and each other Loan Party, hereby (a) acknowledges and consents to this Amendment, (b) confirms and agrees that the Credit Agreement and each other Loan Document to which it is a party is, and shall continue to be, in full force and effect and is hereby ratified and confirmed in all respects except that on and after the First Amendment Effective Date all references in the Credit Agreement and any such other Loan Document to “the Credit Agreement,” the “Agreement,” “thereto,” “thereof,” “thereunder” or words of like import referring to the Credit Agreement shall mean the Credit Agreement as amended by this Amendment, and (c) confirms and agrees that to the extent that the Credit Agreement and any such other Loan Document purports to assign or pledge to Agent for the benefit of Lender Group, or to grant to Agent for the benefit of Lender Group and Bank Product Providers, a security interest in or Lien on, any Collateral as security for the Obligations of any Loan Party from time to time existing in respect of the Credit Agreement (as amended hereby) and the other Loan Documents, such pledge, assignment, and/or grant of which security interest or Lien is hereby ratified and confirmed in all respects. This Amendment does not and shall not affect any of the Obligations of any Loan Party, other than as expressly provided herein, including, without limitation, Borrowers’ obligation to repay the Loans in accordance with the terms of Credit Agreement, pay or repay all other Obligations as provided in the Loan Documents to which it is a party, all of which Obligations shall remain in full force and effect. The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power, or remedy of Agent or any Lender under the Credit Agreement or any other Loan Document, nor constitute a waiver of any provision of the Credit Agreement or any other Loan Document.

5.Miscellaneous.

(a) This Amendment may be executed in any number of counterparts and by

different parties on separate counterparts, each of which, when executed and delivered, shall be deemed to be an original, and all of which, when taken together, shall constitute but one and the same agreement. Delivery of an executed counterpart of this Amendment by telefacsimile or other electronic method of

transmission shall be equally as effective as delivery of an original executed counterpart of this Amendment. Any party delivering an executed counterpart of this Amendment by telefacsimile or other electronic method of transmission also shall deliver an original executed counterpart of this Amendment but the failure to deliver an original executed counterpart shall not affect the validity, enforceability, and binding effect of this Amendment.

(b) Headings and numbers have been set forth herein for convenience only. Unless

the contrary is compelled by the context, everything contained in each Section applies equally to this entire Amendment.

(c) THE VALIDITY OF THIS AMENDMENT, THE CONSTRUCTION, INTERPRETATION, AND ENFORCEMENT HEREOF, THE RIGHTS OF THE PARTIES HERETO WITH RESPECT TO ALL MATTERS ARISING HEREUNDER OR RELATED HERETO, AND ANY CLAIMS, CONTROVERSIES OR DISPUTES ARISING HEREUNDER OR RELATED HERETO SHALL BE DETERMINED UNDER, GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

(d) Each Loan Party hereby acknowledges and agrees that this Amendment

constitutes a “Loan Document” under the Credit Agreement. Accordingly, it shall be an Event of Default under the Credit Agreement if any representation or warranty made by a Loan Party under or in connection with this Amendment shall have been untrue, false or misleading in any material respect when made.

(e) Each provision of this Amendment shall be severable from every other provision

of this Amendment for the purpose of determining the legal enforceability of any specific provision.

(f) Borrowers will pay on demand all Lender Group Expenses in connection with the

preparation, execution and delivery of this Amendment or otherwise payable under the Credit Agreement, including, without limitation, reasonable fees, disbursements and other charges of counsel to Agent.

[Signatures on Following Page]

EXHIBIT A TO

AMENDMENT NO. 1 TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT

Schedule 1.2

Individual Letter of Credit Sublimits



Lender	Individual Letter of Credit Sublimit
Wells Fargo Bank, National Association	$250,000,000
Bank Leumi USA	$15,000,000
Israel Discount Bank of New York	$10,000,000
Fifth Third Bank	$5,000,000
Bank of Montreal	$20,000,000
Total	$300,000,000

Exhibit 10.2

AMENDMENT NO. 2 TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT

This AMENDMENT NO. 2 TO SECOND AMENDED AND RESTATED CREDIT

AGREEMENT (this “Amendment”) is entered into as of July 13, 2018, by and among (a) DELEK US HOLDINGS, INC., a Delaware corporation, as administrative borrower (in such capacity, “Administrative Borrower”) for itself and the other Borrowers party to the Credit Agreement referred to below, (b) WELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent for each member of the Lender Group and the Bank Product Providers (in such capacity, “Agent”), and (c) the Issuing Banks party hereto (each, a “Consenting Issuing Bank” and collectively, the “Consenting Issuing Banks”). All terms used herein that are defined in the Credit Agreement (as defined below) and not otherwise defined herein shall have the respective meanings ascribed thereto in the Credit Agreement.

W I T N E S S E T H:

AGREEMENT

(a) After giving effect to this Amendment, no Default or Event of Default shall have

occurred and be continuing.

(b) The Agent shall have received counterparts of the signature pages to this Amendment, duly executed by Administrative Borrower and each Consenting Issuing Bank.

5.Miscellaneous.

(a) This Amendment may be executed in any number of counterparts and by

(b) Headings and numbers have been set forth herein for convenience only. Unless

the contrary is compelled by the context, everything contained in each Section applies equally to this entire Amendment.

(d) Each Loan Party hereby acknowledges and agrees that this Amendment

(e) Each provision of this Amendment shall be severable from every other provision

of this Amendment for the purpose of determining the legal enforceability of any specific provision.

(f) Borrowers will pay on demand all Lender Group Expenses in connection with the

[Signatures on Following Page]

EXHIBIT A TO

AMENDMENT NO. 1 TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT

Schedule 1.2

Individual Letter of Credit Sublimits



Lender	Individual Letter of Credit Sublimit
Wells Fargo Bank, National Association	$235,000,000
Bank Leumi USA	$15,000,000
Israel Discount Bank of New York	$10,000,000
Fifth Third Bank	$5,000,000
Bank of Montreal	$35,000,000
Total	$300,000,000

**Certain information, marked by brackets as [*CONFIDENTIAL*], has been excluded from this exhibit because it (i) is not material and (ii) would be competitively harmful if publicly disclosed.**

Exhibit 10.3

AMENDMENT to
SECOND AMENDED AND RESTATED SUPPLY AND OFFTAKE
AGREEMENT

THIS AMENDMENT to SECOND AMENDED AND RESTATED SUPPLY AND OFFTAKE AGREEMENT (this “Amendment”), dated as of September 19, 2019 is made between J. Aron & Company LLC, a limited liability company organized under the laws of New York (“Aron”) located at 200 West Street, New York, New York 10282-2198, and Alon Refining Krotz Springs, Inc. (the “Company”), a Delaware corporation located at 7102 Commerce Way, Brentwood, Tennessee 370273 (each referred to individually as a “Party” or collectively as the “Parties”).

RECITALS

Aron and the Company are parties to the Second Amended and Restated Supply and Offtake Agreement dated as of February 1, 2015 as from time to time amended, modified, supplemented and/or restated (the “S&O Agreement”); and

Aron and the Company have entered into certain additional transactions under the S&O Agreement setting the Step-Out Price for certain Baseline Volumes and wish to amend certain terms and conditions of the S&O Agreement and the Fee Letter to confirm certain terms and conditions of such additional transactions and, accordingly, agree as follows:

SECTION 1.Definitions; Interpretation

Section 1.1 Defined Terms. All capitalized terms used in this Amendment (including in the Recitals hereto) and not otherwise defined herein shall have the meanings assigned to them in the S&O Agreement.

Section 1.2 Interpretation. The rules of construction set forth in Section 1.2 of the S&O Agreement shall be applicable to this Amendment and are incorporated herein by this reference.

SECTION 2. Amendments and Agreements

Section 2.1 Amendments to S&O Agreement as of Effective Date. Upon the effectiveness of this Amendment, the S&O Agreement is amended by replacing the Schedule B attached to the S&O Agreement with the Schedule B attached hereto.

Section 2.2 Amendment to the Fee Letter. Concurrently with the effectiveness of this Amendment, the Parties are executing an amendment to the Fee Letter.

Section 2.3 Payment of September 2019 Adjustment Fee. Aron agrees to pay to the Company the September 2019 Adjustment Fee (as defined in the Fee Letter) on the September 2019 Amendment Date (as defined in the Fee Letter).

Section 2.4 References Within S&O Agreement. Each reference in the S&O Agreement to “this Agreement” and the words “hereof,” “hereto,” “herein,” “hereunder,” or words of like import, shall mean and be a reference to the S&O Agreement as heretofore amended and as amended by this Amendment.

SECTION 3. Representations and Warranties

To induce the other Party to enter into this Amendment, each Party hereby represents and warrants that (i) it has the corporate, governmental or other legal capacity, authority and power to execute this Amendment, to deliver this Amendment and to perform its obligations under the S&O Agreement, as amended hereby, and has taken all necessary action to authorize the foregoing; (ii) the execution, delivery and performance of this Amendment does not violate or conflict with any law applicable to it, any provision of its constitutional documents, any order or judgment of any court or Governmental Authority applicable to it or any of its assets or subject; (iii) all governmental and other consents required to have been obtained by it with respect to this Amendment have been obtained and are in full force and effect; (iv) its obligations under the S&O Agreement, as amended hereby, constitute its legal, valid and binding obligations, enforceable in accordance with its terms (subject to applicable bankruptcy, reorganization, insolvency, moratorium or similar laws affecting creditors’ rights generally and subject, as to enforceability, to equitable principles of general application regardless of whether enforcement is sought in a proceeding in equity or at law) and (v) no Event of Default with respect to it has occurred and is continuing.

SECTION 4. Miscellaneous

Section 4.1 S&O Agreement Otherwise Not Affected. Except for the amendments pursuant hereto, the S&O Agreement remains unchanged. As amended pursuant hereto, the S&O Agreement remains in full force and effect and is hereby ratified and confirmed in all respects. The execution and delivery of, or acceptance of, this Amendment and any other documents and instruments in connection herewith by either Party shall not be deemed to create a course of dealing or otherwise create any express or implied duty by it to provide any other or further amendments, consents or waivers in the future.

Section 4.2 No Reliance. Each Party hereby acknowledges and confirms that it is executing this Amendment on the basis of its own investigation and for its own reasons without reliance upon any agreement, representation, understanding or communication by or on behalf of any other Person.

Section 4.3 Binding Effect. This Amendment shall be binding upon, inure to the benefit of and be enforceable by the Company, Aron and their respective successors and assigns.

Section 4.4 Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, CONSTRUED AND ENFORCED UNDER THE LAWS OF THE STATE OF NEW YORK WITHOUT GIVING EFFECT TO ITS CONFLICTS OF LAW PRINCIPLES THAT WOULD REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER STATE.

Section 4.5 Amendments. This Amendment may not be modified, amended or otherwise altered except by written instrument executed by the Parties’ duly authorized representatives.

Section 4.6 Effectiveness; Counterparts. This Amendment shall be effective as of the date provided for above. No Party shall be bound until each Party has executed a counterparty hereof. This Amendment may be executed in any number of counterparts and by different Parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute but one and the same agreement.

Section 4.7 Interpretation. This Amendment is the result of negotiations between and have been reviewed by counsel to each of the Parties, and is the product of all Parties hereto. Accordingly, this Amendment shall not be construed against either Party merely because of such Party’s involvement in the preparation hereof.

[Remainder of Page Intentionally Left Blank]

TN WITNESS WHEREOF, the Parties hereto have duly executed this Amendment to the S&O Agreement as of the date first above written.

J. ARON & COMPANY LLC

By:

Name:

Title:

ALON REFINING KLOTZ SPRINGS, INC.

By: /s/ Stephen Sundstrum

Name: Stephen Sundstrum

Title: VP

By: /s/ Jaime Urquidi

Name: Jaime Urquidi

Title: VP

Schedule B

Table 1: Baseline Volume



Group		Step-In Price	Step-Out Price for Termination Dates other than May 31, 2020	Step-Out Price for Termination Date May 31, 2020
GASOLINE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL]and (ii) $[CONFIDENTIAL]

JET	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

CATFEED	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A

Schedule B-1



Group		Step-In Price	Step-Out Price for Termination Dates other than May 31, 2020	Step-Out Price for Termination Date May 31, 2020
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

CRUDE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]
SUPPLE-MENTAL MATERIAL	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

SLOP	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A

Schedule B-2



Group		Step-In Price	Step-Out Price for Termination Dates other than May 31, 2020	Step-Out Price for Termination Date May 31, 2020
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

DIESEL	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

SLURRY	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of : (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

Trading Day: Any Business Day for which the relevant price is published.

Schedule B-3

Applicable Step-Out Pricing Dates for Baseline Volume: In the event of a Termination Date of :

May 31, 2018, the Applicable Step-Out Pricing Dates shall be: May 29, 30, 31 of 2018
May 31, 2019, the Applicable Step-Out Pricing Dates shall be May 29, 30, 31 of 2019
May 31, 2020, the Applicable Step-Out Pricing Dates shall be May 27, 28, 29 of 2020
May 31, 2021, the Applicable Step-Out Pricing Dates shall be May 26, 27, 28 of 2021

Table 2: Volume in excess of Baseline Volume



Group		Step-In Price	Weekly Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
GASOLINE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days in the relevant Production Week	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	(The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract minus $[CONFIDENTIAL]/ gallon) times [CONFIDENTIAL]	(The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract minus $[CONFIDENTIAL]/ gallon) times [CONFIDENTIAL]	(The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract minus $[CONFIDENTIAL]/ gallon) times [CONFIDENTIAL]	(The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract minus $[CONFIDENTIAL]/ gallon) times [CONFIDENTIAL]	(The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract minus $[CONFIDENTIAL]/ gallon) times [CONFIDENTIAL]

JET	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days in the relevant Production Week	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates

Schedule B-4



Group		Step-In Price	Weekly Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	(The means of the daily quotations appearing in 'Platts US Marketscan' in the section 'Distillates and blendstocks' under the heading 'Gulf Coast' - Pipeline' for the 'Jet 54' quotation) times [CONFIDENTIAL]	(The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Jet 54 quotation) times [CONFIDENTIAL]	(The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Jet 54 quotation) times [CONFIDENTIAL]	(The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Jet 54 quotation) times [CONFIDENTIAL]	(The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Jet 54 quotation) times [CONFIDENTIAL]

CATFEED	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days in the relevant Production Week	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates

Schedule B-5



Group		Step-In Price	Weekly Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	[CONFIDENTIAL]* Nymex RBOB * 42 + [CONFIDENTIAL] * USGC ULSD * 42 - $[CONFIDENTIAL]/ barrel, where Nymex RBOB is defined as "The closing settlement prices on the New York Mercantile Exchange for the Nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract" and USGC ULSD is defined as "Arithmetic average of the means of the daily quotations appearing in Platt's US Marketscan in the section GULF COAST under the heading Distillates and blendstocks for the Ultra low sulfur diesel-Pipeline quotation"	[CONFIDENTIAL] * Nymex RBOB * 42 + [CONFIDENTIAL] * USGC ULSD * 42 - $[CONFIDENTIAL]/ barrel, where Nymex RBOB is defined as "The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract" and USGC ULSD is defined as "The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation"	[CONFIDENTIAL] * Nymex RBOB * 42 + [CONFIDENTIAL]* USGC ULSD * 42 - $[CONFIDENTIAL]/ barrel, where Nymex RBOB is defined as "The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract" and USGC ULSD is defined as "The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation"	[CONFIDENTIAL] * Nymex RBOB * 42 + [CONFIDENTIAL]* USGC ULSD * 42 - $[CONFIDENTIAL]/ barrel, where Nymex RBOB is defined as "The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract" and USGC ULSD is defined as "The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation"	[CONFIDENTIAL]* Nymex RBOB * 42 + [CONFIDENTIAL]* USGC ULSD * 42 - $[CONFIDENTIAL]/ barrel, where Nymex RBOB is defined as "The closing settlement prices on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending Contract" and USGC ULSD is defined as "The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation"

CRUDE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the closing settlement prices for each calendar day in the relevant Production Week. For each calendar day that is not a Trading Day (i.e. weekends and holidays), the closing settlement price shall be deemed to be the closing settlement price for the immediately preceding Trading Day.	Arithmetic average of the Trading Days in the applicable calendar month	Base Price	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates

Schedule B-6



Group		Step-In Price	Weekly Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract plus $[CONFIDENTIAL] / barrel	Applicable Grade Differential and Roll Component from the Procurement Contract plus the closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract	Base Price	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract plus $[CONFIDENTIAL] / barrel

SUPPLE-MENTAL MATERIAL	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Not applicable	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	[CONFIDENTIAL]	Not applicable	[CONFIDENTIAL]	[CONFIDENTIAL]	[CONFIDENTIAL]

SLOP	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days in the relevant Production Week	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract minus $[CONFIDENTIAL] / barrel	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract minus $[CONFIDENTIAL]/ barrel	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract minus $[CONFIDENTIAL]/ barrel	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract minus $[CONFIDENTIAL]/ barrel	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract minus $[CONFIDENTIAL]/ barrel

Schedule B-7



Group		Step-In Price	Weekly Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
SLURRY	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days in the relevant Production Week	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	Arithmetic average of the means of the daily quotations appearing in 'Platts US Marketscan' under the heading 'GULF COAST' in the section 'Residual fuel ($/bbl)' for the No. 6 3.0% quotation minus $[CONFIDENTIAL] / barrel	For the period up to, and including December 31, 2016: The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston " and subheading "($/barrel)" for the No.6 3% quotation minus $[CONFIDENTIAL] / barrel For the period commencing January 1, 2017: The sum of (i.) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the USGC HSFO quotation (ii.) minus $[CONFIDENTIAL]/ barrel	For the period up to, and including December 31, 2016: The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston " and subheading "($/barrel)" for the No.6 3% quotation minus $[CONFIDENTIAL] / barrel For the period commencing January 1, 2017: The sum of (i.) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the USGC HSFO quotation (ii.) minus $[CONFIDENTIAL]/ barrel	For the period up to, and including December 31, 2016: The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston " and subheading "($/barrel)" for the No.6 3% quotation minus $[CONFIDENTIAL] / barrel For the period commencing January 1, 2017: The sum of (i.) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the USGC HSFO quotation (ii.) minus $[CONFIDENTIAL]/ barrel	The average of the means of the daily quotations appearing in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston " and subheading "($/barrel)" for the USGC HSFO quotation minus $[CONFIDENTIAL] / barrel

Schedule B-8



Group		Step-In Price	Weekly Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
DIESEL	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days in the relevant Production Week	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	(Arithmetic average of the means of the daily quotations appearing in Platt's US Marketscan in the section GULF COAST under the heading Distillates and blendstocks for the Ultra low sulfur diesel-Pipeline quotation minus $[CONFIDENTIAL] / gallon) times 42	(The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation minus $[CONFIDENTIAL] / gallon) times 42	(The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation minus $[CONFIDENTIAL] / gallon) times 42	(The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation minus $[CONFIDENTIAL] / gallon) times 42	(The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation minus $[CONFIDENTIAL] / gallon) times 42

Trading Day: Any day for which the relevant price is published.

Base Price: The volume weighted average purchase price per barrel calculated under all Procurement Contracts under which such Crude Oil was acquired during such month. The volume weighted average will be calculated as the net dollars paid or received on all Procurement Contracts, with Aron payments to third parties represented as a positive dollar amount and Aron receipts from third parties represented as a negative dollar amount, divided by the net volume on all Procurement Contracts, with Aron purchases represented as a positive volume and Aron sales represented as a negative volume. If for such month Aron does not enter any Crude Oil Procurement Contracts, the Base Price will equal the Short Crude FIFO price as defined in Schedule B.

Applicable Step-Out Pricing Dates for Volume in excess of Baseline Volume: In the event of a Termination Date of:

May 31, 2018, the Applicable Step-Out Pricing Dates shall be: May 29, 30, 31 of 2018

May 31, 2019, the Applicable Step-Out Pricing Dates shall be May 29, 30, 31 of 2019

May 31, 2020, the Applicable Step-Out Pricing Dates shall be May 27, 28, 29 of 2020

May 31, 2021, the Applicable Step-Out Pricing Dates shall be May 26, 27, 28 of 2021

27255835.2

Schedule B-9

**Certain information, marked by brackets as [*CONFIDENTIAL*], has been excluded from this exhibit because it (i) is not material and (ii) would be competitively harmful if publicly disclosed.**

Exhibit 10.4

AMENDMENT to
SECOND AMENDED AND RESTATED SUPPLY AND OFFTAKE
AGREEMENT

THIS AMENDMENT to SECOND AMENDED AND RESTATED SUPPLY AND OFFTAKE AGREEMENT (this “Amendment”), dated as of September 19, 2019 is made between J. Aron & Company LLC f/k/a J. Aron & Company, a New York limited liability company (“Aron”) located at 200 West Street, New York, New York 10282-2198, and Alon USA, LP (the “Company”), a limited partnership organized under the laws of Texas located at 7102 Commerce Way, Brentwood, Tennessee 370273 (each referred to individually as a “Party” or collectively as the “Parties”).

RECITALS

SECTION 1.Definitions; Interpretation

Section 1.2 Interpretation. The rules of construction set forth in Section 1.2 of the S&O Agreement shall be applicable to this Amendment and are incorporated herein by this reference.

SECTION 2. Amendments and Agreements

Section 2.2 Amendment to the Fee Letter. Concurrently with the effectiveness of this Amendment, the Parties are executing an amendment to the Fee Letter.

SECTION 3. Representations and Warranties

SECTION 4. Miscellaneous

Section 4.3 Binding Effect. This Amendment shall be binding upon, inure to the benefit of and be enforceable by the Company, Aron and their respective successors and assigns.

Section 4.5 Amendments. This Amendment may not be modified, amended or otherwise altered except by written instrument executed by the Parties’ duly authorized representatives.

[Remainder of Page Intentionally Left Blank]

TN WITNESS WHEREOF, the Parties hereto have duly executed this Amendment to the S&O Agreement as of the date first above written.

J. ARON & COMPANY LLC

By:

Name:

Title:

ALON USA, LP

By: /s/ Stephen Sundstrum

Name: Stephen Sundstrum

Title: VP

By: /s/ Jaime Urquidi

Name: Jaime Urquidi

Title: VP

Schedule B

Table 1: Baseline Volume



Group		Step-In Price	Step-Out Price for Termination Dates other than May 31, 2020	Step-Out Price for Termination Date May 31, 2020
GASOLINE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

JET	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

CATFEED	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

CRUDE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]
SLOP / TRANSMIX	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

DIESEL	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

SLURRY	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

ZERO PEN	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of : (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

ASPHALT	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of : (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

PROPANE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates	N/A
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of: (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) plus $[CONFIDENTIAL]	The sum, expressed in USD/BBL, of : (i) $[CONFIDENTIAL] and (ii) $[CONFIDENTIAL]

BUTANE	Averaging Mechanism	N/A	N/A	N/A
	Reference Price	N/A	N/A	N/A

Trading Day: Any Business Day for which the relevant price is published.

Applicable Step-Out Pricing Dates for Baseline Volume: In the event of a Termination Date of :

May 31, 2018, the Applicable Step-Out Pricing Dates shall be: May 29, 30, 31 of 2018

May 31, 2019, the Applicable Step-Out Pricing Dates shall be May 29, 30, 31 of 2019

May 31, 2020, the Applicable Step-Out Pricing Dates shall be May 27, 28, 29 of 2020

May 31, 2021, the Applicable Step-Out Pricing Dates shall be May 26, 27, 28 of 2021

Table 2: Volume in excess of Baseline Volume



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
GASOLINE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The product of (i) the sum of the closing settlement price on the New York Mercantile for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract and minus $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of the closing settlement price on the New York Mercantile for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract and minus $[CONFIDENTIAL] / gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of the closing settlement price on the New York Mercantile for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract and minus $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of the closing settlement price on the New York Mercantile for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract and minus $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of the closing settlement price on the New York Mercantile for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract and minus $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel

JET	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The product of (i) the sum of (x) the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Distillates and blendstocks’ for the Jet 54-Pipeline quotation and (y) $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of (x) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “Gulf Coast” under the heading “Houston” and subheading “Prompt Pipeline” for the Jet 54 quotation and (y) $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of (x) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “Gulf Coast” under the heading “Houston” and subheading “Prompt Pipeline” for the Jet 54 quotation and (y) $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of (x) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “Gulf Coast” under the heading “Houston” and subheading “Prompt Pipeline” for the Jet 54 quotation and (y) $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel	The product of (i) the sum of (x) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “Gulf Coast” under the heading “Houston” and subheading “Prompt Pipeline” for the Jet 54 quotation and (y) $[CONFIDENTIAL]/ gallon, and (ii) 42 gallons / barrel

CATFEED	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The sum of (i) [CONFIDENTIAL] * Nymex RBOB * 42, (ii) [CONFIDENTIAL]* USGC ULSD * 42, and (iii) minus $[CONFIDENTIAL] / barrel. Where “Nymex RBOB” is: the closing settlement price on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract. Where “USGC ULSD” is: the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Distillates and blendstocks’ for the Ultra low sulfur diesel-Pipeline quotation *Common pricing does not apply	The sum of (i) [CONFIDENTIAL] * Nymex RBOB * 42, (ii) [CONFIDENTIAL] * USGC ULSD * 42, and (iii) minus $[CONFIDENTIAL] / barrel. Where “Nymex RBOB” is: the closing settlement price on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract. Where “USGC ULSD” is: the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Distillates and blendstocks’ for the Ultra low sulfur diesel-Pipeline quotation *Common pricing does not apply	The sum of (i) [CONFIDENTIAL]* Nymex RBOB * 42, (ii) [CONFIDENTIAL]* USGC ULSD * 42, and (iii) minus $[CONFIDENTIAL]/ barrel. Where “Nymex RBOB” is: the closing settlement price on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract. Where “USGC ULSD” is: the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Distillates and blendstocks’ for the Ultra low sulfur diesel-Pipeline quotation *Common pricing does not apply	The sum of (i) [CONFIDENTIAL]* Nymex RBOB * 42, (ii) [CONFIDENTIAL]* USGC ULSD * 42, and (iii) minus $[CONFIDENTIAL]/ barrel. Where “Nymex RBOB” is: the closing settlement price on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract. Where “USGC ULSD” is: the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Distillates and blendstocks’ for the Ultra low sulfur diesel-Pipeline quotation *Common pricing does not apply	The sum of (i) [CONFIDENTIAL]* Nymex RBOB * 42, (ii) [CONFIDENTIAL]* USGC ULSD * 42, and (iii) minus $[CONFIDENTIAL]/ barrel. Where “Nymex RBOB” is: the closing settlement price on the New York Mercantile Exchange for the first nearby New York Harbor Reformulated Gasoline Blendstock for Oxygen Blending contract. Where “USGC ULSD” is: the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Distillates and blendstocks’ for the Ultra low sulfur diesel-Pipeline quotation *Common pricing does not apply

CRUDE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Base Price	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) minus $[CONFIDENTIAL]/ barrel	Best estimate for the applicable Procurement Price	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract	Base Price	The closing settlement prices on the New York Mercantile Exchange for the first nearby Light Crude Futures Contract minus $[CONFIDENTIAL]/ barrel

SLOP	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract and (ii) minus $[CONFIDENTIAL] / barrel

SLURRY	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The sum of (i) the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Residual fuel ($/barrel)’ for the No. 6 3% quotation (ii) minus $[CONFIDENTIAL]/ barrel	For the period up to, and including December 31, 2016: The sum of (i) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the No.6 3% quotation (ii) minus $[CONFIDENTIAL]/ barrel For the period commencing January 1, 2017: The sum of (i.) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the USGC HSFO quotation (ii.) minus $[CONFIDENTIAL]/ barrel	For the period up to, and including December 31, 2016: The sum of (i) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the No.6 3% quotation (ii) minus $[CONFIDENTIAL]/ barrel For the period commencing January 1, 2017: The sum of (i.) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the USGC HSFO quotation (ii.) minus $[CONFIDENTIAL]/ barrel	For the period up to, and including December 31, 2016: The sum of (i) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the No.6 3% quotation (ii) minus $[CONFIDENTIAL]/ barrel For the period commencing January 1, 2017: The sum of (i.) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the USGC HSFO quotation (ii.) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the average of the means of the daily quotations appearing in “Platts US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “($/barrel)” for the USGC HSFO quotation (ii) minus $[CONFIDENTIAL]/ barrel

DIESEL	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The product of (i) the sum of (x) the arithmetic average of the high and low quotations appearing in ‘Platt's US Marketscan’ in the section ‘GULF COAST’ under the heading ‘Distillates and blendstocks’ for the Ultra low sulfur diesel- Pipeline quotation and (y) $[CONFIDENTIAL]/ gallons, and (ii) 42 gallons / barrel	The product of (i) the sum of )x_ the average of the mean of the high and low daily quotation published in “Platt's US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “Prompt Pipeline” for the Ultra low sulfur diesel quotation and (y) $[CONFIDENTIAL]/ gallons, and (ii) 42 gallons / barrel	The product of (i) the sum of (x) the average of the mean of the high and low daily quotation published in “Platt's US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “Prompt Pipeline” for the Ultra low sulfur diesel quotation and (y) $[CONFIDENTIAL]/ gallons, and (ii) 42 gallons / barrel	The product of (i) the sum of (x) the average of the mean of the high and low daily quotation published in “Platt's US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “Prompt Pipeline” for the Ultra low sulfur diesel quotation and (y) $[CONFIDENTIAL]/ gallons, and (ii) 42 gallons / barrel	The product of (i) the sum of (x) the average of the mean of the high and low daily quotation published in “Platt's US Marketscan” in the section “GULF COAST” under the heading “Houston” and subheading “Prompt Pipeline” for the Ultra low sulfur diesel quotation and (y) $[CONFIDENTIAL]/ gallons, and (ii) 42 gallons / barrel

ASPHALT (0-PEN)	Averaging Mechanism	The arithmetic average of the Trading Days in the month of March 2013	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The sum of (i) the product of (x) [CONFIDENTIAL] and (y) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract, and (ii) minus $[CONFIDENTIAL] / barrel	The sum of (i) the product of (x) [CONFIDENTIAL] and (y) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract, and (ii) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the product of (x) [CONFIDENTIAL] and (y) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract, and (ii) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the product of (x) [CONFIDENTIAL]and (y) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract, and (ii) minus $[CONFIDENTIAL]/ barrel	The sum of (i) the product of (x) [CONFIDENTIAL]and (y) the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract, and (ii) minus $[CONFIDENTIAL]/ barrel

ASPHALT (OTHER)	Averaging Mechanism	The arithmetic average of the Trading Days in the month of February 2013	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	[CONFIDENTIAL]	[CONFIDENTIAL]	[CONFIDENTIAL]	[CONFIDENTIAL]	[CONFIDENTIAL]

PROPANE	Averaging Mechanism	Arithmetic average of the 4 Trading Days ending with and including the penultimate Trading Day of the month (May 24, 28, 29, & 30 of 2013)	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Dates
	Reference Price	The product of (i) [CONFIDENTIAL], (ii) the TET propane price quoted in the Oil Price Information Service (“OPIS”) LP Report under the heading ‘Mont Belvieu Spot Gas Liquids Prices’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘AVG’ (iii) 42 gallons / barrel	The product of (i) [CONFIDENTIAL], (ii) the TET propane price quoted in the Oil Price Information Service (“OPIS”) LP Report under the heading ‘Mont Belvieu Spot Gas Liquids Prices’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘AVG’ (iii) 42 gallons / barrel	The product of (i) [CONFIDENTIAL], (ii) the TET propane price quoted in the Oil Price Information Service (“OPIS”) LP Report under the heading ‘Mont Belvieu Spot Gas Liquids Prices’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘AVG’ (iii) 42 gallons / barrel	The product of (i) [CONFIDENTIAL], (ii) the TET propane price quoted in the Oil Price Information Service (“OPIS”) LP Report under the heading ‘Mont Belvieu Spot Gas Liquids Prices’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘AVG’ (iii) 42 gallons / barrel	The product of (i) [CONFIDENTIAL], (ii) the TET propane price quoted in the Oil Price Information Service (“OPIS”) LP Report under the heading ‘Mont Belvieu Spot Gas Liquids Prices’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘AVG’ (iii) 42 gallons / barrel

BUTANE	Averaging Mechanism	N/A	The Trading Day preceding the relevant Invoice Date	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days in the applicable calendar month	Arithmetic average of the Trading Days on the relevant Applicable Step-Out Pricing Date
	Reference Price	N/A	The product of (i) [CONFIDENTIAL] (ii) 42 gallons / barrel	The product of (i) [CONFIDENTIAL] (ii) 42 gallons / barrel	The product of (i) [CONFIDENTIAL] (ii) 42 gallons / barrel	The product of (i) [CONFIDENTIAL] (ii) 42 gallons / barrel

Procurement Price: The volume weighted average purchase price per barrel calculated under all Procurement Contracts under which such Crude Oil was acquired during such month. The volume weighted average will be calculated as the net dollars paid or received on all Procurement Contracts, with Aron payments to third parties represented as a positive dollar amount and Aron receipts from third parties represented as a negative dollar amount, divided by the net volume on all Procurement Contracts, with Aron purchases represented as a positive volume and Aron sales represented as a negative volume. If for such month Aron does not enter any Crude Oil Procurement Contracts, the Procurement Price will equal the sum of the closing settlement price on the New York Mercantile Exchange for the first nearby Light Crude Futures contract for the Trading Day preceding the relevant Invoice Date.

Trading Day: Any day for which the relevant price is published.

Applicable Step-Out Pricing Dates: In the event of a Termination Date of:

May 31, 2018, the Applicable Step-Out Pricing Dates shall be: May 29, 30, 31 of 2018

May 31, 2019, the Applicable Step-Out Pricing Dates shall be May 29, 30, 31 of 2019

May 31, 2020, the Applicable Step-Out Pricing Dates shall be May 27, 28, 29 of 2020

May 31, 2021, the Applicable Step-Out Pricing Dates shall be May 26, 27, 28 of 2021

**Certain information, marked by brackets as [*CONFIDENTIAL*], has been excluded from this exhibit because it (i) is not material and (ii) would be competitively harmful if publicly disclosed.**

Exhibit 10.5

AMENDMENT to
SECOND AMENDED AND RESTATED MASTER SUPPLY AND OFFTAKE
AGREEMENT

THIS AMENDMENT to SECOND AMENDED AND RESTATED MASTER SUPPLY AND OFFTAKE AGREEMENT (this “Amendment”), dated as of September 19, 2019 is made among J. Aron & Company LLC, a limited liability company organized under the laws of New York (“Aron”) located at 200 West Street, New York, New York 10282-2198, Lion Oil Company (the “Company”), a corporation organized under the laws of Arkansas located at 7102 Commerce Way, Brentwood, Tennessee 37027, and Lion Oil Trading & Transportation, LLC (“LOTT”), a limited liability company organized under the laws of Texas (each referred to individually as a “Party” or collectively as the “Parties”).

RECITALS

Aron, the Company and LOTT are parties to the Second Amended and Restated Master Supply and Offtake Agreement dated as of February 27, 2017 as from time to time amended, modified, supplemented and/or restated (the “S&O Agreement”); and

Aron, the Company and LOTT have entered into certain additional transactions under the S&O Agreement setting the Step-Out Price for certain Baseline Volumes and wish to amend certain terms and conditions of the S&O Agreement and the Fee Letter to confirm certain terms and conditions of such additional transactions and, accordingly, agree as follows:

SECTION 1.Definitions; Interpretation

Section 1.2 Interpretation. The rules of construction set forth in Section 1.2 of the S&O Agreement shall be applicable to this Amendment and are incorporated herein by this reference.

SECTION 2. Amendments and Agreements

Section 2.2 Amendment to the Fee Letter. Concurrently with the effectiveness of this Amendment, the Parties are executing an amendment to the Fee Letter.

SECTION 3. Representations and Warranties

SECTION 4. Miscellaneous

Section 4.3 Binding Effect. This Amendment shall be binding upon, inure to the benefit of and be enforceable by the Company, Aron and their respective successors and assigns.

Section 4.5 Amendments. This Amendment may not be modified, amended or otherwise altered except by written instrument executed by the Parties’ duly authorized representatives.

[Remainder of Page Intentionally Left Blank]

TN WITNESS WHEREOF, the Parties hereto have duly executed this Amendment to the S&O Agreement as of the date first above written.

J. ARON & COMPANY LLC

By:

Name:

Title:

LION OIL COMPANY

By: /s/ Jaime Urquidi

Name: Jaime Urquidi

Title: VP

By: /s/ Stephen Sundstrum

Name: Stephen Sundstrum

Title: VP

LION OIL TRADING & TRANSPORTATION, LLC

By: /s/ Stephen Sundstrum

Name: Stephen Sundstrum

Title: VP

By: /s/ Jaime Urquidi

Name: Jaime Urquidi

Title: VP

[Amendment to Lion/LOTT S&O Agreement]

Schedule B-3

Pricing Benchmarks

Table 1: Baseline Volume



Group		Step-In Price	Step-Out Price
GASOLINE	Averaging Days	April 24, 25, 26, 27 of 2017	N/A
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	The result of: (i) $[CONFIDENTIAL]/bbl, plus (ii) $[CONFIDENTIAL]/bbl

SLURRY	Averaging Days	April 24, 25, 26, 27 of 2017	April 24, 27, 28, 29 of 2020
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL]	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL]

CATFEED	Averaging Days	April 24, 25, 26, 27 of 2017	All Trading Days in the calendar month of April 2020.



Group		Step-In Price	Step-Out Price
	Reference Price	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) Catfeed Second Adjustment Date Differential	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) Catfeed Second Adjustment Date Differential

CRUDE	Averaging Days	April 24, 25, 26, 27 of 2017	N/A
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	The result of: (i) $[CONFIDENTIAL]/bbl, plus (ii) $[CONFIDENTIAL]/bbl

SLOP	Averaging Days	April 24, 25, 26, 27 of 2017	April 24, 27, 28, 29 of 2020
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl



Group		Step-In Price	Step-Out Price

DIESEL	Averaging Mechanism	April 24, 25, 26, 27 of 2017	N/A
	Reference Price	The result of: (i) The arithmetic average of the closing settlement prices on the New York Mercantile Exchange for the second nearby New York Harbor Ultra Low Sulfur Diesel Contract on the Averaging Days, with such result expressed in $/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, minus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) $[CONFIDENTIAL]/gal, multiplied by (ii) 42, with such result expressed in $/bbl and rounded to 4 decimal points, minus (iii) $[CONFIDENTIAL]/bbl

ASPHALT	Averaging Days	All Trading Days in the calendar month that is 2 months prior to the calendar day immediately preceding the Applicable Step-In Date	All Trading Days in the calendar month that is 2 months prior to the calendar day immediately preceding the Applicable Step-Out Date
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl, plus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl, plus (iii) $[CONFIDENTIAL]bbl

LPG	Averaging Days	April 24, 25, 26, 27 of 2017	April 24, 27, 28, 29 of 2020



Group		Step-In Price	Step-Out Price
	Reference Price	The result of: (i) The average of the TET propane price published by Oil Price Information Service in the ‘OPIS North America LPG Report’ under the heading ‘OPIS Mont Belvieu Spot Gas Liquids Prices (cts/gal)’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘Avg’ on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) [CONFIDENTIAL]/ gallon, multiplied by [CONFIDENTIAL], with such result expressed in $/bbl	The result of: (i) The average of the TET propane price published by Oil Price Information Service in the ‘OPIS North America LPG Report’ under the heading ‘OPIS Mont Belvieu Spot Gas Liquids Prices (cts/gal)’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘Avg’ on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) [CONFIDENTIAL]/ gallon, multiplied by [CONFIDENTIAL], with such result expressed in $/bbl

Trading Day: Any Business Day for which the relevant price is published.

Table 2: Volume in excess of Baseline Volume



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
GASOLINE	Averaging Days	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) Gasoline Second Adjustment Date Differential	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) Gasoline Second Adjustment Date Differential	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) Gasoline Second Adjustment Date Differential	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) Gasoline Second Adjustment Date Differential	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) Gasoline Second Adjustment Date Differential

SLURRY	Averaging Days	April 24, 25, 26, 27 of 2017	The Trading Day preceding the relevant invoice date	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	April 24, 27, 28, 29 of 2020



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL]	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL]	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL]	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL]	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL]

CATFEED	Averaging Days	April 24, 25, 26, 27 of 2017	The Trading Day preceding the relevant invoice date	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	All Trading Days in the calendar month of April 2020.



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) Catfeed Second Adjustment Date Differential	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) Catfeed Second Adjustment Date Differential	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) Catfeed Second Adjustment Date Differential	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) Catfeed Second Adjustment Date Differential	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) Catfeed Second Adjustment Date Differential

CRUDE	Averaging Days	April 24, 25, 26, 27 of 2017	The Trading Day preceding the relevant invoice date	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	As set forth in the applicable Base Price section or Alternate Price section	April 24, 27, 28, 29 of 2020



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	Best estimate for the applicable Procurement Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	(i) Base Price, or (ii) Alternate Price plus the Phys Diff	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus $[CONFIDENTIAL]/bbl

SLOP	Averaging Days	April 24, 25, 26, 27 of 2017	The Trading Day preceding the relevant invoice date	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	April 24, 27, 28, 29 of 2020
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days, with such result expressed in $/bbl and rounded to 4 decimal points, plus (ii) $[CONFIDENTIAL]/bbl



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
DIESEL	Averaging Days	April 24, 25, 26, 27 of 2017	The Trading Day preceding the relevant invoice date	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	April 24, 27, 28, 29 of 2020
	Reference Price	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, minus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, minus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, minus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, minus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The average of the mean of the high and low daily quotation published in "Platts US Marketscan" in the section "GULF COAST" under the heading "Houston" and subheading "Prompt Pipeline" for the Ultra low sulfur diesel quotation on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, minus (iii) $[CONFIDENTIAL]/bbl

ASPHALT	Averaging Days	All Trading Days in the calendar month that is 2 months prior to the calendar day immediately preceding the Applicable Step-In Date	All Trading Days in the calendar month that is 2 months prior to the relevant payment date	All Trading Days in the calendar month that is 2 months prior to the invoice date for the Monthly True- Up Amount	All Trading Days in the calendar month that is 2 months prior to the invoice date for the Monthly True- Up Amount	All Trading Days in the calendar month that is 2 months prior to the calendar day immediately preceding the Applicable Step-Out Date



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl, plus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl, plus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl, plus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl, plus (iii) $[CONFIDENTIAL]/bbl	The result of: (i) The arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract on the Averaging Days with such result expressed in $/bbl and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl, plus (iii) $[CONFIDENTIAL]/bbl

LPG	Averaging Days	April 24, 25, 26, 27 of 2017	The Trading Day preceding the relevant invoice date	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	All Trading Days in the calendar month preceding the relevant invoice date for the Monthly True-Up Amount	April 24, 27, 28, 29 of 2020



Group		Step-In Price	Daily Price	Short Crude FIFO Price / Short Product FIFO Price	Long Crude FIFO Price / Long Product FIFO Price	Step-Out Price
	Reference Price	The result of: (i) The average of the TET propane price published by Oil Price Information Service in the ‘OPIS North America LPG Report’ under the heading ‘OPIS Mont Belvieu Spot Gas Liquids Prices (cts/gal)’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘Avg’ on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) [CONFIDENTIAL]cents / gallon, multiplied by [CONFIDENTIAL], with such result expressed in $/bbl	The result of: (i) The average of the TET propane price published by Oil Price Information Service in the ‘OPIS North America LPG Report’ under the heading ‘OPIS Mont Belvieu Spot Gas Liquids Prices (cts/gal)’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘Avg’ on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) [CONFIDENTIAL]cents / gallon, multiplied by [CONFIDENTIAL], with such result expressed in $/bbl	The result of: (i) The average of the TET propane price published by Oil Price Information Service in the ‘OPIS North America LPG Report’ under the heading ‘OPIS Mont Belvieu Spot Gas Liquids Prices (cts/gal)’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘Avg’ on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) [CONFIDENTIAL] cents / gallon, multiplied by [CONFIDENTIAL], with such result expressed in $/bbl	The result of: (i) The average of the TET propane price published by Oil Price Information Service in the ‘OPIS North America LPG Report’ under the heading ‘OPIS Mont Belvieu Spot Gas Liquids Prices (cts/gal)’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘Avg’ on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) [CONFIDENTIAL] cents / gallon, multiplied by [CONFIDENTIAL], with such result expressed in $/bbl	The result of: (i) The average of the TET propane price published by Oil Price Information Service in the ‘OPIS North America LPG Report’ under the heading ‘OPIS Mont Belvieu Spot Gas Liquids Prices (cts/gal)’ in the section ‘TET Propane’ under the heading ‘Any Current Month’ in the column ‘Avg’ on the Averaging Days, with such result expressed in cents/gal and rounded to 4 decimal points, multiplied by (ii) [CONFIDENTIAL], with such result expressed in $/bbl and rounded to 4 decimal points, plus (iii) [CONFIDENTIAL]cents / gallon, multiplied by [CONFIDENTIAL], with such result expressed in $/bbl

Trading Day: A day on which (i) the relevant exchange is open for trading during its regular trading session, or (ii) the price is published by the relevant price source.

Contracts, with Aron purchases represented as a positive volume and Aron sales represented as a negative volume, with such result being rounded to 4 decimal points.

Procurement Price: The volume weighted average purchase price per barrel calculated under all Procurement Contracts under which such Crude Oil was acquired during such month. The volume weighted average will be calculated as the net dollars paid or received on all Procurement Contracts, with Aron payments to third parties represented as a positive dollar amount and Aron receipts from third parties represented as a negative dollar amount, divided by the net volume on all Procurement Contracts, with Aron purchases represented as a positive volume and Aron sales represented as a negative volume, with such result being rounded to 4 decimal points.

Alternate Price: a + b + c

Where:

“a” shall be the arithmetic average of the closing settlement price(s) on the New York Mercantile Exchange for the first nearby Light Sweet Crude Oil Futures Contract, as determined on each Trading Day during the Delivery Month.

“b” shall be the arithmetic average of the daily quotations as published by “Argus Crude”, in the section “US Gulf Coast and Midcontinent”, subsection “WTI ($/bl)”, for “WTI Midland” under the column “Weighted average” for the prompt month, for the pricing dates from and including the 26th of the month, two months prior to the Delivery Month, to and including the 25th of the month, one month prior to the Delivery Month. Saturdays, Sundays and holidays are excluded.

LESS

The arithmetic average of the daily quotations as published by “Argus Crude”, in the section “US Gulf Coast and Midcontinent”, subsection “WTI ($/bl)”, for “WTI Cushing”, under the column “WTI formula basis price” for the prompt month, for the pricing dates from and including the 26th of the month, two months prior to the Delivery Month, to and including the 25th of the month, one month prior to the Delivery Month. Saturdays, Sundays and holidays are excluded.

“c” shall be the arithmetic average of the daily quotation as published by “Argus Crude”, in the section “US Gulf Coast and Midcontinent”, subsection “WTI ($/bl)”, for “WTI diff to CMA Nymex” under the column “Diff weighted average” for the prompt month, for the pricing dates from and including the 26th of the month, two months prior to the Delivery Month, to and including the 25th of the month, one month prior to the Delivery Month. Saturdays, Sundays and holidays are excluded.

The Phys Diff for each calendar month equals:

a-b

Where:
“a” shall equal the Base Price for the previous calendar month
“b” shall equal the Alternate Price for the previous calendar month

Applicable Step-In Date: May 1, 2017
Applicable Step-Out Date: April 30, 2020

Exhibit 10.6

Execution Version

AMENDMENT NO. 1 TO TERM LOAN CREDIT AGREEMENT

AMENDMENT NO. 1 TO TERM LOAN CREDIT AGREEMENT, dated as of

October 26, 2018 (this “Amendment”), by and among DELEK US HOLDINGS, INC., a Delaware corporation (the “Borrower”), each of the Guarantors, each of the Lenders, WELLS FARGO BANK, NATIONAL ASSOCIATION, as the New Lender (as defined below), and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Agent (in such capacity, the “Agent”), to that certain Term Loan Credit Agreement, dated as of March 30, 2018, among the Borrower, the Agent, each Lender from time to time party thereto and the other agents party thereto (as amended, restated, amended and restated, supplemented or otherwise modified from time to time prior to the date hereof, the “Credit Agreement” and the Credit Agreement, as amended by this Amendment, the “Amended Credit Agreement”). Terms defined in the Credit Agreement and used herein shall have the meanings given to them in the Credit Agreement unless otherwise defined herein.

W I T N E S S E T H:

WHEREAS, the Borrower desires to amend the Credit Agreement on the terms set forth herein;

WHEREAS, Section 13.1(a) of the Credit Agreement provides that the Borrower may amend the Credit Agreement with the consent of the requisite number of Lenders as set forth therein;

WHEREAS, Wells Fargo Securities, LLC (acting through such of its affiliates or branches as it deems appropriate) has been appointed, and is acting, as the lead arranger and bookrunner for this Amendment (in such capacities, the “Amendment No. 1 Arranger”);

WHEREAS, the Consenting Lenders (as defined below) consenting to this Amendment pursuant to the Amendment No. 1 Consents (as defined below) constitute Required Lenders, and the Consenting Lenders and the New Lender constitute all Lenders under the Credit Agreement on the Amendment No. 1 Effective Date directly affected by this Amendment;

WHEREAS, (i) each Lender holding Loans outstanding immediately prior to the effectiveness of this Amendment on the Amendment No. 1 Effective Date (the “Existing Loans”) that executes and delivers a consent to this Amendment (each, a “Consenting Lender”) substantially in the form of Exhibit A hereto (each, an “Amendment No. 1 Consent”) prior to 4:00 p.m. New York time on October 23, 2018 (the “Consent Deadline”) shall be deemed, upon effectiveness of this Amendment, to have consented to the amendments to the Credit Agreement set forth herein, including, without limitation, the reduction of the Applicable Margin with respect to its outstanding Existing Loans and (x) if such Consenting Lender elects the “Cashless Amendment” option on the Amendment No. 1 Consent, such Consenting Lender will retain its Existing Loans as amended by this Amendment and (y) if such Consenting Lender elects the “Post-Closing Settlement” option on the Amendment No. 1 Consent, the entire amount of such Consenting Lender’s Existing Loans will be assigned to the New Lender (as defined below) at par on the Amendment No. 1 Effective Date (as defined below) (it being understood that no Assignment and Acceptance shall be required to be executed by such Consenting Lender to

effect such assignment) and following the Amendment No. 1 Effective Date such Consenting Lender shall purchase by assignment the Loans in an equal principal amount as its Existing Loans or such lesser amount allocated to such Consenting Lender by the Amendment No. 1 Arranger, (ii) each Lender holding Existing Loans that does not execute and deliver an Amendment No. 1 Consent (each, a “Non-Consenting Lender”) by the Consent Deadline shall, so long as Consenting Lenders constitute Required Lenders by the Consent Deadline, be required to assign the entire amount of its Loans to Wells Fargo Bank, National Association (in such capacity, the “New Lender”), in accordance with Section 12.1 and Section 2.16(b) of the Credit Agreement immediately prior to the effectiveness of this Amendment on the Amendment No. 1 Effective Date, and such New Lender shall become a Lender under the Amended Credit Agreement with respect to the Loans so assigned (with delivery of an unexecuted copy of this Amendment to each Non-Consenting Lender, including by posting this Amendment on the Platform, constituting notice of such required assignment pursuant to Section 2.16(b) of the Credit Agreement) and (iii) on the Amendment No. 1 Effective Date, the Borrower shall have paid to the Agent, for the ratable benefit of the existing Lenders immediately prior to the effectiveness of this Amendment on the Amendment No. 1 Effective Date, all accrued and unpaid interest to, but not including, the Amendment No. 1 Effective Date, with respect to the Existing Loans;

NOW, THEREFORE, the parties hereto hereby agree as follows:

ARTICLE I

Amendments

Section 1.1 Amendments. Subject to satisfaction (or waiver) of the conditions set forth in Article II hereof, on the Amendment No. 1 Effective Date, the Credit Agreement is hereby amended as follows:

(a)The following defined terms shall be added to Section 1.1 of the Credit Agreement in alphabetical order:

“Amendment No. 1” means Amendment No. 1 to Term Loan Credit Agreement, dated as of October 26, 2018.

“Amendment No. 1 Arranger” has the meaning assigned to such term in the recitals to Amendment No. 1.

“Amendment No. 1 Consent” has the meaning assigned to such term in the recitals to Amendment No. 1.

“Amendment No. 1 Effective Date” means October 26, 2018, the date of effectiveness of Amendment No. 1.

“Beneficial Ownership Certification” means a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation” means 31 C.F. R. § 1010.230.

(b)The definition of “Applicable Margin” in Section 1.1 of the Credit Agreement is hereby amended by deleting such definition and replacing it with the following:

“Applicable Margin” means (a) in the case of a Base Rate Loan, 1.25 percentage points (the “Base Rate Margin”) and (b) in the case of a LIBOR Rate Loan, 2.25 percentage points (the “LIBOR Rate Margin”).

(c)The definition of “Loan Documents” in Section 1.1 of the Credit Agreement is hereby amended by inserting after “this Agreement,” the following: “Amendment No. 1,”.

(d)Section 1.4 of the Credit Agreement is hereby amended by inserting the following immediately at the end thereof: “For all purposes under the Loan Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized on the first date of its existence by the holders of its Equity Interests at such time.”

(e)The reference to the “Closing Date” in Section 2.4(c) of the Credit Agreement is hereby replaced with a reference to the “Amendment No. 1 Effective Date”.

(f)Section 4.12 of the Credit Agreement is hereby amended by inserting the following sentence immediately at the end thereof: “As of the Amendment No. 1 Effective Date, the information included in the Beneficial Ownership Certification is true and correct in all respects.”

(g)Section 5.3 of the Credit Agreement is hereby amended by inserting the following sentence at the end thereof: “Promptly following any request therefor, the Borrower will provide all information and documentation reasonably requested by the Agent or any Lender for purposes of compliance with applicable “know your customer” requirements under the Patriot Act, the Beneficial Ownership Regulation or other applicable anti-money laundering laws.”

ARTICLE II

Conditions to Effectiveness

This Amendment shall become effective on the date (the “Amendment No. 1 Effective Date”) on which the following conditions precedent are satisfied (or waived by the Agent):


(a)	The Agent (or its counsel) shall have received from (i) the New Lender,

(ii) the Agent and (iii) each Loan Party, (x) a counterpart of this Amendment signed on behalf of such party or (y) written evidence reasonably satisfactory to the Agent (which may include the electronic transmission of a signed signature page of this Amendment) that such party has signed a counterpart of this Amendment. The Agent (or its counsel) shall have received from each

Consenting Lender, constituting at least the Required Lenders immediately prior to giving effect to this Amendment on the Amendment No. 1 Effective Date, a duly executed Amendment No. 1

Consent. Each Non-Consenting Lender and the New Lender shall have executed an Assignment and Acceptance assigning all of such Non-Consenting Lender’s Existing Loans to the New Lender or shall have been deemed to have executed such an Assignment and Acceptance in accordance with Section 2.16(b) of the Credit Agreement;

(b)The Borrower and each of the Guarantors shall have provided the documentation and other information reasonably requested in writing at least five (5) days prior to the Amendment No. 1 Effective Date by the Consenting Lenders as they reasonably determine is required by regulatory authorities in connection with applicable “know your customer” and anti-money-laundering rules and regulations, including, without limitation, the Patriot Act and the requirements of the Beneficial Ownership Regulation (as defined in Section 1.1 of this Amendment), in each case at least one (1) Business Day prior to the Amendment No. 1 Effective Date (or such shorter period as the Agent shall otherwise agree);

(c)The Borrower shall have paid to the Agent for the ratable account of the Lenders holding Existing Loans all accrued and unpaid interest on such Existing Loans to, but not including, the Amendment No. 1 Effective Date; and

(d)The Borrower shall have delivered a certificate of an Authorized Person of the Borrower certifying that at the time of and after giving effect to this Amendment, (A) each of the representations and warranties made by any Loan Party contained in Article 4 of the Credit Agreement and each other Loan Document are true and correct in all material respects (and in all respects if any such representation or warranty is already qualified by materiality) on and as of the Amendment No. 1 Effective Date, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects (and in all respects if any such representation or warranty is already qualified by materiality) as of such earlier date and (B) no Default or Event of Default shall have occurred and be continuing on such date.

ARTICLE III

Miscellaneous

Section 3.1 Continuing Effect; No Other Amendments or Waivers. Except as expressly set forth herein, this Amendment shall not by implication or otherwise limit, impair, constitute a waiver of or otherwise affect the rights and remedies of the Lenders or the Agent under the Credit Agreement or any other Loan Document, and shall not alter, modify, amend or in any way affect any of the terms, conditions, obligations, covenants or agreements contained in the Credit Agreement or any other Loan Document or any other provision of the Credit Agreement or any other Loan Document, all of which are hereby ratified and affirmed in all respects and shall continue in full force and effect. Except as expressly amended hereby, the provisions of the Credit Agreement and the other Loan Documents are and shall remain in full force and effect in accordance with their terms. The parties hereto acknowledge and agree that the amendment of the Credit Agreement pursuant to this Amendment and all other Loan Documents amended and/or executed and delivered in connection herewith shall not constitute a

novation of the Credit Agreement and the other Loan Documents as in effect prior to the Amendment No. 1 Effective Date. This Amendment shall constitute a “Loan Document” for all purposes of the Credit Agreement and the other Loan Documents. All references to the Credit Agreement in any document, instrument, agreement, or writing shall from after the Amendment No. 1 Effective Date be deemed to refer to the Credit Agreement as amended hereby, and, as used in the Credit Agreement, the terms “Agreement,” “herein,” “hereafter,” “hereunder,” “hereto” and words of similar import shall mean, from and after the Amendment No. 1 Effective Date, the Credit Agreement as amended hereby.

Section 3.2 New Lender. The New Lender hereby consents to this Amendment. Each of the New Lender, the Agent and the Borrower acknowledges and agrees that, upon the execution and delivery of an Assignment and Acceptance signed by the New Lender, as assignee, and each Non-Consenting Lender, as assignor (or signed by the Agent on behalf of such Non-Consenting Lender, pursuant to Section 2.16(b) of the Amended Credit Agreement), the New Lender (i) shall become a “Lender” under, and for all purposes, and subject to and bound by the terms, of the Amended Credit Agreement and other Loan Documents with Loans in an amount equal to the aggregate principal amount of all Existing Loans of all Non-Consenting Lenders, (ii) appoints and authorizes the Agent to take such action as agent on its behalf and to exercise such powers under the Amended Credit Agreement and the other Loan Documents as are delegated to the Agent by the terms thereof, together with such powers as are reasonably incidental thereto and (iii) shall perform all the obligations of and shall have all rights of a Lender thereunder. Each Non-Consenting Lender that does not execute such Assignment and Acceptance shall be deemed to have executed and delivered such Assignment and Acceptance in accordance with Section 2.16(b) of the Credit Agreement. After the assignment (or deemed assignment) of Loans by each Non-Consenting Lender to the New Lender as contemplated above, the New Lender and the Consenting Lenders shall together hold all of the Loans.

Section 3.3 Waiver of Notice to Non-Consenting Lenders. To the extent necessary, the Required Lenders hereby agree to waive the notice provided for in Section 2.16(b) of the Credit Agreement.

Section 3.4 Counterparts. This Amendment may be executed in any number of counterparts and by different parties on separate counterparts, each of which, when executed and delivered, shall be deemed to be an original, and all of which, when taken together, shall constitute but one and the same Amendment. Delivery of an executed counterpart of this Amendment by telefacsimile or other electronic method of transmission shall be equally as effective as delivery of an original executed counterpart of this Amendment. Any party delivering an executed counterpart of this Amendment by telefacsimile or other electronic method of transmission also shall deliver an original executed counterpart of this Amendment but the failure to deliver an original executed counterpart shall not affect the validity, enforceability, and binding effect of this Amendment.

Section 3.5 CHOICE OF LAW AND VENUE; JURY TRIAL WAIVER; JUDICIAL REFERENCE PROVISION. SECTION 11 OF THE CREDIT AGREEMENT IS HEREBY INCORPORATED AND SHALL APPLY TO THIS AMENDMENT, MUTATIS MUTANDIS.

Section 3.6 Reaffirmation. Each Loan Party hereto expressly acknowledges the terms of this Amendment and reaffirms, as of the date hereof and on the Amendment No. 1 Effective Date, that its guarantee of the Guarantied Obligations (as defined in the Guaranty and Security Agreement) and its grant of Liens on the Collateral to secure the Secured Obligations (as defined in the Guaranty and Security Agreement) pursuant to each Security Document to which it is a party, in each case, continues in full force and effect and extends to the obligations of the Loan Parties under the Loan Documents (including the Amended Credit Agreement) subject to any limitations set out in the Amended Credit Agreement and any other Loan Document applicable to that Loan Party. Neither the execution, delivery, performance or effectiveness of this Amendment nor the modification of the Credit Agreement effected pursuant hereto: (i) impairs the validity, effectiveness or priority of the Liens granted pursuant to any Loan Document, and such Liens continue unimpaired with the same priority to secure repayment of all Secured Obligations, whether heretofore or hereafter incurred; or (ii) requires that any new filings be made or other action be taken to perfect or to maintain the perfection of such Liens.

Section 3.7 Arranger. The Amendment No. 1 Arranger, in such capacity, shall benefit from the same protections, immunities, indemnities and exclusions from liability as are conferred in favor of the Joint Lead Arrangers in the Credit Agreement, which shall apply mutatis mutandis.

[Signature Pages Follow]

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed and delivered by their respective duly authorized officers as of the date first above written.

DELEK US HOLDINGS, INC.

By:/s/ Kevin Kremke

Name: Kevin Kremke

Title: Executive Vice President and Chief Accounting Officer

DELEK US ENERGY, INC. DELEK RAIL LOGISTICS, INC. DELEK FINANCE, INC.

LION OIL COMPANY

LION OIL TRADING & TRANSPORTATION, LLC

J. CHRISTY CONSTRUCTION CO., INC. DK CANADA ENERGY ULC

DELEK PERMIAN GATHERING, LLC DELEK RENEWABLES, LLC

DELEK LAND HOLDINGS, LLC

DELEK MARKETING & SUPPLY, LLC DELEK HELENA, LLC

DELEK REFINING, INC.,

DELEK U.S. REFINING GP, LLC, on behalf of itself and as the general partner of DELEK REFINING, LTD.

By:/s/ Kevin Kremke

Name: Kevin Kremke

Title: Executive Vice President and Chief Accounting Officer

ALON USA ENERGY, INC.

ALON USA, INC.

ALON USA CAPITAL, INC. ALON ASSETS, INC.

ALON SUPPLY, INC.

ALON LOUISIANA HOLDINGS, INC.

ALON REFINING LOUISIANA, INC.

ALON REFINING KROTZ SPRINGS, INC.

ALON BAKERSFIELD HOLDINGS, INC. ALON BAKERSFIELD LOGISTICS, INC. ALON RENEWABLE FUELS, INC.

ALON TERMINALS, INC.

ALON ASPHALT COMPANY

ALON ASPHALT BAKERSFIELD, INC.

ALON BAKERSFIELD PROPERTY, INC. PARAMOUNT PETROLEUM CORPORATION OF ARIZONA, INC.

ALON USA GP II, LLC, on behalf of itself and as the general partner of ALON USA, LP

ALON USA PARTNERS GP, LLC, on behalf of itself and as the general partner of ALON USA PARTNERS, LP

ALON USA GP, LLC

ALON USA DELAWARE, LLC ALON USA REFINING, LLC ALON USA HOLDINGS, LLC ALON CRUDE PIPELINE, LLC ALON WEST COAST, LLC

ALON STORE ACQUISITIONS, LLC EDGINGTON OIL COMPANY, LLC PARAMOUNT OF OREGON, LLC PARAMOUNT OF WASHINGTON, LLC ALON BRANDS, INC.

GTS LICENSING COMPANY, INC.

ALON FINANCIAL SERVICES, INC.

SOUTHWEST CONVENIENCE STORES, LLC SKINNY'S, LLC

By:/s/ Kevin Kremke

Name: Kevin Kremke

Title: Executive Vice President and Chief Accounting Officer

DELEK BIG SPRING GATHERING, LLC

DELEK BIG SPRING NORTH GATHERING, LLC DELEK BIG SPRING SOUTH MAINLINE, LLC

By:/s/ Kevin Kremke

Name: Kevin Kremke

Title: Executive Vice President and Chief Accounting Officer

ALON PARAMOUNT HOLDINGS, INC. PARAMOUNT PETROLEUM CORPORATION

By:/s/ Mark Page

Name: Mark Page

Title: President and Treasurer

DELEK LOGISTICS SERVICES COMPANY

By:/s/ Kevin Kremke

Name: Kevin Kremke

Title: Executive Vice President

By:/s/ Greg Intemann

Name: Greg Intemann

Title: Vice President

WELLS FARGO BANK, NATIONAL ASSOCIATION,

as Agent and New Lender

By:/s/ Ryan C. Tozier

Name: Ryan C. Tozier

Title: Vice President

EXHIBIT A

FORM OF LENDER CONSENT

CONSENT (this “Amendment No. 1 Consent”) to AMENDMENT NO. 1 TO TERM LOAN CREDIT AGREEMENT (the “Amendment”) to the TERM LOAN CREDIT

AGREEMENT, dated as of March 30, 2018, among DELEK US HOLDINGS, INC., a Delaware corporation (the “Borrower”), each Lender from time to time party thereto and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Agent (in such capacity, the “Agent”) (as amended, restated, amended and restated, supplemented or otherwise modified from time to time prior to the date hereof, the “Credit Agreement” and the Credit Agreement, as amended by the Amendment, the “Amended Credit Agreement”). Capitalized terms used in this Amendment No. 1 Consent but not defined in this Amendment No. 1 Consent have meanings assigned to such terms in the Amendment.

The undersigned Lender hereby consents to the Amendment and, if such Lender holds Loans, hereby agrees as follows with respect to its Existing Loans:

[Check ONLY ONE of the two boxes below]

CASHLESS AMENDMENT OPTION

•The undersigned Lender agrees to reprice 100% of the outstanding principal amount of such Lender’s Existing Loans on a cashless basis.

POST-CLOSING SETTLEMENT OPTION

•The undersigned Lender agrees that the entire amount of such Lender’s Existing Loans will be assigned to the New Lender at par on the Amendment No. 1 Effective Date (it being understood that no Assignment and Acceptance shall be required to be executed by such Lender to effect such assignment) and, following the Amendment No. 1 Effective Date, such Lender shall purchase by assignment Loans in an equal principal amount as its Existing Loans or such lesser amount allocated to such Lender by the Amendment No. 1 Arranger.

IN WITNESS WHEREOF, the undersigned has caused this Amendment No. 1 Consent to be executed and delivered by a duly authorized officer as of the date first written above.

, (Name of Institution)


By:	Name:

Title:

If a second signature is necessary:


By:	Name:

Title:

Exhibit 31.1

Certification by Chief Executive Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Ezra Uzi Yemin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Delek US Holdings, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



By:	/s/ Ezra Uzi Yemin
	Ezra Uzi Yemin,
	President and Chief Executive Officer (Principal Executive Officer)

Dated: November 7, 2019

Exhibit 31.2

Certification by Chief Financial Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Assaf Ginzburg, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Delek US Holdings, Inc.;

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



By:	/s/ Assaf Ginzburg
	Assaf Ginzburg,
	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Dated: November 7, 2019

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the quarterly report of Delek US Holdings, Inc. (the “Company”) on Form 10-Q for the three months ended September 30, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ezra Uzi Yemin, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, and to the best of my knowledge, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



By:	/s/ Ezra Uzi Yemin
	Ezra Uzi Yemin,
	President and Chief Executive Officer (Principal Executive Officer)

Dated: November 7, 2019

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the quarterly report of Delek US Holdings, Inc. (the “Company”) on Form 10-Q for the three months ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Assaf Ginzburg, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, and to the best of my knowledge, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



By:	/s/ Assaf Ginzburg
	Assaf Ginzburg,
	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Dated: November 7, 2019