Renewable Energy Group, Inc. - Quarter Report: 2019 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

For the Quarterly Period Ended June 30, 2019



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

For the transition period from to

Commission File Number 001-35397

RENEWABLE ENERGY GROUP, INC.

(Exact name of registrant as specified in its charter)



Delaware			26-4785427
(State of other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

416 South Bell Avenue	Ames	Iowa	50010
(Address of principal executive offices)			(Zip code)

(515) 239-8000

(Registrant’s telephone number, including area code)

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.0001 per share	REGI	NASDAQ Global Market

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨

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



Large accelerated filer	☐	Accelerated filer	x

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

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

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

As of July 31, 2019, the registrant had 38,958,744 shares of Common Stock outstanding.

TABLE OF CONTENTS



		Page
PART I	FINANCIAL INFORMATION	1
ITEM 1.	Condensed Consolidated Financial Information	1
ITEM 2.	Management's Discussion and Analysis of Financial Information	26
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	40
ITEM 4.	Controls and Procedures	41

PART II	OTHER INFORMATION	42
ITEM 1.	Legal Proceedings	42
ITEM 1A.	Risk Factors	42
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
ITEM 3.	Defaults Upon Senior Securities	56
ITEM 4.	Mine Safety Disclosures	56
ITEM 5.	Other Information	56
ITEM 6.	Exhibits	56

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL INFORMATION

RENEWABLE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(in thousands, except share and per share amounts)



	June 30, 2019			December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	61,597		$	123,575
Marketable securities	—			50,932
Accounts receivable (net of allowance for doubtful accounts of $626 and $673, respectively)	75,207			74,551
Inventories	171,397			168,900
Prepaid expenses and other assets	40,654			41,169
Restricted cash	3,000			3,000
Current assets held for sale	—			3,250
Total current assets	351,855			465,377
Property, plant and equipment, net	591,710			590,723
Right of use assets	43,490			—
Goodwill	16,080			16,080
Intangible assets, net	12,802			13,646
Other assets	21,466			21,270
TOTAL ASSETS	$	1,037,403		$	1,107,096
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Lines of credit	$	70,854		$	14,250
Current maturities of long-term debt	83,324			149,006
Current maturities of operating lease obligations	18,580			—
Accounts payable	107,246			95,866
Accrued expenses and other liabilities	24,570			35,256
Deferred revenue	4,536			300
Total current liabilities	309,110			294,678
Unfavorable lease obligation	—			2,259
Deferred income taxes	7,879			8,410
Long-term debt (net of debt issuance costs of $3,063 and $3,390, respectively)	30,454			33,421
Long-term operating lease obligations	35,577			—
Other liabilities	1,562			3,075
Total liabilities	384,582			341,843
COMMITMENTS AND CONTINGENCIES
EQUITY:
Common stock ($.0001 par value; 300,000,000 shares authorized; 38,958,744 and 37,318,942 shares outstanding, respectively)	5			5
Common stock—additional paid-in-capital	444,636			451,427
Retained earnings	315,227			427,244
Accumulated other comprehensive income	(1,623		)	(1,656		)
Treasury stock (10,399,818 and 11,524,975 shares outstanding, respectively)	(105,424		)	(111,767		)
Total equity	652,821			765,253
TOTAL LIABILITIES AND EQUITY	$	1,037,403		$	1,107,096

See notes to condensed consolidated financial statements.

RENEWABLE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

(in thousands, except share and per share amounts)



	Three months ended						Six months ended
	June 30, 2019			June 30, 2018			June 30, 2019			June 30, 2018
REVENUES:
Biomass-based diesel sales	$	540,019		$	551,109		$	995,225		$	825,870
Separated RIN sales	19,596			26,186			42,059			73,365
Biomass-based diesel government incentives	530			915			998			366,200
	560,145			578,210			1,038,282			1,265,435
Other revenue	498			690			570			1,467
	560,643			578,900			1,038,852			1,266,902
COSTS OF GOODS SOLD:
Biomass-based diesel	580,133			510,375			1,064,546			916,184
Separated RINs	7,282			11,011			13,867			43,749
Other costs of goods sold	—			—			3			—
	587,415			521,386			1,078,416			959,933
GROSS PROFIT (LOSS)	(26,772		)	57,514			(39,564		)	306,969
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	26,865			24,512			52,010			56,166
RESEARCH AND DEVELOPMENT EXPENSE	176			27			385			1,061
IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT	468			—			468			—
INCOME (LOSS) FROM OPERATIONS	(54,281		)	32,975			(92,427		)	249,742
OTHER INCOME (EXPENSE), NET:
Change in fair value of contingent consideration	(398		)	(30		)	(702		)	(488		)
Gain (loss) on debt extinguishment	—			2,337			(2		)	2,105
Gain on involuntary conversion	—			454			—			4,454
Other income, net	691			2,066			1,545			3,279
Interest expense	(3,737		)	(4,925		)	(7,956		)	(9,576		)
	(3,444		)	(98		)	(7,115		)	(226		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(57,725		)	32,877			(99,542		)	249,516
INCOME TAX BENEFIT (EXPENSE)	90			(3,835		)	520			(2,632		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(57,635		)	29,042			(99,022		)	246,884
NET INCOME (LOSS) ON DISCONTINUED OPERATIONS (NOTE 4)	(4,462		)	4,808			(6,479		)	1,353
NET INCOME (LOSS) TO THE COMPANY	$	(62,097	)	$	33,850		$	(105,501	)	$	248,237
LESS—EFFECT OF PARTICIPATING SHARE-BASED AWARDS ON CONTINUING OPERATIONS	—			765			—			6,222
NET INCOME (LOSS) FROM CONTINUING OPERATIONS ATTRIBUTABLE TO THE COMPANY’S COMMON STOCKHOLDERS	$	(57,635	)	$	28,277		$	(99,022	)	$	240,662
LESS—EFFECT OF PARTICIPATING SHARE-BASED AWARDS ON DISCONTINUED OPERATIONS	—			127			—			34
NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS ATTRIBUTABLE TO THE COMPANY’S COMMON STOCKHOLDERS	$	(4,462	)	$	4,681		$	(6,479	)	$	1,319
Basic net income (loss) per share attributable to common stockholders:
Continuing operations	$	(1.52	)	$	0.76		$	(2.63	)	$	6.31
Discontinued operations	$	(0.12	)	$	0.13		$	(0.17	)	$	0.03
Net income (loss) per share	$	(1.64	)	$	0.88		$	(2.81	)	$	6.35
Diluted net income (loss) per share attributable to common stockholders:
Continuing operations	$	(1.52	)	$	0.67		$	(2.63	)	$	5.91
Discontinued operations	$	(0.12	)	$	0.11		$	(0.17	)	$	0.03
Net income (loss) per share	$	(1.64	)	$	0.78		$	(2.81	)	$	5.94
Weighted-average shares used to compute basic net income (loss) per share attributable to common stockholders:
Basic	37,851,735			37,413,387			37,603,921			38,112,531
Weighted-average shares used to compute diluted net income (loss) per share attributable to common stockholders:
Continuing operations	37,851,735			42,081,341			37,603,921			40,713,114
Discontinued operations	37,851,735			42,081,341			37,603,921			40,713,114
Net income (loss)	37,851,735			42,081,341			37,603,921			40,713,114

See notes to condensed consolidated financial statements.

RENEWABLE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)

(in thousands)



	Three months ended						Six months ended
	June 30, 2019			June 30, 2018			June 30, 2019			June 30, 2018
Net income (loss)	$	(62,097	)	$	33,850		$	(105,501	)	$	248,237
Unrealized gains on marketable securities, net of taxes of $0 and $0, respectively	1			—			—			—
Foreign currency translation adjustments	394			(1,823		)	33			(1,104		)
Other comprehensive income (loss)	395			(1,823		)	33			(1,104		)
Comprehensive income (loss) attributable to the Company	$	(61,702	)	$	32,027		$	(105,468	)	$	247,133

See notes to condensed consolidated financial statements.

RENEWABLE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(unaudited)

(in thousands, except share amounts)



	Company Stockholders’ Equity
	Common Stock Shares		Common Stock		Common Stock - Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total
BALANCE, January 1, 2018	38,837,749		$	5	$	515,452		$	134,928	$	278		$	(83,081	)	$	567,582
Conversion of restricted stock units to common stock (net of 51,995 shares of treasury stock purchased)	127,470		—		—			—		—			(621		)	(621		)
Settlement of stock appreciation rights in common stock (net of 14,558 shares of treasury stock purchased)	33,463		—		—			—		—			(172		)	(172		)
Partial termination of capped call options	(15,012	)	—		252			—		—			(167		)	85
Convertible debt extinguishment impact (net of tax impact of $68)	—		—		(440		)	—		—			—			(440		)
Treasury stock purchases	(641,601	)	—		—			—		—			(7,828		)	(7,828		)
Stock compensation expense	—		—		1,794			—		—			—			1,794
Other comprehensive income	—		—		—			—		719			—			719
Net income	—		—		—			214,389		—			—			214,389
BALANCE, March 31, 2018	38,342,069		$	5	$	517,058		$	349,317	$	997		$	(91,869	)	$	775,508
Conversion of restricted stock units to common stock (net of 88,651 shares of treasury stock purchased)	149,362		—		—			—		—			(1,516		)	(1,516		)
Settlement of stock appreciation rights in common stock (net of 28,036 shares of treasury stock purchased)	63,549		—		(95		)	—		—			(485		)	(580		)
Convertible debt extinguishment impact (net of tax impact of $2,267)	—		—		(23,634		)	—		—			—			(23,634		)
Treasury stock purchases	(1,296,243	)	—		—			—		—			(17,220		)	(17,220		)
Stock compensation expense	—		—		2,203			—		—			—			2,203
Other comprehensive income	—		—		—			—		(1,823		)	—			(1,823		)
Net income	—		—		—			33,850		—			—			33,850
BALANCE, June 30, 2018	37,258,737		$	5	$	495,532		$	383,167	$	(826	)	$	(111,090	)	$	766,788



	Company Stockholders’ Equity
	Common Stock Shares		Common Stock		Common Stock - Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total
BALANCE, January 1, 2019	37,318,942		$	5	$	451,427		$	427,244		$	(1,656	)	$	(111,767	)	$	765,253
Conversion of restricted stock units to common stock (net of 138,012 shares of treasury stock purchased)	283,339		—		—			—			—			(2,760		)	(2,760		)
Settlement of stock appreciation rights in common stock (net of 9,888 shares of treasury stock purchased)	16,937		—		(12		)	—			—			(159		)	(171		)
Partial termination of capped call options	(1,087	)	—		30			—			—			(30		)	—
Convertible debt extinguishment impact	—		—		(152		)	—			—			—			(152		)
Stock compensation expense	—		—		1,353			—			—			—			1,353
Other comprehensive loss	—		—		—			—			(362		)	—			(362		)
Adoption of ASC Topic 842, Leases	—		—		—			(6,516		)	—			—			(6,516		)
Net loss	—		—		—			(43,404		)	—			—			(43,404		)
BALANCE, March 31, 2019	37,618,131		$	5	$	452,646		$	377,324		$	(2,018	)	$	(114,716	)	$	713,241
Conversion of restricted stock units to common stock (net of 805 shares of treasury stock purchased)	58,759		—		—			—			—			(518		)	(518		)
Settlement of stock appreciation rights in common stock (net of 2,274 shares of treasury stock purchased)	4,631		—		(7		)	—			—			(17		)	(24		)
Settlement of 2019 Convertible Senior Notes conversion premium	1,902,781		—		(18,779		)	—			—			18,779			—
Termination of capped call options	(625,558	)	—		8,952			—			—			(8,952		)	—
Stock compensation expense	—		—		1,824			—			—			—			1,824
Other comprehensive income	—		—		—			—			395			—			395
Net loss	—		—		—			(62,097		)	—			—			(62,097		)
BALANCE, June 30, 2019	38,958,744		$	5	$	444,636		$	315,227		$	(1,623	)	$	(105,424	)	$	652,821

See notes to condensed consolidated financial statements.

RENEWABLE ENERGY GROUP, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)



	Six months ended
	June 30, 2019			June 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(105,501	)	$	248,237
Net income (loss) from discontinuing operations	(6,479		)	1,353
Net income (loss) from continuing operations	(99,022		)	246,884
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation expense	18,241			17,743
Amortization expense of assets and liabilities, net	10,316			596
Gain on involuntary conversion	—			(4,454		)
Accretion of convertible note discount	2,092			2,651
Amortization of marketable securities	(146		)	—
Change in fair value of contingent consideration	702			488
Gain on sale of assets	—			(977		)
(Gain) loss on debt extinguishment	2			(2,105		)
Provision (benefit) for doubtful accounts	(120		)	144
Impairment of property, plant and equipment	468			—
Stock compensation expense	3,177			3,997
Deferred tax expense	(530		)	2,584
Other operating activities	76			(359		)
Changes in assets and liabilities:
Accounts receivable, net	(1,798		)	(1,085		)
Inventories	(2,645		)	(6,625		)
Prepaid expenses and other assets	3,997			30,498
Accounts payable	7,178			42,267
Accrued expenses and other liabilities	(4,131		)	(17,032		)
Operating lease obligations	(8,231		)	—
Deferred revenue	4,236			(2,058		)
Net cash flows (used in) provided by operating activities - continuing operations	(66,138		)	313,157
Net cash flows used in operating activities - discontinuing operations	(6,794		)	(1,619		)
Cash (used in) provided by operating activities	(72,932		)	311,538
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for marketable securities	(3,478		)	—
Cash received from maturities of marketable securities	54,584			—
Cash receipts for involuntary conversion	—			4,454
Cash paid for purchase of property, plant and equipment	(18,032		)	(28,845		)
Cash receipts for sale of assets	—			1,599
Cash paid for investments	(1,203		)	—
Net cash flows provided by (used in) investing activities - continuing operations	31,871			(22,792		)
Net cash flows provided by (used in) investing activities - discontinuing operations	3,100			(335		)
Cash provided by (used in) investing activities	34,971			(23,127		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings (repayments) on revolving line of credit	54,490			(57,288		)
Borrowings on other lines of credit	36,925			28,477
Repayments on other lines of credit	(34,728		)	(28,712		)
Cash received from notes payable	—			10,933
Cash paid on notes payable	(71,068		)	(63,613		)
Cash paid for debt issuance costs	(58		)	(249		)
Cash paid for treasury stock	—			(25,048		)
Cash paid for contingent consideration settlement	(6,128		)	(5,659		)
Cash received on partial termination of capped call options	—			85
Cash paid for conversion of restricted stock units and stock appreciation rights	(3,473		)	(2,889		)
Net cash flows used in financing activities - continuing operations	(24,040		)	(143,963		)
Net cash flows used in financing activities - discontinuing operations	—			—
Cash used in financing activities	(24,040		)	(143,963		)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(62,001		)	144,448
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, Beginning of period	126,575			77,627
Effect of exchange rate changes on cash	23			(300		)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, End of period	$	64,597		$	221,775

(continued)

RENEWABLE ENERGY GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)



	Six months ended
	June 30, 2019			June 30, 2018
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash paid for income taxes	$	1,259		$	613
Cash paid for interest	$	4,734		$	6,694
Leased assets obtained in exchange for new operating lease liabilities	$	8,528		$	—

SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
Amounts included in period-end accounts payable for:
Purchases of property, plant and equipment	$	5,446		$	1,511
Issuance of treasury stock to settle 2019 Convertible Senior Notes conversion premium	$	(18,779	)	$	—
Receipt in treasury stock for settlement of capped call options	$	8,952		$	—

(concluded)

See notes to condensed consolidated financial statements.

RENEWABLE ENERGY GROUP, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For The Three and Six Months Ended June 30, 2019 and 2018

(unaudited)

(in thousands, except share and per share amounts)

NOTE 1 — BASIS OF PRESENTATION AND NATURE OF THE BUSINESS

The condensed consolidated financial statements have been prepared by Renewable Energy Group, Inc. and its subsidiaries (the "Company" or "REG"), pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC"). Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted as permitted by such rules and regulations. All adjustments, consisting of normal recurring adjustments, have been included. Management believes that the disclosures are adequate to present fairly the financial position, results of operations and cash flows at the dates and for the periods presented. It is suggested that these interim financial statements be read in conjunction with the consolidated financial statements and the notes thereto appearing in the Company’s latest annual report on Form 10-K filed on March 7, 2019. Results for interim periods are not necessarily indicative of those to be expected for the fiscal year.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts and related disclosures. Actual results could differ from those estimates.

As of June 30, 2019, the Company owns and operates a network of fourteen biorefineries, with twelve locations in North America and two locations in Europe, which includes thirteen operating biomass-based diesel production facilities with aggregate nameplate production capacity of 520 million gallons per year ("mmgy") and one fermentation facility. Ten of these plants are “multi-feedstock capable” which allows them to use a broad range of lower-cost feedstocks, such as inedible corn oil, used cooking oil and inedible animal fats in addition to vegetable oils, such as soybean oil and canola oil. In July 2019, the Company announced the closure of the New Boston, Texas biorefinery. The plant's nameplate capacity is 15 mmgy which will reduce the Company's overall nameplate capacity to 505 mmgy.

The biomass-based diesel industry and the Company’s business have benefited from certain federal and state incentives. The federal biodiesel mixture excise tax credit (the "BTC") was retroactively reinstated on February 9, 2018, for the fiscal year 2017, but has not been reinstated for 2018 or 2019 as of the date of this report. The expiration or modification of any one or more of those incentives, could adversely affect the financial results of the Company.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The following accounting policies should be read in conjunction with a summary of the significant accounting policies the Company has disclosed in its Annual Report on Form 10-K for the year ended December 31, 2018.

Restricted Cash

The Company segregates certain cash balances as restricted cash that represent those funds required to be set aside by a contractual agreement. The Company classifies restricted cash between current and non-current assets based on the length of time of the restricted use.

As of June 30, 2019 and 2018, current restricted cash amounted to $3,000 and $0, respectively, which was held as pledges for letters of credit issued to support our operations. See the table below for reconciliation of "Cash, Cash Equivalents and Restricted Cash" in regards to the Condensed Consolidated Statements of Cash Flows:



	June 30, 2019		June 30, 2018
Cash and cash equivalents	$	61,597	$	221,775
Restricted cash	3,000		—
Total cash, cash equivalents and restricted cash in the Condensed Statements of Cash Flows	$	64,597	$	221,775

Marketable Securities

The Company’s marketable securities were classified as available-for-sale and were reported at fair value, with unrealized gains and losses, net of tax, recorded in accumulated other comprehensive income (loss). Realized gains or losses and declines in value judged to be other-than-temporary, if any, on available-for-sale securities are reported in other income, net. The Company evaluates such investments periodically for possible other-than-temporary impairment. A decline of fair value below

amortized costs of debt securities is considered an other-than-temporary impairment if the Company has the intent to sell the security or if it is more likely than not that the Company will be required to sell the security before recovery of the entire amortized cost basis. In those instances, an impairment charge equal to the difference between the fair value and the amortized cost basis is recognized in earnings. Regardless of the Company’s intent or requirement to sell a debt security, an impairment is considered other-than-temporary if the Company does not expect to recover the entire amortized cost basis; in those instances, a credit loss equal to the difference between the present value of the cash flows expected to be collected based on credit risk and the amortized cost basis of the debt security is recognized in earnings. There were no marketable securities as of June 30, 2019 as the balance has been utilized to settle the 2019 Senior Convertible Notes that matured on June 15, 2019. Refer to "Note 7 - Debt" for further detail.

Renewable Identification Numbers ("RINs")

When the Company produces and sells a gallon of biomass-based diesel, 1.5 to 1.7 RINs per gallon are generated. RINs are used to track compliance with the Renewable Fuel Standard ("RFS2"). RFS2 allows the Company to attach between zero and 2.5 RINs to any gallon of biomass-based diesel. As a result, a portion of the selling price for a gallon of biomass-based diesel is generally attributable to RFS2 compliance. However, RINs that the Company generates are a form of government incentive and not a result of the physical attributes of the biomass-based diesel production. Therefore, no cost is allocated to the RIN when it is generated, regardless of whether the RIN is transferred with the biomass-based diesel produced or held by the Company pending attachment to other biomass-based diesel production sales.

In addition, the Company also obtains RINs from third parties who have separated the RINs from gallons of biomass-based diesel. From time to time, the Company holds varying amounts of these separated RINs for resale. RINs obtained from third parties are initially recorded at their cost and are subsequently revalued at the lower of cost or net realizable value as of the last day of each accounting period. The resulting adjustments are reflected in costs of goods sold for the period. The value of these RINs is reflected in “Prepaid expenses and other assets” on the Condensed Consolidated Balance Sheets. The cost of goods sold related to the sale of these RINs is determined using the average cost method, while market prices are determined by RIN values, as reported by the Oil Price Information Service ("OPIS").

Low Carbon Fuel Standard

The Company generates Low Carbon Fuel Standard ("LCFS") credits for its low carbon fuels or blendstocks when its qualified low carbon fuels are transported into an LCFS market. LCFS credits are used to track compliance with the LCFS. As a result, a portion of the selling price for a gallon of biomass-based diesel sold into an LCFS market is also attributable to LCFS compliance. However, LCFS credits that the Company generates are a form of government incentive and not a result of the physical attributes of the biomass-based diesel production. Therefore, no cost is allocated to the LCFS credit when it is generated, regardless of whether the LCFS credit is transferred with the biomass-based diesel produced or held by the Company.

In addition, the Company also obtains LCFS credits from third-party trading activities. From time to time, the Company holds varying amounts of these third-party LCFS credits for resale. LCFS credits obtained from third parties are initially recorded at their cost and are subsequently revalued at the lower of cost or net realizable value as of the last day of each accounting period, and the resulting adjustments are reflected in costs of goods sold for the period. The value of LCFS credits obtained from third parties is reflected in “Prepaid expenses and other assets” on the Condensed Consolidated Balance Sheet. The cost of goods sold related to the sale of these LCFS credits is determined using the average cost method, while market prices are determined by LCFS values, as reported by the OPIS. At June 30, 2019 and December 31, 2018, the Company held no LCFS credits purchased from third parties.

The Company records assets acquired and liabilities assumed through the exchange of non-monetary assets based on the fair value of the assets and liabilities acquired or the fair value of the consideration exchanged, whichever is more readily determinable.

Convertible Debt

In June 2016, the Company issued $152,000 aggregate principal amount of 4% convertible senior notes due in 2036 (the "2036 Convertible Senior Notes"). See "Note 7 - Debt" for a further description of the 2036 Convertible Senior Notes. During the three and six months ended June 30, 2019 the Company made no repurchases of the 2036 Convertible Senior Notes. For the three and six months ended June 30, 2018, the Company used $41,763 to repurchase $24,500 principal amount of the 2036 Convertible Senior Notes. See "Security Repurchase Programs" below.

In June 2014, the Company issued $143,800 aggregate principal amount of 2.75% convertible senior notes due in 2019 (the "2019 Convertible Senior Notes"). During the six months ended June 30, 2018, the Company used $6,689 under the 2017 Program (defined below in "Security Repurchase Programs") to repurchase $6,311 principal amount of the 2019 Convertible Senior Notes. During the three months ended June 30, 2019, the 2019 Convertible Senior Notes matured. The Company

elected to settle the principal balance with cash and the excess conversion amount was satisfied by the Company issuing shares from treasury stock. 1,902,781 shares of treasury stock were issued at settlement.

Capped Call Transaction

In connection with the issuance of the 2019 Convertible Senior Notes, the Company entered into capped call transactions ("Capped Call"). The purchased capped call transactions were recorded as a reduction to common stock-additional paid-in-capital. Because this was considered to be an equity transaction and qualifies for the derivative scope exception, no future changes in the fair value of the capped call will be recorded by the Company. During 2016, in connection with the issuance of the 2036 Convertible Senior Notes, certain call options covered by the original capped call transaction were rebalanced and reset to cover 100% of the total number of shares of the Company's Common Stock underlying the remaining principal of the 2019 Convertible Senior Notes. As part of the settlement of the 2019 Convertible Senior Notes, the Company settled all related capped call options in June 2019 and received 625,558 shares of common stock. The impact of these transactions, net of tax, was reflected as an addition to Additional Paid-in Capital as presented in the Condensed Consolidated Statements of Stockholders' Equity.

Security Repurchase Programs

In December 2017, June 2018 and January 2019, the Company's Board of Directors approved a repurchase program, each of up to $75,000 of the Company's convertible notes and/or shares of common stock (the "2017 Program","2018 Program", and "2019 Program", respectively). Under these programs, the Company may repurchase convertible notes or shares from time to time in open market transactions, privately negotiated transactions or by other means. The timing and amount of repurchase transactions under each program are determined by the Company's management based on its evaluation of market conditions, share price, bond price, legal requirements and other factors. The Company made no repurchases of shares of common stock or convertible notes during the three and six months ended June 30, 2019.

The table below sets out the information regarding the activities under the 2017 Program and 2018 Program during the three and six months ended June 30, 2018:



	Three months ended June 30, 2018								Six months ended June 30, 2018
	Number of shares/ Principal amount in 000's		December 2017 Program		June 2018 Program		Both Programs		Number of shares/Principal amount in 000's		December 2017 Program		June 2018 Program		Both Programs
Repurchases of shares of common stock	1,296,243		$	17,220	$	—	$	17,220	1,937,844		$	25,048	$	—	$	25,048
2019 Senior Convertible Notes Repurchases	$	—	$	—	$	—	$	—	$	6,311	$	6,689	$	—	$	6,689
2036 Senior Convertible Notes Repurchases	$	24,500	$	41,763	$	—	$	41,763	$	24,500	$	41,763	$	—	$	41,763

Revenue Recognition

The Company generally has a single performance obligation in its arrangements with customers. The Company believes for most of its contracts with customers, control is transferred at a point in time, typically upon delivery to the customers. When the Company performs shipping and handling activities after the transfer of control to the customers (e.g., when control transfers prior to delivery), they are considered as fulfillment activities, and accordingly, the costs are accrued for when the related revenue is recognized. Taxes collected from customers relating to product sales and remitted to governmental authorities are excluded from revenues. The Company generally expenses sales commissions when incurred because the amortization period would have been less than one year. The Company records these costs within selling, general and administrative expenses.

The following is a description of principal activities from which we generate revenue. Revenues from contracts with customers are recognized when control of the promised goods or services are transferred to our customers, in an amount that reflects the consideration that we expect to receive in exchange for those goods or services.


•	sales of biodiesel and renewable diesel produced at our facilities and acquired from third parties, including RINs and LCFS credits;


•	resale of petroleum acquired from third parties, along with the sale of petroleum-based products further blended with biodiesel produced at our wholly owned facilities or acquired from third parties;


•	sales of raw materials, glycerin, and other co-products of the biomass-based diesel production process;


•	other revenue, including biomass-based diesel facility management and operational services; and


•	incentive payments from federal and state governments, including the BTC, and from the USDA Advanced Biofuel Program.

Disaggregation of revenue:

All revenue recognized in the income statement, except for Biomass-based diesel Government Incentives, is considered to be revenue from contracts with customers. The following table depicts the disaggregation of revenue according to product line and segment:



	Reportable Segments
Three months ended June 30, 2019	Biomass-based Diesel		Services		Corporate and other		Intersegment Revenues			Consolidated Total
Biomass-based diesel sales, net of BTC related amount due to customers of $0	$	430,971	$	—	$	—	$	(1,158	)	$	429,813
Petroleum diesel sales	—		—		78,184		—			78,184
Other biomass-based diesel revenue	32,022		—		—		—			32,022
Separated RIN sales	19,596		—		—		—			19,596
Other revenues	—		24,139		—		(23,641		)	498
Total revenues from contracts with customers	$	482,589	$	24,139	$	78,184	$	(24,799	)	$	560,113
Biomass-based diesel government incentives	530		—		—		—			530
Total revenues	$	483,119	$	24,139	$	78,184	$	(24,799	)	$	560,643

Three months ended June 30, 2018	Biomass-based Diesel		Services		Corporate and other		Intersegment Revenues			Consolidated Total
Biomass-based diesel sales, net of BTC related amount due to customers of $0	$	484,150	$	—	$	6,103	$	(16,737	)	$	473,516
Petroleum diesel sales	—		—		47,070		—			47,070
Other biomass-based diesel revenue	30,523		—		—		—			30,523
Separated RIN sales	26,186		—		—		—			26,186
Other revenues	—		17,523		—		(16,833		)	690
Total revenues from contracts with customers	$	540,859	$	17,523	$	53,173	$	(33,570	)	$	577,985
Biomass-based diesel government incentives	915		—		—		—			915
Total revenues	$	541,774	$	17,523	$	53,173	$	(33,570	)	$	578,900



	Reportable Segments
Six months ended June 30, 2019	Biomass-based Diesel		Services		Corporate and other		Intersegment Revenues			Consolidated Total
Biomass-based diesel sales, net of BTC related amount due to customers of $0	$	746,700	$	—	$	—	$	(2,775	)	$	743,925
Petroleum diesel sales	—		—		162,087		—			162,087
Other biomass-based diesel revenue	89,213		—		—		—			89,213
Separated RIN sales	42,059		—		—		—			42,059
Other revenues	—		43,722		—		(43,152		)	570
Total revenues from contracts with customers	$	877,972	$	43,722	$	162,087	$	(45,927	)	$	1,037,854
Biomass-based diesel government incentives	998		—		—		—			998
Total revenues	$	878,970	$	43,722	$	162,087	$	(45,927	)	$	1,038,852

Six months ended June 30, 2018	Biomass-based Diesel		Services		Corporate and other		Intersegment Revenues			Consolidated Total
Biomass-based diesel sales, net of BTC related amount due to customers of $144,944	$	648,369	$	—	$	9,682	$	(32,448	)	$	625,603
Petroleum diesel sales	—		—		118,034		—			118,034
Other biomass-based diesel revenue	82,233		—		—		—			82,233
Separated RIN sales	73,365		—		—		—			73,365
Other revenues	—		52,738		—		(51,271		)	1,467
Total revenues from contracts with customers	$	803,967	$	52,738	$	127,716	$	(83,719	)	$	900,702
Biomass-based diesel government incentives	366,200		—		—		—			366,200
Total revenues	$	1,170,167	$	52,738	$	127,716	$	(83,719	)	$	1,266,902

Contract balances:

The following table provides information about receivables and contract liabilities from contracts with customers:



	June 30, 2019			December 31, 2018
Accounts receivable	$	75,207		$	74,551
Short-term contract liabilities (deferred revenue)	$	(4,536	)	$	(300	)

The Company receives payments from customers based upon contractual billing schedules; accounts receivable are recorded when the right to consideration becomes unconditional. Contract liabilities include payments received in advance of performance under the contract, and are realized with the associated revenue recognized under the contract. Significant changes to the contract liabilities during the three and six months ended June 30, 2019 and 2018 are as follows:



	April 1, 2019		Cash receipts (Payments)			Less: Impact on Revenue		Other			June 30, 2019
Deferred revenue	$	13,315	$	11,690		$	20,469	$	—		$	4,536

	April 1, 2018		Cash receipts (Payments)			Less: Impact on Revenue		Other			June 30, 2018
Deferred revenue	$	1,740	$	3,296		$	4,872	$	(3	)	$	161
Payables to customers related to BTC	150,776		(109,841		)	—		—			40,935
	$	152,516	$	(106,545	)	$	4,872	$	(3	)	$	41,096



	January 1, 2019		Cash receipts (Payments)			Less: Impact on Revenue			Other			June 30, 2019
Deferred revenue	$	300	$	40,347		$	36,111		$	—		$	4,536

	January 1, 2018		Cash receipts (Payments)			Less: Impact on Revenue			Other			June 30, 2018
Deferred revenue	$	2,218	$	13,803		$	15,857		$	(3	)	$	161
Payables to customers related to BTC	—		(109,841		)	(144,944		)	5,832			40,935
	$	2,218	$	(96,038	)	$	(129,087	)	$	5,829		$	41,096

Discontinued Operations

Income (loss) from discontinued operations mainly relates to the research and development activities and the sale of REG Life Sciences, the Company's industrial biotechnology business, which had been classified as assets held for sale following our decision to pursue a sale of this business in the fourth quarter of 2018. In May 2019, the Company entered into a sale and purchase agreement to sell REG Life Sciences core assets and business. See "Note 4 - Discontinued Operations" for further details.

New Accounting Standards

On February 25, 2016, the FASB issued Accounting Standard Update ("ASU") 2016-02, Topic 842, Leases, which introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in ASC 606, the FASB’s new revenue recognition standard (e.g., those related to evaluating when profit can be recognized). Furthermore, the ASU addresses other concerns related to the current leases model.

On July 19, 2018, the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases, which addresses certain aspects of the new leases standard, including the rate implicit in the lease, impairment of the net investment in the lease, lessee reassessment of lease classification, lessor reassessment of lease term and purchase options, variable payments that depend on an index or rate and certain transition adjustments, among other things. On July, 31, 2018, the FASB issued ASU 2018-11, Codification Improvements to Topic 842, Leases, which provides entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption.

The Company adopted all of the ASU's related to ASC 842 effective January 1, 2019. The Company applied a modified retrospective transition approach. The Company did not elect the practical expedient (1) to reassess the lease classification for any expired or existing leases; (2) to reassess whether any expired or existing contracts are or contain leases and (3) to reassess initial direct costs. The Company elected the hindsight practical expedient to determine the reasonably certain lease term for existing leases and to assess the impairment of its right-of-use assets. While lease classification remained unchanged, hindsight resulted in generally shorter accounting lease terms and useful lives of the corresponding right of use assets. The hindsight analysis also resulted in an approximate negative impact on beginning retained earnings of $7,000, related to the impairment of a right-of-use asset at the Company's New Orleans facility. The Company elected the transitional practical expedient for existing or expired land easements, allowing the Company to elect not to assess whether those land easements are, or contain, leases in accordance with ASC 842. The Company also elected the practical expedient to adjust the carrying amount of the right-of-use assets for the unfavorable lease liability previously recognized on the balance sheet. Additionally, the Company made an accounting policy election that keeps leases with an initial term of 12 months or less off of the balance sheet and resulted in recognizing those lease payments in the Condensed Consolidated Statements of Operations on a straight-line basis over the lease term. Refer to "Note 8 - Leases" for further detail.

On August 28, 2017, the FASB issued ASU 2017-12, which amends the hedge accounting recognition and presentation requirements in ASC 815 to (1) improve the transparency and understandability of information conveyed to financial statement users about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and (2) reduce the complexity of and simplify the application of hedge accounting by preparers. For public business entities, the amendments in ASU 2017-12 are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Company believes that the ASU 2017-12 will allow more of its derivative contracts to qualify for hedge accounting elections. The Company adopted ASU 2017-12 effective January 1, 2019, and changes in fair value of derivatives continue to be recognized in current period earnings for the three and six months ended June 30, 2019.

On November 7, 2018, the FASB issued ASU 2018-16, which permits entities to use the Overnight Index Swap ("OIS") Rate based on Secured Overnight Financing Rate ("SOFR") as an eligible benchmark interest rate during the early stages of the transition from LIBOR to SOFR. For public business entities, the amendments in ASU 2018-16 are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Company's adoption of ASU 2018-16 did not have a material impact on its consolidated financial statements.

On June 16, 2016, the FASB issued ASU 2016-13, which amends the Board's guidance on the impairment of financial instruments. The ASU 2016-13 adds to U.S. GAAP an impairment model (known as the current expected credit loss (CECL) model) that is based on expected losses rather than incurred losses. Under this new guidance, an entity recognizes as an allowance its estimate of expected credit losses. For public companies, the ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. On May 15, 2019. the FASB issued ASU 2019-05, which allows companies to elect a fair value option under Subtopic 825-10 as targeted transition relief for comparability purposes of some financial instruments. The transition relief is effective at the same time as ASU 2016-13. The Company is evaluating the impact of the guidance, but does not expect it to have any material impact on its consolidated financial statements.

On August 28, 2018, the FASB issued ASU 2018-13, which changes the fair value measurement disclosure requirements of ASC 820. ASU 2018-13 eliminates or modifies certain disclosure requirements of ASC 820 and requires new disclosures relating to changes in unrealized gains or losses included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the applicable reporting period. ASU 2018-13 also explicitly requires entities to disclose the range and weighted average used to develop significant unobservable inputs for Level 3 fair value measurements. ASU 2018-13 is effective for all entities for fiscal years beginning after December 15, 2019, including interim periods therein. The Company is evaluating the impact of this guidance on its consolidated financial statements, but does not expect the impact to be significant.

NOTE 3 — INVENTORIES

Inventories consist of the following:



	June 30, 2019		December 31, 2018
Raw materials	$	56,547	$	40,348
Work in process	3,915		3,840
Finished goods	110,935		124,712
Total	$	171,397	$	168,900

Inventories are valued at the lower of cost or net realizable value. Cost is determined based on the first-in, first-out method. There were no lower of cost or market adjustments made to the inventory values reported as of June 30, 2019 and December 31, 2018.

NOTE 4 — DISCONTINUED OPERATIONS

In the fourth quarter of 2018, concluding a comprehensive strategic assessment of the Company's development-stage industrial biotechnology business, REG Life Sciences, the Company's Board of Directors authorized it to pursue a plan to sell the REG Life Sciences core assets and business. The Company recorded an impairment loss, net of tax, of $11,226 on classifying the REG Life Sciences assets as held for sale reflecting the fair value of the estimated proceeds from the sale, net of costs to sell for the year ended December 31, 2018. This valuation technique was considered as Level 3 pricing category.

In May 2019, the Company entered into a sale and purchase agreement to sell REG Life Sciences core assets and business. The Company recorded a loss, net of tax, on sale of assets of $1,250.

REG Life Sciences' results for all periods and for the three and six months ended June 30, 2019 are classified as discontinued operations. There was no income tax impact from discontinued operations for all periods.

Loss on Discontinued Operations:



	For the three months ended June 30,						For the six months ended June 30,
	2019			2018			2019			2018
Other revenues	$	—		$	1,250		$	1,786		$	2,500
Other costs of goods sold	—			(1,143		)	(2,200		)	(2,281		)
Research and development expense	(3,205		)	(2,458		)	(4,803		)	(8,022		)
Other income (expense), net	(7		)	7,159			(12		)	9,157
Loss on sale of assets	(1,250		)	—			(1,250		)	—
Pre-tax income (loss) from discontinued operations	(4,462		)	4,808			(6,479		)	1,354
Income tax expense	—			—			—			—
Net income (loss) on discontinued operations	$	(4,462	)	$	4,808		$	(6,479	)	$	1,354

Reconciliation of the Carrying Amounts of Major Classes of Assets and Liabilities Included in Assets and Liabilities Held for Sale:



	June 30, 2019		December 31, 2018
Machinery and equipment, net	$	—	$	824
In-process research and development	—		13,652
Impairment recognized on assets classified as held for sale	—		(11,226		)
Total assets classified as held for sale	$	—	$	3,250

NOTE 5 — OTHER ASSETS

Prepaid expense and other assets consist of the following:



	June 30, 2019		December 31, 2018
Commodity derivatives and related collateral, net	$	6,080	$	13,799
Prepaid expenses	18,231		17,187
Deposits	3,543		2,123
RIN inventory	5,354		2,000
Taxes receivable	2,458		2,991
Other	4,988		3,069
Total	$	40,654	$	41,169

RIN inventory values were adjusted in the amounts of $0 and $630 at June 30, 2019 and December 31, 2018, respectively, to reflect the lower of cost or net realizable value.

Other noncurrent assets consist of the following:



	June 30, 2019		December 31, 2018
Investments	$	14,256	$	13,053
Spare parts inventory	2,680		2,680
Catalysts	1,632		1,989
Deposits	552		381
Other	2,346		3,167
Total	$	21,466	$	21,270

NOTE 6— INTANGIBLE ASSETS

Intangible assets consist of the following:



	June 30, 2019
	Cost		Accumulated Amortization			Net
Raw material supply agreement	$	6,230	$	(3,113	)	$	3,117
Renewable diesel technology	8,300		(2,813		)	5,487
Ground lease	200		(164		)	36
Acquired customer relationships	4,747		(1,289		)	3,458
Trademarks	704		—			704
Total intangible assets	$	20,181	$	(7,379	)	$	12,802



	December 31, 2018
	Cost		Accumulated Amortization			Net
Raw material supply agreement	$	6,230	$	(2,866	)	$	3,364
Renewable diesel technology	8,300		(2,536		)	5,764
Ground lease	200		(157		)	43
Acquired customer relationships	4,747		(976		)	3,771
Trademarks	704		—			704
Total intangible assets	$	20,181	$	(6,535	)	$	13,646

The Company recorded intangible amortization expense of $510 and $844 for the three and six months ended June 30, 2019, and $327 and $651 for the three and six months ended June 30, 2018, respectively.

The estimated intangible asset amortization expense for the remainder of 2019 through 2025 and thereafter is as follows:



July 1, 2019 through December 31, 2019	$	854
2020	1,686
2021	1,692
2022	1,685
2023	1,693
2024	1,700
2025 and thereafter	3,492
Total	$	12,802

NOTE 7 — DEBT

The following table shows the Company’s term debt:



	June 30, 2019		December 31, 2018
4.00% Convertible Senior Notes, $96,300 face amount, due in June 2036	$	76,406	$	75,477
2.75% Convertible Senior Notes, due in June 2019	—		66,361
REG Danville term loan, secured, variable interest rate of LIBOR plus 4%, due in July 2022	7,924		8,964
REG Ralston term loan, variable interest rate of Prime Rate plus 2.25%, due in October 2025	17,350		18,948
REG Grays Harbor term loan, variable interest of minimum of 3.5% or Prime Rate plus 0.25%, due in May 2022	8,061		8,828
REG Capital term loan, fixed interest rate of 3.99%, due in January 2028	7,058		7,185
Other	42		54
Total term debt before debt issuance costs	116,841		185,817
Less: Current portion of long-term debt	83,324		149,006
Less: Debt issuance costs (net of accumulated amortization of $4,201 and $3,813, respectively)	3,063		3,390
Total long-term debt	$	30,454	$	33,421

2019 Convertible Senior Notes

In June 2014, the Company issued $143,800 in convertible senior notes (the "2019 Convertible Senior Notes") with a maturity date of June 15, 2019, unless earlier converted or repurchased. The 2019 Convertible Senior Notes bear interest at a rate of 2.75% per annum, payable semi-annually in arrears, beginning December 15, 2014. The initial conversion rate was 75.3963 shares of Common Stock per $1,000 principal amount of 2019 Convertible Senior Notes, which represented an initial conversion price of approximately $13.26 per share.

On June 15, 2019, the 2019 Convertible Senior Notes matured. The Company elected to settle all conversions of each $1,000 principal amount of such notes being converted on or after October 23, 2018, with $1,000 in cash and any conversion value in excess of that amount in shares of the Company's common stock. The Company paid $67,380 in cash to settle the outstanding principal amount, and issued 1,902,781 treasury shares at an average share price of $9.87 to settle the conversion value that was in excess of the principal.

In connection with the issuance of the Convertible Notes, the Company entered into capped call transactions in private transactions. Under the Capped Call, the Company purchased capped call options that in aggregate relate to 92.5% of the total number of shares of the Company's Common Stock underlying the Convertible Notes, with a strike price equal to the conversion price of the Convertible Notes and with a cap price equal to $16.02 per share. As part of the settlement of the 2019 Convertible Senior Notes, the Company settled all related capped call options in June 2019 and received 625,558 shares of common stock. The impact of this transaction, net of tax, was reflected as an addition to Additional Paid-in Capital as presented in the Condensed Consolidated Statements of Stockholders' Equity.

2036 Convertible Senior Notes

On June 2, 2016, the Company issued $152,000 aggregate principal amount of the 2036 Convertible Senior Notes in a private offering to qualified institutional buyers. The 2036 Convertible Senior Notes bear interest at a rate of 4.00% per year payable semi-annually in arrears on June 15 and December 15 of each year, beginning December 15, 2016. The notes will mature on June 15, 2036, unless repurchased, redeemed or converted in accordance with their terms prior to such date.

Prior to December 15, 2035, the 2036 Convertible Senior Notes will be convertible only upon satisfaction of certain conditions and during certain periods as stipulated in the indenture. On or after December 15, 2035 until the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2036 Convertible Senior Notes may convert their notes at any time. The 2036 Convertible Senior Notes may be settled in cash, the Company’s common shares or a combination of cash and the Company’s common shares, at the Company’s election. The Company may not redeem the 2036 Convertible Senior Notes prior to June 15, 2021. Holders of the 2036 Convertible Senior Notes will have the right to require the Company to repurchase for cash all or some of their notes at 100% of their principal, plus any accrued and unpaid interest on each of June 15, 2021, June 15, 2026 and June 15, 2031. Holders of the 2036 Convertible Senior Notes will have the

right to require the Company to repurchase for cash all or some of their notes at 100% of their principal, plus any accrued and unpaid interest upon the occurrence of certain fundamental changes. The initial conversion rate is 92.8074 common shares per $1,000 (one thousand) principal amount of 2036 Convertible Senior Notes (equivalent to an initial conversion price of approximately $10.78 per common share).

In addition, the 2036 Convertible Senior Notes will become convertible in the subsequent quarter if the closing price of the Company’s common stock exceeds $14.01, 130% of the Convertible Senior Notes’ initial conversion price, for at least 20 trading days during the 30 consecutive trading days prior to each quarter-end date. If the 2036 Convertible Senior Notes become convertible and should the holders elect to convert, the Company’s current intent is to settle the principal amount the 2036 Convertible Senior Notes in cash, with the remaining value satisfied at the Company’s option in cash, stock or a combination of cash and stock. As of June 30, 2019 and December 31, 2018, the early conversion event was met based on the Company's stock price and as a result, the 2036 Convertible Senior Notes have been classified as a current liability on the Company's Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018.

The net proceeds from the offering of the 2036 Convertible Senior Notes were approximately $147,118, after deducting fees and offering expenses of $4,882, which was capitalized as debt issuance costs and is being amortized through June 2036. The debt discount is to be amortized through June 2036. The effective interest rate on the debt liability component was 2.45%.

Lines of Credit And Subsequent Event

The following table shows the Company's lines of credit:



	June 30, 2019		December 31, 2018
Amount outstanding under lines of credit	$	70,854	$	14,250
Maximum available to be borrowed under lines of credit	$	67,874	$	114,889

The Company's wholly-owned subsidiaries, REG Services Group, LLC and REG Marketing & Logistics Group, LLC, are borrowers under a Credit Agreement dated December 23, 2011 with the lenders party thereto (“Lenders”) and Wells Fargo Capital Finance, LLC, as the agent, (as amended, the “M&L and Services Revolver”). The maximum commitment of the Lenders under the M&L and Services Revolver to make revolving loans is $150,000, subject to an accordion feature, which allows the borrowers to request commitments for additional revolving loans in an aggregate amount not to exceed to $50,000, the making of which is subject to customary conditions, including the consent of Lenders providing such additional commitments.

The maturity date of the M&L and Services Revolver is September 30, 2021. Loans advanced under the M&L and Services Revolver bear interest based on a one-month LIBOR rate (which shall not be less than zero), plus a margin based on Quarterly Average Excess Availability (as defined in the Revolving Credit Agreement), which may range from 1.75% per annum to 2.25% per annum.

The M&L and Services Revolver contains various loan covenants that restrict each subsidiary borrower’s ability to take certain actions, including restrictions on incurrence of indebtedness, creation of liens, mergers or consolidations, dispositions of assets, repurchase or redemption of capital stock, making certain investments, making distributions to the Company unless certain conditions are satisfied, entering into certain transactions with affiliates or changing the nature of the subsidiary’s business. In addition, the subsidiary borrowers are required to maintain a fixed charge coverage ratio of at least 1.0 to 1.0 if excess availability under the M&L and Services Revolver is less than 10% of the total $150,000 of current revolving loan commitments, or $15,000 currently. The M&L and Services Revolver is secured by the subsidiary borrowers’ membership interests and substantially all of their assets. In addition, the M&L and Services Revolver is secured by the accounts receivable and inventory of REG Albert Lea, LLC, REG Houston, LLC, REG New Boston, LLC, REG Geismar, LLC, and REG Seneca, LLC (collectively, the "Plant Loan Parties") subject to a $40,000 limitation with respect to each of the Plant Loan Parties.

On July 9, 2019, the Company entered into an agreement with the lenders of the M&L and Services Revolver to provide the Company the ability to increase the maximum borrowing amount on the line of credit to $175,000, or $200,000 if the BTC is retroactively reinstated for 2018 and/or 2019. This agreement is for a specified period from the date of the agreement through October 31, 2019.

REG Germany has a trade finance facility agreement ("Uncommitted Credit Facility Agreement") with BNP Paribas, which allows it to borrow up to $25,000 for funding the purchase of goods and services. Amounts outstanding under the Uncommitted Credit Facility Agreement bear variable interest and are payable as stipulated in the agreement. The amount that can be borrowed under the agreement can be amended, cancelled or restricted at BNP Paribas's sole discretion and therefore is

not included in the maximum available to be borrowed under lines of credit above. The Uncommitted Credit Facility Agreement contains various loan covenants that require REG Germany to maintain certain financial measures. At June 30, 2019, the nominal interest rates ranged from 1.50% to 4.39% per annum.

NOTE 8 — LEASES

The Company leases land, property and equipment under certain operating leases. The Company's leases consist primarily of access to distribution terminals, biomass-based diesel and feedstock storage tanks, railcars and vehicles. The Company determines at the inception of a lease whether an arrangement that provides the Company control over the use of an asset is a lease. The Company recognizes at lease commencement a right-of-use ("ROU") asset and lease liability based on the present value of the future lease payments over the lease term. As discussed in Note 2, the Company has elected not to recognize a ROU asset and lease liability for leases with terms of 12 months or less. At the end of the lease term the Company, generally, has the option to (a) return the leased equipment to the lessor, (b) purchase the property at its then fair value or (c) renew its lease at the fair rental value on a year-to-year basis or for an agreed upon term. When it is reasonably certain that the Company will exercise the option, the impact of the option is included in the lease term for purposes of determining total future lease payments. As most of its lease agreements do not explicitly state the discount rate implicit in the lease, the Company uses its incremental borrowing rate on the commencement date to calculate the present value of future payments.

The Company's leases commonly include payments that are based on the Consumer Price Index ("CPI") or other similar indices. If the indices are known at inception of the leases, they are included in the calculation of the ROU asset and lease liability. Other variable lease payments, such as usage-based amounts or when the indices are not known at inception, are excluded from the ROU asset and lease liability, and are expensed as incurred.

In addition to the base rent, office equipment leases typically contain provisions for maintenance services, which are considered non-lease components for accounting purposes. For these leases, non-lease components are excluded from our ROU assets and lease liabilities and expensed as incurred. For all other types of leases, we apply a practical expedient to include these non-lease components in calculating the ROU asset and lease liability.

The following table summarizes information about the Company's lease expense for the three and six months ended June 30, 2019:



	Three months ended June 30, 2019		Six months ended June 30, 2019
Lease expense:
Operating lease expense	$	5,577	$	11,050
Variable lease expenses	469		676
Short-term and other lease expenses	528		954
Total lease expense	$	6,574	$	12,680

The weighted-average remaining lease term for the Company's operating leases is 5.72 years at June 30, 2019. The weighted-average discount rate for the Company's operating leases is 4.72% as of June 30, 2019.

For each of the next five calendar years and thereafter, future minimum lease payments and scheduled maturities under operating leases that have initial or remaining noncancelable lease terms in excess of one year are as follows:



	Total payments		Less: Discount		Operating lease obligation
July 1, 2019 through December 31, 2019	$	11,385	$	1,371	$	10,014
2020	17,408		1,737		15,671
2021	13,421		1,080		12,341
2022	4,079		693		3,386
2023	2,977		560		2,417
2024	1,772		472		1,300
2025 and thereafter	11,404		2,376		9,028
Total	$	62,446	$	8,289	$	54,157

As the Company has not restated prior-year information for its adoption of ASC Topic 842, the following presents the Company's future minimum lease payments for operating leases under ASC Topic 840 at December 31, 2018:



	Total Payments
2019	$	20,326
2020	14,063
2021	10,643
2022	3,162
2023	2,406
Thereafter	13,736
Total minimum payments	$	64,336

NOTE 9 — DERIVATIVE INSTRUMENTS

The Company enters into New York Mercantile Exchange NY Harbor ULSD ("NY Harbor ULSD" or previously referred to as heating oil), CBOT Soybean Oil (previously referred to as soybean oil) and New York Mercantile Exchange Natural Gas futures, swaps and options ("commodity contract derivatives") to reduce the risk of price volatility related to anticipated purchases of feedstock raw materials and to protect cash margins from potentially adverse effects of price volatility on biomass-based diesel sales where prices are set at a future date. All of the Company’s commodity contract derivatives are designated as non-hedge derivatives and recorded at fair value on the Condensed Consolidated Balance Sheets. Unrealized gains and losses are recognized as a component of biomass-based diesel costs of goods sold reflected in current results of operations. As of June 30, 2019, the net notional volumes of NY Harbor ULSD, CBOT Soybean Oil and NYMEX Natural Gas covered under the open commodity derivative contracts were approximately 50 million gallons, 3 million pounds and 2 million million British thermal units, respectively.

The Company offsets the fair value amounts recognized for its commodity contract derivatives with cash collateral with the same counterparty under a master netting agreement. The net position is presented within prepaid and other assets in the Condensed Consolidated Balance Sheets. The following table sets forth the fair value of the Company's commodity contract derivatives and amounts that offset within the Condensed Consolidated Balance Sheets:



	June 30, 2019						December 31, 2018
	Assets			Liabilities			Assets			Liabilities
Gross amounts of derivatives recognized at fair value	$	1,121		$	3,371		$	11,843		$	1,799
Cash collateral	8,330			—			3,755			—
Total gross amount recognized	9,451			3,371			15,598			1,799
Gross amounts offset	(3,371		)	(3,371		)	(1,799		)	(1,799		)
Net amount reported in the condensed consolidated balance sheets	$	6,080		$	—		$	13,799		$	—

The following table sets forth the commodity contract derivatives gains and (losses) included in the Condensed Consolidated Statements of Operations:



	Location of Gain (Loss) Recognized in income	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
Commodity derivatives	Cost of goods sold – Biomass-based diesel	$	(5,571	)	$	(12,909	)	$	(28,310	)	$	(15,347	)

NOTE 10 — FAIR VALUE MEASUREMENT

The fair value hierarchy prioritizes the inputs used in measuring fair value as follows:


•	Level 1 — Quoted prices for identical instruments in active markets.


•	Level 2 — Quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations, in which all significant inputs are observable in active markets.


•	Level 3 — Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

A summary of assets (liabilities) measured at fair value is as follows:



	As of June 30, 2019
	Total			Level 1			Level 2			Level 3
Commodity contract derivatives	$	(2,250	)	$	(722	)	$	(1,528	)	$	—
Contingent considerations for acquisitions	$	(4,037	)	—			—			(4,037		)
	$	(6,287	)	$	(722	)	$	(1,528	)	$	(4,037	)



	As of December 31, 2018
	Total			Level 1		Level 2		Level 3
Commercial paper	$	22,872		$	—	$	22,872	$	—
Corporate bonds	$	28,060		—		28,060		—
Commodity contract derivatives	$	10,044		499		9,545		—
Contingent considerations for acquisitions	$	(9,861	)	—		—		(9,861		)
	$	51,115		$	499	$	60,477	$	(9,861	)

The following is a reconciliation of the beginning and ending balances for liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3):



	Contingent Consideration for Acquisitions
	2019			2018
Balance at beginning of period, January 1	$	9,861		$	20,485
Change in estimates included in earnings	304			459
Settlements	(3,316		)	(2,813		)
Balance at end of period, March 31	$	6,849		$	18,131
Change in estimates included in earnings	—			30
Settlements	(2,812		)	(2,846		)
Balance at end of period, June 30	$	4,037		$	15,315

The estimated fair values of the Company’s financial instruments, which are not recorded at fair value, are as follows:



	As of June 30, 2019						As of December 31, 2018
	Asset (Liability) Carrying Amount			Fair Value			Asset (Liability) Carrying Amount			Fair Value
Financial liabilities:
Debt and lines of credit	$	(187,695	)	$	(256,387	)	$	(200,067	)	$	(410,564	)

The carrying amounts reported in the Condensed Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, accounts payable and accrued expenses approximate their fair values. Money market funds are included in cash and cash equivalents on the Condensed Consolidated Balance Sheets.

The Company used the following methods and assumptions to estimate fair value of its financial instruments:

Marketable securities: The fair value of marketable securities, which include commercial papers and corporate notes/bonds is obtained using quoted prices for similar assets or liabilities in active markets; quoted prices for

identical or similar assets in markets that are not active and inputs other than quoted prices, e.g., interest rates and yield curves.

Commodity derivatives: The instruments held by the Company consist primarily of futures contracts, swap agreements, purchased put options and written call options. The fair value of contracts based on quoted prices of identical assets in an active exchange-traded market is reflected in Level 1. Contract fair value that is determined based on quoted prices of similar contracts in over-the-counter markets is reflected in Level 2.

Contingent consideration for acquisitions: The fair value of all other contingent consideration is determined using an expected present value technique. Expected cash flows are determined using the probability weighted-average of possible outcomes that would occur should the achievement of certain milestones related to the production and/or sale of biomass-based diesel at the specific production facility. A discount rate ranging from 5.8% to 12.5% is used to estimate the fair value of the expected payments.

Debt and lines of credit: The fair value of long-term debt and lines of credit was established using discounted cash flow calculations and current market rates reflecting Level 2 inputs.

NOTE 11 — NET INCOME (LOSS) PER SHARE

Basic net income (loss) per share is presented in conformity with the two-class method required for participating securities. Participating securities include restricted stock units ("RSUs").

Under the two-class method, net income is reduced for distributed and undistributed dividends earned in the current period. The remaining earnings are then allocated to Common Stock and the participating securities. The Company calculates the effects of participating securities on diluted earnings per share ("EPS") using both the “if-converted or treasury stock” and "two-class" methods and discloses the method which results in a more dilutive effect. The effects of Common Stock options, warrants, stock appreciation rights and convertible notes on diluted EPS are calculated using the treasury stock method unless the effects are anti-dilutive to EPS.

For the 2036 Convertible Senior Notes, the Company’s current intent is to settle conversions using cash for the principal amount of convertible senior notes converted, with the remaining value satisfied at the Company’s option in cash, stock or a combination of cash and stock. Therefore, the dilutive effect of the convertible senior notes is limited to the conversion premium.

The following potentially dilutive weighted average securities were excluded from the calculation of diluted net income (loss) per share attributable to common stockholders during the periods presented, as the effect was anti-dilutive:



	Three Months Ended June 30, 2019	Three Months Ended June 30, 2018	Six Months Ended June 30, 2019	Six Months Ended June 30, 2018
Stock appreciation rights	978,522	347	1,003,102	240,303
2019 Convertible Senior Notes	—	4,358,629	—	5,178,146
2036 Convertible Senior Notes	8,937,353	10,087,669	8,937,353	11,574,051
Total	9,915,875	14,446,645	9,940,455	16,992,500

The following table presents the calculation of diluted net income (loss) per share attributable to common stockholders:



	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
Net income (loss) from continuing operations attributable to the Company’s common stockholders - Basic	$	(57,635	)	$	28,277		$	(99,022	)	$	240,662
Plus (less): effect of participating securities	—			765			—			6,222
Net income (loss) attributable to common stockholders	(57,635		)	29,042			(99,022		)	246,884
Less: effect of participating securities	—			(765		)	—			(6,222		)
Net income (loss) from continuing operations attributable to the Company's common stockholders - Diluted	$	(57,635	)	$	28,277		$	(99,022	)	$	240,662

Net income (loss) from discontinued operations attributable to the Company’s common stockholders - Basic	$	(4,462	)	$	4,681		$	(6,479	)	$	1,319
Plus (less): effect of participating securities	—			127			—			34
Net income (loss) attributable to common stockholders	(4,462		)	4,808			(6,479		)	1,353
Less: effect of participating securities	—			(127		)	—			(34		)
Net income (loss) from discontinued operations attributable to the Company's common stockholders - Diluted	$	(4,462	)	$	4,681		$	(6,479	)	$	1,319

Net income (loss) attributable to the Company's common stockholders - Basic	$	(62,097	)	$	32,955		$	(105,501	)	$	241,980
Plus (less): effect of participating securities	—			895			—			6,256
Net income (loss) attributable to common stockholders	(62,097		)	33,850			(105,501		)	248,236
Less: effect of participating securities	—			(895		)	—			(6,256		)
Net income (loss) attributable to the Company's common stockholders - Diluted	$	(62,097	)	$	32,955		$	(105,501	)	$	241,980

Shares:
Weighted-average shares used to compute basic net income (loss) per share	37,851,735			37,413,387			37,603,921			38,112,531
Adjustment to reflect conversion of convertible notes	—			4,334,967			—			2,377,998
Adjustment to reflect stock appreciation right conversions	—			332,987			—			222,585
Weighted-average shares used to compute diluted net income (loss) per share	37,851,735			42,081,341			37,603,921			40,713,114

Net income (loss) per share attributable to common stockholders - Diluted
Continuing operations	$	(1.52	)	$	0.67		$	(2.63	)	$	5.91
Discontinued operations	$	(0.12	)	$	0.11		$	(0.17	)	$	0.03
Diluted net income (loss)	$	(1.64	)	$	0.78		$	(2.81	)	$	5.94

NOTE 12 — REPORTABLE SEGMENTS AND GEOGRAPHIC INFORMATION

The Company reports its reportable segments based on products and services provided to customers. The Company re-assesses its reportable segments on an annual basis. The Company's reportable segments generally align the Company's external financial reporting segments with its internal operating segments, which are based on its internal organizational structure, operating decisions and performance assessment. In the fourth quarter of 2018, concluding a comprehensive strategic assessment of the Company's Life Sciences business, which primarily represented the Renewable Chemicals reportable segment, the Company's Board of Directors authorized it to pursue a plan to sell REG Life Sciences. In May 2019, the Company entered into a sale and purchase agreement to sell REG Life Sciences core assets and business. As a result, the Company's reportable segments at June 30, 2019 and for the year ended December 31, 2018 are composed of Biomass-based Diesel, Services and Corporate and other activities. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. All prior period disclosures below have been recast to present results on a comparable basis.

The Biomass-based Diesel segment processes waste vegetable oils, animal fats, virgin vegetable oils and other feedstocks into biomass-based diesel. The Biomass-based Diesel segment also includes the Company’s purchases and resale of biomass-based diesel produced by third parties. Revenue is derived from the purchases and sales of biomass-based diesel, RINs and raw material feedstocks acquired from third parties, sales of biomass-based diesel produced under toll manufacturing arrangements with third party facilities, sales of processed biomass-based diesel from Company facilities, related by-products and renewable energy government incentive payments, in the U.S. and internationally.

The Services segment offers services for managing the construction of biomass-based diesel production facilities and managing ongoing operations of third-party plants and collects fees related to the services provided. The Company does not allocate items that are of a non-operating nature or corporate expenses to the business segments. Revenues from services provided to other segments are recorded by the Services segment at cost.

The Corporate and Other segment includes trading activities related to petroleum-based heating oil and diesel fuel as well as corporate activities, which consist of corporate office expenses such as compensation, benefits, occupancy and other administrative costs, including management service expenses. Corporate and Other also includes income/(expense) not associated with the reportable segments, such as corporate general and administrative expenses, shared service expenses, interest expense and interest income, all reflected on an accrual basis of accounting. In addition, Corporate and Other includes cash and other assets not associated with the reportable segments, including investments. Intersegment revenues are reported by the Services and Corporate and Other segments.

The following table represents the significant items by reportable segment:



	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
Net sales from continuing operations:
Biomass-based Diesel	$	483,119		$	541,774		$	878,970		$	1,170,167
Services	24,139			17,523			43,722			52,738
Corporate and Other	78,184			53,173			162,087			127,716
Intersegment revenues	(24,799		)	(33,570		)	(45,927		)	(83,719		)
	$	560,643		$	578,900		$	1,038,852		$	1,266,902
Income (loss) from continuing operations before income taxes:
Biomass-based Diesel	$	(58,647	)	$	32,394		$	(93,815	)	$	247,964
Services	1,252			(267		)	383			4,757
Corporate and Other	(330		)	750			(6,110		)	(3,205		)
	$	(57,725	)	$	32,877		$	(99,542	)	$	249,516
Depreciation and amortization expense, net:
Biomass-based Diesel	$	13,525		$	8,161		$	25,532		$	16,199
Services	586			357			1,216			685
Corporate and Other	906			714			1,809			1,455
	$	15,017		$	9,232		$	28,557		$	18,339
Cash paid for purchases of property, plant and equipment:
Biomass-based Diesel	$	9,425		$	11,447		$	17,113		$	27,049
Services	250			911			797			1,763
Corporate and Other	122			—			122			33
	$	9,797		$	12,358		$	18,032		$	28,845



	June 30, 2019			December 31, 2018
Goodwill:
Services	$	16,080		$	16,080

Assets:
Biomass-based Diesel	$	935,273		$	914,843
Services	58,870			63,720
Corporate and Other	364,916			379,658
Intersegment eliminations	(321,656		)	(254,375		)
Assets held for sale	—			3,250
	$	1,037,403		$	1,107,096

Geographic Information:

The following geographic data include net sales attributed to the countries based on the location of the subsidiary making the sale and long-lived assets based on physical location. Long-lived assets represent the net book value of property, plant and equipment.



	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Net revenues:
United States	$	517,893	$	532,860	$	956,498	$	1,172,534
Germany	40,800		43,369		80,268		89,725
Other Foreign	1,950		2,671		2,086		4,643
Non-United States	42,750		46,040		82,354		94,368
	$	560,643	$	578,900	$	1,038,852	$	1,266,902



	June 30, 2019		December 31, 2018
Long-lived assets:
United States	$	572,427	$	571,045
Germany	18,667		18,972
Other Foreign	616		706
	$	591,710	$	590,723

NOTE 13 — COMMITMENTS AND CONTINGENCIES

The Company is involved in legal proceedings in the normal course of business. The Company currently believes that any ultimate liability arising out of such proceedings will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.

NOTE 14 — SUBSEQUENT EVENT

On July 24, 2019, the Company announced the closure of its New Boston, Texas biorefinery, REG New Boston, LLC, ("REG New Boston"). REG New Boston's nameplate capacity is 15 mmgy and its closure will reduce the Company's nameplate capacity from 520 mmgy to 505 mmgy. At June 30, 2019, the net book value of REG New Boston's property, plant and equipment was $15,755.



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

This report contains forward-looking statements regarding Renewable Energy Group, Inc., or “we,” “our” or “the Company,” that involve risks and uncertainties such as anticipated financial performance, business prospects, technological developments, products, possible strategic initiatives and similar matters. In some cases, you can identify forward-looking statements by terms such as “may,” “might,” “objective,” “intend,” “should,” “could,” “can,” “would,” “expect,” “believe,” “estimate,” “predict,” “potential,” “plan,” or the negative of these terms, and similar expressions intended to identify forward-looking statements.

These forward-looking statements include, but are not limited to statements about planned capital expenditures; existing or proposed legislation affecting the biomass-based diesel industry, including governmental incentives and tax credits; the possible joint development of a renewable diesel plant with Phillips 66; our utilization of forward contracting and hedging strategies to minimize feedstock and other input price risk; our ability to renew existing and expired contracts at similar or more favorable terms; expected technological advances in biomass-based diesel production methods; statements about using acquired land to improve existing production capacity and future expansion opportunities at our Geismar facility; the market for biomass-based diesel, including the factors that affect such market and our operating results and seasonal fluctuations in demand, and potential biomass-based diesel consumers; our ability to further develop our financial, managerial and other internal controls and reporting systems to accommodate future growth; the potential impact following the establishment of applicable accounting standards; the impact of recent U.S. tax legislation on our financial condition and results of operations; expectations regarding the realization of deferred tax assets and the establishment and maintenance of tax reserves and anticipated trends; expectations regarding our expenses and sales; anticipated general market conditions; anticipated cash needs and estimates regarding capital requirements and needs for additional financing; and challenges in our business and the biomass-based diesel market.

These forward-looking statements are based on management’s current expectations, estimates, assumptions and projections, which are subject to risks and uncertainties. These risks and uncertainties could cause actual results to differ

materially from those expected. Given these uncertainties, you should not place undue reliance on these forward-looking statements. Risks and uncertainties include, but are not limited to, those risks discussed in Item 1A of Part II of this Quarterly Report on Form 10-Q. We encourage you to read this Management’s Discussion and Analysis of Financial Condition and Results of Operations in conjunction with the accompanying condensed consolidated financial statements and related notes. Forward-looking statements contained in this report present management’s views only as of the date of this report. Except as required under applicable law, we do not intend to issue updates concerning any future revisions of management’s views to reflect events or circumstances occurring after the date of this report.

Overview

We focus on providing cleaner, lower carbon transportation fuels. We are North America's largest producer of advanced biofuels. We utilize a nationwide production, distribution and logistics system as part of an integrated value chain model designed to convert natural fats, oils and greases into advanced biofuels. We believe our fully integrated approach, which includes acquiring feedstock, managing biorefinery facility construction and upgrades, operating biorefineries, and distributing fuel through a network of terminals, positions us to serve the growing market for cleaner transportation fuels. In 2018, we launched REG Ultra Clean^TMDiesel, which is among the lowest emission diesel fuels on the market today.

We own and operate a network of 14 biorefineries. Twelve biorefineries are located in the United States and two in Germany. Twelve biorefineries produce biodiesel, one produces renewable diesel (“RD”), and one is a fermentation facility. Our thirteen biomass-based diesel production facilities have an aggregate nameplate production capacity of 520 million gallons per year ("mmgy"). In July 2019, we announced the closure of our New Boston, Texas biorefinery. The nameplate capacity of this biorefinery is 15 mmgy and its closure will decrease our overall nameplate capacity to 505 mmgy.

We are a lower-cost, lower carbon biomass-based diesel producer. We primarily produce our biomass-based diesel from a wide variety of lower-cost, lower carbon feedstocks, including inedible corn oil, used cooking oil and inedible animal fat. We also produce biomass-based diesel from virgin vegetable oils, such as soybean oil or canola oil, which tend to be higher in price. We believe our ability to process a wide variety of feedstocks at most of our facilities provides us with a cost advantage over many biomass-based diesel producers, particularly those that rely primarily on higher cost virgin vegetable oils.

We also sell petroleum-based diesel fuel and heating oil, which enables us to offer a variety of fuel products to a broader customer base. We sell heating oil and ultra-low sulfur diesel, or ULSD, at terminals throughout the northeastern U.S., as well as BioHeat® blended heating fuel at one of these terminal locations. In 2018, we expanded our sales of biofuel blends to Midwest and West Coast terminal locations and look to potentially expand in other areas across North America and internationally.

Since October 2018, we have been collaborating with Phillips 66 on the possible construction of a large-scale renewable diesel plant in Washington state. The plant would utilize our propriety BioSynfining® technology for the production of renewable diesel. We have not reached a definitive agreement with Phillips 66 with respect to this potential joint development project and there is no assurance that an agreement will be reached.

In the fourth quarter of 2018, concluding a comprehensive strategic assessment of our development-stage industrial biotechnology business, our Board of Directors authorized us to pursue a plan to sell the core assets of REG Life Sciences, which comprised our Renewable Chemicals segment. As a result, the former Renewable Chemicals segment and the operations of the Renewable Chemicals segment have been classified as discontinued operation for all periods covered by this report. In May 2019, we consummated the sale of these assets. See "Note 4 - Discontinued Operations" to the Condensed Consolidated Financial Information.

In July 2019, we opened our first REG branded fueling station, adjacent to REG Seneca, a 60 million gallon-per-year biorefinery in Seneca, Illinois to serve a variety of customers from trucking fleets to local diesel vehicle owners.

During the three and six months ended June 30, 2019, we sold 197 million and 360 million total gallons of fuel, including 16 million and 33 million gallons of biomass-based diesel that we purchased from third parties and resold, 11 million and 23 million biomass-based diesel gallons produced by our facilities in Germany and 38 million and 82 million petroleum-based diesel gallons. During 2018, we sold 649 million gallons of fuel, which included 45 million biomass-based gallons we purchased from third parties, 45 million biomass-based diesel gallons produced by our facilities in Germany and 119 million petroleum-based diesel gallons.

Our businesses are organized into two reportable segments – the Biomass-based Diesel segment and the Services segment.

Biomass-based Diesel Segment

Our Biomass-based Diesel segment includes:


•	the operations of the following biomass-based diesel production refineries:


•	a 30 mmgy nameplate biodiesel production facility located in Ralston, Iowa;


•	a 35 mmgy nameplate biodiesel production facility located near Houston, Texas;


•	a 45 mmgy nameplate biodiesel production facility located in Danville, Illinois;


•	a 30 mmgy nameplate biodiesel production facility located in Newton, Iowa;


•	a 60 mmgy nameplate biodiesel production facility located in Seneca, Illinois;


•	a 30 mmgy nameplate biodiesel production facility located near Albert Lea, Minnesota;


•	a 15 mmgy nameplate biodiesel production facility located in New Boston, Texas (this facility was closed in July 2019);


•	a 30 mmgy nameplate biodiesel production facility located in Mason City, Iowa;


•	a 75 mmgy nameplate renewable diesel production facility located in Geismar, Louisiana;


•	a 27 mmgy nameplate biodiesel production facility located in Emden, Germany;


•	a 23 mmgy nameplate biodiesel production facility located in Oeding, Germany;


•	a 100 mmgy nameplate biodiesel production facility located in Grays Harbor, Washington; and


•	a 20 mmgy nameplate biodiesel production facility located in DeForest, Wisconsin.


•	purchases and resales of biomass-based diesel, petroleum-based diesel, RINs and LCFS credits, and raw material feedstocks acquired from third parties;


•	sales of biomass-based diesel produced under toll manufacturing arrangements with third-party facilities using our feedstocks; and


•	incentives received from federal and state programs for renewable fuels.

We derive a small portion of our revenues from the sale of co-products of the biomass-based diesel production process. For the six months ended June 30, 2019 and for 2018, our revenues from the sale of co-products were less than five percent of our total Biomass-based diesel segment revenues. For the three and six months ended June 30, 2019, revenues from the sale of petroleum-based heating oil and diesel fuel acquired from third parties, along with the sale of these items further blended with biodiesel produced by our facilities or purchased from third parties, were approximately 14% and 16% of our total revenues, respectively.

In accordance with EPA regulations, we generate 1.5 to 1.7 RINs for each gallon of biomass-based diesel we produce. RINs are used to track compliance with Renewable Fuel Standard 2, or RFS2, using the EPA moderated transaction system, or EMTS. RFS2 allows us to attach between zero and 2.5 RINs to any gallon of biomass-based diesel we sell. When we attach RINs to a sale of biomass-based diesel gallons, a portion of our selling price for a gallon of biomass-based diesel is generally attributable to RFS2 compliance; but no cost is allocated to the RINs generated by our biomass-based diesel production because RINs are a form of government incentive and not a result of the physical attributes of the biomass-based diesel production. In addition, RINs, once obtained through the production and sale of gallons of biomass-based diesel, may be separated by the acquirer and sold separately. We regularly obtain RINs from third parties for resale, and the value of these RINs is reflected in “Prepaid expenses and other assets” on our Condensed Consolidated Balance Sheets. At each balance sheet date, this RIN inventory is valued at the lower of cost or net realizable value and any resulting adjustments are reflected in our cost of goods sold for the period. The cost of RINs obtained from third parties is determined using the average cost method. Because we do not allocate costs to RINs generated by our biomass-based diesel production, fluctuations in the value of our RIN inventory represent fluctuations in the value of RINs we have obtained from third parties. RINs significantly decreased in value during the first quarter of 2019 and have remained relatively low through the second quarter, which we believe has been influenced by record levels of Small Refiner Exemptions from RIN compliance requirements for 2016 and 2017.

The table below summarizes our RINs balances available to be sold and the median closing price per RIN at June 30, 2019 and December 31, 2018 according to the Oil Pricing Information System ("OPIS"):



	Quantity		OPIS Median Closing Price per RIN
	June 30, 2019	December 31, 2018	June 30, 2019		December 31, 2018
Biomass-based diesel RINs	30,952,000	12,561,167	$	0.42	$	0.55
Advanced biofuels RINs	1,671,128	3,907,803	$	0.41	$	0.51

We generate Low Carbon Fuel Standard credits for our low carbon fuels or blendstocks when our qualified low carbon fuels are imported into states that have adopted an LCFS program and sold for qualifying purposes. As a result, a portion of the selling price for a gallon of biomass-based diesel sold into an LCFS market is also attributable to LCFS compliance. Like RINs, LCFS credits that we generate are a form of government incentive and not a result of the physical attributes of the

biomass-based diesel production. Therefore, no cost is allocated to the LCFS credit when it is generated, regardless of whether the LCFS credit is transferred with the biomass-based diesel produced or held by us. LCFS prices increased in the second quarter of 2019, which we believe was largely attributable to growing demand for LCFS credits.

The below table summarizes approximate amounts of our LCFS credits available to be sold and the median closing price per LCFS credit at June 30, 2019 and December 31, 2018 according to OPIS:



	Quantity		OPIS Median Closing Price per LCFS Credit
	June 30, 2019	December 31, 2018	June 30, 2019		December 31, 2018
California LCFS	2,288	29,800	$	195.50	$	195.00
Oregon LCFS	2,041	25,900	$	170.00	$	137.50

When California extended its LCFS program in 2018, it revised the process for generating credits under the LCFS program to improve reporting and reduce the number of entities required to undergo an audit under the new verification program. This revised process effectively pushed LCFS credit generation from three month deferral to four month deferral. The law took effect at the beginning of 2019 and has had a negative impact on our second quarter profitability because LCFS credits earned in the first quarter of 2019 will not be received and available for sale until the third quarter of 2019.

Services Segment

Our Services segment, which primarily provides services to our Biomass-based Diesel Segment, includes:


•	biomass-based diesel facility management and operational services, whereby we provide day-to-day management and operational services to biomass-based diesel production facilities; and


•	construction management services, whereby we act as the construction management and general contractor for the construction of biomass-based diesel production facilities.

During recent years, we have utilized our construction management expertise internally to upgrade our facilities, such as our facilities located in Ralston, Albert Lea, New Boston, Mason City and Newton. In March 2018, we completed the expansion project at our Ralston facility. We plan to improve and utilize the new acreage to support existing production capacity and future expansion opportunities using the Services segment.

Factors Influencing Our Results of Operations

The principal factors affecting our results of operations and financial conditions are the market prices for biomass-based diesel and the feedstocks used to produce biomass-based diesel, as well as governmental programs designed to create incentives or requirements for the production and use of cleaner renewable fuels.

Governmental programs favoring biomass-based diesel production and use

Biomass-based diesel has historically been more expensive to produce than petroleum-based diesel. The biomass-based diesel industry’s growth has largely been the result of federal and state programs that require or incentivize production and use of biomass-based diesel, which allows biomass-based diesel to be priced competitively with petroleum-based diesel.

RFS2 was implemented in 2010, stipulating volume requirements for the amount of biomass-based diesel and other advanced biofuels that must be utilized in the United States each year. Under RFS2, Obligated Parties, including petroleum refiners and fuel importers, must show compliance with these standards. Currently, biodiesel and renewable diesel satisfy three categories of an Obligated Party’s annual renewable fuel required volume obligation, or RVO—biomass-based diesel, advanced biofuel and renewable fuel. The final RVO targets for the biomass-based diesel and advanced biofuels volumes for the years 2016 to 2021 as set or proposed by the EPA are as follows:

2016

2017

2018

2019

2020

2021

Biomass-based diesel

1.90 billion gallons

2.00 billion gallons

2.10 billion gallons

2.43 billion gallons

Total Advanced biofuels

3.61 billion RINs*

4.28 billion RINs*

4.29 billion RINs*

4.92 billion RINs*

5.04 billion RINs**

N/A

*Ethanol equivalent gallons

**Proposed by the EPA in July 2019.

The federal biodiesel mixture excise tax credit, or the BTC, has historically provided a $1.00 refundable tax credit per gallon to the first blender of biomass-based diesel with petroleum-based diesel fuel. The BTC became effective January 1, 2005, but since January 1, 2010 it has been allowed to lapse and then been reinstated a number of times. For example, the BTC lapsed on January 1, 2014, was retroactively reinstated for 2014 on December 19, 2014 and then lapsed again on January 1, 2015. On December 18, 2015, the BTC was reinstated for 2015 and extended for 2016. The BTC again lapsed on January 1, 2017 and was reinstated on a retroactive basis for 2017 on February 9, 2018. It has not been retroactively reinstated for 2018 and is not currently in effect for 2019.

As a result of this history of retroactive reinstatement of the BTC, we and many other biomass-based diesel industry producers have adopted contractual arrangements with customers and vendors specifying the allocation and sharing of any retroactively reinstated incentive. The reinstatement of the 2017 BTC resulted in a $205 million net benefit to our net income for the year ended December 31, 2018 and Adjusted EBITDA for the year ended December 31, 2017, with another $11 million related to products delivered and sales recognized in the first quarter of 2018. It is uncertain whether the BTC will be reinstated for 2018, 2019 or later years and if reinstated, whether it would be reinstated retroactively or on the same terms. The failure to reinstate the BTC would have a material adverse effect on our financial results. For the three and six months ended June 30, 2019 and for the year ended December 31, 2018, we estimate that if the BTC is reinstated on the same terms as in 2017, the effect on our Adjusted EBITDA would be as follows:



	Three months ended June 30, 2019			Six months ended June 30, 2019			Twelve months ended December 31, 2018
Adjusted EBITDA without BTC	$	(42,337	)	$	(69,697	)	$	151,981
Estimated net benefit if BTC is reinstated	81,000			136,000			237,000
Estimated Adjusted EBITDA if BTC is reinstated	$	38,663		$	66,303		$	388,981

Biomass-based diesel and feedstock price fluctuations

Our operating results generally reflect the relationship between the price of biomass-based diesel, including credits and incentives, and the price of feedstocks used to produce biomass-based diesel.

Biomass-based diesel is a cleaner low carbon, renewable alternative to petroleum-based diesel fuel and is primarily sold to the end user after it has been blended with petroleum-based diesel fuel. Biomass-based diesel prices have historically been heavily influenced by petroleum-based diesel fuel prices. Accordingly, biomass-based diesel prices have generally been impacted by the same factors that affect petroleum prices, such as crude oil supply and demand balance, worldwide economic conditions, wars and other political events, OPEC production quotas, changes in refining capacity and natural disasters.

Regulatory and legislative factors also influence the price of biomass-based diesel. Biomass-based diesel RIN pricing, a value component that was introduced via RFS2 in July 2010, has had a significant impact on biomass-based diesel pricing. The following table shows for 2017, 2018 and the first half of 2019 the high and low average monthly contributory value of RINs, as reported by OPIS, to the average B100 spot price of a gallon of biodiesel, as reported by The Jacobsen, in terms of dollars per gallon.

At the beginning of 2019, the value of RINs, as reported by OPIS, to the average B100 spot price of a gallon of biodiesel was $0.86 per gallon. The value of RINs to the average B100 spot price of a gallon of biodiesel dropped to $0.62 per gallon at the end of June 2019. It reached a high of $0.87 per gallon of biodiesel in January 2019 and a low of $0.48 per gallon in May 2019. We believe that the decrease in RIN value during the first half of 2019 and during 2018 was heavily influenced by record levels of Small Refiner Exemptions from RIN compliance requirements for 2016 and 2017. We enter into forward contracts to sell RINs and we use risk management position limits to manage RIN exposure.

During 2018, feedstock expense accounted for 78% of our production cost, while methanol and chemical catalysts expense accounted for 5% and 3% of our costs of goods sold, respectively.

Feedstocks for biomass-based diesel production, such as inedible oil, used cooking oil, animal fat, canola oil and soybean oil are commodities and market prices for them will be affected by a wide range of factors unrelated to the price of biomass-based diesel and petroleum-based diesel. There are a number of factors that influence the supply and price of our feedstocks, such as the following: biomass-based diesel demand; export demand; government policies and subsidies; weather conditions; ethanol production; cooking habits and eating habits; number of restaurants near collection facilities; hog/beef/poultry supply and demand; palm oil supply; soybean meal demand and/or production, and crop production both in the U.S. and South America.

During 2018, 77% of the feedstocks used in our operations comprised inedible corn oil, used cooking oil and inedible animal fats with the remainder coming from virgin vegetable oil.

The graph below illustrates the spread between the cost of producing one gallon of biodiesel made from soybean oil to the cost of producing one gallon of biodiesel made from the specified lower-cost feedstock for the period January 2017 to June 2019. The results were derived using assumed conversion factors for the yield of each feedstock and subtracting the cost of producing one gallon of biodiesel made from each respective lower-cost feedstock from the cost of producing one gallon of biodiesel made from soybean oil.


(1)	Used cooking oil ("UCO") prices are based on the monthly average of the daily low sales price of Missouri River yellow grease as reported by The Jacobsen (based on 8.5 pounds per gallon).


(2)	Inedible corn oil ("ICO") prices are reported as the monthly average of the daily distillers’ corn oil market values delivered to Illinois as reported by The Jacobsen (based on 8.2 pounds per gallon).


(3)	Choice white grease ("CWG") prices are based on the monthly average of the daily low prices of Missouri River choice white grease as reported by The Jacobsen (based on 8.0 pounds per gallon).


(4)	Soybean oil (crude) ("SBO") prices are based on the monthly average of the daily closing sale price of the nearby soybean oil contract as reported by CBOT (based on 7.5 pounds per gallon).

Our results of operations generally will benefit when the spread between biomass-based diesel prices and feedstock prices widens and will be harmed when this spread narrows. The following graph shows feedstock cost data for choice white grease and soybean oil on a per gallon basis compared to the per gallon sale price data for biodiesel, and the spread between biodiesel and each of soybean oil and choice white grease, from January 2017 to June 2019.


(1)	Biodiesel prices are based on the monthly average of the midpoint of the high and low prices of B100 (Upper Midwest) as reported by The Jacobsen.


(2)	Soybean oil (crude) prices are based on the monthly average of the daily closing sale price of the nearby soybean oil contract as reported by CBOT (based on 7.5 pounds per gallon).


(3)	Choice white grease prices are based on the monthly average of the daily low price of Missouri River choice white grease as reported by The Jacobsen (based on 8.0 pounds per gallon).


(4)	Spread between biodiesel price and choice white grease price.


(5)	Spread between biodiesel price and soybean oil (crude) price.

During the first half of 2019, NY Harbor ULSD prices ranged from a low of $1.70 per gallon in January to a high of $2.12 per gallon in May with the average price for the first half of 2019 of $1.96 per gallon, down $0.11 from the fourth quarter of 2018 average of $2.07 per gallon. Energy prices declined early in the second quarter on a breakdown in trade talks between U.S. and China along with domestic inventories sitting at near record levels while refineries experienced longer than expected maintenance turnarounds. Prices rebounded in June on elevated Mideast tensions leading to a $0.24 rally in ULSD prices over the month. U.S. biodiesel prices traded in a narrow range during the first half with Jacobsen Upper Midwest B100 prices reaching a high of $2.89 in February and then reaching a low of $2.70 in May.

Soybean oil prices ranged from a high of $0.31 per pound in February 2019 to a low of $0.26 per pound in May 2019 with an average price of $0.29 per pound for the first half of 2019. Soybeans saw weakness over concerns that farmers would switch planted acres from corn to beans due to unfavorable weather to start the year, but beans saw support as weather caused further delays leading to a potential record prevent plant acreage total. Soybean crush has slowed from record levels in the first quarter of 2019 as margins have become compressed and some crush facilities experienced flooding, which has limited run times and provided support to soybean oil prices.

In March 2017, the National Biodiesel Fair Trade Coalition ("Coalition") filed an anti-dumping and countervailing duty petition with the U.S. Department of Commerce and the U.S. International Trade Commission ("USITC"), arguing that Argentinean and Indonesian companies were violating trade laws by flooding the U.S. market with dumped and subsidized biodiesel. The Coalition is comprised of the National Biodiesel Board and U.S. biodiesel producers. In May 2017, the USITC agreed to proceed with an investigation regarding this matter. In relation to this anti-dumping and countervailing duty petition, the Coalition filed a new allegation in July 2017 that "critical circumstances" exist with respect to imports of biodiesel from Argentina, which would allow for the imposition of duties on imports that enter the U.S. prior to preliminary determinations of subsidization and dumping. In December 2017, the USITC voted 4-0 affirming countervailing duty rates of 34% to 72%. The Department of Commerce issued a determination effective March 1, 2018 affirming the agency's earlier preliminary determination that Argentina and Indonesia had dumped biodiesel imports into the U.S. Final anti-dumping rates were set at 60% to 267%. In April 2018, the USITC voted 4-0 affirming the Coalition's assertions that the industry suffered as a result of unfairly dumped imports. The Department of Commerce issued final orders in April 2018. In July 2019, the U.S. Department of

Commerce announced it had reached a preliminary decision that could lead to reduced countervailing duty rates on Argentine biodiesel imports. This was due to a "Changed Circumstance" review that the Department started in November 2018. This ruling has not yet been made final, but could be made final as early as September 2019.

Risk Management

The profitability of producing biomass-based diesel largely depends on the spread between prices for feedstocks and biomass-based diesel, including incentives, each of which is subject to fluctuations due to market factors and each of which is not significantly correlated. Adverse price movements for these commodities directly affect our operating results. We attempt to protect cash margins for our own production and our third-party trading activity by entering into risk management contracts that mitigate the impact on our margins from price volatility in feedstocks and biomass-based diesel. We create offsetting positions by using a combination of forward fixed-price physical purchases and sales contracts on feedstock and biomass-based diesel and risk management futures contracts, swaps and options primarily on the New York Mercantile Exchange NY Harbor ULSD and CBOT Soybean Oil; however, the extent to which we engage in risk management activities varies substantially from time to time, and from feedstock to feedstock, depending on market conditions and other factors. In making risk management decisions, we utilize research conducted by outside firms to provide additional market information in addition to our internal research and analysis.

Inedible corn oil, used cooking oil, inedible animal fat, canola oil and soybean oil were the primary feedstocks we used to produce biomass-based diesel in 2018 and the first six months of 2019. We utilize several varieties of inedible animal fat, such as beef tallow, choice white grease and poultry fat derived from livestock. There is no established futures market for these lower-cost feedstocks. The purchase prices for lower-cost feedstocks are generally set on a negotiated flat price basis or spread to a prevailing market price reported by the USDA price sheet or The Jacobsen. Our efforts to risk manage against changing prices for inedible corn oil, used cooking oil and inedible animal fat have involved entering into futures contracts, swaps or options on other commodity products, such as CBOT soybean oil and New York Mercantile Exchange NY Harbor ULSD. However, these products do not always experience the same price movements as lower-cost feedstocks, making risk management for these feedstocks challenging. We manage feedstock supply risks related to biomass-based diesel production in a number of ways, including, where available, through long-term supply contracts. The purchase price for soybean oil under these contracts may be indexed to prevailing CBOT soybean oil market prices with a negotiated market basis. We utilize futures contracts, swaps and options to risk manage, or lock in, the cost of portions of our future feedstock requirements generally for varying periods up to one year.

Our ability to mitigate our risk of falling biomass-based diesel prices is limited. We have entered into forward contracts to supply biomass-based diesel. However, pricing under these forward sales contracts generally has been indexed to prevailing market prices, as fixed price contracts for long periods on acceptable terms have generally not been available. There is no established derivative market for biomass-based diesel in the United States. Our efforts to hedge against falling biomass-based diesel prices generally involve entering into futures contracts, swaps and options on other commodity products, such as diesel fuel and New York Mercantile Exchange NY Harbor ULSD. However, price movements on these products are not highly correlated to price movements of all of the contract components in aggregate of biomass-based diesel.

We generate 1.5 to 1.7 biomass-based diesel RINs for each gallon of biomass-based diesel we produce and sell. We also obtain RINs from third-party transactions which we hold for resale. There is no established futures market for biomass-based diesel RINs, which severely limits the ability to risk manage the price of RINs. We enter into forward contracts to sell RINs, and we use risk management position limits to manage RIN exposure, however, pricing under those forward contracts generally has been indexed to prevailing market prices as fixed price contracts for long periods have generally not been available.

As a result of our strategy, we frequently have gains or losses on derivative financial instruments that are conversely offset by losses or gains on forward fixed-price physical contracts on feedstocks and biomass-based diesel or inventories. Gains and losses on derivative financial instruments are recognized each period in operating results while corresponding gains and losses on physical contracts are generally not recognized until quantities are delivered or title transfers which may be in the same or later periods. Our results of operations are impacted when there is a period mismatch of recognized gains or losses associated with the change in fair value of derivative instruments used for risk management purposes at the end of the reporting period but the purchase or sale of feedstocks or biomass-based diesel has not yet occurred resulting in the offsetting gain or loss that will be recognized in a later accounting period.

We recorded risk management losses of $5.6 million and $28.3 million from our derivative financial instrument activity for the three and six months ended June 30, 2019, compared to losses of $12.9 million and $15.3 million for the three and six months ended June 30, 2018. Changes in the value of these futures, swaps or options instruments are recognized in current income or loss.

Increasing importance of renewable diesel

Renewable diesel has become an increasingly significant part of our business. Renewable diesel carries a premium price to biodiesel as a result of a variety of factors including the ability to blend it with petroleum diesel seamlessly, better cold weather performance, and because it generates more RINs on a per gallon basis. We estimate that our renewable diesel production facility in Geismar, Louisiana generated more than half of our adjusted EBITDA in 2018. We experienced two fires at this facility in 2015 that each resulted in the plant being shut down for a lengthy period. If production at this facility were interrupted again due to a fire or for any other reason, it would have a disproportionately significant and material adverse impact on our results of operations and financial condition.

Seasonality

Our operating results are influenced by seasonal fluctuations in the demand for biodiesel. Our biodiesel sales tend to decrease during the winter season due to reduced blending concentrations to adjust for performance during colder weather. Colder seasonal temperatures can cause the higher cloud point biodiesel we make from inedible animal fats to become cloudy and eventually gel at a higher temperature than petroleum-based diesel, renewable diesel, or lower cloud point biodiesel made from soybean oil, canola oil or inedible corn oil. Such gelling can lead to plugged fuel filters and other fuel handling and performance problems for customers and suppliers. Reduced demand in the winter for our higher cloud point biodiesel can result in excess supply of such higher cloud point biodiesel and lower prices for such biodiesel. In addition, most of our biodiesel production facilities are located in colder Midwestern states in proximity to feedstock origination, and our costs of shipping can increase as more biodiesel is transported to warmer climate geographies during winter. To mitigate some of these seasonal fluctuations, we have upgraded our Newton and Danville biorefineries to produce distilled biodiesel from low-cost feedstocks, which has improved cold-weather performance.

RIN prices may also be subject to seasonal fluctuations. The RIN is dated for the calendar year in which it is generated, commonly referred to as the RIN vintage. Since 20% of the annual RVO of an Obligated Party (as defined under the RFS2) can be satisfied by prior year RINs, most RINs must come from biofuel produced or imported during the RVO year. As a result, RIN prices can be expected to decrease as the calendar year progresses if the RIN market is oversupplied compared to that year's RVO and increase if it is undersupplied. We believe that the record levels of Small Refiner Exemptions ("SREs") from RIN compliance requirements for 2016 and 2017 have also significantly impacted RIN prices. See chart below for comparison between actual RIN generation and RVO level for Advanced Biofuel as set by the EPA and the impact of the SREs.



Year	RIN Generation (Advanced Biofuel)	Finalized RVO level for Advanced Biofuel	Estimated Advanced Biofuel RVO Exempted due to SREs
2016	4.30 billion RINs	3.61 billion RINs*	0.16 billion RINs
2017	4.23 billion RINs	4.28 billion RINs*	0.40 billion RINs
2018	4.34 billion RINs	4.29 billion RINs*	**
YTD Q2-2019	2.28 billion RINs	4.92 billion RINs*	**

*Ethanol equivalent gallons

**Information not yet available

Industry capacity, production and imports

Our operating results are influenced by our industry’s capacity and production, including in relation to RFS2 production requirements. Under RFS2, Obligated Parties are entitled to satisfy up to 20% of their annual requirement with prior year RINs. Biomass-based diesel production and/or imports, as reported by EMTS, were 2.50 billion gallons for 2017, 100 million gallons lower than 2016. The amount of biomass-based diesel produced and/or imported into the U.S in 2018 was 2.50 billion gallons. In the first half of 2019, according to EMTS data, 1.29 billion gallons of biomass-based diesel were produced and/or imported into the U.S., compared to the equivalent 0.86 billion gallons over the same period in 2018.

The amount of imported biodiesel gallons qualifying under RFS2 decreased from 662.1 million gallons in 2017 to approximately 371.6 million gallons in 2018, according to the Energy Information Administration ("EIA"). Imported gallons made up less of the RVO in 2018 as a result of the anti-dumping and countervailing duty trade case.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amount of assets, liabilities, equities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an

ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for judgments we make about the carrying values of assets and liabilities that are not readily apparent from other sources. Because these estimates can vary depending on the situation, actual results may differ from the estimates.

We have disclosed under the heading “Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2018 the critical accounting policies which materially affect our financial statements. There have been no material changes from the critical accounting policies previously disclosed. You should carefully consider the critical accounting policies set forth in our Annual Report on Form 10-K.

Results of Operations

Three and six months ended June 30, 2019 and 2018

Set forth below is a summary of certain financial information (dollars in thousands and gallons in millions except for per gallon data) for the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018

Gallons sold	197.4			171.9			359.8			307.2
Average biomass-based diesel price per gallon (BTC net benefit adjusted ASP of $3.11 and $3.14 for the three and six months ended June 30, 2018)	$	2.70		$	3.11		$	2.68		$	3.98

Revenues from continuing operations	$	560,643		$	578,900		$	1,038,852		$	1,266,902
Cost of goods sold from continuing operations	587,415			521,386			1,078,416			959,933
Gross profit (loss) from continuing operations	(26,772		)	57,514			(39,564		)	306,969
Selling, general and administrative expenses	26,865			24,512			52,010			56,166
Research and development expense	176			27			385			1,061
Impairment of property, plant and equipment	468			—			468			—
Income (loss) from operations	(54,281		)	32,975			(92,427		)	249,742
Other expenses, net	(3,444		)	(98		)	(7,115		)	(226		)
Income tax benefit (expense)	90			(3,835		)	520			(2,632		)
Net income (loss) from continuing operations attributable to the Company	(57,635		)	29,042			(99,022		)	246,884
Net income (loss) from discontinued operations attributable to the Company	(4,462		)	4,808			(6,479		)	1,353
Net income (loss) to the Company	$	(62,097	)	$	33,850		(105,501		)	248,237

Effect of participating share-based awards on continuing operations	—			765			—			6,222
Net income (loss) from continuing operations attributable to the Company's common stockholders	$	(57,635	)	$	28,277		$	(99,022	)	$	240,662
Net income (loss) from discontinued operations attributable to the Company's common stockholders	$	(4,462	)	$	4,681		$	(6,479	)	$	1,319

Continuing Operations:

Revenues. In the three and six months ended June 30, 2018, we recognized government incentives revenue of approximately $0.9 million and $366.2 million, respectively, due to the retroactive reinstatement of the 2017 BTC in February 2018, resulting in a net increase of $0.9 million and $220.2 million in biomass-based diesel revenues, respectively. The BTC has not been reinstated for 2018 or 2019, and accordingly we did not recognize any BTC revenue in the three and six months ended June 30, 2019. Primarily as a result of the absence of BTC revenues in the 2019 period, our revenues decreased by $228.1 million, or 18%, for the six months ended June 30, 2019, as compared to the same period in 2018. The decrease in total revenues in the three and six months ended June 30, 2019, as compared to the same periods in 2018, was also attributable to a reduction in revenues from separated RIN sales and a drop in the average biomass-based diesel selling price, which was partially offset by a 15% and 17% increase in gallons sold in the three and six months ended June 30, 2019.

Gallons sold in the three and six months ended June 30, 2019 increased by 25.5 million and 52.6 million gallons, or 15% and 17%, respectively. The increase in gallons sold for the three and six months ended June 30, 2019 accounted for a revenue increase of $68.9 million and $141.0 million, respectively, using the 2019 average sales price. Our average biomass-based diesel sales price per gallon decreased $0.41 and $1.30, or 13% and 33%, respectively, for the three and six months ended June 30, 2019. The average biomass-based diesel sales price per gallon after adjustment for the 2017 BTC decreased $0.41 and $0.46, or 13% and 15%, respectively, for the three and six months ended June 30, 2019. The decrease in adjusted average sales price contributed to a $70.5 million and $141.3 million, respectively, decrease in revenues for the three and six months ended June 30, 2019, when applied to the number of gallons sold in 2018. Sales of separated RIN inventory were $19.6 million and $42.1 million respectively, for the three and six months ended June 30, 2019, as compared to $26.2 million and $73.4 million, respectively, for the three and six months ended June 30, 2018. The decrease in average selling price per gallon was primarily due to D4 RIN prices in the three and six months ended June 30, 2019 that were lower by $0.16 per RIN and $0.22 per RIN, respectively, on average compared to the three and six months ended June 30, 2018, according to OPIS.

Costs of goods sold. Our costs of goods sold increased $66.0 million and $118.5 million, or 13% and 12%, for the three and six months ended June 30, 2019, respectively as compared to the same periods in 2018. Costs of goods sold as a percentage of revenues were 105% and 103.8% for the three and six months ended June 30, 2019, respectively, and 90% and 75.8% for the three and six months ended June 30, 2018, respectively, primarily due to the recognition of the 2017 BTC in full as revenues in the first quarter of 2018, coupled with lower revenues due to lower average selling prices and a reduced spread between biomass-based diesel prices and feedstock costs, partially offset by smaller risk management losses compared to the losses in 2018.

Average prices for lower-cost feedstocks used in our production were $0.27 and $0.26 per pound for the three and six months ended June 30, 2019, respectively, as compared to $0.26 per pound for both the three and six months ended June 30, 2018. Average soybean oil costs were $0.31 and $0.30 per pound for three and six months ended June 30, 2019, respectively, as compared to $0.30 and $0.33 per pound for the three and six months ended June 30, 2018, respectively. Average canola oil costs were $0.34 per pound for both the three and six months ended June 30, 2019, as compared to $0.35 per pound for both the three and six months ended June 30, 2018. We recorded risk management losses of $5.6 million and $28.3 million from our derivative financial instrument activity for the three and six months ended June 30, 2019, respectively, compared to risk management losses of $12.9 million and $15.3 million for the three and six months ended June 30, 2018, respectively. Costs of goods sold for separated RIN inventory sales were $7.3 million and $13.9 million for the three and six months ended June 30, 2019, respectively, and $11.0 million and $43.7 million for the three and six months ended June 30, 2018, respectively. We did not record a lower of cost or net realizable value write down on RINs in the 2019 periods, but recorded write downs of $3.0 million and $6.5 million during the three and six months ended June 30, 2018, respectively.

Selling, general and administrative expenses. Our selling, general and administrative, or SG&A, expenses were $26.9 million and $52.0 million for the three and six months ended June 30, 2019, or 5% of total revenue in each period and $24.5 million and $56.2 million, or 4% of total revenue, in the same periods of 2018. The $2.4 million, or 10%, increase in the three months ended June 30, 2019 compared to the same period in 2018 resulted primarily from higher legal and professional fees as well as information technology costs. SG&A expenses decreased $4.2 million, or 7%, in the first half of 2019 compared to 2018 primarily due to higher employee related compensation recorded in the first quarter of 2018 arising from the Company's strong financial performance in 2017.

Other income (expense), net. Other expense was $3.4 million and $7.1 million for the three and six months ended June 30, 2019, respectively, compared to other expense of $0.1 million and $0.2 million for the same respective periods in 2018. Other income (expense) is primarily comprised of change in value of contingent consideration, gain on debt extinguishment, gain from involuntary conversion, interest expense, interest income and other non-operating items. The gain from involuntary conversion related to the fire at our Madison facility and gain the partial extinguishment of the 2036 and 2019 Senior Convertible Notes, along with decreased interest expense due to the early extinguishment of debt, resulted in lower other expense for the three and six months ended June 30, 2018 as compared to 2019.

Income tax expense. We recognized an income tax benefit of $0.1 million and $0.5 million for the three and six months ended June 30, 2019, respectively, as compared to tax expense of $3.8 million and $2.6 million for the same respective periods in 2018. Our tax provision for an interim period is determined using an estimate of our annual effective tax rate, adjusted for discrete items arising in that quarter. Our effective tax rate differs from the statutory tax rate primarily due to the fact that we have a valuation allowance on our domestic deferred tax assets and most of our foreign deferred tax assets.

Effects of participating share-based awards. Effects of participating share-based awards was $0.0 million for the three and six months ended June 30, 2019 and $0.8 million and $6.2 million for the same respective periods in 2018.

Discontinued Operations:

Net loss from discontinued operations for the three and six months ended June 30, 2019 was attributable to the research and development activities at and expenses incurred related to the sale of the REG Life Sciences business. Net income from discontinued operations for the three and six months ended June 30, 2018 was mainly driven by the research and development activities at REG Life Sciences, offset by change in value of contingent consideration.

Non - GAAP Financial Measures:

Adjusted EBITDA

Earnings before interest, taxes, depreciation and amortization ("EBITDA") and adjusted EBITDA are not measures of financial performance under GAAP. We use EBITDA and EBITDA adjusted for certain additional items, identified in the table below, or Adjusted EBITDA, as a supplemental performance measure. We present EBITDA and Adjusted EBITDA because we believe they assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. In addition, we use Adjusted EBITDA to evaluate, assess and benchmark our financial performance on a consistent and a comparable basis and as a factor in determining incentive compensation for our executives.

In the fourth quarter of 2018, the operations of REG Life Sciences have been classified as discontinued operations. We have excluded the results from these discontinued operations from the calculation of Adjusted EBITDA. The corresponding prior period amounts have been reclassified to conform with the current period presentation. The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income (loss) from continuing operations:



(In thousands)	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
Net income (loss) from continuing operations	$	(57,635	)	$	29,042		$	(99,022	)	$	246,886
Adjustments:
Income tax (benefit) expense	(90		)	3,835			(520		)	2,632
Interest expense	3,737			4,925			7,956			9,576
Depreciation	9,142			9,004			18,241			17,743
Amortization of intangible assets	510			44			844			86
EBITDA	$	(44,336	)	$	46,850		$	(72,501	)	$	276,923
Gain on involuntary conversion	—			(454		)	—			(4,454		)
Gain on sale of assets	—			—			—			(990		)
Change in fair value of contingent consideration	398			30			702			488
Loss (gain) on debt extinguishment	—			(2,337		)	2			(2,105		)
Other income, net	(691		)	(2,067		)	(1,545		)	(2,292		)
Impairment of assets	468			—			468			—
Straight-line lease expense	—			(3		)	—			(36		)
Executive severance	—			50			—			215
Non-cash stock compensation	1,824			2,203			3,177			3,997
Adjusted EBITDA excluding 2017 BTC allocation	$	(42,337	)	$	44,272		$	(69,697	)	$	271,746
Biodiesel tax credit ⁽¹⁾	—			—			—			(206,521		)
Adjusted EBITDA	$	(42,337	)	$	44,272		$	(69,697	)	$	65,225

⁽¹⁾ On February 9, 2018, the Biodiesel Mixture Excise Tax Credit ("BTC") was retroactively reinstated for the 2017 calendar year. The retroactive credit for 2017 resulted in a net benefit to us that was recognized in the first quarter of 2018 for GAAP purposes. Because this credit relates to the 2017 full year operating performance and results, we removed the net benefit of the 2017 BTC from our 2018 results.

Adjusted EBITDA is a supplemental performance measure that is not required by, or presented in accordance with, generally accepted accounting principles, or GAAP. Adjusted EBITDA should not be considered as an alternative to net income or any other performance measure derived in accordance with GAAP, or as an alternative to cash flows from operating

activities or a measure of our liquidity or profitability. Adjusted EBITDA has limitations as an analytical tool, and should not be considered in isolation, or as a substitute for any of our results as reported under GAAP. Some of these limitations are:


•	Adjusted EBITDA does not reflect our cash expenditures for capital assets or the impact of certain cash charges that we consider not to be an indication of our ongoing operations;


•	Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital requirements;


•	Adjusted EBITDA does not reflect the interest expense, or the cash requirements necessary to service interest or principal payments, on our indebtedness;


•	although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect cash requirements for such replacements;


•	stock-based compensation expense is an important element of our long term incentive compensation program, although we have excluded it as an expense when evaluating our operating performance;


•	Adjusted EBITDA does not include loss from discontinued operations. Loss from discontinued operations mainly relates to the research and development activities of REG Life Sciences; and


•	other companies, including other companies in the industry, may calculate these measures differently than we do, limiting their usefulness as a comparative measure.

Liquidity and Capital Resources

Sources of liquidity. At June 30, 2019, the total of our cash and cash equivalents and marketable securities was $61.6 million, compared to $174.5 million at December 31, 2018. At June 30, 2019, we had total assets of $1,037.4 million, compared to $1,107.1 million at December 31, 2018. At June 30, 2019, we had term debt before debt issuance costs of $116.8 million, compared to term debt of $185.8 million at December 31, 2018. Our debt is subject to various financial covenants. We were in compliance with all financial covenants associated with our borrowings as of June 30, 2019.

Our term debt (in thousands) is as follows:



	June 30, 2019		December 31, 2018
4.00% Convertible Senior Notes, $96,300 face amount, due in June 2036	$	76,406	$	75,477
2.75% Convertible Senior Notes, due in June 2019	—		66,361
REG Danville term loan, secured, variable interest rate of LIBOR plus 4%, due in July 2022	7,924		8,964
REG Grays Harbor term loan, variable interest of minimum of 3.5% or Prime Rate plus 0.25%, due in May 2022	8,061		8,828
REG Capital term loan, fixed interest rate of 3.99%, due in January 2028	7,058		7,185
REG Ralston term loan, variable interest rate of Prime Rate plus 2.25%, due in October 2025	17,350		18,948
Other	42		54
Total term debt before debt issuance costs	$	116,841	$	185,817

In addition, we had revolving debt (in thousands) as follows:



	June 30, 2019		December 31, 2018
Amount outstanding under lines of credit	$	70,854	$	14,250
Maximum available to be borrowed under lines of credit	$	67,874	$	114,889

A full description of our credit facilities and other agreements related to our outstanding indebtedness is included under the heading “Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2018.

In accordance with the indenture governing the 2019 Convertible Senior Notes, we elected to settle all conversions of each $1,000 principal amount of such Notes being converted on or after October 23, 2018, with $1,000 in cash and any conversion value in excess of that amount in shares of our common stock. On June 15, 2019, the 2019 Convertible Senior Notes matured. We paid $67.4 million in cash to settle the outstanding principal amount, and issued 1,902,781 treasury shares to settle the conversion value that was in excess of the principal.

On July 9, 2019, we entered into an agreement with the lenders of the M&L and Services Revolver to provide us the ability to increase the maximum borrowing amount on the line of credit to $175,000, or $200,000 if the BTC is retroactively reinstated for 2018 and/or 2019. This agreement is for a specified period from the date of the agreement through October 31, 2019.

Cash flows. The following table presents information regarding our cash flows and cash and cash equivalents for the six months ended June 30, 2019 and 2018 (in thousands):



	Six Months June 30,
	2019			2018
Cash (used in) provided by operating activities	$	(72,932	)	$	311,538
Cash provided by (used in) investing activities	34,971			(23,127		)
Cash used in financing activities	(24,040		)	(143,963		)
Net change in cash, cash equivalents and restricted cash	(62,001		)	144,448
Cash, cash equivalents and restricted cash end of period	$	64,597		$	221,775

In the first half of 2019, we used $72.9 million of cash in operations, compared to $311.5 million of cash provided by operations in the first half of 2018. The increase in cash used in operations is largely driven by a net loss of $105.5 million, compared to a net income of $248.2 million for the six months ended June 30, 2018. The net income for the six months ended June 30, 2018 was primarily due to a net benefit of $206.5 million (after satisfaction of sharing arrangements) related to the reinstatement of the 2017 BTC. Payments of the 2017 BTC were received in the second quarter of 2018 which created a large in-flow of cash. Net income for the six months ended June 30, 2019 has been negatively impacted primarily by a significant reduction in average selling price per gallon compared to 2018. The net cash flows generated from investing activity in the first half of 2019 was primarily impacted by the maturities of marketable securities of $54.6 million, compared to no maturities in 2018, coupled with a decrease in cash paid for property, plant and equipment of $18.0 million, compared to $28.8 million in the first half of 2018. Cash flows used in financing activities for the six months ended June 30, 2019 were impacted primarily by the payment of $67.4 million upon maturity of the 2019 Convertible Senior Notes. This was offset largely by net borrowings on revolving line of credit of $54.5 million for the first six months of 2019. Cash used in financing activities for the same period in 2018 was primarily driven by $57.3 million of net repayments of borrowings on revolving line of credit. Additionally, financing activities for the first half of 2018 included $25.0 million used to repurchase treasury stock, $6.7 million used to repurchase $6.3 million principal amount of the 2019 Convertible Senior Notes and $41.8 million used to repurchase $24.5 million principal amount of the 2036 Convertible Senior Notes.

Capital expenditures. During the six months ended June 30, 2019, our capital expenditures were $18.0 million involving various plant optimization projects, the majority of which were at the Houston, Seneca and Geismar facilities. During 2018, our capital expenditures were $46.5 million involving various projects, the majority of which were at the Madison, Ralston, Grays Harbor and Geismar facilities. Our budgeted capital expenditures for 2019 were between $65.0 million and $75.0 million and we carefully manage our capital investments in response to the market environment. We continue to invest in plant optimization projects, environmental, health and safety projects and plant maintenance across a variety of facilities. This budgeted amount does not include potential investments under evaluation in a potential joint venture with Phillips 66 to construct a renewable diesel production facility in Washington state or in the possible expansion of production capacity at our renewable diesel facility in Geismar, Louisiana.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Recent Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to “Note 2 – Summary of Significant Accounting Policies” to our Condensed Consolidated Financial Statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objectives of our investment activity are to preserve principal, provide liquidity and maximize income without significantly increasing risk. Some of the securities we invest in are subject to market risk. This means that a change in prevailing interest rates may cause the principal amount of the investment to fluctuate. To minimize this risk, we maintain a portfolio of cash equivalents in short-term investments in money market funds.

Commodity Price Risk

Over the period from January 2017 through June 30, 2019, average diesel prices based on Platts reported pricing for Group 3 (Midwest) have ranged from a high of approximately $2.47 per gallon reported in October 2018 to a low of approximately $1.31 per gallon in June 2017, with prices averaging $1.88 per gallon during this period. Over the period January 2017 to June 30, 2019, soybean oil prices (based on daily closing nearby futures prices on the Chicago Board of Trade for crude soybean oil) have ranged from a high of $0.36 per pound, or $2.69 per gallon of biodiesel, in January 2017, to a low of $0.26 per pound, or $1.98 per gallon, in May 2019, assuming 7.5 pounds of soybean oil yields one gallon of biodiesel with closing sales prices averaging $0.31 per pound, or $2.33 per gallon. Over the period from January 2017 through June 30, 2019, animal fat prices (based on prices from The Jacobsen Missouri River, for choice white grease) have ranged from a high of $0.28 per pound in September 2017 to a low of $0.16 per pound in March 2018, with sales prices averaging $0.22 per pound during this period. Over the period from January 2017 through June 30, 2019, RIN prices (based on prices from OPIS) have ranged from a high of $1.17 in August 2017 to a low of $0.31 in October 2018, with sales prices averaging $0.71 during this period.

Adverse fluctuations in feedstock prices as compared to biomass-based diesel prices result in lower profit margins and, therefore, represent unfavorable market conditions. The availability and price of feedstocks are subject to wide fluctuations due to unpredictable factors such as weather conditions during the growing season, rendering volumes, carry-over from the previous crop year and current crop year yield, governmental policies with respect to agriculture and supply and demand.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our sales contracts, lower-cost feedstock requirements, soybean oil requirements and the related exchange-traded contracts for the first six months of 2019. Market risk is estimated as the potential loss in fair value, resulting from a hypothetical 10% adverse change in the fair value of our lower-cost feedstock and soybean oil requirements and biomass-based diesel sales. The results of this analysis, which may differ from actual results, are as follows:



	First half of 2019 Volume (in millions)	Units	Hypothetical Adverse Change in Price		Impact on Annual Gross Profit (in millions)			Percentage Change in Gross Profit
Total Biomass-based Diesel	359.8	gallons	10	%	$	(96.4	)	(243.72	)%
Total Lower Cost Feedstocks	1,357.4	pounds	10	%	$	(35.3	)	(89.2	)%
Total Canola Oil	275.9	pounds	10	%	$	(9.4	)	(23.7	)%
Total Soy Oil	296.2	pounds	10	%	$	(8.9	)	(22.5	)%

We attempt to protect operating margins by entering into risk management contracts that reduce the risk of price volatility related to anticipated purchases of feedstocks, such as inedible animal fat and inedible corn oil and energy prices. We create offsetting positions by using a combination of forward physical purchases and sales contracts on feedstock and biomass-based diesel, including risk management futures contracts, swaps and options primarily on NYMEX NY Harbor ULSD, CBOT Soybean Oil, and NYMEX Natural Gas; however, the extent to which we engage in risk management activities varies substantially from time to time, and from feedstock to feedstock, depending on market conditions and other factors. A 10% adverse change in the prices of NYMEX NY Harbor ULSD would have had a positive effect on the fair value of these instruments of $9.7 million at June 30, 2019. A 10% adverse change in the price of CBOT Soybean Oil and NYMEX Natural Gas would have had an immaterial impact on our gross margin at June 30, 2019.

Interest Rate Risk

Our weighted average interest rate on variable rate debt balances for the six months months ended June 30, 2019 was 4.43%. A hypothetical increase in interest rate of 10% would not have a material effect on our annual interest expenses or consolidated financial statements.

Inflation

To date, inflation has not significantly affected our operating results, though costs for petroleum-based diesel fuel, feedstocks, construction, labor, taxes, repairs, maintenance and insurance are all subject to inflationary pressures. Inflationary pressure in the future could affect our ability to sell the biomass-based diesel we produce, to maintain our production facilities adequately, to build new biomass-based diesel production facilities and to expand our existing facilities, as well as the demand for our facility construction management and operations management services.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Company’s reports we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities Exchange Commission’s rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO"), as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.

Our management, under the supervision of and with the participation of the CEO and CFO, performed an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15-d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act") as of the end of the period covered by this report, June 30, 2019. In connection with our evaluation of disclosure controls and procedures, we have concluded that our disclosure controls and procedures were effective as of June 30, 2019.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of June 30, 2019. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting

There have been no changes during our quarter ended June 30, 2019 in our internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Neither the Company nor any of its subsidiaries are a party to any material pending legal or governmental proceeding, nor is any of our property the subject of any material pending legal or governmental proceeding, except ordinary routine legal or governmental proceedings arising in the ordinary course of our business and incidental to our business, none of which is expected to have a material adverse impact upon our business, financial position or results of operations.

ITEM 1A. Risk Factors

Our business, financial condition, results of operations and liquidity are subject to various risks and uncertainties, including those described below. As a result, the trading price of our common stock could decline.

RISKS RELATED TO FEDERAL AND STATE INCENTIVES

The Renewable Fuel Standard Program, a Federal law mandating the consumption of qualifying biofuels, could be repealed, curtailed or otherwise changed, which might have a material adverse effect on our revenues, operating margins and financial condition.

We and other participants in the biomass-based diesel industry rely on governmental programs requiring or incentivizing the consumption of biofuels. Biomass-based diesel has historically been more expensive to produce than petroleum-based diesel fuel and these governmental programs support a market for biomass-based diesel that might not otherwise exist.

One of the most important of these programs is the Renewable Fuel Standard ("RFS2"), a Federal law which requires that transportation fuels in the United States contain a minimum amount of renewable fuel. This program is administered by the Environmental Protection Agency ("EPA"). The EPA's authority includes setting annual minimum aggregate levels of consumption in four renewable fuel categories, including the two primary categories in which our fuel competes (biomass-based diesel and advanced biofuel). The parties obligated to comply with this renewable volume obligation ("RVO"), are petroleum refiners and petroleum fuel importers.

The petroleum industry is strongly opposed to the RFS2 and can be expected to continue to press for changes both in the RFS2 itself and in the way that it is administered by the EPA. One key point of contention is the rate of growth in the annual RVO. The RVO for biomass-based diesel was set at steadily rising levels beginning at 1.0 billion gallons in 2012 and increasing to 2.00 billion gallons in 2017. However, growth in the RVO was constrained from 2017 through 2019, as the biomass-based diesel RVO increased by only 100,000 gallons from 2.00 billion to 2.10 billion gallons while the advanced biofuel RVO increased from 4.28 billion gallons to 4.92 billion gallons. For 2020, the EPA set the biomass-based diesel RVO at 2.43 billion gallons. The 2020 advanced biofuel RVO has been proposed at 5.04 billion gallons which represents zero growth in the advance biofuels category after taking into account the increase in the cellulosic volumes. We believe that growth in the annual RVOs strongly influences our ability to grow our business and supports the price of our fuel through the RINs. The EPA's future decisions regarding the RVO will significantly influence our revenues and profit margins.

The RFS2 also grants to the EPA authority to grant small refiner waivers, waiving a qualifying refiner's obligation based on a determination that the program is causing severe economic harm to that refinery. The table below summarizes the small refiner waiver petitions requested, granted, denied or pending and the impacted volumes as of June 24, 2019, according to the EPA's website:



	2018		2017		2016		2015
Petitions received	40		37		20		14
Petitions granted	—		35		19		7
Petitions denied or withdrawn	2		1		—		7
Petitions pending	38		1		1		—
Estimated volume of fuel exempted (million gallons)	—		17,050		7,841		3,070
Estimated RVO Exempted (million RINs)	—		404		157		49
Estimated RVO Exempted (% of Advanced biofuels RVOs)	—	%	9.4	%	4.3	%	1.7	%

We believe that the increase in small refinery waivers granted in 2018 for the 2016 and 2017 RVO years impacted the demand for and price of RINs as the average price of D4 RINs fell from $0.82 to $0.55 during 2018 and from $0.55 to $0.42 during the first half of 2019 according to OPIS data. If the EPA continues this practice, it will harm demand for and the price of RINs and thus our profitability.

The United States Congress could repeal, curtail or otherwise change the RFS2 program in a manner adverse to us. Similarly, the EPA could curtail or otherwise change its administration of the RFS2 program in a manner adverse to us, including by not increasing or even decreasing the RVO, by waiving compliance with the RVO or otherwise. In addition, while Congress specified RFS2 volume requirements through 2022 (subject to adjustment in the rulemaking process), beginning in 2023 required volumes of renewable fuel will be largely at the discretion of the EPA (in coordination with the Secretary of Energy and Secretary of Agriculture). We cannot predict what changes, if any, will be instituted or the impact of any changes on our business, although adverse changes could seriously harm our revenues, earnings and financial condition.

Loss of or reductions in Federal and State Government tax incentives for biomass-based diesel production or consumption may have a material adverse effect on our revenues and operating margins.

Federal and State Government tax incentives have assisted the biomass-based diesel industry by making the price of biomass-based diesel more cost competitive with the price of petroleum-based diesel fuel to the end user.

Federal Tax Incentives

The most significant tax incentive program has been the federal biodiesel mixture excise tax credit, referred to as the Biodiesel Tax Credit ("BTC"). Under the BTC, the first person to blend pure biomass-based diesel with petroleum-based diesel fuel receives a $1.00-per-gallon refundable tax credit.

The BTC was established on January 1, 2005 and has lapsed and been reinstated retroactively and prospectively several times. Most recently in February 2018, the BTC was retroactively reinstated for 2017, but was not reinstated for any subsequent periods. As a result, the BTC has not been in effect since January 1, 2018. As was the case in previous periods when the BTC was not in effect, we and many other biomass-based diesel industry producers have adopted contractual arrangements with customers and vendors specifying the allocation and sharing of any retroactively reinstated incentive. Whether the BTC will be reinstated for 2018, 2019 or future years will have a very significant impact on our results of operations and financial condition. Reinstatement of the BTC for 2017 resulted in a $205 million net benefit (after satisfaction of sharing arrangements) to our net income in the first quarter of 2018 and to our Adjusted EBITDA for 2017. We estimate that

if the BTC is reinstated for 2019 and 2018 on the same terms as in 2017, the net benefits to our Adjusted EBITDA for business conducted in the three and six months ended June 30, 2019, would be approximately $81 million and $136 million, respectively. The estimated amount for the year ended December 31, 2018 would be approximately $237 million.

Unlike the RFS2 program, the BTC has a direct effect on Federal Government spending and changes in federal budget policy could result in its elimination or in changes to its terms that are less beneficial to us. We cannot predict what action, if any, Congress may take with respect to the BTC. There is no assurance that the BTC will be reinstated, that it will be reinstated on the same terms or, if reinstated, that its application will be retroactive, prospective or both. Due to the significance of this program to our business, adverse changes in the BTC can be expected to seriously harm our results of operations and financial condition.

State Tax Incentives

Several states have enacted tax incentives for the use of biodiesel. For example, Illinois has a generally applicable 6.25% sales tax, but offers an exemption from this tax for a blend of fuel that consists of 11% biodiesel ("B11"). In Iowa, for 2018 through 2024, retailers earn $0.035 per gallon of B5 - B10 and $0.055 per gallon for B11 and above. Iowa also has a biomass-based diesel production incentive that provides $0.02 per gallon of production capped after the first 25 million gallons per production plant. The biodiesel and renewable diesel portion of fuel blends are exempt from Texas state excise tax, which results in a $0.20 per gallon incentive for B100. Minnesota law requires a B5 biodiesel blend except during the summer months when a B20 blend is required. State budget or other considerations could cause the modification or elimination of tax incentive programs. The curtailment or elimination of such incentives could materially and adversely affect our revenues and profitability.

We derive a significant portion of our revenues from sales of our renewable fuel in the State of California primarily as a result of California’s Low Carbon Fuel Standard; adverse changes in this law or reductions in the value of LCFS credits would harm our revenues and profits.

We estimate that our revenues from the sale of renewable fuel in California and from sales of credits received under California's Low Carbon Fuel Standard ("LCFS") were approximately $255.7 million in the first half of 2019. The LCFS is designed to reduce greenhouse gas emissions associated with transportation fuels used in California by ensuring that the total amount of fuel consumed meets declining targets for such emissions. The regulation quantifies lifecycle greenhouse gas emissions by assigning a “carbon intensity” ("CI") score to each transportation fuel based on that fuel’s lifecycle assessment. Each petroleum fuel provider, generally the fuel’s producer or importer is required to ensure that the overall CI score for its fuel pool meets the annual carbon intensity target for a given year. This obligation is tracked through credits and deficits and credits can be traded. We receive LCFS credits when we sell qualified fuels in California. As a result of the trading price of LCFS credits, California has become a desirable market in which to sell our renewable fuel. In 2018, LCFS credit prices increased from $116 per credit on January 2, 2018 to $195 per credit on December 31, 2018. In the first half of 2019, LCFS credit prices were in the range of $175 to $197 per credit. As a result, an increasing percentage of our revenue and profit is related to sales to California and LCFS credit values. If the value of LCFS credits were to materially decrease as a result of greater supply or reduced demand for LCFS credits, if the fuel we produce is deemed not to qualify for LCFS credits or if the LCFS or the manner in which it is administered or applied were otherwise changed in a manner adverse to us, our revenues and profits could be seriously harmed.

RISKS RELATED TO OUR BUSINESS OPERATIONS AND THE MARKETS IN WHICH WE OPERATE

Increased industry-wide production of biodiesel as a result of potential utilization of existing excess production capacity, announced large plant expansions of renewable diesel and potential co-processing of renewable diesel by petroleum refiners, could reduce prices for our fuel and increase the cost of feedstocks used to produce them, which would seriously harm our revenues and results of operations.

If additional volumes of advanced biofuel RIN production come online and the EPA does not increase the RVO in accordance with the increased production, the volume of advanced biofuel RINs generated could exceed the volume required under the RFS2. In the event this occurs, biomass-based diesel and advanced biofuel RIN prices would be expected to decrease, potentially significantly, harming demand for our products and our profitability.

According to the National Biodiesel Board ("NBB"), in 2017, 4.1 billion gallons per year of biomass-based diesel production capacity in the United States was registered under the RFS2 program by NBB members. In addition to this amount, several hundred million more gallons of U.S. based biomass-based diesel production capacity was registered by non-NBB members and another 4.5 billion gallons of biomass-based diesel production was registered by foreign producers. These

amounts far exceed both historic consumption of biomass-based diesel in the United States and required consumption under the RFS2.

Additionally, several leading biomass-based diesel companies have announced their intention to expand their production of renewable diesel for the U.S. market. World Energy has announced that it will expand capacity at its Los Angeles area biorefinery from its existing 45 mmgy to over 300 mmgy. Diamond Green Diesel, the largest U.S. producer of renewable diesel, has announced plans to expand its 275 million mmgy capacity by 400 mmgy. Neste, the largest global producer of renewable diesel, announced in December 2018 a 440 mmgy expansion of its Singapore facility that exports a significant portion of its production to the U.S.West Coast.

Further, due to the economic incentives available, several petroleum refiners have started or may soon start to produce co-processed renewable diesel, or CPRD. CPRD uses the same feedstocks we use to produce biomass-based diesel and it generates an advanced biofuel RIN. CPRD may be more cost-effective to produce than biomass-based diesel, particularly biodiesel.

If production of competitive advanced renewable fuels increases significantly as a result of utilization of existing excess production capacity or new capacity as described above, competition for a relatively fixed supply of feedstocks would increase significantly, harming our margins. Furthermore if supply of advanced renewable fuels exceeds demand, prices for our renewable fuel and for RINs and other credits may decrease significantly, harming our profitability and potentially forcing us to idle our facilities.

Our gross margins are dependent on the spread between biomass-based diesel prices and feedstock costs, each of which is volatile and can cause our results of operations to fluctuate substantially.

Biomass-based diesel has traditionally been marketed primarily as an additive or alternative to petroleum-based diesel fuel, and, as a result, biomass-based diesel prices have been heavily influenced by the price of petroleum-based diesel fuel, adjusted for government incentives supporting renewable fuels, more so than biomass-based diesel production costs. The absence of a close correlation between production costs and biomass-based diesel prices means that we may be unable to pass increased production costs on to our customers in the form of higher prices. If there is a decrease in the spread between biomass-based diesel prices and feedstock costs, whether as a result of an increase in feedstock prices or as a result of a reduction in biomass-based diesel and credit prices, our gross margins, cash flow and results of operations would be adversely affected.

Energy prices, particularly the market price for crude oil, are volatile. The NYMEX ULSD prices ranged from a low of $1.70 per gallon to a high of $2.12 per gallon in the first half of 2019. Petroleum prices are volatile due to global factors, such as the impact of wars, political uprisings, new extraction technologies and techniques, OPEC production quotas, worldwide economic conditions, changes in refining capacity and natural disasters.

In addition, an element of the price of biomass-based diesel that we produce is the value of the associated credits, including RINs. RIN prices in the biomass-based diesel category as reported by OPIS fluctuated in the first half of 2019, ranging from $0.32 to $0.58 per RIN per gallon, while in 2018, RIN per gallon prices ranged from $0.31 to $0.91 per RIN. For the past several years there has been significant volatility in RIN prices. Reductions in RIN values, such as those experienced in prior years, may have a material adverse effect on our revenues and profits as they directly reduce the value we are able to capture for our biomass-based diesel.

A decrease in the availability or an increase in the price, of feedstocks may have a material adverse effect on our financial condition and operating results. The price and availability of feedstocks and other raw materials may be influenced by general economic, market and regulatory factors. These factors include weather conditions, farming decisions, government policies and subsidies with respect to agriculture and international trade and global supply and demand. During periods when the BTC has lapsed, biomass-based diesel producers may elect to continue purchasing feedstock and producing biomass-based diesel at negative margins under the assumption the BTC will be retroactively reinstated, and consequently, the price of feedstocks may not decrease to a level proportionate to current operating margins. Increasing production of biomass-based diesel and, particularly recent and prospective expansion of renewable diesel capacity, and the development of alternative fuels and renewable chemicals also puts pressure on feedstock supply and availability to the biomass-based diesel industry. The biomass-based diesel industry may have difficulty in procuring feedstocks at economical prices if competition for biomass-based diesel feedstocks increases due to newly added renewable diesel capacity.

Historically, the spread between biomass-based diesel prices and feedstock costs has varied significantly. Although actual yields vary depending on the feedstock quality, the average monthly spread between the price per gallon of 100% pure biodiesel ("B100") as reported by The Jacobsen Publishing Company, and the price per gallon for the amount of choice white grease necessary to produce one gallon of B100 was $1.20 in 2017, $1.38 in 2018 and $1.01 in the first half of 2019, assuming eight pounds of choice white grease yields one gallon of biomass-based diesel. The average monthly spread for the amount of crude soybean oil required to produce one gallon of B100, based on the nearby futures contract as reported on the Chicago

Board of Trade, was $0.64 in 2017, $0.76 in 2018 and $0.63 in the first half of 2019, assuming 7.5 pounds of soybean oil yields one gallon of biomass-based diesel. For each year from 2016 to 2018, approximately 72%, 73% and 77%, respectively, of our annual total feedstock usage was inedible corn oil, used cooking oil or inedible animal fat, and approximately 28%, 27% and 23%, respectively, was virgin vegetable oils. When the spread between biomass-based diesel prices and feedstock costs narrows, our profitability will be harmed.

Risk management transactions could significantly increase our operating costs and may not be effective.

In an attempt to partially offset the effects of volatile feedstock costs and biomass-based diesel fuel prices, we enter into contracts that establish market positions in feedstocks, such as inedible corn oil, used cooking oil, inedible animal fats and soybean oil, along with related commodities, such as heating oil and ultra-low sulfur diesel ("ULSD"). The financial impact of such market positions depends on commodity prices at the time that we are required to perform our obligations under these contracts, as well as the cumulative sum of the obligations we assume under these contracts.

Risk management activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. Risk management arrangements expose us to the risk of financial loss in situations where the counterparty defaults on its contract or, in the case of exchange-traded or over-the-counter futures or options contracts, where there is a change in the expected differential between the underlying price in the contract and the actual prices paid or received by us. Changes in the value of these futures instruments are recognized in current income and may result in margin calls. We had risk management losses of $28.3 million from our derivative financial instrument trading activity for the first half of 2019, compared to risk management losses of $15.3 million for the first half of 2018. At June 30, 2019, the net notional volumes of NY Harbor ULSD, CBOT Soybean Oil and NYMEX Natural Gas covered under the open risk management contracts were approximately 50 million gallons, 3 million pounds and 2 million million British thermal units, respectively. A 10% positive change in the prices of NYMEX NY Harbor ULSD would have a negative effect of $9.7 million on the fair value of these instruments at June 30, 2019. A 10% positive change in the price of CBOT Soybean Oil would have had an immaterial positive effect on the fair value of these instruments at June 30, 2019. If these adverse changes in derivative instrument fair value were to occur in larger magnitude or simultaneously, a significant amount of liquidity would be needed to fund margin calls. In addition, we may also vary the amount of risk management strategies we undertake, or we may choose not to engage in risk management transactions at all. Our results of operations may be negatively impacted if we are not able to manage our risk management strategy effectively.

One customer accounted for a meaningful percentage of revenues and a loss of this customer could have an adverse impact on our total revenues.

One customer, Pilot Travel Centers LLC, ("Pilot"), the largest operator of travel centers in North America, accounted for 8%, 9% and 8% of our revenues in the first half of 2019, and the full years of 2018, and 2017, respectively. Our revenues from Pilot generally do not include the RINs or LCFS credits associated with the gallons of biomass-based diesel sold to Pilot. The value of those RINs and LCFS credits represented approximately an additional 0.5%, 2% and 9% of our total sales in the first half of 2019, and the full years of 2018 and 2017, respectively, based on the OPIS average RIN and LCFS prices for these periods. In the event we lose Pilot as a customer or Pilot significantly reduces the volume of biomass-based diesel purchased from us, it could be difficult to replace the lost revenues, and our profitability and cash flow could be materially harmed. We do not have a long-term contract with Pilot that ensures a continuing level of business from Pilot.

Our facilities and our customers' facilities are subject to risks associated with fire, explosions, leaks, and natural disasters, which may disrupt our business and increase costs and liabilities.

Because biomass-based diesel and some of its inputs and outputs are combustible and/or flammable, a leak, fire or explosion may occur at a plant or customer’s facility which could result in damage to the plant and nearby properties, injury to employees and others, and interruption of operations. For example, we experienced fires at our Geismar facility in April 2015 and again in September 2015 and there was a fire at our Madison facility in June 2017. As a result of these fires, people were injured and the affected facilities were shut down for lengthy periods while repairs and upgrades were completed.

The operations at our facilities are also subject to the risk of natural disasters. Our Houston and Geismar facilities, due to their Gulf Coast locations, are vulnerable to hurricanes and flooding, which may cause plant damage, injury to employees and others and interruption of operations. For example, in August 2016 we experienced reduced operating days at our Geismar facility as a result of local area flooding and reduced operating days at our Houston facility as a result of Hurricane Harvey in August 2017. A majority of our facilities are located in the Midwest, and are subject to tornado activity. In addition, California has become one of our largest markets, serviced by our Geismar and Midwest facilities. An earthquake or other natural disaster could disrupt our ability to transport, store and deliver products to the California market.

If we experience a fire or other serious incident at our facilities or if any of our facilities is affected by a natural disaster, we may incur significant additional costs including, among other things, loss of profits due to unplanned temporary or

permanent shutdowns of our facilities, or the means of transporting our products, cleanup costs, liability for damages or injuries, legal expenses and reconstruction expenses, which would harm our results of operations and financial condition.

In addition to biodiesel and renewable diesel, we store and transport petroleum-based motor fuels. The dangers inherent in the storage and transportation of fuels could cause disruptions in our operations and could expose us to potentially significant losses, costs or liabilities.

We store fuel in above ground storage tanks and transport fuel in our own trucks as well as with third-party carriers. Our operations are subject to significant hazards and risks inherent in transporting and storing fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to our properties and the properties of others. Any such event not covered by our insurance could have a material adverse effect on our business, financial condition and results of operations.

Our insurance may not protect us against our business and operating risks.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially and, in some instances, certain insurance policies may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we intend to maintain insurance at levels we believe are appropriate for our business and consistent with industry practice, we will not be fully insured against all risks. In addition, pollution, environmental risks and the risk of natural disasters generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.

We operate in a highly competitive industry and competition in our industry would increase if new participants enter the biomass-based diesel or advanced biofuels business.

We operate in a very competitive environment. The biomass-based diesel industry primarily comprises smaller entities that engage exclusively in biodiesel production, large integrated agribusiness companies that produce biodiesel along with their soybean crush businesses and increasingly, integrated petroleum companies producing renewable diesel. We face competition for capital, labor, feedstocks and other resources from these companies. In the United States, we compete with soybean processors and refiners, including Archer-Daniels-Midland Company, Cargill, and Louis Dreyfus Commodities. In addition, petroleum refiners are increasingly entering into renewable diesel production. Such petroleum refiners include Neste Corporation with approximately 882 mmgy of global renewable diesel production capacity in Asia and Europe, and Valero Energy Corporation through its Diamond Green Diesel joint venture that operates an approximate 275 mmgy capacity renewable diesel facility in Norco, Louisiana that is in the process of being expanded by 400 mmgy. In addition, petroleum refiners such as Sinclair, British Petroleum and Marathon Petroleum Corporation have announced that they have begun co-processing renewable diesel at certain of their refineries. All of these named competitors have greater financial resources than we do and may be able to produce biomass-based diesel at a lower cost than we do due to their integrated operations or greater refining capacity.

Petroleum companies and diesel retailers form the primary distribution networks for marketing biomass-based diesel through blended petroleum-based diesel. If these companies increase their direct or indirect biomass-based diesel production, including in the form of co-processing, there will be less need to purchase biomass-based diesel from independent biomass-based diesel producers like us. Such a shift in the market would materially harm our operations, cash flows and financial position.

We derive a substantial portion of our profitability from the production of renewable diesel at our plant located in Geismar, Louisiana and any interruption in our operations at this facility would have a material adverse effect on our results of operations and financial conditions.

Renewable diesel carries a premium price to biodiesel as a result of a variety of factors including the ability to blend it with petroleum diesel seamlessly, better cold weather performance, and because it generates more RINs on a per gallon basis. We estimated that our renewable diesel production facility in Geismar, Louisiana generated more than half of our adjusted EBITDA in 2018. We experienced two fires at this facility in 2015 that each resulted in the plant being shut down for a lengthy period. If production at this facility were interrupted again due to a fire or for any other reason, it would have a disproportionately significant and material adverse impact on our results of operations and financial condition.

Technological advances and changes in production methods in the biomass-based diesel industry and renewable chemical industry could render our plants obsolete and adversely affect our ability to compete.

It is expected that technological advances in biomass-based diesel production methods will continue to occur and new technologies for biomass-based diesel production may develop. Advances in the process of converting oils and fats into biodiesel and renewable diesel, including CPRD, could allow our competitors to produce biomass-based diesel faster and more efficiently and at a substantially lower cost. In addition, we currently produce biomass-based diesel to conform to or exceed standards established by the American Society for Testing and Materials ("ASTM"). ASTM standards for biomass-based diesel and biomass-based diesel blends may be modified in response to new technologies from the industries involved with diesel fuel.

New standards or production technologies may require us to make additional capital investments in, or modify, plant operations to meet these standards. If we are unable to adapt or incorporate technological advances into our operations, our production facilities could become less competitive or obsolete. Further, it may be necessary for us to make significant expenditures to acquire any new technology, acquire licenses or other rights to technology and retrofit our plants in order to incorporate new technologies and remain competitive.There is no assurance that we will be able to obtain such technologies, licenses or rights on favorable terms. If we are unable to obtain, implement or finance new technologies, our production facilities could be less efficient than our competitors, and our ability to produce biomass-based diesel on a competitive level may be harmed, negatively impacting our revenues and profitability.

Our intellectual property is integral to our business. If we are unable to protect our intellectual property, or others assert that our operations violate their intellectual property, our business could be adversely affected.

Our success depends in part upon our ability to protect and prevent others from using our intellectual property. Failure to obtain or maintain adequate intellectual property protection could adversely affect our competitive business position. We rely on a combination of intellectual property rights, including patents, copyrights, trademarks and trade secrets in the United States and in select foreign countries. Effective patent, copyright, trademark and trade secret protection may be unavailable, limited or not applied for in some countries.

We rely in part on trade secret protection to protect our confidential and proprietary information and processes. However, trade secrets are difficult to protect. We have taken measures to protect our trade secrets and proprietary information, but these measures may not be effective. For example, we require new employees and consultants to execute confidentiality agreements upon the commencement of their employment or consulting arrangement with us. These agreements generally require that all confidential information developed by the individual or made known to the individual by us during the course of the individual’s relationship with us be kept confidential and not disclosed to third parties. These agreements also generally provide that knowhow and inventions conceived by the individual in the course of rendering services to us are our exclusive property. Nevertheless, these agreements may be breached, or may not be enforceable, and our proprietary information may be disclosed. Despite the existence of these agreements, third parties may independently develop substantially equivalent proprietary information and techniques.

It may be difficult for us to protect and enforce our intellectual property. Costly and time-consuming litigation could be necessary to enforce and determine the scope of our proprietary rights. If we pursue litigation to assert our intellectual property rights, an adverse judicial decision in any legal action could limit our ability to assert our intellectual property rights, limit our ability to develop new products, limit the value of our technology or otherwise negatively impact our business, financial condition and results of operations.

A competitor could seek to enforce intellectual property claims against us. Defending intellectual property rights claims asserted against us, regardless of merit, could be time-consuming, expensive to litigate or settle, divert management resources and attention and force us to acquire intellectual property rights and licenses, which may involve substantial royalty payments. Further, a party making such a claim, if successful, could secure a judgment that requires us to pay substantial damages.

Increases in our transportation costs or disruptions in our transportation services could have a material adverse effect on our business.

Our business depends on transportation services to deliver raw materials to us and finished products to our customers. The costs of these transportation services are affected by the volatility in fuel prices or other factors. For example, from January 2016 to mid-2018, diesel prices increased from just over one dollar per gallon to over two dollars per gallon for the second and third quarters of 2018 and ending the year around one dollar and fifty cents per gallon. During the first half of 2019, diesel prices were just below two dollars per gallon on average.

Changes in fuel prices, and thus changes in our transportation costs, can be drastic and unpredictable. Our transportation costs are also affected by U.S. oil production in the Bakkens, which has had a significant impact on tank car availability and prices. If oil production from this area increases, the demand for rail cars will rise and will significantly increase rail car prices. We have not been able in the past, and may not be able in the future, to pass along part or all of any of these price increases to customers.

If we continue to be unable to increase our prices as a result of increased fuel costs charged to us by transportation providers, our gross margins may be materially adversely affected. If any transportation providers fail to deliver raw materials to us in a timely manner, we may be unable to manufacture products on a timely basis. Shipments of products and raw materials may be delayed due to weather conditions, strikes or other events. Any failure of a third-party transportation provider to deliver raw materials or products in a timely manner could harm our reputation, negatively affect our customer relationships and have a material adverse effect on our business, financial condition and results of operations.

We are dependent upon our key management personnel and other personnel whereby the loss of any of these persons could adversely affect our results of operations.

Our success depends on the abilities, expertise, judgment, discretion, integrity and good faith of our management and employees to manage the business and respond to economic, market and other conditions. We are highly dependent upon key members of our relatively small management team and employee base that possess unique technical skills for the execution of our business plan. There can be no assurance that any individual will continue in his or her capacity for any particular period of time or that replacement personnel with comparable skills could be found. The inability to retain our management team and employee base or attract suitably qualified replacements and additional staff could adversely affect our business. The loss of employees could delay or prevent the achievement of our business objectives and have a material adverse effect upon our results of operations and financial position.

We may encounter difficulties in effectively integrating the businesses we acquire, including our international businesses where we have limited operating history.

We may face significant challenges in effectively integrating entities and businesses that we acquire, and we may not realize the benefits anticipated from such acquisitions. Achieving the anticipated benefits of our acquired businesses will depend in part upon whether we can integrate our businesses in an efficient and effective manner. Our integration of acquired businesses involves a number of risks, including:


•	difficulty in integrating the operations and personnel of the acquired company;


•	difficulty in effectively integrating the acquired technologies, products or services with our current technologies, products or services;


•	demands on management related to the increase in our size after the acquisition;


•	the diversion of management’s attention from daily operations to the integration of acquired businesses and personnel;


•	failure to achieve expected synergies and costs savings;


•	difficulties in the assimilation and retention of employees;


•	difficulties in the assimilation of different cultures and practices, as well as in the assimilation of broad and geographically dispersed personnel and operations;


•	difficulties in the integration of departments, systems, including accounting systems, technologies, books and records and procedures, as well as in maintaining uniform standards and controls, including internal control over financial reporting, and related procedures and policies;


•	incurring acquisition-related costs or amortization costs for acquired intangible assets that could impact our operating results;


•	the need to fund significant working capital requirements of any acquired production facilities;

•

potential failure of the due diligence processes to identify significant problems, liabilities or other shortcomings or challenges of an acquired company or technology, including but not limited to, issues with the acquired company’s intellectual property, product quality, environmental liabilities, data back-up and security, revenue recognition or other accounting practices, employee, customer or partner issues or legal and financial contingencies;


•	exposure to litigation or other claims in connection with, or inheritance of claims or litigation risk as a result of, an acquisition, including but not limited to, claims from terminated employees, customers, former stockholders or other third parties; and


•	incurring significant exit charges if products or services acquired in business combinations are unsuccessful.

Our ability to recognize the benefit of our acquisition of two biodiesel production facilities in Germany and associated business operations, or any other international operations we may invest in the future, will require the attention of management and is subject to a number of risks. Our experience operating a biorefinery and other business operations outside of the United States is limited. In addition, while the biodiesel market in Europe benefits from regulations that encourage the use of biodiesel, these regulations are subject to political and public opinion and may be changed. In addition, expanding our operations internationally subjects us to the following risks:


•	recruiting and retaining talented and capable management and employees in foreign countries;


•	challenges caused by distance, language and cultural differences;


•	protecting and enforcing our intellectual property rights;


•	difficulties in the assimilation and retention of employees;


•	the inability to extend proprietary rights in our technology into new jurisdictions;


•	currency exchange rate fluctuations;


•	general economic and political conditions in foreign jurisdictions;


•	foreign tax consequences;


•	foreign exchange controls or U.S. tax laws in respect of repatriating income earned in countries outside the United States;


•	compliance with the U.S.'s Foreign Corrupt Practices Act and other similar anti-bribery and anti-corruption regulations;


•	political, economic and social instability;


•	higher costs associated with doing business internationally; and


•	export or import regulations as well as trade and tariff restrictions.

Our failure to successfully manage and integrate our acquisitions could have an adverse effect on our operating results, ability to recognize international revenue, and our overall financial condition.

We incur significant expenses to maintain and upgrade our operating equipment and plants, and any interruption in the operation of our facilities may harm our operating performance.

We regularly incur significant expenses to maintain and upgrade our equipment and facilities. The machines and equipment that we use to produce our products are complex, have many parts and some are run on a continuous basis. We must perform routine maintenance on our equipment and will have to periodically replace a variety of parts such as motors, pumps, pipes and electrical parts. In addition, our facilities require periodic shutdowns to perform major maintenance and upgrades. These scheduled shutdowns of facilities result in decreased sales and increased costs in the periods in which a shutdown occurs and could result in unexpected operational issues in future periods as a result of changes to equipment and operational and mechanical processes made during the shutdown period.

Growth in the sale and distribution of biodiesel is dependent on the expansion of related infrastructure which may not occur on a timely basis, if at all, and our operations could be adversely affected by infrastructure limitations or disruptions.

While renewable diesel has the same chemical composition as petroleum diesel and can utilize the same distribution infrastructure, biodiesel has a different chemical composition and may require separate or additional infrastructure. Growth in the biodiesel market depends on continued development of infrastructure for the distribution of biodiesel. Substantial investment required for these infrastructure changes and expansions may not be made on a timely basis or at all. The scope and timing of any infrastructure expansion are often beyond our control. Also, we compete with other biofuel companies for access to some of the key infrastructure components such as pipeline, terminal and underground storage tank capacity. As a result, increased production of biodiesel will increase the demand and competition for necessary infrastructure. Any delay or failure in expanding distribution infrastructure could hurt the demand for or prices of biodiesel, impede delivery of our biodiesel, and impose additional costs, each of which would have a material adverse effect on our results of operations and financial condition. Our business will be dependent on the continuing availability of infrastructure for the distribution of increasing volumes of biodiesel and any infrastructure disruptions could materially harm our business.

Our business is subject to seasonal changes based on regulatory factors and weather conditions and this seasonality could cause our revenues and operating results to fluctuate.

Our operating results are influenced by seasonal fluctuations in the price of and demand for biomass-based diesel. Seasonal fluctuations may be based on both the weather and the status of both the BTC and RVO.

Demand for our biomass-based diesel may be higher in the quarters leading up to the expiration of the BTC as customers seek to purchase biomass-based diesel when they can benefit from the agreed upon value sharing of the BTC with producers. This higher demand prompted by an expiring BTC has often resulted in reduced demand for biodiesel in the following quarter. In addition, RIN prices may also be subject to seasonal fluctuations. The RIN is dated for the calendar year in which it is generated. Since 20% of an Obligated Party's annual RVO can be satisfied by prior year RINs, most RINs must come from biofuel produced or imported during the RVO year. As a result, RIN prices can be expected to increase as the calendar year progresses if the RIN market is undersupplied compared to that year's RVO and decrease if it is oversupplied.

Weather also impacts our business because biodiesel typically has a higher cloud point than petroleum-based or renewable diesel. The cloud point is the temperature below which a fuel exhibits a noticeable cloudiness and eventually gels, leading to fuel handling and performance problems for customers and suppliers. Reduced demand in the winter for our higher cloud point biodiesel may result in excess supply of such higher cloud point biodiesel and lower prices for such higher cloud point biodiesel. Most of our production facilities are located in colder Midwestern states and our costs of shipping biodiesel to warmer climates generally increase in cold weather months.

The tendency of biodiesel to gel in colder weather may also result in long-term storage problems. In cold climates, fuel may need to be stored in a heated building or heated storage tanks, which result in higher storage costs. Higher cloud point biodiesel may have other performance problems, including the possibility of particulate formation above the cloud point which may result in increased expenses as we try to remedy these performance problems, including the costs of extra cold weather treatment additives. Remedying these performance problems may result in decreased yields, lower process throughput or both, as well as substantial capital costs. Any reduction in the demand for our biodiesel product, or the production capacity of our facilities will reduce our revenues and have an adverse effect on our cash flows and results of operations.

Failure to comply with governmental regulations, including EPA requirements relating to RFS2, could result in the imposition of penalties, fines, or restrictions on our operations and remedial liabilities.

The biomass-based diesel industry is subject to extensive federal, state and local laws and regulations. Under certain environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, and regardless of whether current or prior operations were conducted consistent with the accepted standards of practice. Many of our assets and plants were acquired from third parties and we may incur costs to remediate property contamination caused by previous owners. Compliance with these laws, regulations and obligations could require substantial capital expenditures. Failure to comply could result in the imposition of penalties, fines or restrictions on operations and remedial liabilities.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our business in general and on our results of operations, competitive position or financial condition. We are unable to predict the effect of additional environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would significantly increase our cost of doing business or affect our operations in any area.

We are subject to various laws and regulations related to RFS2, most significantly regulations related to the generation and dissemination of RINs. These regulations are highly complex and continuously evolving, requiring us to periodically update our compliance systems. In 2014, the EPA issued a final rule to establish a quality assurance program and the EPA also implemented regulations related to the generation and sale of biomass-based diesel RINs. Compliance with these or any new regulations or Obligated Party verification procedures could require significant expenditures to attain and maintain compliance. Any violation of these regulations by us, could result in significant fines and harm our customers’ confidence in the RINs we issue, either of which could have a material adverse effect on our business.

Renewable diesel fuel is superior to biodiesel in certain respects and if renewable diesel production capacity increases to a sufficient extent, it could largely supplant biodiesel as the renewable fuel of choice; we may not be successful in expanding our renewable diesel production capacity.

Renewable diesel is not as widely available as biodiesel, but it has certain characteristics that favorably distinguish it from traditional biodiesel and as a result renewable diesel carries a price premium compared to biodiesel. For example, renewable diesel has very similar chemical properties to petroleum-based diesel, which permits 100% renewable diesel (unlike 100% biodiesel) to flow through the same fuel storage and distribution network as petroleum diesel. Renewable diesel can also be used in its pure form in modern engines rather than as a blend with petroleum diesel and has similar cold weather performance as petroleum diesel. Renewable diesel and co-processed renewable diesel may receive 1.6 or 1.7 RINs per gallon, whereas biodiesel receives 1.5 RINs per gallon. As the value of RINs increases, this RIN advantage makes renewable diesel more cost-effective, both as a petroleum-based diesel substitute and for meeting RFS2 requirements. If renewable diesel proves to have

superior performance characteristics and is more cost-effective than biodiesel, revenues from our biodiesel plants and our results of operations would be adversely impacted.

In view of the demand and price premium for renewable diesel, we are evaluating opportunities to expand our renewable diesel operations. The opportunities currently under review include a potential collaboration with Phillips 66 on the possible construction of a large-scale renewable diesel plant in Washington state. We have not reached a definitive agreement with Phillips 66 and an agreement may never be reached. We are also evaluating a large-scale expansion of our renewable diesel facility in Geismar, Louisiana. If we elect to undertake either or both of these projects to expand our renewable diesel capacity, we will be required to make substantial capital expenditures, we may incur significant indebtedness and there is no assurance that the new or expanded operations will operate profitably or profitably enough to support the investment we make.

Perception about “food vs. fuel” could impact public policy which could impair our ability to operate at a profit and substantially harm our revenues and operating margins.

Some people believe that biomass-based diesel may increase the cost of food, as some feedstocks such as soybean oil used to make biomass-based diesel can also be used for food products. This debate is often referred to as “food vs. fuel.” This is a concern to the biomass-based diesel industry because biomass-based diesel demand is heavily influenced by government policy and if public opinion were to erode, it is possible that these policies could lose political support. These views could also negatively impact public perception of biomass-based diesel. Such claims have led some, including members of Congress, to urge the modification of current government policies which affect the production and sale of biofuels in the United States.

Concerns regarding the environmental impact of biomass-based diesel production could affect public policy which could impair our ability to operate at a profit and substantially harm our revenues and operating margins.

Under the Energy Independence and Security Act of 2007 ("EISA"), the EPA is required to produce a study every three years of the environmental impacts associated with current and future biofuel production and use, including effects on air and water quality, soil quality and conservation, water availability, energy recovery from secondary materials, ecosystem health and biodiversity, invasive species and international impacts. The only such triennial report was released in February 2012. The 2012 report concludes that (1) the extent of negative impacts to date are limited in magnitude and are primarily associated with the intensification of corn production; (2) whether future impacts are positive or negative will be determined by the choice of feedstock, land use change, cultivation and conservation practices; and (3) realizing potential benefits will require implementation and monitoring of conservation and best management practices, improvements in production efficiency, and implementation of innovative technologies at commercial scales. Should future EPA triennial studies, or other analyses find that biofuel production and use has resulted in, or could in the future result in, adverse environmental impacts, such findings could also negatively impact public perception and acceptance of biofuel as an alternative fuel, which also could result in the loss of political support. To the extent that state or federal laws are modified or public perception turns against biomass-based diesel, use requirements such as RFS2 and state tax incentives may not continue, which could materially harm our ability to operate profitably.

Nitrogen oxide emissions from biodiesel may harm its appeal as a renewable fuel and increase costs.

In some instances, biodiesel may increase emissions of nitrogen oxide as compared to petroleum-based diesel fuel, which could harm air quality. Nitrogen oxide is a contributor to ozone and smog. While newer diesel engines are believed to eliminate any such increase, emissions from older vehicles may decrease the appeal of biodiesel to environmental groups and agencies who have been historic supporters of the biodiesel industry, potentially harming our ability to market our biodiesel.

In addition, several states may act to regulate potential nitrogen oxide emissions from biodiesel. California adopted regulations that limit the volume of biodiesel that can be used or requires an additive to reduce potential emissions. In states where such an additive is required to sell biodiesel, the additional cost of the additive may make biodiesel less profitable or make biodiesel less cost competitive against petroleum-based diesel or renewable diesel, which would negatively impact our ability to sell biodiesel in such states and therefore have an adverse effect on our revenues and profitability.

We are dependent upon one supplier to provide hydrogen necessary to execute our renewable diesel production process and the loss of this supplier could disrupt our production process.

Our Geismar facility relies on one supplier to provide hydrogen necessary to execute the production process. Any disruptions to the hydrogen supply during production from this supplier will result in the shutdown of our Geismar plant operations. We are currently seeking additional hydrogen suppliers for our Geismar facility.

RISKS RELATED TO OUR INDEBTEDNESS

We and certain subsidiaries have indebtedness, which subjects us to potential defaults, that could adversely affect our ability to raise additional capital to fund our operations and limits our ability to react to changes in the economy or the biomass-based diesel industry.

At June 30, 2019, our total term debt before debt issuance costs was $116.8 million. This includes $76.4 million aggregate carrying value on our $96.3 million face amount, 4.00% convertible senior notes due in June 2036, which we refer to as the "2036 Convertible Senior Notes". At June 30, 2019, our total term debt also includes borrowings at our Danville facility of $7.9 million, at our Ralston facility of $17.4 million, at our Grays Harbor facility of $8.1 million and at REG Capital LLC. of $7.1 million.

Our indebtedness could:


•	require us to dedicate a substantial portion of our cash flow from operations to payments of principal, interest on, and other fees related to such indebtedness, thereby reducing the availability of our cash flow to fund working capital and capital expenditures, and for other general corporate purposes;


•	increase our vulnerability to general adverse economic and biomass-based diesel industry conditions, including interest rate fluctuations, because a portion of our revolving credit facilities are and will continue to be at variable rates of interest;


•	limit our flexibility in planning for, or reacting to, changes in our business and the biomass-based diesel industry, which may place us at a competitive disadvantage compared to our competitors that have less debt; and


•	limit among other things, our ability to borrow additional funds.

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness, including the 2036 Convertible Senior Notes, depends on our future financial performance, which is subject to several factors including economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to satisfy our obligations under our indebtedness or any future indebtedness we may incur as well as our ability to make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying investments or capital expenditures, selling assets, refinancing or obtaining additional capital on terms that may be onerous or highly dilutive. Our ability to refinance our existing or future indebtedness will depend on the conditions in the capital markets and our financial condition prior to maturity of the indebtedness.

Despite our current indebtedness levels, we may still incur significant additional indebtedness. Incurring more indebtedness could increase the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness, including additional secured indebtedness, in the future. As of June 30, 2019, we had $67.9 million of undrawn availability under our lines of credit, subject to borrowing base limitations. In addition, the indentures governing our convertible notes do not prevent us from incurring additional indebtedness or other liabilities that constitute indebtedness. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

We may not have the ability to raise the funds necessary to settle conversions of our convertible notes in cash or to repurchase the convertible notes for cash upon a fundamental change or on a repurchase date, and our future debt may contain limitations on our ability to repurchase the convertible notes.

Holders of the 2036 Convertible Senior Notes will have the right to require us to repurchase their 2036 Convertible Senior Notes upon the occurrence of a fundamental change at a repurchase price generally equal to 100% of their principal amount, plus accrued and unpaid interest, if any.

Holders of the 2036 Convertible Senior Notes will also have the right to require us to repurchase their notes on each of June 15, 2021, June 15, 2026 and June 15, 2031 at a repurchase price generally equal to 100% of their principal amount, plus accrued and unpaid interest, if any.

In addition, holders of the 2036 Convertible Senior Notes have the right to convert their notes during any calendar quarter when the last reported sale price of our common stock for 20 trading days during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the applicable conversion price of $14.01.

For the 2036 Convertible Senior Notes, our current intent is to settle conversions using cash for the principal amount of convertible senior notes converted, with the remaining value satisfied at the Company's option in cash, stock or a combination of cash and stock. However, we may not have enough available cash or be able to obtain financing at the time we are required

to make repurchases of the 2036 Convertible Senior Notes upon a fundamental change or to settle conversion of the 2036 Convertible Senior Notes in cash.

In addition, our ability to repurchase the 2036 Convertible Senior Notes may be limited by law, by regulatory authority or by agreements governing our future indebtedness. Our failure to repurchase 2036 Convertible Senior Notes at a time when the repurchase is required by the indenture would constitute a default under the indenture governing the 2036 Convertible Senior Notes. A default under the indenture or the fundamental change itself could also lead to a default under agreements governing our other indebtedness. If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness and repurchase the convertible notes.

Certain provisions in the indenture governing the 2036 Convertible Senior Notes could delay or prevent an otherwise beneficial takeover or takeover attempt of us.

Certain provisions in the 2036 Convertible Senior Notes and the indenture could make it more difficult or more expensive for a third party to acquire us. For example, if a takeover would constitute a fundamental change, holders of the 2036 Convertible Senior Notes will have the right to require us to repurchase their 2036 Convertible Senior Notes in cash. In addition, if a takeover constitutes a make-whole fundamental change, we may be required to increase the conversion rate for holders who convert their 2036 Convertible Senior Notes in connection with such takeover. In either case, and in other cases, our obligations under the 2036 Convertible Senior Notes and the indenture could increase the cost of acquiring us or otherwise discourage a third party from acquiring us or removing incumbent management.

We are a holding company and there are limitations on our ability to receive dividends and distributions from our subsidiaries.

All of our principal assets, including our biomass-based diesel production facilities, are owned by subsidiaries and some of these subsidiaries are subject to loan covenants that generally restrict them from paying dividends, making distributions or making loans to us or to any other subsidiary. These limitations will restrict our ability to repay indebtedness, finance capital projects or pay dividends to stockholders from our subsidiaries’ cash flows from operations.

Our debt agreements impose significant operating and financial restrictions on our subsidiaries, which may prevent us from capitalizing on business opportunities.

Certain of our revolving and term credit agreements, including our M&L and Services Revolver, impose significant operating and financial restrictions on certain of our subsidiaries. These restrictions limit certain of our subsidiaries’ ability, among other things, to:

•incur additional indebtedness or issue certain disqualified stock and preferred stock;

•place restrictions on the ability of certain of our subsidiaries to pay dividends or make other payments to us;

•engage in transactions with affiliates;

•sell certain assets or merge with or into other companies;

•guarantee indebtedness; and

•create liens.

When (and for as long as) the availability under the M&L and Services Revolver is less than a specified amount for a certain period of time, funds deposited into deposit accounts used for collections will be transferred on a daily basis into a blocked account with the administrative agent and applied to prepay loans under the M&L and Services Revolver.

As a result of these covenants and restrictions, we may be limited in how we conduct our business and we may be unable to raise additional debt or equity financing to compete effectively or to take advantage of new business opportunities. The terms of any future indebtedness we may incur could include more restrictive covenants. There is no assurance that we will be able to maintain compliance with these covenants in the future and, if we fail to do so, that we will be able to obtain waivers from the lenders and/or amend the covenants.

There are limitations on our ability to incur the full $150.0 million of commitments under the M&L and Services Revolver. Borrowings under our M&L and Services Revolver are limited by a specified borrowing base consisting of a percentage of eligible accounts receivable and inventory, less customary reserves. In addition, under the M&L and Services Revolver, a monthly fixed charge coverage ratio would become applicable if excess availability under the M&L and Services Revolver is less than 10% of the total $150 million of current revolving loan commitments, or $15 million. As of June 30, 2019, availability under the M&L and Services Revolver was approximately $67.9 million. However, it is possible that excess availability under the Revolving Credit could fall below the 10% threshold in a future period. If the covenant trigger were to occur, our subsidiaries who are the borrowers under the M&L and Services Revolver would be required to satisfy and maintain on the last day of each month a fixed charge coverage ratio of at least 1.0x for the preceding twelve month period.

As of June 30, 2019, the fixed charge coverage ratio for our M&L and Services Revolver was approximately 0.331, which was below the minimum amount required for compliance with this ratio. However, as noted above, we are not required to comply with the minimum fixed charge covenant of 1.0 unless availability under the M&L and Services Revolver drops below the agreed threshold. Our ability to meet the required fixed charge coverage ratio can be affected by events beyond our control, and we cannot assure you that we will meet this ratio. A breach of any of these covenants would result in a default under the M&L and Services Revolver.

RISKS RELATED TO OUR COMMON STOCK

The market price for our common stock may be volatile.

The market price for our common stock is likely to be highly volatile and subject to wide fluctuations in response to factors including the following:


•	actual or anticipated fluctuations in our financial condition and operating results;


•	changes in the performance or market valuations of other companies engaged in our industry;


•	issuance of new or updated research reports by securities or industry analysts;


•	changes in financial estimates by us or of securities or industry analysts;


•	investors’ general perception of us and the industry in which we operate;


•	changes in the political climate in the industry in which we operate, existing laws, regulations and policies applicable to our business and products, including RFS2, and the continuation or adoption or failure to continue or adopt renewable energy requirements and incentives, including the BTC;


•	other regulatory developments in our industry affecting us, our customers or our competitors;


•	announcements of technological innovations by us or our competitors;


•	announcement or expectation of additional financing efforts, including sales or expected sales of additional common stock;


•	additions or departures of key management or other personnel;


•	litigation;


•	inadequate trading volume;


•	general market conditions in our industry;


•	whether our shares are included in stock market indexes such as the S&P SmallCap 600 index; and


•	general economic and market conditions, including continued dislocations and downward pressure in the capital markets.

In addition, stock markets experience significant price and volume fluctuations from time to time that are not related to the operating performance of particular companies. These market fluctuations may have material adverse effect on the market price of our common stock.

We may issue additional common stock as consideration for future investments or acquisitions.

We have issued in the past, and may issue in the future, our securities in connection with investments and acquisitions. Our stockholders could suffer significant dilution, from our issuances of equity or convertible debt securities. Any new equity securities we issue could have rights, preferences and privileges superior to those of holders of our common stock. The amount of our common stock or securities convertible into or exchangeable for our common stock issued in connection with an investment or acquisition could constitute a material portion of our then outstanding common stock.

If we fail to maintain effective internal control over financial reporting, we might not be able to report our financial results accurately or prevent fraud. In that case, our stockholders could lose confidence in our financial reporting, which would harm our business and could negatively impact the value of our stock.

Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. The process of maintaining our internal controls may be expensive and time consuming and may require significant attention from management. Although we have concluded as of June 30, 2019 that our internal control over financial reporting provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, because of its inherent limitations, internal control over financial reporting may not prevent or detect fraud or misstatements.

Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our results of operations or cause us to fail to meet our reporting obligations. If we or our independent registered public accounting firm discover a material weakness, the disclosure of that fact could harm the value of our stock and our business.

Delaware law and our amended and restated certificate of incorporation and bylaws contain anti-takeover provisions that could delay or discourage takeover attempts that stockholders may consider favorable.

Provisions in our amended and restated certificate of incorporation and bylaws may have the effect of delaying or preventing a change of control or changes in our management. These provisions include the following:


•	the right of the board of directors to elect a director to fill a vacancy created by the expansion of the board of directors;


•	the requirement for advance notice for nominations for election to the board of directors or for proposing matters that can be acted upon at a stockholders’ meeting;


•	the ability of the board of directors to alter our bylaws without obtaining stockholder approval;


•	the ability of the board of directors to issue, without stockholder approval, up to 10,000,000 shares of preferred stock with rights set by the board of directors, which rights could be senior to those of common stock;


•	a classified board;


•	the required approval of holders of at least two-thirds of the shares entitled to vote at an election of directors to adopt, amend or repeal our bylaws or amend or repeal the provisions of our amended and restated certificate of incorporation regarding the classified board, the election and removal of directors and the ability of stockholders to take action by written consent; and


•	the elimination of the right of stockholders to call a special meeting of stockholders and to take action by written consent.

In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law ("DGCL"). These provisions may prohibit or restrict large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us. These provisions in our amended and restated certificate of incorporation and bylaws and under Delaware law could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock in the future and result in our market price being lower than it would without these provisions.

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

Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

(A) Exhibits:



Exhibit No.		Description
10.1		Amendment No. 13 to Credit Agreement, dated as of July 9, 2019, by and among Wells Fargo Capital Finance, LLC, Fifth Third Bank, REG Services Group, LLC and REG Marketing and Logistics Group, LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed July 11, 2019).
31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a).
31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a).
32.1		Certification of the Chief Executive Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
32.2		Certification of the Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB		XBRL Taxonomy Extension Label Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

* In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release No. 34-47986, the certifications furnished in Exhibit 32.1 and Exhibit 32.2 hereto are deemed to accompany this Form 10-Q and will not be deemed “filed” for purposes of Section 18 of the Exchange Act. Such certifications will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.




		RENEWABLE ENERGY GROUP, INC.


Dated:	August 7, 2019	By:	/s/ Cynthia J. Warner
			Cynthia J. Warner
			President and Chief Executive Officer (Principal Executive Officer)

Dated:	August 7, 2019	By:	/s/ Chad Stone
			Chad Stone
			Chief Financial Officer (Principal Financial Officer)

Dated:	August 7, 2019	By:	/s/ Todd M. Samuels
			Todd M. Samuels
			Chief Accounting Officer (Principal Accounting Officer)