Edgar Filing: Delek US Holdings, Inc.

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)



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

		For the quarterly period ended September 30, 2015



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

		For the transition period from to

Commission file number 001-32868

DELEK US HOLDINGS, INC.

(Exact name of registrant as specified in its charter)



Delaware		52-2319066
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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 þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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

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

At October 30, 2015, there were 62,202,745 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



PART I. FINANCIAL INFORMATION

Item 1. Financial Statements	3

Condensed Consolidated Balance Sheets as of September 30, 2015 (Unaudited) and December 31, 2014	3

Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014 (Unaudited)	4

Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014 (Unaudited)	5

Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014 (Unaudited)	6

Notes to Condensed Consolidated Financial Statements (Unaudited)	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3. Quantitative and Qualitative Disclosures about Market Risk	46

Item 4. Controls and Procedures	46

PART II. OTHER INFORMATION

Item 1A. Risk Factors	48

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	48

Item 5. Other Information	48

Item 6. Exhibits	49

Signatures	50

Exhibit Index	51

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

Part I.

FINANCIAL INFORMATION


Item 1.	Financial Statements

Delek US Holdings, Inc.

Condensed Consolidated Balance Sheets (Unaudited)



	September 30, 2015			December 31, 2014
	(In millions, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	366.3		$	444.1
Accounts receivable	227.5			197.0
Accounts receivable from related party	2.1			—
Inventory	384.1			469.6
Other current assets	108.5			136.7
Total current assets	1,088.5			1,247.4
Property, plant and equipment:
Property, plant and equipment	2,065.8			1,952.9
Less: accumulated depreciation	(550.8		)	(509.6		)
Property, plant and equipment, net	1,515.0			1,443.3
Goodwill	73.9			73.9
Other intangibles, net	27.5			21.4
Equity method investments	618.8			—
Other non-current assets	109.8			105.1
Total assets	$	3,433.5		$	2,891.1
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	443.1		$	476.7
Current portion of long-term debt and capital lease obligations	103.7			56.4
Obligation under Supply and Offtake Agreement	160.8			200.9
Accrued expenses and other current liabilities	124.5			122.9
Total current liabilities	832.1			856.9
Non-current liabilities:
Long-term debt and capital lease obligations, net of current portion	850.0			533.3
Environmental liabilities, net of current portion	8.1			8.5
Asset retirement obligations	9.5			9.2
Deferred tax liabilities	261.6			266.3
Other non-current liabilities	52.5			18.5
Total non-current liabilities	1,181.7			835.8
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, 66,892,775 shares and 60,637,525 shares issued at September 30, 2015 and December 31, 2014, respectively	0.7			0.6
Additional paid-in capital	636.2			395.1
Accumulated other comprehensive loss	(30.8		)	(12.6		)
Treasury stock, 4,325,314 shares and 3,365,561 shares, at cost, as of September 30, 2015 and December 31, 2014, respectively	(141.6		)	(112.6		)
Retained earnings	754.5			731.2
Non-controlling interest in subsidiaries	200.7			196.7
Total stockholders’ equity	1,419.7			1,198.4
Total liabilities and stockholders’ equity	$	3,433.5		$	2,891.1

See accompanying notes to condensed consolidated financial statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Income (Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In millions, except share and per share data)
Net sales	$	1,554.2		$	2,322.2		$	4,397.9		$	6,562.6
Operating costs and expenses:
Cost of goods sold	1,355.6			2,035.2			3,799.9			5,786.8
Operating expenses	106.6			100.9			304.0			301.6
General and administrative expenses	34.1			36.0			101.1			97.6
Depreciation and amortization	34.2			29.2			97.4			82.0
Other operating income, net	(0.1		)	—			(0.2		)	—
Total operating costs and expenses	1,530.4			2,201.3			4,302.2			6,268.0
Operating income	23.8			120.9			95.7			294.6
Interest expense	15.7			10.0			43.1			29.7
Interest income	(0.3		)	—			(0.9		)	(0.4		)
Income from equity method investments	(16.5		)	—			(23.9		)	—
Other income, net	—			(0.1		)	(1.0		)	(0.1		)
Total non-operating (income) expenses, net	(1.1		)	9.9			17.3			29.2
Income before income tax (benefit) expense	24.9			111.0			78.4			265.4
Income tax (benefit) expense	(0.5		)	32.8			8.6			84.7
Net income	25.4			78.2			69.8			180.7
Net income attributed to non-controlling interest	6.7			5.7			18.9			19.6
Net income attributable to Delek	$	18.7		$	72.5		$	50.9		$	161.1
Basic earnings per share	$	0.30		$	1.23		$	0.84		$	2.73
Diluted earnings per share	$	0.29		$	1.22		$	0.84		$	2.70
Weighted average common shares outstanding:
Basic	63,189,399			58,744,099			60,366,532			59,090,291
Diluted	63,658,386			59,302,788			60,894,206			59,673,599
Dividends declared per common share outstanding	$	0.15		$	0.25		$	0.45		$	0.75

See accompanying notes to condensed consolidated financial statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Comprehensive Income (Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In millions)
Net income attributable to Delek	$	18.7		$	72.5		$	50.9		$	161.1
Other comprehensive (loss) income:
Commodity contracts designated as cash flow hedges:
Unrealized (losses) gains, net of ineffectiveness losses (gains) of $12.4 million and $21.3 million for the three and nine months ended September 30, 2015, respectively, and $8.9 million and $(5.4) million for the three and nine months ended September 30, 2014, respectively.	(24.3		)	(3.5		)	(20.8		)	20.8
Realized losses (gains) reclassified to cost of goods sold	0.6			5.9			(1.7		)	8.0
Net (loss) gain before tax	(23.7		)	2.4			(22.5		)	28.8
Income tax benefit (expense)	8.3			(0.8		)	7.9			(10.4		)
Net (loss) gain on commodity contracts designated as cash flow hedges	(15.4		)	1.6			(14.6		)	18.4
Foreign currency translation loss	(0.1		)	—			(0.2		)	—
Other comprehensive loss from equity method investments, net of tax benefit of $1.8 million for both the three and nine months ended September 30, 2015	(1.9		)	—			(3.4		)	—
Total other comprehensive income	(17.4		)	1.6			(18.2		)	18.4
Comprehensive income attributable to Delek	$	1.3		$	74.1		$	32.7		$	179.5

See accompanying notes to condensed consolidated financial statements

Delek US Holdings, Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)



	Nine Months Ended September 30,
	2015			2014
Cash flows from operating activities:	(In millions)
Net income	$	69.8		$	180.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	97.4			82.0
Amortization of deferred financing costs	3.4			3.6
Accretion of asset retirement obligations	0.4			0.5
Amortization of unfavorable contract liability	—			(2.0		)
Deferred income taxes	0.1			10.8
Income from equity method investments	(23.9		)	—
Dividends from equity method investments	10.1			—
Gain on disposal of assets	(0.2		)	—
Equity-based compensation expense	12.3			10.0
Income tax benefit of equity-based compensation	(1.7		)	(2.3		)
Changes in assets and liabilities, net of acquisitions:
Accounts receivable	(32.6		)	(73.5		)
Inventories and other current assets	110.0			174.9
Market value of derivatives	30.4			(34.1		)
Accounts payable and other current liabilities	(29.0		)	(14.0		)
Obligation under Supply and Offtake Agreement	(40.1		)	(48.5		)
Non-current assets and liabilities, net	(14.7		)	(46.4		)
Net cash provided by operating activities	191.7			241.7
Cash flows from investing activities:
Business combinations	(0.4		)	(11.1		)
Equity method investments	(230.6		)	—
Purchases of property, plant and equipment	(175.9		)	(211.1		)
Purchase of intangible assets	(7.2		)	—
Proceeds from sales of assets	2.2			0.2
Net cash used in investing activities	(411.9		)	(222.0		)
Cash flows from financing activities:
Proceeds from long-term revolvers	517.6			888.0
Payments on long-term revolvers	(436.2		)	(791.3		)
Proceeds from term debt and capital lease obligations	178.2			104.1
Payments on term debt and capital lease obligations	(40.6		)	(16.6		)
Proceeds from exercise of stock options	0.2			1.0
Taxes paid due to the net settlement of equity-based compensation	(3.6		)	(4.8		)
Income tax benefit of equity-based compensation	1.7			2.3
Repurchase of common stock	(29.0		)	(41.6		)
Distribution to non-controlling interest	(15.3		)	(12.3		)
Dividends paid	(27.6		)	(44.7		)
Deferred financing costs paid	(3.0		)	(6.1		)
Net cash provided by financing activities	142.4			78.0
Net (decrease) increase in cash and cash equivalents	(77.8		)	97.7
Cash and cash equivalents at the beginning of the period	444.1			400.0
Cash and cash equivalents at the end of the period	$	366.3		$	497.7
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest, net of capitalized interest of $0.7 million and $1.6 million in the 2015 and 2014 periods, respectively.	$	36.2		$	26.9
Income taxes	$	5.4		$	73.4
Non-cash investing activities:
Equity method investments	$	3.8		$	—
Decrease in accrued capital expenditures	$	(2.3	)	$	(17.8	)
Non-cash financing activities:
Stock issued in connection with the Alon Acquisition	$	230.8		$	—
Note payable issued in connection with the Alon Acquisition	$	145.0		$	—

See accompanying notes to condensed consolidated financial statements

Delek US Holdings, Inc.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Organization and Basis of Presentation

Delek US Holdings, Inc. is the sole shareholder or owner of membership interests of Delek Refining, Inc. ("Refining"), Delek Finance, Inc., Delek Marketing & Supply, LLC, Lion Oil Company ("Lion Oil"), Delek Renewables, LLC, Delek Rail Logistics, Inc., Delek Logistics Services Company, MAPCO Express, Inc. ("MAPCO Express"), MAPCO Fleet, Inc., NTI Investments, LLC, GDK Bearpaw, LLC, Delek Helena, LLC, Commerce Way Insurance Company, Inc., Delek Transportation, LLC and Delek Land Holdings, LLC. Unless otherwise indicated or the context requires otherwise, the terms "we," "our," "us," "Delek" and the "Company" are used in this report to refer to Delek US Holdings, Inc. and its consolidated subsidiaries. Delek is listed on the New York Stock Exchange under the symbol "DK."

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

The condensed consolidated financial statements include the accounts of Delek and its consolidated 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 financial statements included in our Annual Report on Form 10-K filed with the Securities and Exchange Commission ("SEC") on February 26, 2015 (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, 2014 included in our Annual Report on Form 10-K.

In the opinion of management, all adjustments necessary for a fair presentation of the financial position 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.

Certain prior period amounts have been reclassified in order to conform to the current year presentation. These reclassifications had no effect on net income or shareholders' equity as previously reported. Additionally, we corrected an immaterial error for the prior period in the statement of cash flows.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

New Accounting Pronouncements

In September 2015, the Financial Accounting Standards Board ("FASB") issued guidance that eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Instead, acquirers must recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts they would have recorded in previous periods if the accounting had been completed at the acquisition date. This guidance is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years and can be early adopted for any interim or annual financial statements that have not yet been issued. We expect to adopt this guidance on or before the effective date and we do not anticipate that the adoption will have a material impact on our business, financial position or results of operations.

In July 2015, the FASB issued guidance requiring entities to measure first-in, first-out ("FIFO") or average cost inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This guidance does not change the measurement of

inventory measured using last-in, first-out ("LIFO") or the retail inventory method. This guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years and can be early adopted at the beginning of any interim or annual period for which financial statements have not yet been issued. We expect to adopt this guidance on or before the effective date and we do not anticipate that the adoption will have a material impact on our business, financial position or results of operations.

In April 2015, the FASB issued guidance which requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. Prior to the issuance of this guidance, debt issuance costs were required to be presented in the balance sheet as an asset. In August 2015, the FASB issued further clarification regarding an SEC staff announcement related to this guidance which permits entities to defer and present debt issuance costs associated with line-of-credit arrangements as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Upon adoption, the guidance requires prior period financial statements to be retrospectively adjusted. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 with early adoption permitted in certain circumstances. We expect to adopt this guidance on or before the effective date and we do not anticipate that the adoption will have a material impact on our business, financial position or results of operations.

2. Delek Logistics Partners, LP

Delek Logistics is a publicly traded limited partnership that was formed by Delek 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 Delek’s refining and marketing operations. As of September 30, 2015, we owned a 59.8% limited partner interest in Delek Logistics, and a 95.6% interest in Logistics GP, which owns the entire 2.0% general partner interest in Delek Logistics and all of the incentive distribution rights. Delek's partnership interest in Delek Logistics includes 2,799,258 common units, 11,999,258 subordinated units and 494,900 general partner units.

In March 2015, a subsidiary of Delek Logistics completed the acquisition from Lion Oil of two crude oil offloading racks in El Dorado, Arkansas (the "El Dorado refinery") and related ancillary assets adjacent to our El Dorado refinery (the "El Dorado Offloading Racks Acquisition"). The cash paid for the assets acquired was approximately $42.5 million, financed with borrowings under the DKL Revolver (as defined in Note 6).

In March 2015, a subsidiary of Delek Logistics completed the acquisition from Refining of a crude oil storage tank with 350,000 barrels of shell capacity that supports our refinery in Tyler, Texas (the "Tyler refinery") and related ancillary assets adjacent to our Tyler refinery (the "Tyler Crude Tank Acquisition"). The purchase price paid for the assets acquired was $19.4 million in cash, financed with borrowings under the DKL Revolver (as defined in Note 6).

The El Dorado Offloading Racks Acquisition and the Tyler Crude Tank Acquisition are each considered a transfer of a business between entities under common control. As such, the assets acquired and liabilities assumed were transferred to Delek Logistics at historical basis instead of fair value.

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.

With the exception of affiliate balances which are eliminated in consolidation, the Delek Logistics condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014, as presented below, are included in the consolidated balance sheets of Delek (in millions).



	September 30, 2015			December 31, 2014⁽¹⁾
	September 30, 2015			December 31, 2014⁽¹⁾
	(Unaudited)
ASSETS
Cash and cash equivalents	$	—		$	1.9
Accounts receivable	37.1			28.0
Inventory	5.0			10.3
Other current assets	0.4			0.8
Net property, plant and equipment	255.2			254.8
Equity method investments	30.5			—
Goodwill	11.7			11.7
Intangible assets, net	15.7			16.5
Other non-current assets	6.2			7.3
Total assets	$	361.8		$	331.3
LIABILITIES AND (DEFICIT) EQUITY
Accounts payable	$	12.4		$	17.9
Accounts payable to related parties	9.6			0.6
Accrued expenses and other current liabilities	12.3			11.8
Revolving credit facility	325.2			251.8
Asset retirement obligations	3.4			3.3
Deferred tax liabilities	0.3			0.2
Other non-current liabilities	10.3			5.9
(Deficit) equity	(11.7		)	39.8
Total liabilities and equity	$	361.8		$	331.3

⁽¹⁾These amounts have been restated to reflect the assets and liabilities acquired in the El Dorado Offloading Racks Acquisition and the Tyler Crude Tank Acquisition.

3. Equity Method Investments

On May 14, 2015, Delek acquired from Alon Israel Oil Company, Ltd. ("Alon Israel") approximately 33.7 million shares of common stock (the "ALJ Shares") of Alon USA Energy, Inc. (NYSE: ALJ) ("Alon USA") pursuant to the terms of a stock purchase agreement with Alon Israel dated April 14, 2015 (the "Alon Acquisition"). The ALJ Shares represented an equity interest in Alon USA of approximately 48%. We acquired the ALJ Shares for the following combination of cash, stock and seller-financed debt:


•	Delek issued 6,000,000 restricted shares of its common stock, par value $0.01 per share (the "DK Shares"), to Alon Israel;


•	Delek issued an unsecured $145.0 million term promissory note payable to Alon Israel (the "Alon Israel Note") (See Note 6 for further information); and


•	Delek paid Alon Israel $200.0 million in cash at closing funded with a combination of cash on hand and borrowings under the Lion Term Loan (as defined in Note 6).

Delek will also issue an additional 200,000 restricted shares of its common stock, par value $0.01 per share, to Alon Israel if the closing price of Delek's common stock is greater than $50.00 per share for at least 30 consecutive trading days that end on or before May 14, 2017.

As of September 30, 2015, our investment balance in Alon USA was $588.3 million and the excess of our initial investment over our net equity in the underlying net assets of Alon USA was approximately $256.6 million. This excess is included in equity method investments in our consolidated balance sheet and has been preliminarily attributed to property, plant and equipment. This excess will be depreciated as a reduction to earnings from equity method investments on a straight-line basis over the lives of the related assets. The earnings from this equity method investment reflected in our consolidated statements of income include our share of net earnings directly attributable to this equity method investment, and depreciation of the excess of our investment balance over the underlying net assets of Alon USA.

Below is summarized financial information of the financial position and results of operations of Alon USA, as of September 30, 2015 and for the period from May 14, 2015 through September 30, 2015 (in millions):



Balance Sheet Information	September 30, 2015
Current assets	$	559.3
Non-current assets	1,660.7
Current liabilities	397.7
Non-current liabilities	1,082.4
Non-controlling interests	35.9



Income Statement Information	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
Revenue	$	1,151.2	$	1,837.6
Gross profit	237.0		359.1
Pre-tax income	69.7		107.5
Net income	52.4		77.6
Net income attributable to Alon USA	41.9		61.1

Also, in March 2015, Delek Logistics entered into two joint ventures that will construct logistics assets to serve third parties and subsidiaries of Delek. Delek Logistics' total projected investment for the two joint ventures is approximately $96.0 million and will be financed by Delek Logistics through a combination of cash from operations and borrowings under the DKL Revolver (as defined in Note 6). As of September 30, 2015, the investment in these joint ventures totaled $30.5 million and was accounted for using the equity method.

4. Inventory

Refinery inventory consists of crude oil, in-process, refined products and blendstocks which are stated at the lower of cost or market. Cost of inventory for the Tyler refinery is determined under the LIFO valuation method. Cost of inventory for the El Dorado refinery is determined on a FIFO basis.

Logistics inventory consists of refined products which are stated at the lower of cost or market on a FIFO basis.

Retail inventory consists of gasoline, diesel fuel, other petroleum products, cigarettes, beer, convenience merchandise and food service merchandise. Fuel inventories are stated at the lower of cost or market on a FIFO basis. Non-fuel inventories are stated at estimated cost as determined by the retail inventory method.

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



	September 30, 2015		December 31, 2014
Refinery raw materials and supplies	$	129.9	$	158.8
Refinery work in process	37.1		26.5
Refinery finished goods	176.1		235.1
Retail fuel	9.9		10.9
Retail merchandise	26.1		28.0
Logistics refined products	5.0		10.3
Total inventories	$	384.1	$	469.6

At both September 30, 2015 and December 31, 2014, the excess of replacement cost (FIFO) over the carrying value (LIFO) of the Tyler refinery inventories was $0.3 million.

Permanent Liquidations

We incurred a permanent reduction in a LIFO layer resulting in a liquidation loss in our refinery inventory of $8.9 million and $19.1 million during the three and nine months ended September 30, 2015, respectively, and $10.2 million and $7.9 million during the three and nine months ended September 30, 2014, respectively. These liquidations were recognized as a component of cost of goods sold.

5. Crude Oil Supply and Inventory Purchase Agreement

Delek has a Master Supply and Offtake Agreement (the "Supply and Offtake Agreement") with J. Aron & Company ("J. Aron"). Throughout the term of the Supply and Offtake Agreement, which was amended on December 23, 2013 to expire on April 30, 2017, Lion Oil and J. Aron will identify mutually acceptable contracts for the purchase of crude oil from third parties and J. Aron will supply up to 100,000 barrels per day ("bpd") of crude to the El Dorado refinery. Crude oil supplied to the El Dorado refinery by J. Aron will be purchased daily at an estimated average monthly market price by Lion Oil. J. Aron will also purchase all refined products from the El Dorado refinery at an estimated market price daily, as they are produced. These daily purchases and sales are trued-up on a monthly basis in order to reflect actual average monthly prices. We have recorded a receivable (payable) related to this settlement of $4.9 million and $(4.9) million as of September 30, 2015 and December 31, 2014, respectively, which is included in accounts receivable on the condensed consolidated balance sheet. Also pursuant to the Supply and Offtake Agreement and other related agreements, Lion Oil will endeavor to arrange potential sales by either Lion Oil or J. Aron to third parties of the products produced at the El Dorado refinery or purchased from third parties. In instances where Lion Oil is the seller to such third parties, J. Aron will first transfer the applicable products to Lion Oil.

While title to the inventories will reside with J. Aron, this arrangement will be accounted for as a product financing arrangement. Delek incurred fees payable to J. Aron of $2.6 million and $7.9 million during the three and nine months ended September 30, 2015, respectively, and $2.6 million and $7.6 million during the three and nine months ended September 30, 2014, respectively. These amounts are included as a component of interest expense in the condensed consolidated statements of income. Upon any termination of the Supply and Offtake Agreement, including in connection with a force majeure event, the parties are required 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.

Upon the expiration of the Supply and Offtake Agreement on April 30, 2017, or upon any earlier termination, Delek will be required to repurchase the consigned crude oil and refined products from J. Aron at then prevailing market prices. At September 30,

2015, Delek had 3.2 million barrels of inventory consigned for J. Aron, and we have recorded liabilities associated with this consigned inventory of $160.8 million in the condensed consolidated balance sheet.

6. Long-Term Obligations and Notes Payable

Outstanding borrowings under Delek’s existing debt instruments and capital lease obligations are as follows (in millions):



	September 30, 2015		December 31, 2014
MAPCO Revolver	$	84.0	$	76.0
DKL Revolver	325.2		251.8
Wells Term Loan	46.6		64.2
Reliant Bank Revolver	17.0		17.0
Promissory notes	213.8		76.0
Lion Term Loan, net of $1.4 million and $0.3 million debt discount at September 30, 2015 and December 31, 2014, respectively	266.7		104.2
Capital lease obligations	0.4		0.5
	953.7		589.7
Less: Current portion of long-term debt, notes payable and capital lease obligations	103.7		56.4
	$	850.0	$	533.3

MAPCO Revolver

Our subsidiary, MAPCO Express, has a revolving credit facility with Fifth Third Bank, as administrative agent, and a syndicate of lenders that was amended and restated on May 6, 2014 (the "MAPCO Revolver"). The MAPCO Revolver consists of a $160.0 million revolving credit limit which includes (i) a $10.0 million swing line loan sub-limit; (ii) a $40.0 million letter of credit sub-limit; and (iii) an accordion feature which permits an increase in borrowings by up to $50.0 million, subject to additional lender commitments. As of September 30, 2015, we had $84.0 million outstanding under the MAPCO Revolver, as well as letters of credit issued of $2.6 million, with approximately $73.4 million availability remaining. Borrowings under the MAPCO Revolver are secured by (i) substantially all the assets of MAPCO Express and its subsidiaries, subject to certain exceptions and limitations, (ii) all of Delek’s shares in MAPCO Express, and (iii) a limited guaranty provided by Delek of up to $50.0 million in obligations. The MAPCO Revolver will mature on May 6, 2019. The MAPCO Revolver bears interest based on predetermined pricing grids which allow us to choose between base rate loans or London Interbank Offered Rate ("LIBOR") rate loans. At September 30, 2015, the weighted average borrowing rate under the MAPCO Revolver was approximately 2.55%. Additionally, the MAPCO Revolver requires us to pay a leverage ratio dependent quarterly fee on the average unused revolving commitment. As of September 30, 2015, this fee was 0.30% per year.

Wells ABL

Our subsidiary, Delek Refining, Ltd., has an asset-based loan credit facility with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders (the "Wells ABL") that consists of (i) a $600.0 million revolving loan (the "Wells Revolving Loan"), which includes a $55.0 million swing line loan sub-limit and a $550.0 million letter of credit sub-limit, (ii) a $70.0 million delayed single draw term loan (the "Wells Term Loan"), and (iii) an accordion feature which permits an increase in the size of the revolving credit facility to an aggregate of $875.0 million, subject to additional lender commitments and the satisfaction of certain other conditions precedent. The Wells Revolving Loan matures on January 16, 2019 and the Wells Term Loan matures on December 31, 2016. The Wells Term Loan is subject to repayment in level principal installments of approximately $5.8 million per quarter, beginning December 31, 2014, with a final balloon payment due on December 31, 2016. As of September 30, 2015, under the Wells ABL, we had letters of credit issued totaling approximately $91.5 million and no amounts outstanding under the Wells Revolving Loan; under the Wells Term Loan we had approximately $46.6 million outstanding. Borrowings under the Wells ABL are secured by substantially all the assets of Refining and its subsidiaries, with certain limitations. Under the facility, revolving loans and letters of credit are provided subject to availability requirements which are determined pursuant to a borrowing base calculation as defined in the credit agreement. The borrowing base as calculated is primarily supported by cash, certain accounts receivable and certain inventory. Borrowings under the Wells Revolving Loan and Wells Term Loan bear interest based on separate predetermined pricing grids which allow us to choose between base rate loans or LIBOR rate loans. At September 30, 2015, the weighted average borrowing rate under the Wells Term Loan was approximately 3.94%. Additionally, the Wells ABL requires us to pay a quarterly unused credit commitment fee. As of September 30, 2015, this fee was approximately

0.38% per year. Unused availability, as calculated and reported under the terms of the Wells ABL credit facility, as of September 30, 2015, was $145.0 million.

DKL Revolver

Delek Logistics has a $700.0 million Senior Secured Revolving Credit Agreement with Fifth Third Bank, as administrative agent, and a syndicate of lenders (the "DKL Revolver"). Delek Logistics and each of its existing subsidiaries are borrowers under the DKL Revolver. The DKL Revolver contains a dual currency borrowing tranche that permits draw downs in U.S. or Canadian dollars and an accordion feature whereby Delek Logistics can increase the size of the credit facility to an aggregate of $800.0 million, subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent.

The obligations under the DKL Revolver are secured by a first priority lien on substantially all of Delek Logistics' tangible and intangible assets. Additionally, a subsidiary of Delek provides a limited guaranty of Delek Logistics' obligations under the DKL Revolver. 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 DKL Revolver lenders. As of September 30, 2015, the principal amount of the Holdings Note was $102.0 million.

The DKL Revolver will mature on December 30, 2019. Borrowings under the DKL Revolver bear interest at either a U.S. base rate, Canadian prime rate, LIBOR, or a Canadian Dealer Offered Rate plus applicable margins, at the election of the borrowers and as a function of draw down currency. The applicable margin, in each case, varies based upon Delek Logistics' Leverage Ratio, which is defined as the ratio of total funded debt to EBITDA for the most recently ended four fiscal quarters. At September 30, 2015, the weighted average borrowing rate was approximately 2.52%. Additionally, the DKL Revolver requires Delek Logistics to pay a leverage ratio dependent quarterly fee on the average unused revolving commitment. As of September 30, 2015, this fee was 0.40% per year. As of September 30, 2015, Delek Logistics had $325.2 million of outstanding borrowings under the credit facility, as well as letters of credit issued of $2.5 million. Amounts available under the DKL Revolver, as of September 30, 2015, were approximately $372.3 million.

Reliant Bank Revolver

We have a revolving credit agreement with Reliant Bank, which was amended on June 26, 2014 (the "Reliant Bank Revolver"). The Reliant Bank Revolver provides for unsecured loans of up to $17.0 million. As of September 30, 2015, we had $17.0 million outstanding under this facility. The Reliant Bank Revolver matures on June 28, 2016, and bears interest at a fixed rate of 5.25% per annum. The Reliant Bank Revolver requires us to pay a quarterly fee of 0.50% per year on the average available revolving commitment. As of September 30, 2015, we had no undrawn amounts available under the Reliant Bank Revolver.

Promissory Notes

In 2011, Delek began construction on new MAPCO Mart convenience stores (each a "Build-to-Suit Development" or "BTS"). In order to fund these construction projects, we entered into separate notes for each BTS project with Standard Insurance Company (collectively, the "Notes") varying in size from $1.0 million to $2.2 million. The Notes bear interest at fixed rates, ranging from 5.00% to 6.38% per annum. Each of the Notes is secured by the land or leasehold interest, as applicable, and the building and equipment of its respective completed MAPCO Mart. Under the terms of each Note, beginning on the first day of the eleventh month following the initial fund advancement, payments of principal on each respective Note are due over a ten-year term calculated using a 25-year amortization schedule. If any Note is not paid in full after the initial ten-year period, we may continue to make monthly payments under the Note; however, the interest rate will reset pursuant to the terms of the Note. There is also an additional interest rate reset after the first 20-year period. The final maturity dates of the Notes range from June 1, 2036 to November 1, 2039. As of September 30, 2015, we had amounts drawn under 29 Notes related to these BTS projects, for a total amount of approximately $48.8 million outstanding under the Notes.

On April 29, 2011, Delek entered into a $50.0 million promissory note (the "Ergon Note") with Ergon, Inc. ("Ergon") in connection with the closing of our acquisition of Lion Oil. As of September 30, 2015, $20.0 million was outstanding under the Ergon Note. The Ergon Note requires Delek to make annual amortization payments of $10.0 million each, commencing April 29, 2013. The Ergon Note matures on April 29, 2017. Interest under the Ergon Note is computed at a fixed rate equal to 4.00% per annum.

On May 14, 2015, in connection with the Company’s closing of the acquisition of the ALJ shares, the Company issued the Alon Israel Note, which is payable to Alon Israel. The Alon Israel Note that bears interest at a fixed rate of 5.50% per annum and requires five annual principal amortization payments of $25.0 million beginning in January 2016 followed by a final principal amortization payment of $20.0 million at maturity on January 4, 2021. As of September 30, 2015, $145.0 million was outstanding

under the Alon Israel Note. In October 2015, we made a principal and interest prepayment on the Alon Israel Note of approximately $25.5 million. See "Alon Israel Note Prepayment" under Note 15 for additional information.

Lion Term Loan

Our subsidiary, Lion Oil, has a term loan credit facility with Fifth Third Bank, as administrative agent, and a syndicate of lenders, which was amended and restated on May 14, 2015 in connection with the Company’s closing of the Alon Acquisition to, among other things, increase the total loan size from $99.0 million to $275.0 million (the "Lion Term Loan"). The Lion Term Loan requires Lion Oil to make quarterly principal amortization payments of approximately $6.9 million each, commencing on September 30, 2015, with a final balloon payment due on the maturity date. The Lion Term Loan matures on May 14, 2020, and is secured by among other things, (i) substantially all assets of Lion Oil and its subsidiaries (excluding inventory and accounts receivable), (ii) all shares in Lion Oil, (iii) the subordinated and common units of Delek Logistics held by Lion Oil, and (iv) the ALJ Shares. Additionally, the Lion Term Loan is guaranteed by Delek and the subsidiaries of Lion Oil. Interest on the unpaid balance of the Lion Term Loan is 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. As of September 30, 2015, $268.1 million was outstanding under the Lion Term Loan and the weighted average borrowing rate was 5.50%.

Restrictive Covenants

Under the terms of our MAPCO Revolver, Wells ABL, DKL Revolver, Reliant Bank Revolver and Lion Term Loan, we are required to comply with certain usual and customary financial and non-financial covenants. Further, although we were not required to comply with separate fixed charge coverage ratio financial covenants under the Wells ABL and the Lion Term Loan during the three or nine months ended September 30, 2015, we may be required to comply with these covenants at times when certain trigger thresholds are met, as defined in each of the Wells ABL and Lion Term Loan agreements. We believe we were in compliance with all covenant requirements under each of our credit facilities as of September 30, 2015.

Certain of our credit facilities contain limitations on the incurrence of additional indebtedness, making of investments, creation of liens, dispositions of property, 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 our subsidiaries. Additionally, certain of our credit 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.

Interest-Rate Derivative Instruments

As of September 30, 2015, Delek had an interest rate cap agreement for a total notional amount of $45.0 million. This agreement is intended to economically hedge floating interest rate risk related to a portion of our existing debt. However, as we have elected to not apply the permitted hedge accounting treatment, including formal hedge designation and documentation, in accordance with the provisions of ASC 815, Derivatives and Hedging ("ASC 815"), the fair value of the derivatives is recorded in other current assets in the accompanying condensed consolidated balance sheets with the offset recognized in interest expense in the accompanying condensed consolidated statements of income. The derivative instrument matures in 2016. The estimated mark-to-market liability associated with our interest rate derivatives, as of September 30, 2015 and December 31, 2014, was nominal and $0.9 million, respectively.

In accordance with ASC 815, we recorded expense representing cash settlements and changes in estimated fair value of the interest rate derivative agreements of a nominal amount and $0.2 million for the three and nine months ended September 30, 2015, respectively, and a nominal amount and $0.4 million for the three and nine months ended September 30, 2014, respectively. These amounts are included in interest expense in the accompanying consolidated statements of income.

While Delek has not elected to apply permitted hedge accounting treatment for these interest rate derivatives in accordance with the provisions of ASC 815 in the past, we may choose to apply that treatment for future transactions.

7. Income Taxes

At September 30, 2015, Delek had unrecognized tax benefits of $0.3 million that, if recognized, would affect our effective tax rate. Delek recognizes accrued interest and penalties related to unrecognized tax benefits as an adjustment to the current provision for income taxes. Interest of a nominal amount was recognized related to unrecognized tax benefits during both the three and nine months ended September 30, 2015. Interest of $0.2 million was recognized related to unrecognized tax benefits during both the three and nine months ended September 30, 2014. During the three and nine months ended September 30, 2015, we reversed $2.1 million and $2.4 million, respectively, of unrecognized tax benefits related to prior year tax positions.

Our effective tax rate was (2.0)% and 11.0% for the three and nine months ended September 30, 2015, respectively, compared to 29.5% and 31.9% for the three and nine months ended September 30, 2014. The decrease in our effective tax rate in the three and nine months ended September 30, 2015 was primarily due to the greater impact of permanent differences on the tax rate, due to the lower pre-tax income during the three and nine months ended September 30, 2015, as compared to the prior periods, as well as the actualization of prior-year provision amounts.

8. Stockholders' Equity

Changes to equity during the nine months ended September 30, 2015 are presented below (in millions, except per share amounts):



	Delek Stockholders' Equity			Non-Controlling Interest in Subsidiaries			Total Stockholders' Equity
Balance at December 31, 2014	$	1,001.7		$	196.7		$	1,198.4
Net income	50.9			18.9			69.8
Unrealized loss on cash flow hedges, net of income tax benefit of $7.9 million and ineffectiveness loss of $21.3 million	(14.6		)	—			(14.6		)
Foreign currency translation loss	(0.2		)	—			(0.2		)
Other comprehensive loss from equity method investments, net of income tax benefit of $1.8 million	(3.4		)	—			(3.4		)
Common stock dividends ($0.45 per share)	(27.6		)	—			(27.6		)
Distribution to non-controlling interest	—			(15.3		)	(15.3		)
Stock issued in connection with the Alon Acquisition	230.8			—			230.8
Equity-based compensation expense	11.6			0.7			12.3
Purchase of common stock	(29.0		)	—			(29.0		)
Income tax benefit from equity-based compensation expense	1.7			—			1.7
Taxes paid due to the net settlement of equity-based compensation	(3.6		)	—			(3.6		)
Exercise of equity-based awards	0.2			—			0.2
Other	0.5			(0.3		)	0.2
Balance at September 30, 2015	$	1,219.0		$	200.7		$	1,419.7

Dividends

During the nine months ended September 30, 2015, our Board of Directors declared the following dividends:



Date Declared	Dividend Amount Per Share	Record Date	Payment Date
February 23, 2015	$0.15	March 10, 2015	March 24, 2015
May 5, 2015	$0.15	May 26, 2015	June 16, 2015
August 2, 2015	$0.15	August 25, 2015	September 15, 2015

Stock Repurchase Program

Our Board of Directors has authorized common stock repurchases in the aggregate amount of $125.0 million. Any repurchases 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 upon prevailing market prices, general economic and market conditions and other considerations. The stock repurchase authorization does not obligate us to acquire any particular amount of stock and any unused portion of the authorization will expire on December

31, 2015. During both the three and nine months ended September 30, 2015, 959,753 shares of our common stock were repurchased, for a total of $29.0 million, under the stock repurchase authorization.

9. Equity-Based Compensation

Delek US Holdings, Inc. 2006 Long-Term Incentive Plan

Compensation expense for Delek equity-based awards amounted to $3.6 million ($2.3 million, net of taxes) and $10.7 million ($7.0 million, net of taxes) for the three and nine months ended September 30, 2015, respectively, and $3.0 million ($1.9 million, net of taxes) and $8.5 million ($5.5 million, net of taxes) for the three and nine months ended September 30, 2014, respectively. These amounts are included in general and administrative expenses in the accompanying condensed consolidated statements of income.

As of September 30, 2015, there was $30.0 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 2.5 years.

We issued 56,567 and 255,250 shares of common stock as a result of exercised stock options, stock appreciation rights, and vested restricted stock units during the three and nine months ended September 30, 2015, respectively, and 111,488 and 330,624 shares of common stock during the three and nine months ended September 30, 2014, respectively. These amounts do not include shares withheld to satisfy employee tax obligations related to the exercises and vestings. Such withheld shares totaled 38,235 and 240,392 shares during the three and nine months ended September 30, 2015, respectively, and 89,834 and 205,821 shares during the three and nine months ended September 30, 2014, respectively.

Delek Logistics, GP, LLC 2012 Long-Term Incentive Plan

Compensation expense for Delek Logistics GP equity-based awards was $0.4 million ($0.3 million, net of taxes) and $1.5 million ($1.0 million, net of taxes) for the three and nine months ended September 30, 2015, respectively, and $0.4 million ($0.3 million, net of taxes) and $1.2 million ($0.8 million, net of taxes) for the three and nine months ended September 30, 2014, respectively. These amounts are included in general and administrative expenses in the accompanying condensed consolidated statements of income.

As of September 30, 2015, there was $3.5 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 2.2 years.

Granting of GP Interests

On March 10, 2013, we granted membership interests in Logistics GP, the general partner of Delek Logistics, to certain executives, including Ezra Uzi Yemin, our Chairman, President and Chief Executive Officer. These interests consisted of a total 1.4% membership interest in Logistics GP and vested on June 10, 2013. On December 10, 2013, we granted Mr. Yemin an additional 4.0% membership interest in Logistics GP. Half of the 4.0% vested immediately, 0.50% vested on June 10, 2014 and, subject to Mr. Yemin's continued employment with Delek, 0.25% will continue to vest every six months following June 10, 2014 through June 10, 2017. Total compensation expense recognized for these grants was nominal and $0.1 million ($0.1 million, net of taxes) for the three and nine months ended September 30, 2015, respectively, and nominal and $0.3 million ($0.2 million, net of taxes) for the three and nine months ended September 30, 2014. As of September 30, 2015, there was $0.3 million of total unrecognized compensation cost related to non-vested GP membership interests, which is expected to be recognized over a weighted-average period of 1.7 years.

10. Earnings Per Share

Basic and diluted earnings per share are computed by dividing net income by the weighted average common shares outstanding. The common shares used to compute Delek’s basic and diluted earnings per share are as follows:



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2015	2014	2015	2014
Weighted average common shares outstanding	63,189,399	58,744,099	60,366,532	59,090,291
Dilutive effect of equity instruments	468,987	558,689	527,674	583,308
Weighted average common shares outstanding, assuming dilution	63,658,386	59,302,788	60,894,206	59,673,599

Outstanding common share equivalents totaling 2,240,684 and 2,157,852 were excluded from the diluted earnings per share calculation for the three and nine months ended September 30, 2015, respectively, compared to 1,476,368 and 1,815,193 excluded the three and nine months ended September 30, 2014, as these common share equivalents did not have a dilutive effect under the treasury stock method.

11. Segment Data

We report our operating results in three reportable segments: refining, logistics and retail. Decisions concerning the allocation of resources and assessment of operating performance are made based on this segmentation. Management measures the operating performance of each reportable segment based on the segment contribution margin.

In conjunction with the El Dorado Offloading Racks Acquisition and the Tyler Crude Tank Acquisition, we reclassified the components of certain operating segments. The results of the operations of the assets associated with these acquisitions were previously reported as part of our refining segment and are now reported in our logistics segment. The historical results of the operations of these assets have been reclassified to conform to the current presentation.

Segment contribution margin is defined as net sales less cost of sales and operating expenses, excluding depreciation and amortization. Operations which are not specifically included in the reportable segments are included in the corporate and other category, which primarily consists of operating expenses associated with ancillary company operations and intercompany eliminations.

The refining segment processes crude oil and other purchased feedstocks for the manufacture of transportation motor fuels, including various grades of gasoline, diesel fuel, aviation fuel, asphalt and other petroleum-based products that are distributed through both our own and third-party product terminals and pipelines. The refining segment has a combined nameplate capacity of 155,000 bpd, comprised of 75,000 bpd at the Tyler refinery and 80,000 bpd at the El Dorado refinery. The refining segment also operates two biodiesel facilities.

Our logistics segment owns and operates crude oil and refined products logistics and marketing assets. The logistics segment generates revenue and subsequently contribution margin, which we define as net sales less cost of goods sold and operating expenses, by charging fees for gathering, transporting and storing crude oil and for marketing, distributing, transporting and storing refined products.

Our retail segment markets gasoline, diesel, other refined petroleum products and convenience store merchandise through a network of company-operated retail fuel and convenience stores throughout the southeastern United States. As of September 30, 2015, we had 355 stores in total, consisting of 191 located in Tennessee, 90 in Alabama, 45 in Georgia, 12 in Arkansas, 8 in Virginia, 6 in Kentucky and 3 in Mississippi. The retail fuel and convenience stores operate under our MAPCO Express^®, MAPCO Mart^®, East Coast^®, Fast Food and Fuel^TM, Favorite Markets^®, Delta Express^® and Discount Food Mart^TM brands. The retail segment also supplied fuel to approximately 66 contracted dealer locations as of September 30, 2015. In the retail segment, management reviews operating results on a divisional basis, where a division represents a specific geographic market. These divisional operating segments exhibit similar economic characteristics, generally provide the same products and services, and operate in a manner such that aggregation of these operations is appropriate for segment presentation.

Our refining segment has a services agreement with our logistics segment, which, among other things, requires the refining segment to pay service fees based on the number of gallons sold at the Tyler refinery and a sharing of a portion of the margin achieved in return for providing marketing, sales and customer services. These intercompany transaction fees were $4.4 million and $11.2 million during the three and nine months ended September 30, 2015, respectively, and $3.6 million and $10.7 million during the three and nine months ended September 30, 2014, respectively. Additionally, the refining segment pays transportation

and storage fees to the logistics segment for the utilization of certain crude and finished product pipeline and tank assets. These fees were $31.2 million and $90.7 million during the three and nine months ended September 30, 2015, respectively, and $24.9 million and $70.0 million during the three and nine months ended September 30, 2014, respectively. The logistics segment also sold $1.0 million and $4.9 million of RINs to the refining segment during the three and nine months ended September 30, 2015, respectively and $1.3 million and $3.3 million during the three and nine months ended September 30, 2014, respectively. The refining segment sold finished product and services to the retail and logistics segments in the amount of $180.7 million and $495.9 million during the three and nine months ended September 30, 2015, respectively, and $183.8 million and $478.4 million during the three and nine months ended September 30, 2014, respectively. All intersegment transactions have been eliminated in consolidation.

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, 2015
	Refining		Logistics		Retail		Corporate, Other and Eliminations			Consolidated
Net sales (excluding intercompany fees and sales)	$	1,027.3	$	128.5	$	396.9	$	1.5		$	1,554.2
Intercompany fees and sales	180.7		36.6		—		(217.3		)	—
Operating costs and expenses:
Cost of goods sold	1,100.7		124.4		339.5		(209.0		)	1,355.6
Operating expenses	59.9		11.6		35.5		(0.4		)	106.6
Segment contribution margin	$	47.4	$	29.1	$	21.9	$	(6.4	)	92.0
General and administrative expenses										34.1
Depreciation and amortization										34.2
Other operating income										(0.1		)
Operating income										$	23.8
Total assets	$	1,965.2	$	361.8	$	440.5	$	666.0		$	3,433.5
Capital spending (excluding business combinations)	$	23.6	$	4.1	$	4.8	$	2.7		$	35.2



	Three Months Ended September 30, 2014
	Refining		Logistics		Retail		Corporate, Other and Eliminations			Consolidated
Net sales (excluding intercompany fees and sales)	$	1,618.4	$	198.2	$	505.1	$	0.5		$	2,322.2
Intercompany fees and sales	183.8		29.8		—		(213.6		)	—
Operating costs and expenses:
Cost of goods sold	1,598.5		194.1		452.3		(209.7		)	2,035.2
Operating expenses	52.4		10.4		36.4		1.7			100.9
Segment contribution margin	$	151.3	$	23.5	$	16.4	$	(5.1	)	186.1
General and administrative expenses										36.0
Depreciation and amortization										29.2
Operating income										$	120.9
Total assets	$	2,065.5	$	316.2	$	462.2	$	213.7		$	3,057.6
Capital spending (excluding business combinations)	$	30.1	$	0.7	$	6.9	$	2.2		$	39.9



	Nine Months Ended September 30, 2015
	Refining		Logistics		Retail		Corporate, Other and Eliminations			Consolidated
Net sales (excluding intercompany fees and sales)	$	2,875.9	$	373.8	$	1,144.8	$	3.4		$	4,397.9
Intercompany fees and sales	495.9		106.9		—		(602.8		)	—
Operating costs and expenses:
Cost of goods sold	3,022.4		365.3		992.7		(580.5		)	3,799.9
Operating expenses	168.1		33.2		103.6		(0.9		)	304.0
Segment contribution margin	$	181.3	$	82.2	$	48.5	$	(18.0	)	294.0
General and administrative expenses										101.1
Depreciation and amortization										97.4
Other operating income										$	(0.2	)
Operating income										$	95.7
Capital spending (excluding business combinations)	$	146.8	$	13.9	$	8.3	$	4.6		$	173.6



	Nine Months Ended September 30, 2014
	Refining		Logistics		Retail		Corporate, Other and Eliminations			Consolidated
Net sales (excluding intercompany fees and sales)	$	4,533.2	$	583.9	$	1,445.3	$	0.2		$	6,562.6
Intercompany fees and sales	478.4		84.0		—		(562.4		)	—
Operating costs and expenses:
Cost of goods sold	4,468.2		562.9		1,302.9		(547.2		)	5,786.8
Operating expenses	168.7		29.6		103.4		(0.1		)	301.6
Segment contribution margin	$	374.7	$	75.4	$	39.0	$	(14.9	)	474.2
General and administrative expenses										97.6
Depreciation and amortization										82.0
Operating income										$	294.6
Capital spending (excluding business combinations)	$	155.1	$	5.0	$	20.0	$	13.2		$	193.3

Property, plant and equipment and accumulated depreciation as of September 30, 2015 and depreciation expense by reporting segment for the three and nine months ended September 30, 2015 are as follows (in millions):



	Refining			Logistics			Retail			Corporate, Other and Eliminations			Consolidated
Property, plant and equipment	$	1,170.7		$	321.4		$	524.1		$	49.6		$	2,065.8
Less: Accumulated depreciation	(261.1		)	(66.2		)	(211.0		)	(12.5		)	(550.8		)
Property, plant and equipment, net	$	909.6		$	255.2		$	313.1		$	37.1		$	1,515.0
Depreciation expense for the three months ended September 30, 2015	$	21.5		$	4.3		$	6.9		$	1.2		$	33.9
Depreciation expense for the nine months ended September 30, 2015	$	58.4		$	13.0		$	21.7		$	3.3		$	96.4

In accordance with ASC 360, Property, Plant & Equipment, Delek evaluates the realizability of property, plant and equipment as events occur that might indicate potential impairment.

12. Fair Value Measurements

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, Financial Instruments.

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 applies to our interest rate and commodity derivatives that are measured at fair value on a recurring basis. The standard also requires that we assess the impact of nonperformance risk on our derivatives. Nonperformance risk is not considered material at this time.

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 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.

Over the counter ("OTC") commodity swaps, physical commodity purchase and sale contracts and interest rate swaps and caps 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 using quotations provided by brokers based on exchange pricing and/or price index developers such as Platts or Argus and are, therefore, classified as Level 2.

The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis at September 30, 2015 and December 31, 2014, was as follows (in millions):



	As of September 30, 2015
	Level 1		Level 2			Level 3		Total
Assets
OTC commodity swaps	$	—	$	190.8		$	—	$	190.8
Liabilities
OTC commodity swaps	—		(208.6		)	—		(208.6		)
Net liabilities	$	—	$	(17.8	)	$	—	$	(17.8	)



	As of December 31, 2014
	Level 1		Level 2			Level 3		Total
Assets
OTC commodity swaps	$	—	$	389.6		$	—	$	389.6
Liabilities
OTC commodity swaps	—		(353.3		)	—		(353.3		)
Interest rate derivatives	—		(0.9		)	—		(0.9		)
Total liabilities	—		(354.2		)	—		(354.2		)
Net assets	$	—	$	35.4		$	—	$	35.4

The derivative values above are based on analysis of each contract as the fundamental unit of account as required by ASC 820. 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 under the guidance of ASC 815-10-45, 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, 2015 and December 31, 2014, $11.4 million and $11.1 million, respectively, of cash collateral was held by counterparty brokerage firms and has been netted with the derivative positions with each counterparty.

13. Derivative Instruments

We use 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 derivatives 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; and


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

We primarily utilize OTC commodity swaps, generally with maturity dates of three years or less, and interest rate swap and cap agreements to achieve these objectives. OTC commodity swap 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. Interest rate swap and cap agreements economically hedge floating rate debt by exchanging interest rate cash flows, based on a notional amount from a floating rate to a fixed rate. At this time, we do not believe there is any material credit risk with respect to the counterparties to these contracts.

In accordance with ASC 815, certain of our OTC commodity swap contracts have been designated as cash flow hedges and the change in fair value between the execution date and the end of period has been recorded in other comprehensive income. The fair value of these contracts is recognized in income at the time the positions are closed and the hedged transactions are recognized in income.

From time to time, we also enter into futures contracts with supply vendors that secure supply of product to be purchased for use in the normal course of business at our refining and retail segments. These contracts are priced based on an index that is clearly and closely related to the product being purchased, contain no net settlement provisions and typically qualify under the normal purchase exemption from derivative accounting treatment under ASC 815.

The following table presents the fair value of our derivative instruments, as of September 30, 2015 and December 31, 2014. 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 will differ from the amounts presented in our condensed consolidated balance sheets (in millions):



		September 30, 2015					December 31, 2014
Derivative Type	Balance Sheet Location	Assets		Liabilities			Assets		Liabilities
Derivatives not designated as hedging instruments:
OTC commodity swaps⁽¹⁾	Other current assets	$	113.6	$	(67.5	)	$	190.3	$	(163.3	)
OTC commodity swaps⁽¹⁾	Other current liabilities	22.7		(32.2		)	20.1		(37.8		)
OTC commodity swaps⁽¹⁾	Other long term assets	—		—			21.5		(14.3		)
OTC commodity swaps⁽¹⁾	Other long term liabilities	3.9		(0.3		)	32.8		(2.7		)
Interest rate derivatives	Other current assets	—		—			—		(0.6		)
Interest rate derivatives	Other current liabilities	—		—			—		(0.3		)

Derivatives designated as hedging instruments:
OTC commodity swaps⁽¹⁾	Other current assets	36.3		(53.4		)	97.1		(76.1		)
OTC commodity swaps⁽¹⁾	Other current liabilities	14.3		(11.7		)	9.4		(7.1		)
OTC commodity swaps⁽¹⁾	Other long term liabilities	—		(43.5		)	18.4		(52.0		)
Total gross fair value of derivatives		$	190.8	$	(208.6	)	$	389.6	$	(354.2	)
Less: Counterparty netting and cash collateral⁽²⁾		150.5		(161.9		)	333.0		(344.1		)
Less: Amounts subject to master netting arrangements that are not netted on the balance sheet		8.4		(8.4		)	3.2		(3.2		)
Total net fair value of derivatives		$	31.9	$	(38.3	)	$	53.4	$	(6.9	)


⁽¹⁾	As of September 30, 2015 and December 31, 2014, we had open derivative contracts representing 6,884,200 barrels and 11,169,150 barrels, respectively, of crude oil and refined petroleum products. Of these open contracts, contracts representing 4,196,700 barrels and 4,512,400 barrels were designated as hedging instruments as of September 30, 2015 and December 31, 2014, respectively.

⁽²⁾

As of September 30, 2015 and December 31, 2014, $11.4 million and $11.1 million, respectively, of cash collateral has been netted with the derivative positions with each counterparty. As of December 31, 2014, cash collateral included $2.0 million associated with our interest rate derivatives. There was no cash collateral associated with our interest rate derivative instruments as of September 30, 2015.

Total (losses) gains on our commodity derivatives recorded in cost of goods sold on the condensed consolidated statements of income for the three and nine months ended September 30, 2015 and 2014 are as follows (in millions):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Gains on derivatives not designated as hedging instruments	$	11.4		$	44.5		$	11.0		$	73.3
Realized (losses) gains reclassified out of OCI on derivatives designated as cash flow hedging instruments	(0.6		)	(5.9		)	1.7			(8.0		)
(Losses) gains recognized due to cash flow hedging ineffectiveness	(12.4		)	(8.9		)	(21.3		)	5.4
Total	$	(1.6	)	$	29.7		$	(8.6	)	$	70.7

We also recorded expense representing cash settlements and changes in estimated fair value of our interest rate derivative agreements of a nominal amount and $0.2 million for the three and nine months ended September 30, 2015, respectively, and a nominal amount and $0.4 million for the three and nine months ended September 30, 2014, respectively. These amounts are included in interest expense in the accompanying consolidated statements of income.

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, 2015 or 2014. As of September 30, 2015 and December 31, 2014, losses of $26.9 million and $12.3 million, respectively, on cash flow hedges, net of tax, primarily related to future purchases of crude oil and the associated sale of finished grade fuel, remained in accumulated other comprehensive income. We estimate that $10.3 million of deferred losses will be reclassified into cost of sales over the next 12 months as a result of hedged transactions that are forecasted to occur. (Losses) gains of $(0.4) million and $1.1 million, net of tax, on settled contracts were reclassified into cost of sales during the three and nine months ended September 30, 2015. Losses of $3.9 million and $5.2 million, net of tax, on settled contracts were reclassified into cost of sales during the three and nine months ended September 30, 2014. There were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuation of cash flow hedge accounting for the three or nine months ended September 30, 2015 or September 30, 2014.

14. 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 proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.

Self-insurance

Delek is self-insured for workers’ compensation claims up to $1.0 million on a per-accident basis. We self-insure for general liability claims, inclusive of sudden and accidental pollution claims, up to $4.0 million on a per-occurrence basis. We self-insure for auto liability up to $4.0 million on a per-accident basis.

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

Rate Regulation of Petroleum Pipelines

The rates and terms and conditions of service on certain of our pipelines may be subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Interstate Commerce Act ("ICA") or by the state regulatory commissions in the states in which we transport crude oil and refined products, including the Railroad Commission of Texas, the Louisiana Public Service Commission, and the Arkansas Public Service Commission. Certain of our pipeline systems are subject to such regulation and have filed tariffs with the appropriate entities. We also comply with the reporting requirements for these pipelines. Other of our pipelines have received a waiver from application of FERC's tariff requirements but will comply with other applicable regulatory requirements.

FERC regulates interstate transportation under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including pipelines that transport crude oil and refined products in interstate commerce (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Under the ICA, shippers may challenge new or existing rates or services. FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period.

While FERC regulates rates for shipments of crude oil or refined products in interstate commerce, state agencies may regulate rates and service for shipments in intrastate commerce. We own pipeline assets in Texas, Arkansas and Louisiana.

Environmental, Health and Safety

We are subject to extensive federal, state and local environmental and safety laws and regulations enforced by agencies, including the United States Environmental Protection Agency (the "EPA"), the United States Department of Transportation, the Occupational Safety and Health Administration, the Texas Commission on Environmental Quality, the Railroad Commission of Texas, the Arkansas Department of Environmental Quality and the Tennessee Department of Environment and Conservation as well as other state and federal 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 for the operation of our refineries, biodiesel facilities, terminals, pipelines, underground storage tanks ("USTs"), 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 Comprehensive Environmental Response, Compensation and Liability Act, also known as Superfund, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Analogous state laws impose similar responsibilities and liabilities on responsible parties. In the course of our ordinary operations, our various businesses generate waste, some of which falls within the statutory definition of a hazardous substance and some of which may have been disposed of at sites that may require future cleanup under Superfund. At this time, our El Dorado refinery has been named as a minor potentially responsible party at one site for which we believe future costs will not be material.

As of September 30, 2015, we have recorded an environmental liability of approximately $9.0 million, primarily related to the probable estimated costs of remediating or otherwise addressing certain environmental issues of a non-capital nature at the Tyler and El Dorado refineries. This liability includes estimated costs for ongoing investigation and remediation efforts, which were already being performed by the former operators of the Tyler and El Dorado refineries prior to our acquisition of those facilities, for known contamination of soil and groundwater, as well as estimated costs for additional issues which have been identified subsequent to the acquisitions. We expect approximately $0.4 million of this amount to be reimbursable by a prior owner of the El Dorado refinery and have recorded $0.2 million in other current assets and $0.2 million in other non-current assets in our condensed consolidated balance sheet as of September 30, 2015. Approximately $0.9 million of the total liability is expected to be expended over the next 12 months with most of the balance expended by 2022. In the future, we could be required to extend the expected remediation period or undertake additional investigations of our refineries, pipelines and terminal facilities or convenience stores, which could result in additional remediation liabilities.

Most of the cost of remediating releases from USTs in our retail segment is reimbursed by state reimbursement funds which are funded by a tax on petroleum products and subject to certain deductible amounts. As of September 30, 2015, our accrual for such UST-related remediation was less than $0.1 million.

The EPA issued final rules for gasoline formulation that required the reduction of average benzene content by January 1, 2011 and the reduction of maximum annual average benzene content by July 1, 2012. It is necessary for us to purchase credits to fully comply with these content requirements for the Tyler refinery. Although credits have been acquired that we believe will be sufficient to cover our obligations through 2016, there can be no assurance that such credits will be available in the future or that we will be able to purchase available credits at reasonable prices. Additional benzene reduction projects may be implemented to reduce or eliminate our need to purchase benzene credits depending on the availability and cost of such credits.

In recent years, various legislative and regulatory measures to address climate change and greenhouse gas ("GHG") emissions (including carbon dioxide, methane and nitrous oxides) have been discussed or implemented. They include proposed and enacted federal regulation and state actions to develop statewide, regional or nationwide programs designed to control and reduce GHG emissions from fixed sources, such as our refineries, as well as power plants, mobile transportation sources and fuels. We are not aware of any state or regional initiatives for controlling existing GHG emissions that would affect our refineries. Although it is not possible to predict the requirements of any GHG legislation that may be enacted, any laws or regulations that may be adopted

to restrict or reduce GHG emissions will likely require us to incur increased operating and capital costs. In August 2015, the EPA finalized the “Clean Power Plan” requiring states to reduce carbon dioxide emissions from coal fired power plants through a combination of plant closures, switching to renewable energy and natural gas, and demand reduction. This rule will not directly affect our operations but it could result in increased power costs for our refineries in future years. The EPA has indicated that it intends to regulate refinery GHG emissions from new and existing sources through a New Source Performance Standard ("NSPS"), although there is no firm proposal or date for such regulation and the EPA has said that such a performance standard is not imminent.

Since the 2010 calendar year, EPA rules require us to report GHG emissions from our refinery operations and consumer use of fuel products produced at our refineries on an annual basis. While the cost of compliance with the reporting rule is not material, data gathered under the rule may be used in the future to support additional regulation of GHG. Effective January 2011, the EPA began regulating GHG emissions from refineries and other major sources through the Prevention of Significant Deterioration ("PSD") and Federal Operating Permit ("Title V") programs. In June 2014, the United States Supreme Court ruled that the EPA may not require PSD and Title V permits solely because of GHG emissions, but may require Best Available Control Technology (“BACT”) for GHG emissions above a certain threshold if emissions of other pollutants would otherwise require PSD permitting. While this decision does not impose any limits or controls on GHG emissions from current operations, GHG emission increases from future projects or operational changes, such as capacity increases, may be impacted and required to meet emission limits or technological requirements such as BACT. We do not believe this decision will materially affect our operations. Other litigation challenging the EPA’s authority to regulate GHG emissions is pending in federal court.

In mid-2012, the EPA announced an industry-wide enforcement initiative directed at flaring operations and performance at refineries and petrochemical plants. In September 2012, the EPA finalized revisions to the NSPS for Petroleum Refineries ("NSPS Subpart Ja") that primarily affects flares and process heaters. We believe our existing process heaters meet the applicable requirements and our refineries have not received any associated inquiries or requests for information, nor are they a party to any associated enforcement action at this time. The NSPS will impact the way some flares at our Tyler and El Dorado refineries are designed and/or operated. Affected flares have three years to comply with the new standard. We implemented capital projects at our Tyler refinery related to flare compliance during the 2015 turnaround and additional projects will be implemented later in 2015 and 2016.

In September 2015, the EPA finalized rules under the Risk and Technology Review provisions of the Clean Air Act to further regulate refinery air emissions through additional NSPS and Maximum Achievable Control Technology requirements. The final rules will require capital expenditures for additional controls on the Tyler refinery’s coker and for the relief systems, flares, tanks and other sources at both refineries, as well as requiring changes to the way we operate or start up some process units. The final rule also requires that we monitor property line benzene concentrations and provide the results to the EPA quarterly, which will make the results available to the public. We have two to three years to comply with most of the requirements. We do not anticipate that the required capital and operating costs will be material and do not believe compliance will affect our production capacities or have a material adverse effect upon our business, financial condition or results of operations.

The Energy Independence and Security Act of 2007 ("EISA") increased the amounts of renewable fuel required to be blended into domestic transportation fuel supplies by the Energy Policy Act of 2005 to 32 billion gallons by 2022. The Renewable Fuel Standard - 2 ("RFS-2") rule finalized by the EPA in 2010 to implement EISA, requires that most refiners blend increasing amounts of biofuels with refined products through 2022. Because EISA requires specified volumes of biofuels, if the demand for motor fuels decreases in future years, even higher percentages of biofuels may be required. Alternatively, credits called Renewable Identification Numbers ("RINs") can be used instead of physically blending biofuels. In 2013, we internally generated, through our logistics, retail and refining segments, most of the RINs required to meet the obligations of our refineries, including a carryover of 2012 RINs, with a net surplus of biodiesel RINs that were available to be sold to purchase RINs in other categories. The cost of purchased biofuel credits is charged to cost of sales as such credits are needed to satisfy our obligation. To the extent we have not purchased enough biofuel credits to satisfy our obligation as of the balance sheet date, we charge cost of sales for such deficiency based on the market price of the biofuel credits as of the balance sheet date, and we record a liability for our obligation to purchase those credits.

In November 2013, the EPA proposed slightly lower overall renewable fuel obligations for 2014 in recognition of blending issues associated with exceeding the 10% "blendwall" (the point at which gasoline contains 10% ethanol - the maximum amount allowed by most vehicle warranties) in gasoline; however the EPA did not finalize the proposed 2014 obligations. In May 2015, the EPA re-proposed the 2014 obligation as well as the obligation for 2015 and 2016. The new proposal for 2014 increases the total nationwide volume of renewable fuels by 4.7% (compared to the 2013 proposal); however, the requirement expressed as a percentage of our gasoline and diesel volume is slightly less because of increased fuel demand. Proposed nationwide volumes for 2015 and 2016 would increase about 2% and 9% respectively compared with the newly proposed 2014 volume. Proposed 2016 ethanol volumes would exceed the 10% “blendwall,” requiring substantial increased usage of higher ethanol blends such as E15 and E85. EPA has indicated their intention to finalize the required 2014-2016 volumes by November 2015.

Under the new proposed rule, by 2016 our ethanol volume requirement would increase 3% and the biodiesel requirement would increase 5%. If the required volumes are finalized as proposed, we have sufficient RINs to meet our 2014 obligation and believe we will internally generate almost all of the RINs required to meet our refineries' 2015 obligation. It is possible however, that in 2016 we will be unable to blend sufficient quantities of ethanol and biodiesel to meet our requirements and will have to purchase an increasing number of RINs. It is not possible at this time to predict with certainty what those volumes or costs may be but given the potential increase in volumes and the volatile price of RINs, the proposed increase in renewable volume requirements for 2016 could have an adverse impact on our results of operations.

The EPA finalized Tier 3 gasoline rules in March 2014. The final Tier 3 rule requires a reduction in annual average gasoline sulfur content from 30 ppm to 10 ppm and retains the current maximum per-gallon sulfur content of 80 ppm. Larger refineries must comply with the 10 ppm sulfur standard by January 1, 2017 but the final rule provides a three-year waiver period, to January 1, 2020, for small volume refineries that processed less than 75,000 bpd in 2012. Both of our refineries meet this waiver provision. We anticipate that the Tyler refinery will meet these new limits when they become effective with only minor operational changes and that a minor capital project may be required for additional sulfur removal capacity at the El Dorado refinery. In February 2015, EPA issued a Direct Final Rule ("DFR") to address technical corrections to the Tier 3 standard requiring small volume refineries that increase their annual average crude processing rate above 75,000 bpd to meet the Tier 3 sulfur limits 30 months from that “disqualifying” date. Because adverse comments were received on this change, EPA withdrew the DFR but subsequently re-proposed the same revision. It is not known when or if EPA will finalize the proposed change. Our El Dorado refinery may average more than 75,000 bpd in 2015, accelerating its Tier 3 compliance date to as early as mid-2018 if the EPA finalizes the rule change. However, we believe that our current refineries will generate sufficient sulfur credits to delay the need to produce 10 ppm gasoline at El Dorado into 2019.

Following the November 2008 explosion and fire at the Tyler refinery, the EPA conducted an investigation under Section 114 of the Clean Air Act pertaining to our compliance with the chemical accident prevention standards. In late 2011, the EPA referred an enforcement action to the U.S. Department of Justice and in the fourth quarter of 2014, we settled this matter by entering into a Consent Decree with the government. The Consent Decree required Delek to pay a penalty of $0.5 million and make a minor change to its written inspection procedures. The Consent Decree terminated upon completion of these requirements and had no effect on production at the refinery and no cost implications other than the penalty amount.

We have detected several crude oil releases from pipelines owned by our logistics segment, including a release at Magnolia Station in March 2013, a release near Macedonia, Arkansas in October 2013, a release in Haynesville, Louisiana in April 2014 and a release near Fouke, Arkansas in April 2015. In June 2015, the United States Department of Justice notified Delek Logistics that they were evaluating an enforcement action on behalf of the EPA with regard to potential Clean Water Act violations arising from the March 2013 Magnolia release; however, no specific claim for penalties or affirmative relief has been made at this time. Based on current information available to us, we do not believe the total costs associated with these events, whether alone or in the aggregate, including any fines or penalties and net of partial insurance reimbursement, will have a material adverse effect upon our business, financial condition or results of operations. As of September 30, 2015, we have accrued $3.3 million in expenses associated with the release in Fouke, Arkansas.

Vendor Commitments

We maintain an agreement with a significant vendor that requires our retail segment to purchase certain general merchandise exclusively from this vendor over a specified period of time. Additionally, we maintain agreements with certain fuel suppliers that contain terms which generally require our retail segment to purchase predetermined quantities of third-party branded fuel for a specified period of time. In certain fuel vendor contracts, penalty provisions exist if our retail segment does not purchase certain minimum quantities of fuel.

Letters of Credit

As of September 30, 2015, we had in place letters of credit totaling approximately $99.0 million with various financial institutions securing obligations primarily with respect to our crude oil purchases for the refining segment, our gasoline and diesel purchases for the logistics segment and our workers’ compensation and general liability self-insurance programs. No amounts were drawn by beneficiaries of these letters of credit at September 30, 2015.

15. Subsequent Events

Dividend Declaration

On November 3, 2015, our Board of Directors voted to declare a quarterly cash dividend of $0.15 per share, payable on December 15, 2015 to shareholders of record on November 24, 2015.

Alon Israel Note Prepayment

On October 22, 2015, we made a payment of approximately $25.5 million on the Alon Israel Note, which represented a prepayment of $25.0 million in principal and a payment of approximately $0.5 million in adjusted, accrued and unpaid interest on the prepaid principal. As a result of this payment, our sole payment obligation due and owing on January 4, 2016 will be the accrued and unpaid interest on the outstanding balance following this payment. See “Promissory Notes” under Note 6 for additional information regarding the Alon Israel Note.

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 filed with the Securities and Exchange Commission ("SEC") on February 26, 2015 (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. Unless the context otherwise requires, references to "Delek," "the Company," and "we," "our," or "us," and like terms refer to Delek US Holdings, Inc. and its consolidated subsidiaries.

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 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (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 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, the benefits and synergies to be obtained from our completed and any future acquisitions, and 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:


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


•	our ability to execute our strategy of growth through acquisitions and the transactional risks inherent in such acquisitions;


•	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;


•	competition;


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


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


•	the effect on our financial results by the financial results of Alon USA, in which we hold a significant equity investment but the management and policies of which we do not control;


•	general economic and business conditions, particularly levels of spending relating to travel and tourism or conditions affecting the southeastern United States;


•	dependence on one wholesaler for a significant portion of our convenience store merchandise;


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


•	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;


•	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 aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;


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


•	volatility of derivative instruments; 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 results or future period trends. There can be no assurances that any of the events anticipated by the forward-looking statements will occur or, if any such events do occur, what impact they will have on our results of operations and financial condition.

Forward-looking statements speak only as of the date the statements are made. We assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking information except to the extent required by applicable securities laws. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect thereto or with respect to other forward-looking statements.

Overview

We are an integrated downstream energy business focused on petroleum refining, the wholesale distribution of refined products and convenience store retailing. Our business consists of three operating segments: (1) refining, (2) logistics, and (3) retail. Our refining segment operates independent refineries in Tyler, Texas (the "Tyler refinery") and El Dorado, Arkansas (the "El Dorado refinery") with a combined design crude distillation capacity of 155,000 barrels per day ("bpd"). 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 both our refining segment and third parties. Our retail segment markets gasoline, diesel, other refined petroleum products and convenience merchandise through a network of 355 company-operated retail fuel and convenience stores located in Tennessee, Alabama, Georgia, Arkansas, Virginia, Kentucky and Mississippi.

We currently own a 59.8% limited partner interest in Delek Logistics Partners, LP ("Delek Logistics") and a 95.6% interest in the entity that owns the entire 2.0% general partner interest in Delek Logistics and all of the income 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. Delek Logistics' initial assets were contributed by us and included certain assets formerly owned or used by certain of our subsidiaries. A substantial majority of Delek Logistics' assets are currently integral to our refining and marketing operations.

In conjunction with the acquisition by a subsidiary of Delek Logistics of two crude oil offloading racks and related ancillary assets adjacent to the El Dorado refinery (the "El Dorado Offloading Racks Acquisition") and the acquisition of a crude oil storage tank and related ancillary assets adjacent to the Tyler refinery (the "Tyler Crude Tank Acquisition"), we reclassified the components of certain operating segments. The results of the operations of the assets associated with these acquisitions were previously reported as part of our refining segment and are now reported in our logistics segment. The historical results of the operations of these assets have been reclassified to conform to the current presentation.

Our profitability in the refining segment is substantially determined by the spread between the prices of refined products we sell from our refineries and the prices of crude oil we acquire to produce them, referred to as the "refining margin." The cost to acquire crude oil and the prices of refined petroleum products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline, asphalt 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 the cost of crude, our primary feedstock, operating costs, particularly the cost of natural gas used for fuel and the cost of electricity, seasonal factors, utilization rates and planned or unplanned maintenance activities or turnarounds. Moreover, while increases in the cost of crude oil are often reflected in the prices of light refined products, the value of heavier products, such as asphalt, coke, carbon black oil, and liquefied petroleum gas ("LPG"), are typically less likely to move in parallel with crude cost. This may cause additional pressure on our realized margin.

For our Tyler refinery, we compare our per barrel refining margin to a well established industry metric: the U.S. Gulf Coast 5-3-2 crack spread ("Gulf Coast crack spread"). The Gulf Coast crack spread is used as a benchmark against which to measure a refining margin and represents the approximate gross margin resulting from processing one barrel of crude oil into three-fifths of a barrel of gasoline and two-fifths of a barrel of high sulfur diesel. We calculate the Gulf Coast crack spread using the market value of U.S. Gulf Coast Pipeline 87 Octane Conventional Gasoline and U.S. Gulf Coast Pipeline No. 2 Heating Oil (high sulfur diesel) and the first month futures price of light sweet crude oil on the New York Mercantile Exchange ("NYMEX"). U.S. Gulf Coast Pipeline 87 Octane Conventional Gasoline is a grade of gasoline commonly marketed as Regular Unleaded at retail locations. U.S. Gulf Coast Pipeline No. 2 Heating Oil is a petroleum distillate that can be used as either a diesel fuel or a fuel oil. This is the standard by which other distillate products (such as ultra low sulfur diesel) are priced. The NYMEX is the commodities trading exchange where contracts for the future delivery of petroleum products are bought and sold.

As of the date of this Quarterly Report on Form 10-Q, we do not believe a reliable benchmark exists for the El Dorado refinery due to fluctuations in the quantities and varieties of crude oil processed and products manufactured at the El Dorado refinery and because asphalt products do not typically trade in line with other refined products. As a result, past results may not be indicative of future performance.

The cost to acquire the refined fuel products we sell to our wholesale customers in our logistics segment and to retail customers 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, 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 equal to 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, customer demand, weather, competitor pricing and product brand.

As part of our overall business strategy, we regularly evaluate opportunities to expand and complement our business 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.

Recent Developments

Return to Shareholders

Dividends

On September 15, 2015, we paid a regular dividend of $0.15 per share of our common stock, declared on August 2, 2015 to shareholders of record on August 25, 2015. On November 3, 2015, our Board of Directors voted to declare a quarterly cash dividend of $0.15 per share, payable on December 15, 2015 to shareholders of record on November 24, 2015.

Share Repurchase Program

In 2015, the Board of Directors authorized a share repurchase program for up to $125.0 million of our 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 the authorization under the repurchase program will expire on December 31, 2015. During both the three and nine months ended September 30, 2015, 959,753 shares of our common stock were repurchased, for a total of $29.0 million, under the stock repurchase authorization.

Market Trends

Our results of operations are significantly affected by the cost of the commodities that we purchase, process, produce and sell. Sudden change in petroleum-based commodity prices is our primary source of market risk. Historically, our profitability has been affected by the volatility of commodity prices, including crude oil and refined products.

We continue to experience volatility in the energy markets. The price of WTI crude oil ranged from a high of $61.43 per barrel to a low of $38.24 per barrel during the first nine months of 2015 and averaged $51.10 and $99.65 per barrel in the first nine months of 2015 and 2014, respectively. The Gulf Coast crack spread ranged from a high of $24.91 per barrel to a low of $3.93 per barrel and averaged $16.67 per barrel during the first nine months of 2015, compared to an average of $15.72 in the same period of 2014.

Our Tyler and El Dorado refineries both continued to have access to WTI and WTI-linked crude feedstocks during the first nine months of 2015. However, as new pipelines have increased others' access to price-advantaged crude oil supplies in the mid-continent region, we have experienced a decline in certain crude oil price differentials. We believe that infrastructure development will continue into the foreseeable future, but the pace of development is partly determined by fluctuations in the price of crude oil. Crude oil price changes impact drilling activity, which impacts the demand for the infrastructure needed to support crude oil supply capabilities. The price of WTI crude oil declined to an average discount of $5.54 per barrel when compared to Brent crude oil during the first nine months of 2015, compared to a discount of $7.37 per barrel in the same period of 2014. The WTI Midland crude oil discount to WTI Cushing crude oil averaged $0.62 per barrel in the first nine months of 2015, compared to an average of $7.24 in the same period of 2014. As these price differentials decrease, so does our competitive advantage inherent in our access to WTI-linked crude oils.

Environmental regulations continue to affect our margins in the form of the increasing cost of Renewable Identification Numbers ("RINs"). On a consolidated basis, we work to balance our RINs obligations in order to minimize the effect of RINs on our results. We generate RINs in all three operating segments through ethanol and biodiesel blending. However, our refining segment may need to purchase increasing volumes of RINs from outside the company to satisfy its obligations. For example, under the EPA's new proposed ethanol volume requirements for 2014-2016, by 2016 our ethanol volume requirement would increase 3% and the biodiesel requirement would increase 5%. If the required volumes are finalized as proposed, we have sufficient RINs to meet our 2014 obligation and believe we will internally generate almost all of the RINs required to meet our refineries' 2015 obligation. It is possible however, that in 2016 we will be unable to blend sufficient quantities of ethanol and biodiesel to meet our requirements and will have to purchase an increasing number of RINs. As a result, increases in the price of RINs can adversely affect our results of operations. The cost of ethanol RINs has fluctuated from an average of $0.50 in the third quarter of 2014 to an average of $0.39 in the third quarter of 2015. The cost of biodiesel RINs has fluctuated from an average of $0.80 in the third quarter of 2014 to an average of $0.82 in the third quarter of 2015.

As part of our overall business strategy, management determines the cost to store crude oil, the pricing of products and whether we should maintain, increase or decrease inventory levels of crude oil or other intermediate feedstocks based on various factors, including the crude pricing market in the U.S. Gulf Coast region, the refined products market in the same region, the relationship between these two markets, our ability to obtain credit with crude oil vendors, and any other factors which may impact the costs of crude oil. During the first nine months of 2015, crude oil and refined product inventories remained at consistent levels as compared to the end of 2014, with inventory levels targeted at maintaining minimum volumes necessary to satisfy customer demand and line space requirements.

Seasonality

Demand for gasoline, convenience merchandise and asphalt products is generally lower during the winter months due to seasonal decreases in motor vehicle traffic and road and home construction. Additionally, varying vapor pressure requirements between the summer and winter months tighten summer gasoline supply. As a result, our operating results are generally lower during the first and fourth quarters of the year.

Contractual Obligations

There have been no material changes to our contractual obligations and commercial commitments during the nine months ended September 30, 2015, 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, complex or subjective judgments or estimates. Based on this definition and as further described in our Annual Report on Form 10-K, we believe our critical accounting policies include the following: (i) determining our inventory using the last-in, first-out valuation method, (ii) evaluating impairment for property, plant and equipment and definite life intangibles, (iii) valuing goodwill and potential impairment, and (iv) estimating environmental expenditures. 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.

Summary Financial and Other Information

The following table provides summary financial data for Delek:



	Three Months Ended						Nine Months Ended
Statement of Operations Data	September 30,						September 30,
	2015			2014			2015			2014
	(In millions, except share and per share data)
Net sales	$	1,554.2		$	2,322.2		4,397.9			6,562.6
Operating costs and expenses:
Cost of goods sold	1,355.6			2,035.2			3,799.9			5,786.8
Operating expenses	106.6			100.9			304.0			301.6
General and administrative expenses	34.1			36.0			101.1			97.6
Depreciation and amortization	34.2			29.2			97.4			82.0
Other operating income	(0.1		)	—			(0.2		)	—
Total operating costs and expenses	1,530.4			2,201.3			4,302.2			6,268.0
Operating income	23.8			120.9			95.7			294.6
Interest expense	15.7			10.0			43.1			29.7
Interest income	(0.3		)	—			(0.9		)	(0.4		)
Income from equity method investments	(16.5		)	—			(23.9		)	—
Other income, net	—			(0.1		)	(1.0		)	(0.1		)
Total non-operating (income) expenses, net	(1.1		)	9.9			17.3			29.2
Income before income tax (benefit) expense	24.9			111.0			78.4			265.4
Income tax (benefit) expense	(0.5		)	32.8			8.6			84.7
Net income	25.4			78.2			69.8			180.7
Net income attributed to non-controlling interest	6.7			5.7			18.9			19.6
Net income attributable to Delek	$	18.7		$	72.5		$	50.9		$	161.1
Basic earnings per share	$	0.30		$	1.23		$	0.84		$	2.73
Diluted earnings per share	$	0.29		$	1.22		$	0.84		$	2.70

Results of Operations

Consolidated Results of Operations — Comparison of the Three Months Ended September 30, 2015 versus the Three Months Ended September 30, 2014

Consolidated net income for the third quarter of 2015 was $18.7 million, or $0.29 per diluted share, compared to $72.5 million, or $1.22 per diluted share, for the third quarter of 2014.

In the third quarters of 2015 and 2014, we generated net sales of $1,554.2 million and $2,322.2 million, respectively, a decrease of $768.0 million, or 33.1%. The decrease in net sales was primarily due to decreases in the price of finished petroleum products in all three operating segments in the third quarter of 2015, compared to the same period in 2014. The decline in prices was partially offset by an increase in fuel volumes and merchandise sales in the retail segment and an increase in sales volumes at the Tyler refinery, which was a result of the Tyler expansion completed in the first quarter of 2015.

Cost of goods sold was $1,355.6 million for the third quarter of 2015 compared to $2,035.2 million for the third quarter of 2014, a decrease of $679.6 million, or 33.4%. The decrease in cost of goods sold primarily resulted from a decrease in the cost of both crude oil feedstocks in the refining segment and refined products in both the retail and logistics segments. These decreases were partially offset by increased sales volumes at the Tyler refinery and in the retail segment for the third quarter of 2015, as compared to the same period of 2014, and losses associated with our hedging program of $1.6 million for the third quarter of 2015, compared to gains of $29.7 million for the third quarter of 2014.

Operating expenses were $106.6 million for the third quarter of 2015 compared to $100.9 million for the third quarter of 2014, an increase of $5.7 million, or 5.6%. The increase in operating expenses was primarily due to increased maintenance expenses in both the refining and logistics segments, partially offset by a decrease in credit expenses in our retail segment.

General and administrative expenses were $34.1 million and $36.0 million for the third quarter of 2015 and 2014, respectively, a decrease of $1.9 million, or 5.3%. The decrease in general and administrative expenses was primarily due to a decrease in employee compensation related expenses, partially offset by an increase in expenses associated with assets acquired by our logistics segment and expenses associated with a new payroll system in the third quarter of 2015, as compared to the same period of 2014. We do not allocate general and administrative expenses to our operating segments.

Depreciation and amortization was $34.2 million for the third quarter of 2015 compared to $29.2 million for the third quarter of 2014, an increase of $5.0 million, or 17.1%. The increase in depreciation expense is primarily attributable to the turnaround and expansion of the Tyler refinery completed in the first quarter of 2015, as well as capital expenditures and acquisitions completed in 2014.

Interest expense was $15.7 million for the third quarter of 2015 compared to $10.0 million for the third quarter of 2014, an increase of $5.7 million, or 57.0%. The increase was primarily attributable to interest costs associated with increased debt levels related to the Alon Acquisition.

During the third quarter of 2015, we recognized income from equity method investments of $16.5 million, which is primarily attributable to our proportionate share of the net income from our investment in Alon USA of $16.8 million, net of $3.4 million in amortization of the excess of our investment over our equity in the underlying net assets of Alon USA. We did not hold any equity method investments during the third quarter of 2014.

Income tax (benefit) expense was $(0.5) million for the third quarter of 2015, compared to $32.8 million for the third quarter of 2014, a decrease of $33.3 million, or 101.5%. The decrease was primarily attributable to the decline in pre-tax income, from $111.0 million for the third quarter of 2014, to $24.9 million in the third quarter of 2015. Our effective tax rate was (2.0)% for the third quarter of 2015, compared to 29.5% for the third quarter of 2014. The decrease in our effective tax rate in the third quarter of 2015 was primarily due to the greater impact of permanent book to tax differences on the tax rate, due to the lower pre-tax income in the third quarter of 2015 compared to the third quarter of 2014, as well as the actualization of prior-year provision amounts.

Consolidated Results of Operations — Comparison of the Nine Months Ended September 30, 2015 versus the Nine Months Ended September 30, 2014

Consolidated net income for the nine months ended September 30, 2015 was $50.9 million, or $0.84 per diluted share, compared to $161.1 million, or $2.70 per diluted share, for the nine months ended September 30, 2014.

For the nine months ended September 30, 2015 and 2014, we generated net sales of $4,397.9 million and $6,562.6 million, respectively, a decrease of $2,164.7 million, or 33.0%. The decrease in net sales is primarily due to decreases in the price of refined

products in the refining, logistics and retail segments and a decrease in sales volume in the refining segment in the nine months ended September 30, 2015, compared to the same period in 2014. The decline in sales volume in the refining segment was primarily attributable to the downtime associated with the turnaround and expansion of the Tyler refinery that was completed in the first quarter of 2015. These decreases were partially offset by an increase in fuel volumes and merchandise sales in the retail segment.

Cost of goods sold was $3,799.9 million for the nine months ended September 30, 2015, compared to $5,786.8 million for the nine months ended September 30, 2014, a decrease of $1,986.9 million, or 34.3%. The decrease in cost of goods sold primarily resulted from decreases in the cost of crude oil in the refining segment and refined products in both the logistics and retail segments, a decrease in sales volume in the refining segment and a one-time expense of $22.6 million related to the financial settlement under the Supply and Offtake Agreement that was recorded in the second quarter of 2014. Partially offsetting the decrease were losses associated with our hedging program of $8.6 million for the nine months ended September 30, 2015, compared to gains of $70.7 million for the nine months ended September 30, 2014.

Operating expenses were $304.0 million for the nine months ended September 30, 2015, compared to $301.6 million for the nine months ended September 30, 2014, an increase of $2.4 million, or 0.8%. The increase in operating expenses primarily resulted from increases in various maintenance initiatives in the logistics segment and increased insurance expenses in the retail segment, partially offset by a decline in credit expenses in the retail segment and a decrease in expenses attributable to the downtime associated with the turnaround and expansion of the Tyler refinery in the first quarter of 2015, as well as a decrease in insurance expense at the Tyler refinery.

General and administrative expenses were $101.1 million for the nine months ended September 30, 2015, compared to $97.6 million for the nine months ended September 30, 2014, an increase of $3.5 million, or 3.6%. The increase in general and administrative expenses was primarily due to an increase in various acquisition related expenses and expenses associated with a new payroll system for the nine months ended September 30, 2015, as compared to the same period of 2014, partially offset by a decrease in employee compensation related expenses. We do not allocate general and administrative expenses to our operating segments.

Depreciation and amortization was $97.4 million for the nine months ended September 30, 2015, compared to $82.0 million for the nine months ended September 30, 2014, an increase of $15.4 million, or 18.8%. This increase was primarily due to completed capital projects and accelerated depreciation of assets replaced in the turnaround and expansion of the Tyler refinery completed in the first quarter of 2015.

Interest expense was $43.1 million for the nine months ended September 30, 2015, compared to $29.7 million for the nine months ended September 30, 2014, an increase of $13.4 million, or 45.1%. The increase was primarily attributable to $3.9 million of one-time fees associated with the amendment to the Lion Term Loan in the second quarter of 2015 and interest costs associated with increased debt levels related to the Alon Acquisition.

During the nine months ended September 30, 2015, we recognized income from equity method investments of $23.9 million, which is primarily attributable to our proportionate share of the net income from our investment in Alon USA of $24.4 million, net of $5.1 million in amortization of the excess of our investment over our equity in the underlying net assets of Alon USA. We did not hold any equity method investments during the nine months ended September 30, 2014.

Other income of $1.0 million and $0.1 million for the nine months ended September 30, 2015 and 2014, respectively, and was primarily attributable to foreign currency gains and other miscellaneous income.

Income tax expense was $8.6 million for the nine months ended September 30, 2015, compared to $84.7 million for the nine months ended September 30, 2014, a decrease of $76.1 million, or 89.8%. The decrease was primarily attributable to the decline in pre-tax income, from $265.4 million for the nine months ended September 30, 2014, to $78.4 million for the nine months ended September 30, 2015. Our effective tax rate was 11.0% for the nine months ended September 30, 2015, compared to 31.9% for the nine months ended September 30, 2014. The decrease in our effective tax rate for the nine months ended September 30, 2015 was primarily due to the actualization of prior-year provision amounts, as well the greater impact of permanent book to tax differences on the tax rate, due to the lower pre-tax income for the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014.

Operating Segments

We report operating results in three reportable segments: refining, logistics and retail. 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 its reportable segments based on the segment contribution margin.

Refining Segment

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Refining Segment Contribution:
Net sales	$	1,208.0	$	1,802.2	$	3,371.8	$	5,011.6
Cost of goods sold	1,100.7		1,598.5		3,022.4		4,468.2
Gross Margin	107.3		203.7		349.4		543.4
Operating expenses	59.9		52.4		168.1		168.7
Contribution margin	$	47.4	$	151.3	$	181.3	$	374.7

Tyler Refinery
Days in period	92		92		273		273
Total sales volume (average bpd)⁽¹⁾	80,177		63,107		58,531		65,026
Products manufactured (average bpd):
Gasoline	41,412		33,846		30,499		34,971
Diesel/Jet	32,034		24,922		23,356		25,473
Petrochemicals, LPG, NGLs	3,606		2,714		2,583		2,473
Other	1,706		1,636		1,285		1,706
Total production	78,758		63,118		57,723		64,623
Throughput (average bpd):
Crude oil	71,540		59,981		53,460		58,766
Other feedstocks	8,368		4,450		5,177		6,888
Total throughput	79,908		64,431		58,637		65,654
Per barrel of sales⁽³⁾:
Tyler refining margin⁽⁴⁾	$	6.12	$	19.05	$	10.17	$	18.37
Direct operating expenses⁽⁵⁾	$	3.81	$	4.24	$	4.59	$	4.47



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
El Dorado Refinery
Days in period	92		92		273		273
Total sales volume (average bpd)⁽²⁾	78,736		85,880		81,812		76,955
Products manufactured (average bpd):
Gasoline	38,068		41,134		39,336		34,510
Diesel	27,206		34,205		28,188		27,569
Petrochemicals, LPG, NGLs	561		711		666		803
Asphalt	6,137		7,567		7,188		5,817
Other	2,717		930		2,083		865
Total production	74,689		84,547		77,461		69,564
Throughput (average bpd):
Crude oil	71,584		80,266		74,225		65,735
Other feedstocks	4,815		6,424		4,732		5,703
Total throughput	76,399		86,690		78,957		71,438
Per barrel of sales⁽³⁾:
El Dorado refining margin⁽⁴⁾	$	8.71	$	11.51	$	8.46	$	9.88
Direct operating expenses⁽⁵⁾	$	4.17	$	3.35	$	4.05	$	4.06

Pricing statistics (average for the period presented):
WTI — Cushing crude oil (per barrel)	$	46.70	$	97.31	$	51.10	$	99.65
WTI — Midland crude oil (per barrel)	$	47.75	$	87.04	$	50.81	$	91.66
US Gulf Coast 5-3-2 crack spread (per barrel)	$	16.41	$	15.05	$	16.67	$	15.72
US Gulf Coast Unleaded Gasoline (per gallon)	$	1.58	$	2.67	$	1.66	$	2.72
Ultra low sulfur diesel (per gallon)	$	1.51	$	2.80	$	1.68	$	2.88
Natural gas (per MMBTU)	$	2.75	$	3.97	$	2.78	$	4.57

_____________________________

⁽¹⁾

Sales volume includes 6,541 bpd and 3,880 bpd sold to the logistics segment during the three and nine months ended September 30, 2015, respectively, and 1,810 bpd and 1,117 bpd during the three and nine months ended September 30, 2014, respectively. Sales volume also includes sales of 1,477 bpd and 2,407 bpd of intermediate and finished products to the El Dorado refinery during the three and nine months ended September 30, 2015, respectively, and 2,518 bpd and 3,746 bpd of intermediate and finished products during the three and nine months ended September 30, 2014, respectively. Sales volume excludes 61 bpd and 2,185 bpd of wholesale activity during the three and nine months ended September 30, 2015, respectively. There was no wholesale activity during the three and nine months ended September 30, 2014.

⁽²⁾

Sales volume includes 3,112 bpd and 3,686 bpd of produced finished product sold to the retail segment during the three and nine months ended September 30, 2015, respectively, and 2,792 bpd and 3,559 bpd during the three and nine months ended September 30, 2014, respectively. Sales volume also includes 2,027 bpd and 2,244 bpd of produced finished product sold to the Tyler refinery during the three and nine months ended September 30, 2015, respectively, and 945 bpd and 1,420 bpd during the three and nine months ended September 30, 2014, respectively. Sales volume excludes 27,325 bpd and 25,902 bpd of wholesale activity during the three and nine months ended September 30, 2015, respectively, and 14,597 bpd and 13,319 bpd of wholesale activity during the three and nine months ended September 30, 2014, respectively.


⁽³⁾	"Per barrel of sales" information is calculated by dividing the applicable income statement line item (operating margin or operating expenses) by the total barrels sold during the period.


⁽⁴⁾	"Refining margin" is defined as refinery net sales less cost of goods sold.


⁽⁵⁾	"Direct operating expenses" are defined as operating expenses attributed to the refining segment.

Comparison of the Three Months Ended September 30, 2015 versus the Three Months Ended September 30, 2014

Contribution margin for the refining segment decreased to $47.4 million, or 51.5% of our consolidated segment contribution margin, in the third quarter of 2015, compared to $151.3 million, or 81.3% of our consolidated segment contribution margin, in the third quarter of 2014. The refining segment contribution margin decline was primarily attributable to a decline in margins at both the Tyler and El Dorado refineries, partially offset by an increase in sales volumes at the Tyler refinery, attributable to the expansion of the Tyler refinery in the first quarter of 2015. Margins at both refineries were negatively impacted by a change in the average differential between WTI Midland crude oil and WTI Cushing crude oil, to a premium of $0.72 per barrel in the third quarter of 2015, compared to a discount of $9.85 per barrel in the third quarter of 2014. Further contributing to the decline in margins was $27.3 million of lower of cost or market inventory write-downs in the third quarter of 2015, as well as losses on derivative positions of $1.5 million in the third quarter of 2015, compared to gains of $27.9 million in the third quarter of 2014.

Net sales for the refining segment were $1,208.0 million for the third quarter of 2015 compared to $1,802.2 million for the third quarter of 2014, a decrease of $594.2 million, or 33.0%. The decrease was primarily due to decreases in the price of U.S. Gulf Coast gasoline and Ultra-Low-Sulfur diesel ("ULSD") in the third quarter of 2015 as compared to the third quarter of 2014.

Cost of goods sold for the third quarter of 2015 for the refining segment was $1,100.7 million compared to $1,598.5 million for the third quarter of 2014, a decrease of $497.8 million, or 31.1%. This decrease was a result of a decrease in the cost of WTI crude oil, from an average of $97.31 per barrel in the third quarter of 2014 to an average of $46.70 in the third quarter of 2015. The decrease in the cost of crude oil was partially offset by $27.3 million of lower of cost or market inventory write-downs in the third quarter of 2015, as well as losses on derivative positions of $1.5 million in the third quarter of 2015, compared to gains of $27.9 million in the third quarter of 2014.

Our refining segment 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. These fees were $31.2 million and $24.9 million during the third quarters of 2015 and 2014, respectively. We eliminate these intercompany fees in consolidation.

Operating expenses for the refining segment were $59.9 million for the third quarter of 2015 compared to $52.4 million for the third quarter of 2014, an increase of $7.5 million, or 14.3%. The increase in operating expenses was primarily due to higher labor related expenses at both refineries and waste disposal and maintenance expenses at the Tyler refinery, partially offset decreased insurance expense at the Tyler refinery.

Comparison of the Nine Months Ended September 30, 2015 versus the Nine Months Ended September 30, 2014

Contribution margin for the refining segment for the nine months ended September 30, 2015 was $181.3 million, or 61.7% of our consolidated segment contribution margin, compared to $374.7 million, or 79.0% of our consolidated segment contribution margin for the nine months ended September 30, 2014. The decrease in refining segment contribution margin was primarily attributable to a decrease in sales volumes at the Tyler refinery, attributable to downtime at the Tyler refinery as a result of the turnaround and expansion projects completed in the first quarter of 2015, partially offset by subsequent volume increases resulting from the Tyler expansion, as well as a decline in margins at both the Tyler and El Dorado refineries. The decrease in margins at both refineries, from a combined $13.77 per barrel sold in the nine months ended September 30, 2014 to $9.18 per barrel sold in the nine months ended September 30, 2015, primarily resulted from a decrease in the discount between Midland and Cushing crude oil, from $7.24 per barrel for the nine months ended September 30, 2014 to $0.62 for the nine months ended September 30, 2015. Finally, we recognized losses on derivative positions of $8.7 million for the nine months ended September 30, 2015, compared to gains of $69.2 million for the nine months ended September 30, 2014.

Net sales for the refining segment were $3,371.8 million for the nine months ended September 30, 2015, compared to $5,011.6 million for the nine months ended September 30, 2014, a decrease of $1,639.8 million, or 32.7%. Net sales decreased due primarily to the decrease in sales volumes at the Tyler refinery, as well as a decrease in the average price of U.S. Gulf Coast gasoline and ULSD in the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014.

Cost of goods sold for the nine months ended September 30, 2015 was $3,022.4 million compared to $4,468.2 million for the comparable 2014 period, a decrease of $1,445.8 million, or 32.4%. This decrease was primarily a result of the decline in sales volumes at the Tyler refinery, a decrease in the average price of WTI crude oil, from an average of $99.65 per barrel for the nine months ended September 30, 2014 to an average of $51.10 per barrel, for the nine months ended September 30, 2015, and a one-time expense of $22.6 million related to the financial settlement under the Supply and Offtake Agreement that was recorded in the second quarter of 2014. These decreases were partially offset by losses on derivative positions of $8.7 million for the nine months ended September 30, 2015, compared to gains of $69.2 million for the nine months ended September 30, 2014.

Our refining segment has multiple service agreements with our logistics segment which, among other things, requires 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. These fees were$90.7 million and $70.0 million during the nine months ended September 30, 2015 and 2014, respectively. We eliminate these intercompany fees in consolidation.

Operating expenses were $168.1 million for the nine months ended September 30, 2015, compared to $168.7 million for the nine months ended September 30, 2014, a decrease of $0.6 million, or 0.4%. The decrease in operating expenses was primarily attributable to downtime associated with the turnaround and expansion of the Tyler refinery completed in the first quarter of 2015, as well as a decrease in insurance expense at the Tyler refinery. These decreases were largely offset by an increase in labor and outside service expenses at the El Dorado refinery during the nine months ended September 30, 2015.

Logistics Segment

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Logistics Segment Contribution:
Net sales	$	165.1	$	228.0	$	480.7	$	667.9
Cost of goods sold	124.4		194.1		365.3		562.9
Gross Margin	40.7		33.9		115.4		105.0
Operating expenses	11.6		10.4		33.2		29.6
Contribution margin	$	29.1	$	23.5	$	82.2	$	75.4

Operating Information:
East Texas - Tyler Refinery sales volumes (average bpd)⁽¹⁾	75,313		59,659		56,553		61,097
West Texas wholesale marketing throughputs (average bpd)	18,824		17,923		17,661		17,132
West Texas wholesale marketing margin per barrel	$	1.50	$	2.20	$	1.41	$	4.09
Terminalling throughputs (average bpd)⁽²⁾	126,051		95,024		102,534		94,656
Throughputs (average bpd)
Lion Pipeline System:
Crude pipelines (non-gathered)	54,973		57,254		55,168		47,098
Refined products pipelines to Enterprise Systems	54,397		65,439		56,294		52,490
SALA Gathering System	20,264		22,258		21,031		22,221
East Texas Crude Logistics System	19,078		4,361		22,270		6,181
El Dorado Rail Offloading Rack	—		—		1,474		—

_____________________________


⁽¹⁾	Excludes jet fuel and petroleum coke.

⁽²⁾

Consists of terminalling throughputs at our Tyler, Big Sandy and Mount Pleasant, Texas, North Little Rock, Arkansas and Memphis and Nashville, Tennessee terminals. Throughputs at the El Dorado, Arkansas terminal are for the period from February 10, 2014 through September 30, 2015. Prior to February 10, 2014, the logistics segment did not record revenue for throughput at the El Dorado, Arkansas terminal. Throughputs for the Mount Pleasant, Texas terminal are for the period from October 1, 2014 through September 30, 2015, following its acquisition. Throughputs for the Memphis and Nashville, Tennessee, Tyler and Big Sandy, Texas and the North Little Rock, Arkansas terminals are for all periods presented.

Comparison of the Three Months Ended September 30, 2015 versus the Three Months Ended September 30, 2014

Contribution margin for the logistics segment increased to $29.1 million, or 31.6% of our consolidated segment contribution margin, in the third quarter of 2015, compared to $23.5 million, or 12.6% of our consolidated segment contribution margin, in the third quarter of 2014. The increase in contribution margin was primarily attributable to increased fees on our Paline Pipeline System and the effect of the throughput agreements with the refining segment in connection with the El Dorado Offloading Racks Acquisition and the Tyler Crude Tank Acquisition from the refining segment in the first quarter of 2015. Partially offsetting the increases were lower margins in our operations in west Texas. The decrease in our contribution margin in our west Texas operations was partially a result of a more challenging market, in which lower crude oil prices drove a reduction in drilling activity in west Texas, lowering demand in the region. Also contributing to the decrease in our contribution margin in west Texas was a decline in the market price for ethanol, which we use in ethanol blending in our marketing and terminalling services, relative to fixed price contracts that were in place during the third quarter of 2015.

Net sales for the logistics segment were $165.1 million in the third quarter of 2015, compared to $228.0 million for the third quarter of 2014, a decrease of $62.9 million, or 27.6%. The decrease was primarily attributable to decreases in the average sales prices per gallon of gasoline and diesel sold in our west Texas marketing operations. The average sales price per gallon of gasoline decreased $0.99 per gallon during the third quarter of 2015 compared to the third quarter of 2014. The average sales price per gallon of diesel decreased $1.29 per gallon during the third quarter of 2015 compared to the third quarter of 2014. Partially offsetting the decreases were increased fees on our Paline Pipeline System, net sales contributed by trucking assets we acquired from Frank Thompson Transport, Inc. in December 2014 (the "FTT Assets"), the terminalling and pipeline assets we acquired in October 2014 near Mount Pleasant, Texas (the "Greenville-Mount Pleasant Assets") and the effect of the throughput agreements with the refining segment.

Net sales included $4.4 million and $3.6 million of net service fees paid by our refining segment to our logistics segment during the third quarter of 2015 and 2014, respectively. These service fees are based on the number of gallons sold and a shared portion of the margin achieved in return for providing sales and customer support services. Net sales also included crude and refined product transportation, terminalling and storage fees paid by our refining segment to our logistics segment. These fees were $31.2 million and $24.9 million in the third quarter of 2015 and 2014, respectively. The logistics segment also sold $1.0 million and $1.3 million of RINs to the refining segment in the third quarter of 2015 and 2014, respectively. These intercompany sales and fees are eliminated in consolidation.

Cost of goods sold for the logistics segment decreased $69.7 million, or 35.9%, to $124.4 million in the third quarter of 2015, compared to $194.1 million in the third quarter of 2014. The decrease in cost of goods sold was primarily attributable to decreases in the average cost per gallon of gasoline and diesel purchased in our west Texas marketing operations. The average cost per gallon of gasoline decreased $0.98 per gallon during the third quarter of 2015 compared to the third quarter of 2014, while the average cost per gallon of diesel decreased $1.30 per gallon during the third quarter of 2015 compared to the third quarter of 2014.

Operating expenses for the logistics segment were approximately $11.6 million and $10.4 million for the third quarter of 2015 and 2014, respectively, an increase of $1.2 million, or 11.5%. The increase in operating expenses was primarily due to increases in maintenance expense for terminal maintenance initiatives and increases in contract and professional service fees in the third quarter of 2015 as compared to the third quarter of 2014.

Comparison of the Nine Months Ended September 30, 2015 versus the Nine Months Ended September 30, 2014

Contribution margin for the logistics segment for the nine months ended September 30, 2015 was $82.2 million, or 28.0% of our consolidated segment contribution margin, compared to $75.4 million, or 15.9% of our consolidated segment contribution margin, for the nine months ended September 30, 2014. The increase in contribution margin was attributable to increased fees on our Paline Pipeline System and the effects of the throughput agreements we entered into with the refining segment in connection with the El Dorado Offloading Racks Acquisition and the Tyler Crude Tank Acquisition from the refining segment in the first quarter of 2015. Partially offsetting the increases were lower margins in our operations in west Texas. The decrease in our contribution margin in our west Texas operations was a result of a more challenging market, in which lower crude oil prices drove a reduction in drilling activity in west Texas, lowering demand in the region. Also contributing to the decrease in our contribution margin in west Texas was a decline in the market price for ethanol, which we use in ethanol blending in our marketing and terminalling services, relative to fixed price contracts that were in place during the nine months ended September 30, 2015.

Net sales for the logistics segment were $480.7 million for the nine months ended September 30, 2015 compared to $667.9 million for the nine months ended September 30, 2014, a decrease of $187.2 million, or 28.0%. The decrease in net sales was primarily due to decreases in the average sales prices per gallon of gasoline and diesel sold in our west Texas marketing operations. The average sales price of gasoline decreased $1.05 per gallon during the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014. The average sales price of diesel decreased $1.28 per gallon during the nine months

ended September 30, 2015 compared to the nine months ended September 30, 2014. Partially offsetting the decreases were net sales contributed by the FTT Assets and the Greenville-Mount Pleasant Assets, the effects of the throughput and tankage agreements with the refining segment and increased fees on our Paline Pipeline System.

Net sales included $11.2 million and $10.7 million of net service fees paid by our refining segment to our logistics segment during the nine months ended September 30, 2015 and 2014, respectively. These service fees are based on the number of gallons sold and a shared portion of the margin achieved in return for providing sales and customer support services. Net sales also include crude and refined product transportation, terminalling and storage fees paid by our refining segment to our logistics segment. These fees were $90.7 million and $70.0 million in the nine months ended September 30, 2015 and 2014, respectively. The logistics segment also sold $4.9 million and $3.3 million of RINs to the refining segment in the nine months ended September 30, 2015 and 2014. These sales and fees are eliminated in consolidation.

Cost of goods sold decreased $197.6 million, or 35.1%, to $365.3 million in the nine months ended September 30, 2015, compared to cost of goods sold of $562.9 million in the nine months ended September 30, 2014. The decrease in cost of goods sold was primarily attributable to decreases in the average cost per gallon of gasoline and diesel purchased in our west Texas marketing operations. The average cost of gasoline decreased $0.96 per gallon for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014. The average cost of diesel decreased $1.22 per gallon for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014.

Operating expenses in the logistics segment were approximately $33.2 million and $29.6 million for the nine months ended September 30, 2015 and 2014, respectively, an increase of $3.6 million, or 12.2%. The increase in operating expenses was primarily due to increases in various maintenance initiatives related to our tanks and pipelines, contract services fees and acquisitions that have occurred since the nine months ended September 30, 2014.

Retail Segment

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Retail Segment Contribution:
Net sales	$	396.9		$	505.1		$	1,144.8		$	1,445.3
Cost of goods sold	339.5			452.3			992.7			1,302.9
Gross Margin	57.4			52.8			152.1			142.4
Operating expenses	35.5			36.4			103.6			103.4
Contribution margin	$	21.9		$	16.4		$	48.5		$	39.0

Operating Information:
Number of stores (end of period)	355			366			355			366
Average number of stores	358			364			360			362
Retail fuel sales (thousands of gallons)	117,942			116,108			342,756			323,333
Average retail gallons sold per average number of stores (in thousands)	329			319			952			893
Retail fuel margin ($ per gallon)	$	0.217		$	0.194		$	0.178		$	0.173
Merchandise sales (in thousands)	$	111,330		$	107,042		$	315,086		$	300,136
Merchandise margin %	28.0		%	27.7		%	28.3		%	28.1		%
Change in same-store retail fuel gallons sold	0.4		%	5.1		%	2.7		%	(0.3		)%
Change in same-store merchandise sales	3.8		%	2.5		%	3.6		%	3.4		%

Comparison of the Three Months Ended September 30, 2015 versus the Three Months Ended September 30, 2014

Contribution margin for the retail segment increased to $21.9 million, or 23.8% of our consolidated segment contribution margin, in the third quarter of 2015, compared to $16.4 million, or 8.8% of our consolidated segment contribution margin, in the third quarter of 2014. The increase was primarily due to an increase in both retail fuel margins and merchandise margins in the third quarter of 2015, as compared to the third quarter of 2014.

Net sales for the retail segment in the third quarter of 2015 decreased $108.2 million, or 21.4%, to $396.9 million from $505.1 million in the third quarter of 2014. The decrease in net sales was primarily due to a decrease in the retail fuel price per gallon of 30.9% to an average price of $2.26 per gallon in the third quarter of 2015, compared to an average price of $3.27 per gallon in the third quarter of 2014. The decrease in retail fuel prices was partially offset by an increase in fuel sales volumes and merchandise sales in the third quarter of 2015, as compared with the same period of 2014.

Retail fuel gallons sold for the retail segment were 117.9 million gallons for the third quarter of 2015, compared to 116.1 million gallons for the third quarter of 2014. Same-store retail fuel gallons sold increased 0.4% for the third quarter of 2015, compared to the third quarter of 2014. Total fuel sales, including wholesale dollars, decreased 28.2% to $285.6 million in the third quarter of 2015, compared to $398.0 million in the third quarter of 2014.

Merchandise sales for the retail segment increased 4.0% to $111.3 million in the third quarter of 2015, compared to $107.0 million in the third quarter of 2014. Same-store merchandise sales increased 3.8%, primarily due to increases in the cigarette, other tobacco, snack and dairy categories, partially offset by a decline in the soft drinks and candy categories, during the third quarter of 2015 as compared to the same period in 2014.

Cost of goods sold for the retail segment decreased $112.8 million, or 24.9%, to $339.5 million in the third quarter of 2015 from $452.3 million in the third quarter of 2014. This decrease was primarily due to a decrease in the average retail fuel cost per gallon of 33.6% to an average cost of $2.04 per gallon in the third quarter of 2015, compared to an average cost of $3.07 per gallon in the third quarter of 2014, partially offset by an increase in fuel sales volumes.

Operating expenses for the retail segment were $35.5 million in the third quarter of 2015 as compared to $36.4 million in the third quarter of 2014, a decrease of $0.9 million, or 2.5%. This decrease was primarily attributable to a decrease in credit expenses in the third quarter of 2015 as compared to the third quarter of 2014.

Comparison of the Nine Months Ended September 30, 2015 versus the Nine Months Ended September 30, 2014

Contribution margin for the retail segment was $48.5 million, or 16.5% of our consolidated segment contribution margin, in the nine months ended September 30, 2015, versus $39.0 million, or 8.2% of our consolidated segment contribution margin, in the nine months ended September 30, 2014. Both fuel and merchandise margins remained relatively flat during the nine months ended September 30, 2015, when compared to the nine months ended September 30, 2014. The increase in retail contribution margin was primarily due to an increase in fuel sales volumes and merchandise sales.

Net sales for our retail segment in the nine months ended September 30, 2015 decreased $300.5 million, or 20.8%, to $1,144.8 million, compared to $1,445.3 million in the nine months ended September 30, 2014. The decrease in net sales was primarily attributable to a decrease in the retail fuel price per gallon of 32.0% to an average price of $2.27 per gallon in the nine months ended September 30, 2015, from an average price of $3.34 per gallon in the nine months ended September 30, 2014, which was partially offset by an increase in retail fuel sales volumes and merchandise sales.

Retail fuel gallons sold were 342.8 million gallons for the nine months ended September 30, 2015, compared to 323.3 million gallons for the nine months ended September 30, 2014. Same-store gallons increased 2.7% for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014.

Merchandise sales increased 5.0%, from $300.1 million for the nine months ended September 30, 2014 to $315.1 million in the nine months ended September 30, 2015. Same-store merchandise sales increased 3.6%, primarily due to increases in cigarette, other tobacco, dairy and snack categories, during the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014, partially offset by a decline in the soft drink category.

Cost of goods sold for our retail segment decreased $310.2 million, or 23.8%, to $992.7 million in the nine months ended September 30, 2015, compared to $1,302.9 million in the nine months ended September 30, 2014. This decrease was primarily due to a decrease in the average retail fuel cost per gallon of 34.1%, to an average cost of $2.09 per gallon in the nine months ended September 30, 2015 when compared to an average cost of $3.17 per gallon in the nine months ended September 30, 2014. This decline in prices was partially offset by the increase in retail fuel sales volumes.

Operating expenses for our retail segment were $103.6 million in the nine months ended September 30, 2015, compared to $103.4 million in the nine months ended September 30, 2014, an increase of $0.2 million, or 0.2%. This slight increase was primarily due to an increase in workers compensation and general liability insurance expense, which was almost fully offset by a decrease in credit expenses during the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operating activities and borrowings under our revolving credit facilities. We believe that our cash flows from operations and borrowings under or refinancings of our current credit facilities 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 for the nine months ended September 30, 2015 and 2014 (in millions):



	Nine Months Ended September 30,
	2015			2014
Cash Flow Data:
Cash flows provided by operating activities	$	191.7		$	241.7
Cash flows used in investing activities	(411.9		)	(222.0		)
Cash flows provided by financing activities	142.4			78.0
Net (decrease) increase in cash and cash equivalents	$	(77.8	)	$	97.7

Cash Flows from Operating Activities

Net cash provided by operating activities was $191.7 million for the nine months ended September 30, 2015, compared to $241.7 million for the comparable period of 2014. The decrease in cash flows from operations was primarily due to the decrease in net income for the nine months ended September 30, 2015 to $69.8 million, compared to $180.7 million in the same period of 2014. Further contributing to the decrease in cash provided by operating activities for the nine months ended September 30, 2015 compared to the same period of 2014 was a significant decrease in inventory during the nine months ended September 30, 2014, attributable to the processing of surplus crude inventory at both the Tyler and El Dorado refineries. These decreases were partially offset by a decline in the market value of our derivative contracts.

Cash Flows from Investing Activities

Net cash used in investing activities was $411.9 million for the first nine months of 2015, compared to $222.0 million in the comparable period of 2014. The increase was primarily due to equity method investments of $230.6 million in the nine months ended September 30, 2015, primarily associated with the Alon Acquisition in May 2015. There were no equity method investments in the nine months ended September 30, 2014.

Cash used in investing activities includes the cash portion of our capital expenditures, which was $175.9 million and $211.1 million, for the nine months ended September 30, 2015 and 2014, respectively. Total capital expenditures during the first nine months of 2015 were $173.6 million, of which $146.8 million was spent on projects in the refining segment, $8.3 million was spent in the retail segment, $13.9 million was spent in the logistics segment and $4.6 million was spent at the holding company level. During the nine months ended September 30, 2014, we spent $193.3 million, of which $155.1 million was spent on projects in our refining segment, $20.0 million was spent in our retail segment, $5.0 million was spent in our logistics segment and $13.2 million was spent at the holding company level.

Cash Flows from Financing Activities

Net cash provided by financing activities was $142.4 million in the nine months ended September 30, 2015, compared to $78.0 million in the comparable period of 2014. The increase in cash provided by financing activities was primarily due to an increase in net borrowings under promissory notes, to $137.6 million during the nine months ended September 30, 2015, compared to net borrowings of $87.5 million in the comparable 2014 period, partially offset by a decrease in net borrowings under our

revolving credit facilities, to $81.4 million in the nine months ended September 30, 2015, compared to $96.7 million in the comparable period of 2014.

Cash Position and Indebtedness

As of September 30, 2015, our total cash and cash equivalents were $366.3 million and we had total indebtedness of approximately $953.7 million. Borrowing availability under our four separate revolving credit facilities was approximately $590.7 million and we had letters of credit issued of $99.0 million. We believe we were in compliance with our covenants in all debt facilities as of September 30, 2015. See Note 11 of the condensed consolidated financial statements in Item 1, Financial Statements, for additional information about our four separate revolving 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, 2015 were $173.6 million, of which approximately $146.8 million was spent in our refining segment, $8.3 million in our retail segment, $13.9 million in our logistics segment and $4.6 million at the holding company level. Our capital expenditure budget is approximately $227.1 million for 2015. The following table summarizes our actual capital expenditures for the nine months ended September 30, 2015 and planned capital expenditures for the full year 2015 by operating segment and major category (in millions):



	Full Year 2015 Forecast		Nine Months Ended September 30, 2015
Refining:
Sustaining maintenance, including turnaround activities	$	72.4	$	65.2
Regulatory	24.0		17.7
Discretionary projects	76.0		63.9
Refining segment total	172.4		146.8
Logistics:
Regulatory	1.9		0.9
Sustaining maintenance	9.6		8.2
Discretionary projects	5.3		4.8
Logistics segment total	16.8		13.9
Retail:
Sustaining maintenance	9.0		5.3
Growth/profit improvements	3.3		1.1
Retrofit/rebrand/re-image	2.3		1.2
Raze and rebuild/new/land	5.0		0.7
Retail segment total	19.6		8.3
Other:
Growth/profit improvements	7.9		2.9
New builds/land	10.4		1.7
Other total	18.3		4.6
Total capital spending	$	227.1	$	173.6

In the third quarter of 2015, we decreased our total capital spending forecast for 2015 to $227.1 million, down from the prior forecast of $239.7 million. The decrease in our total capital spending forecast for 2015 is primarily attributable to decreased spending in our logistics, retail and other segments from the prior forecast. For the full year 2015, we plan to spend approximately $19.6 million in the retail segment, of which we plan to spend $3.3 million on profit and growth improvements. We expect to spend approximately $172.4 million in our refining segment for the full year 2015. The full year 2015 refining segment forecast includes $24.0 million in regulatory projects, $17.7 million of which was spent in the nine months ended September 30, 2015. In addition, we plan to spend approximately $72.4 million on maintenance projects and approximately $76.0 million for other

discretionary projects in the refining segment in the full year 2015. We plan to spend $16.8 million in the logistics segment for the full year 2015.

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.

Off-Balance Sheet Arrangements

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

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.

Price Risk Management Activities. At times, we enter into commodity derivative contracts 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. In accordance with ASC 815, Derivatives and Hedging ("ASC 815"), all of these commodity contracts 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 consolidated financial statements, unless, at inception, the company elects to designate the 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 consolidated balance sheets and, ultimately, when the forecasted transactions are completed in net sales or cost of goods sold in the consolidated statements of income.

The following table sets forth information relating to our open commodity derivative contracts as of September 30, 2015 ($ in millions).



	Total Outstanding				Notional Contract Volume (barrels) by Year of Maturity
Contract Description	Market Value			Notional Contract Volume (barrels)	2015	2016	2017
Contracts not designated as hedging instruments:
Crude oil price swaps - long	$	42.7		626,000	626,000	—	—
Crude oil price swaps - short	(5.1		)	150,000	150,000	—	—
Inventory, refined product and crack spread swaps - long	(8.6		)	108,500	108,500	—	—
Inventory, refined product and crack spread swaps - short	11.2			1,803,000	1,803,000	—	—
Total	$	40.2		2,687,500	2,687,500	—	—
Contracts designated as cash flow hedging instruments:
Crude oil price swaps - long	$	(70.7	)	2,915,200	220,800	878,400	1,816,000
Inventory, refined product and crack spread swaps - long	1.1			675,000	—	675,000	—
Inventory, refined product and crack spread swaps - short	11.6			606,500	606,500	—	—
Total	$	(58.0	)	4,196,700	827,300	1,553,400	1,816,000

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

Our management has evaluated, with the participation of our principal executive and principal financial officers, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has, based on this evaluation, concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosures.

(b) Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.

OTHER INFORMATION

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 for the year ended December 31, 2014 filed with the Securities and Exchange Commission on February 26, 2015 (the "Form 10-K") as updated by "Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the three months ended June 30, 2015 filed with the Securities and Exchange Commission on August 5, 2015.

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

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, 2015 by or on behalf of us or any “affiliated purchaser,” as defined by Rule 10b-18 of the Exchange Act:



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽¹⁾	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs⁽¹⁾
July 1 - July 31, 2015	—	$	—	—	$	125,000,000
August 1 - August 31, 2015	413,289	30.88		413,289	112,235,578
September 1 - September 30, 2015	546,464	29.72		546,464	$	95,994,274
Total	959,753	$	30.22	959,753	N/A

⁽¹⁾

The Company's Board of Directors has authorized a share repurchase program for up to $125.0 million of the Company’s 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 the Company to acquire any particular amount of stock, and the authorization under the repurchase program will expire on December 31, 2015.

ITEM 5. OTHER INFORMATION

Dividend Declaration

On November 3, 2015, our Board of Directors voted to declare a quarterly cash dividend of $0.15 per share, payable on December 15, 2015 to shareholders of record on November 24, 2015.

ITEM 6. EXHIBITS



Exhibit No.		Description
10.1	§*	Employment Agreement, effective August 3, 2015, between Delek US Holdings, Inc. and Anthony L. Miller.
10.2	§*	Employment Agreement, effective August 3, 2015, between Delek US Holdings, Inc. and Avigal Soreq.
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.
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.
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, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014 (Unaudited), (ii) Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014 (Unaudited), (iii) Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014 (Unaudited), (iv) Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014 (Unaudited), and (v) Notes to Condensed Consolidated Financial Statements (Unaudited).


*	Management contract or compensatory plan or arrangement.


§	Filed herewith.

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 5, 2015

EXHIBIT INDEX



Exhibit No.		Description
10.1	§*	Employment Agreement, effective August 3, 2015, between Delek US Holdings, Inc. and Anthony L. Miller.
10.2	§*	Employment Agreement, effective August 3, 2015, between Delek US Holdings, Inc. and Avigal Soreq.
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.
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.
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, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014 (Unaudited), (ii) Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014 (Unaudited), (iii) Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014 (Unaudited), (iv) Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014 (Unaudited), and (v) Notes to Condensed Consolidated Financial Statements (Unaudited).


*	Management contract or compensatory plan or arrangement.


§	Filed herewith.