Clean Energy Fuels Corp. - Quarter Report: 2014 March (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 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 March 31, 2014
Commission File Number: 001-33480
CLEAN ENERGY FUELS CORP.
(Exact name of registrant as specified in its charter)
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Delaware |
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33-0968580 |
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(State or other jurisdiction of incorporation) |
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(IRS Employer Identification No.) |
4675 MacArthur Court, Suite 800, Newport Beach, CA 92660
(Address of principal executive offices, including zip code)
(949) 437-1000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232,405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer x |
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Accelerated filer o |
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Non-accelerated filer o |
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes o No x
As of April 30, 2014, there were 89,858,816 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.
CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
Table of Contents
Item 1.—Financial Statements (Unaudited)
Clean Energy Fuels Corp. and Subsidiaries
Condensed Consolidated Balance Sheets
December 31, 2013 and March 31, 2014
(Unaudited)
(In thousands, except share data)
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December 31, |
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March 31, |
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Assets |
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|
|
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Current assets: |
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|
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Cash and cash equivalents |
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$ |
240,033 |
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$ |
154,328 |
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Restricted cash |
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8,403 |
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11,923 |
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Short-term investments |
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138,240 |
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164,482 |
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Accounts receivable, net of allowance for doubtful accounts of $832 and $987 as of December 31, 2013 and March 31, 2014, respectively |
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53,473 |
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60,144 |
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Other receivables |
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26,285 |
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19,266 |
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Inventory, net |
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33,822 |
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38,292 |
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Prepaid expenses and other current assets |
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20,840 |
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20,481 |
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Total current assets |
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521,096 |
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468,916 |
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Land, property and equipment, net |
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487,854 |
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520,984 |
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Notes receivable and other long-term assets |
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73,697 |
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72,582 |
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Goodwill |
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88,548 |
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86,869 |
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Intangible assets, net |
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79,770 |
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75,643 |
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Total assets |
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$ |
1,250,965 |
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$ |
1,224,994 |
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Liabilities and Stockholders’ Equity |
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Current liabilities: |
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Current portion of long-term debt and capital lease obligations |
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$ |
23,401 |
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$ |
14,543 |
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Accounts payable |
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33,541 |
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35,394 |
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Accrued liabilities |
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46,745 |
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42,575 |
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Deferred revenue |
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16,419 |
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18,563 |
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Total current liabilities |
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120,106 |
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111,075 |
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Long-term debt and capital lease obligations, less current portion |
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532,017 |
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543,320 |
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Long-term debt, related party |
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65,000 |
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65,000 |
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Other long-term liabilities |
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15,304 |
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11,350 |
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Total liabilities |
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732,427 |
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730,745 |
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Commitments and contingencies |
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Stockholders’ equity: |
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Preferred stock, $0.0001 par value. Authorized 1,000,000 shares; issued and outstanding no shares |
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— |
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— |
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Common stock, $0.0001 par value. Authorized 149,000,000 shares; issued and outstanding 89,364,397 shares and 89,858,816 shares at December 31, 2013 and March 31, 2014, respectively |
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9 |
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9 |
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Additional paid-in capital |
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883,045 |
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890,880 |
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Accumulated deficit |
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(367,782 |
) |
(396,375 |
) | ||
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Accumulated other comprehensive loss |
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(700 |
) |
(4,160 |
) | ||
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Total Clean Energy Fuels Corp. stockholders’ equity |
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514,572 |
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490,354 |
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Noncontrolling interest in subsidiary |
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3,966 |
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3,895 |
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Total stockholders’ equity |
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518,538 |
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494,249 |
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Total liabilities and stockholders’ equity |
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$ |
1,250,965 |
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$ |
1,224,994 |
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See accompanying notes to condensed consolidated financial statements.
Clean Energy Fuels Corp. and Subsidiaries
Condensed Consolidated Statements of Operations
For the Three Months Ended March 31, 2013 and 2014
(Unaudited)
(In thousands, except share and per share data)
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Three Months Ended |
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2013 |
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2014 |
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Revenue: |
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Product revenues |
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$ |
83,483 |
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$ |
85,789 |
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Service revenues |
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9,560 |
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9,486 |
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Total revenues |
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93,043 |
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95,275 |
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Operating expenses: |
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Cost of sales (exclusive of depreciation and amortization shown separately below): |
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Product cost of sales |
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46,814 |
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67,867 |
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Service cost of sales |
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3,927 |
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3,764 |
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Derivative (gains) losses: |
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Series I warrant valuation |
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466 |
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(4,455 |
) | ||
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Selling, general and administrative |
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32,876 |
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33,490 |
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Depreciation and amortization |
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10,158 |
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11,515 |
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Total operating expenses |
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94,241 |
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112,181 |
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Operating loss |
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(1,198 |
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(16,906 |
) | ||
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Interest expense, net |
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(5,071 |
) |
(9,510 |
) | ||
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Other expense, net |
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(390 |
) |
(1,286 |
) | ||
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Loss from equity method investment |
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(76 |
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— |
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Gain from sale of equity method investment |
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4,705 |
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— |
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Loss before income taxes |
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(2,030 |
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(27,702 |
) | ||
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Income tax expense |
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(1,805 |
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(962 |
) | ||
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Net loss |
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(3,835 |
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(28,664 |
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(Income) loss of noncontrolling interest |
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(36 |
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71 |
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Net loss attributable to Clean Energy Fuels Corp. |
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$ |
(3,871 |
) |
$ |
(28,593 |
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Loss per share attributable to Clean Energy Fuels Corp.: |
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Basic |
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$ |
(0.04 |
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$ |
(0.30 |
) |
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Diluted |
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$ |
(0.04 |
) |
$ |
(0.30 |
) |
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Weighted-average common shares outstanding: |
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Basic |
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93,132,454 |
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94,676,325 |
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Diluted |
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93,132,454 |
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94,676,325 |
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See accompanying notes to condensed consolidated financial statements.
Clean Energy Fuels Corp. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Loss)
For the Three Months Ended March 31, 2013 and 2014
(Unaudited)
(In thousands)
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Clean Energy Fuels Corp. |
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Noncontrolling Interest |
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Total |
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Three Months Ended |
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Three Months Ended |
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Three Months Ended |
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2013 |
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2014 |
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2013 |
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2014 |
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2013 |
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2014 |
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Net income (loss) |
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$ |
(3,871 |
) |
$ |
(28,593 |
) |
$ |
36 |
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$ |
(71 |
) |
$ |
(3,835 |
) |
$ |
(28,664 |
) |
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Other comprehensive income, net of tax: |
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Foreign currency translation adjustments |
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(655 |
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196 |
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— |
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— |
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(655 |
) |
196 |
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Foreign currency adjustments on intra-entity long-term investments |
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(1,818 |
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(3,340 |
) |
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(1,818 |
) |
(3,340 |
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Unrealized losses on available-for-sale securities |
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(37 |
) |
(316 |
) |
— |
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— |
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(37 |
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(316 |
) | ||||||
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Unrecognized gains on derivatives |
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106 |
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— |
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— |
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— |
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106 |
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— |
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Total other comprehensive loss, net of tax |
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(2,404 |
) |
(3,460 |
) |
— |
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— |
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(2,404 |
) |
(3,460 |
) | ||||||
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|
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|
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Comprehensive income (loss) |
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$ |
(6,275 |
) |
$ |
(32,053 |
) |
$ |
36 |
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$ |
(71 |
) |
$ |
(6,239 |
) |
$ |
(32,124 |
) |
See accompanying notes to condensed consolidated financial statements.
Clean Energy Fuels Corp.
Condensed Consolidated Statements of Cash Flows
For the Three Months Ended March 31, 2013 and 2014
(Unaudited)
(In thousands)
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Three Months Ended |
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2013 |
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2014 |
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Cash flows from operating activities: |
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Net loss |
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$ |
(3,835 |
) |
$ |
(28,664 |
) |
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Adjustments to reconcile net loss to net cash used in operating activities: |
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Depreciation and amortization |
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10,158 |
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11,515 |
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Provision for doubtful accounts, notes and inventory |
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17 |
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541 |
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Loss on disposal of assets |
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137 |
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— |
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Derivative (gain) loss |
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466 |
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(4,455 |
) | ||
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Stock-based compensation expense |
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6,212 |
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3,420 |
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Amortization of debt issuance cost |
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262 |
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746 |
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Accretion of notes payable |
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340 |
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108 |
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Gain on sale of equity method investment |
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(4,705 |
) |
— |
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Dividend received on equity method investment |
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1,091 |
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— |
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Changes in operating assets and liabilities, net of assets and liabilities acquired: |
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|
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Accounts and other receivables |
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(17,961 |
) |
1,573 |
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Inventory |
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(6,066 |
) |
(4,470 |
) | ||
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Prepaid expenses and other assets |
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(2,276 |
) |
864 |
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Accounts payable |
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(11,742 |
) |
5,714 |
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Accrued expenses and other |
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10,970 |
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(1,420 |
) | ||
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Net cash used in operating activities |
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(16,932 |
) |
(14,528 |
) | ||
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Cash flows from investing activities: |
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Purchases of short-term investments |
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(21,227 |
) |
(56,993 |
) | ||
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Maturities of short-term investments |
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21,233 |
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29,818 |
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Purchases of property and equipment |
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(21,703 |
) |
(46,851 |
) | ||
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Proceeds from sale of property and equipment |
|
95 |
|
— |
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Loans made to customers |
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(361 |
) |
(2,002 |
) | ||
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Payments on and proceeds from sales of loans receivable |
|
2,271 |
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1,515 |
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Restricted cash |
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10,711 |
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(3,520 |
) | ||
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Proceeds from sale of equity method investment |
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6,119 |
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— |
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Net cash used in investing activities |
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(2,862 |
) |
(78,033 |
) | ||
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Cash flows from financing activities: |
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|
|
|
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Proceeds from issuance of common stock and exercise of stock options |
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178 |
|
665 |
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Proceeds from debt instruments |
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— |
|
12,400 |
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Proceeds from revolving line of credit |
|
6,894 |
|
12,329 |
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Repayment of borrowing under revolving line of credit |
|
(7,380 |
) |
(9,517 |
) | ||
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Repayment of capital lease obligations and debt instruments |
|
(5,601 |
) |
(8,727 |
) | ||
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Payments for debt issuance costs |
|
— |
|
(914 |
) | ||
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Net cash provided by (used in) financing activities |
|
(5,909 |
) |
6,236 |
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Effect of exchange rates on cash and cash equivalents |
|
(247 |
) |
620 |
| ||
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Net decrease in cash |
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(25,950 |
) |
(85,705 |
) | ||
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Cash, beginning of period |
|
108,522 |
|
240,033 |
| ||
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Cash, end of period |
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$ |
82,572 |
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$ |
154,328 |
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|
Supplemental disclosure of cash flow information: |
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|
|
|
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Income taxes paid |
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$ |
1,653 |
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$ |
237 |
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Interest paid, net of approximately $829 and $964 capitalized, respectively |
|
4,014 |
|
12,259 |
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See accompanying notes to condensed consolidated financial statements.
Clean Energy Fuels Corp. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(Unaudited)
(In thousands, except share and per share data)
Note 1—General
Nature of Business: Clean Energy Fuels Corp., together with its majority and wholly owned subsidiaries (hereinafter collectively referred to as the “Company”) is engaged in the business of selling natural gas fueling solutions to its customers, primarily in the United States and Canada.
The Company has a broad customer base in a variety of markets, including trucking, airports, taxis, refuse, and public transit. The Company owns, operates, maintains and/or supplies approximately 500 natural gas fueling stations within the United States and Canada. The Company generates revenue through selling compressed natural gas (“CNG”) and liquefied natural gas (“LNG”), providing operation and maintenance services (“O&M”) to customers, building and selling natural gas fueling stations to customers, manufacturing and servicing natural gas fueling compressors and other equipment for CNG and LNG fueling stations, offering solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, processing and selling renewable natural gas (“RNG”), financing customers’ vehicle purchases and selling tradable credits the Company generates by selling natural gas and RNG as a vehicle fuel, including credits under the California low carbon fuel standard (“LCFS Credits”) and Renewable Identification Numbers (“RIN Credits”) under the federal Renewable Fuel Standard Phase 2. In addition, through June 28, 2013, the Company provided natural gas vehicle conversions and design and engineering services for natural gas engine systems.
Basis of Presentation: The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company’s financial position, results of operations and cash flows as of and for the three months ended March 31, 2013 and 2014. All intercompany accounts and transactions have been eliminated in consolidation. The three month periods ended March 31, 2013 and 2014 are not necessarily indicative of the results to be expected for the year ending December 31, 2014 or for any other interim period or for any future year.
Certain information and disclosures normally included in the notes to the financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) as they apply to interim reporting. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2013 that are included in the Company’s Annual Report on Form 10-K filed with the SEC on February 27, 2014.
Use of Estimates: The preparation of condensed consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and revenues and expenses recorded during the reporting period. Actual results could differ from those estimates.
Note 2—Cash and Cash Equivalents
The Company considers all highly liquid investments with maturities of three months or less on the date of acquisition to be cash equivalents.
Note 3—Restricted Cash
The Company classifies restricted cash as a current asset if the cash is expected to be used in operations within a year or to acquire a current asset. Otherwise, the restricted cash is classified as long-term. Restricted cash consisted of the following as of December 31, 2013 and March 31, 2014:
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December 31, |
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March 31, |
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Short-term restricted cash |
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|
|
|
| ||
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Standby letters of credit |
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$ |
1,822 |
|
$ |
1,822 |
|
|
DCEMB bonds — current operating costs |
|
6,581 |
|
7,773 |
| ||
|
Canton bonds — current operating costs |
|
— |
|
2,328 |
| ||
|
Total short-term restricted cash |
|
$ |
8,403 |
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$ |
11,923 |
|
Note 4—Investments
Available-for-sale investments are carried at fair value, inclusive of unrealized gains and losses. Net unrealized gains and losses are included in other comprehensive income (loss) net of applicable income taxes. Gains or losses on sales of available-for-sale investments are recognized on the specific identification basis. All of the Company’s short-term investments are classified as available-for-sale securities.
The Company reviews available-for-sale investments for other-than-temporary declines in fair value below their cost basis each quarter, and whenever events or changes in circumstances indicate that the cost basis of an asset may not be recoverable. This evaluation is based on a number of factors, including the length of time and the extent to which the fair value has been below its cost basis and adverse conditions related specifically to the security, including any changes to the credit rating of the security. As of March 31, 2014, the Company believes its carrying values for its available-for-sale investments are properly recorded.
Short-term investments as of December 31, 2013 are summarized as follows:
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|
|
Amortized Cost |
|
Gross Unrealized |
|
Estimated Fair |
| |||
|
Municipal bonds & notes |
|
$ |
60,047 |
|
$ |
(252 |
) |
$ |
59,795 |
|
|
Corporate bonds |
|
43,166 |
|
(342 |
) |
42,824 |
| |||
|
Certificate of deposits |
|
35,630 |
|
(9 |
) |
35,621 |
| |||
|
|
|
$ |
138,843 |
|
$ |
(603 |
) |
$ |
138,240 |
|
Short-term investments as of March 31, 2014 are summarized as follows:
|
|
|
Amortized Cost |
|
Gross Unrealized |
|
Estimated Fair |
| |||
|
Municipal bonds & notes |
|
$ |
67,309 |
|
$ |
(376 |
) |
$ |
66,933 |
|
|
Corporate bonds |
|
62,364 |
|
(537 |
) |
61,827 |
| |||
|
Certificate of deposits |
|
35,728 |
|
(6 |
) |
35,722 |
| |||
|
|
|
$ |
165,401 |
|
$ |
(919 |
) |
$ |
164,482 |
|
Note 5—Derivative Transactions
The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. From time to time, the Company enters into natural gas future contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed price arrangements. As of March 31, 2014, all of the Company’s previous future contracts had expired. The Company marked to market its open futures positions at the end of each period and recorded the net unrealized gain or loss during the period in derivative (gains) losses in the condensed consolidated statements of operations or in accumulated other comprehensive income in the condensed consolidated balance sheets in accordance with the FASB’s authoritative guidance. For the three month period ended March 31, 2013, the Company recorded unrealized gains of $106 in other comprehensive loss related to its futures contracts.
Note 6—Other Receivables
Other receivables at December 31, 2013 and March 31, 2014 consisted of the following:
|
|
|
December 31, |
|
March 31, |
| ||
|
Loans to customers to finance vehicle purchases |
|
$ |
5,919 |
|
$ |
5,222 |
|
|
Accrued customer billings |
|
6,327 |
|
7,849 |
| ||
|
Fuel tax and carbon credits |
|
6,740 |
|
157 |
| ||
|
Other |
|
7,299 |
|
6,038 |
| ||
|
|
|
$ |
26,285 |
|
$ |
19,266 |
|
Note 7—Inventories
Inventories are stated at the lower of cost or market value on a first-in, first-out basis. Management’s estimate of market value includes a provision for slow-moving or obsolete inventory based upon inventory on hand and forecasted demand.
Inventories consisted of the following as of December 31, 2013 and March 31, 2014:
|
|
|
December 31, |
|
March 31, |
| ||
|
Raw materials and spare parts |
|
$ |
30,521 |
|
$ |
34,074 |
|
|
Work in process |
|
3,011 |
|
3,250 |
| ||
|
Finished goods |
|
290 |
|
968 |
| ||
|
|
|
$ |
33,822 |
|
$ |
38,292 |
|
Note 8—Land, Property and Equipment
Land, property and equipment at December 31, 2013 and March 31, 2014 are summarized as follows:
|
|
|
December 31, |
|
March 31, |
| ||
|
Land |
|
$ |
1,707 |
|
$ |
2,065 |
|
|
LNG liquefaction plants |
|
93,685 |
|
93,746 |
| ||
|
RNG plants |
|
47,932 |
|
73,225 |
| ||
|
Station equipment |
|
194,240 |
|
203,203 |
| ||
|
LNG trailers |
|
22,667 |
|
22,667 |
| ||
|
Other equipment |
|
62,127 |
|
63,745 |
| ||
|
Construction in progress |
|
204,548 |
|
210,307 |
| ||
|
|
|
626,906 |
|
668,958 |
| ||
|
Less: accumulated depreciation |
|
(139,052 |
) |
(147,974 |
) | ||
|
|
|
$ |
487,854 |
|
$ |
520,984 |
|
Included in land, property and equipment are capitalized software costs of $18,214 and $18,385 as of December 31, 2013 and March 31, 2014, respectively. The accumulated amortization on the capitalized software costs is $7,747 and $8,645 as of December 31, 2013 and March 31, 2014, respectively. The Company recorded $732 and $768 of amortization expense related to the capitalized software costs during the three months ended March 31, 2013 and March 31, 2014, respectively.
As of December 31, 2013 and March 31, 2014, $13,930 and $10,069 are included in accounts payable balances, respectively, which are related to purchases of property and equipment. These amounts are excluded from the condensed consolidated statements of cash flows as they are non-cash investing activities.
Note 9—Investments in Other Entities
The Company had invested in Clean Energy del Peru (the “Peru JV”), a former joint venture of the Company in Lima, Peru that operates CNG stations. The Company accounted for its investment in the Peru JV under the equity method of accounting as the Company had the ability to exercise significant influence over Peru JV’s operations while the Company maintained its ownership interest in the joint venture. In March 2013, the Company completed the sale of its entire ownership interest in Peru JV for $6,119 after receiving a dividend distribution of $1,091, and recognized a gain of $4,705.
Note 10—Accrued Liabilities
Accrued liabilities at December 31, 2013 and March 31, 2014 consisted of the following:
|
|
|
December 31, |
|
March 31, |
| ||
|
Salaries and wages |
|
$ |
6,768 |
|
$ |
6,938 |
|
|
Accrued gas and equipment purchases |
|
8,035 |
|
10,857 |
| ||
|
Accrued property and other taxes |
|
5,448 |
|
4,095 |
| ||
|
Accrued professional fees |
|
1,335 |
|
899 |
| ||
|
Accrued employee benefits |
|
2,898 |
|
3,557 |
| ||
|
Accrued warranty liability |
|
2,545 |
|
2,802 |
| ||
|
Accrued interest |
|
4,216 |
|
981 |
| ||
|
Other |
|
15,500 |
|
12,446 |
| ||
|
|
|
$ |
46,745 |
|
$ |
42,575 |
|
Note 11—Warranty Liability
The Company records warranty liabilities at the time of sale for the estimated costs that may be incurred under its standard warranty. Changes in the warranty liability are presented in the following tables:
|
|
|
March 31, |
|
March 31, |
| ||
|
Warranty liability at beginning of year |
|
$ |
2,665 |
|
$ |
2,545 |
|
|
Costs accrued for new warranty contracts and changes in estimates for pre-existing warranties |
|
879 |
|
675 |
| ||
|
Service obligations honored |
|
(659 |
) |
(418 |
) | ||
|
Warranty liability at end of period |
|
$ |
2,885 |
|
$ |
2,802 |
|
Note 12—Long-term Debt
DCEMB Bonds
On March 25, 2011, the Company’s 70% owned subsidiary, Dallas Clean Energy McCommas Bluff, LLC, a Delaware limited liability company (“DCEMB”), completed a $40,200 tax-exempt bond issuance (the “Revenue Bonds”). The Revenue Bonds will be repaid from the revenue generated by DCEMB from the sale of RNG. The Revenue Bonds are secured by the revenue and assets of DCEMB and are non-recourse to DCEMB’s direct and indirect parent companies, including the Company. The bond repayments are amortized through December 2024 and the average coupon interest rate on the bonds is 6.6%. The bond proceeds were primarily used to finance further improvements and expansion of the landfill gas processing facility owned by DCEMB at the McCommas Bluff landfill outside of Dallas, Texas.
The Revenue Bonds were issued by the Mission Economic Development Corporation (the “Issuer”) and the proceeds of such issuance were loaned by the Issuer to DCEMB pursuant to a loan agreement dated January 1, 2011 (the “DCEMB Loan Agreement”). The DCEMB Loan Agreement contains customary events of default, with customary cure periods, including without limitation failure to make required payments when due under the DCEMB Loan Agreement, failure to comply with certain covenants under the DCEMB Loan Agreement, certain events of bankruptcy and insolvency of DCEMB, and the existence of an event of default under the indenture governing the Revenue Bonds that was entered between the Issuer and The Bank of New York Mellon Trust Company, N.A., as trustee. The occurrence of an event of default under the DCEMB Loan Agreement will allow the Issuer or the trustee to accelerate all amounts due under the DCEMB Loan Agreement. As of March 31, 2014, DCEMB was in compliance with all its debt covenants under the DCEMB Loan Agreement.
Purchase Notes
In connection with the closing of the Company’s acquisition of the business of IMW Industries, Ltd. (“IMW”) in 2010 from a seller (the “IMW Seller”), the Company agreed to make future payments consisting of four annual payments in the amount of $12,500, all of which have been paid as of February 2014 (each an “IMW Note” and collectively, the “IMW Notes”). Each payment under the IMW Notes consisted of Canadian dollars (“CAD”) $5,000 in cash and $7,500 in cash and/or shares of the Company’s common stock (the exact combination of cash and/or stock was determined by the Company in its discretion). In addition, pursuant to a security agreement executed at closing, the IMW Notes were secured by a subordinate security interest in IMW. In January 2011, the Company paid CAD$5,000 in cash and $7,500 in shares of its common stock. The Company paid CAD$5,000 in cash in January 2012 and $3,750 in shares of its common stock in each of August 2012 and October 2012. The Company paid CAD$5,000 in cash and $7,500 in shares of its common stock in February 2013. In February 2014, the Company paid the final payment of CAD$5,000 in cash, $3,750 in cash and $3,750 in shares of its common stock. The IMW Notes that were settled with shares of the Company’s common stock are not included in the condensed consolidated statements of cash flows as they are non-cash financing activities.
In connection with the closing of the Company’s acquisition of Northstar in December 2010, the Company agreed to make future payments consisting of five annual payments in the amount of $700 each with the first payment due December 15, 2011. Each of the first three payments of $700 was paid in December 2011, 2012 and 2013, respectively.
In connection with the closing of the Company’s acquisition of the natural gas fuel infrastructure construction business of Weaver Electric, Inc. in October 2011, the Company paid $1,000 in cash and agreed to make four additional annual payments in the amount of $250 each with the first payment due October 3, 2012 (the “Weaver Notes”), subject to retention and/or offset by the Company for Weaver Electric’s indemnity obligations. In May 2012, the Company prepaid $125 of the October 2012 payment, and the remaining amount of such payment was paid in October 2012. At March 31, 2014, the Company had exercised its right to retain the $250 payment that was payable in 2013, pending resolution of certain indemnity claims.
The difference between the carrying amount and the face amount of these obligations is being accreted to interest expense over the remaining term of the obligations.
HSBC Lines of Credit
In connection with the closing of the Company’s acquisition of IMW, the Company entered into an Assumption Agreement (the “Assumption Agreement”) with HSBC Bank Canada (“HSBC”) pursuant to which the Company assumed the obligations and liabilities of IMW under the following arrangements with HSBC (collectively, the “IMW Lines of Credit”):
(i) An operating line of credit with a limit of CAD$13,000 to assist in financing the day-to-day working capital needs of IMW. The interest on amounts outstanding is payable at IMW’s option at (a) HSBC’s Prime Rate plus 1.00% per annum, (b) HSBC’s U.S. Base Rate plus 1.00% per annum, or (c) LIBOR plus 2.25% per annum, subject to availability.
(ii) A demand revolving line of credit with a limit of CAD$2,000 bearing interest at the same rate as that of the operating line of credit discussed above, to assist in financing IMW’s import requirements.
(iii) A demand revolving bank guarantee and standby letter of credit line with a limit of CAD$1,115.
(iv) A bank guarantee line with a limit of CAD$3,000, which allows IMW to provide guarantees and/or standby letters of credit to overseas suppliers or bid/performance deposits on contracts.
(v) A forward exchange contract line with a limit of CAD$13,750 that allows IMW to enter into foreign exchange forward contracts up to the notional limit of CAD$13,750.
(vi) An operating line of credit with a limit of 5,000 Renminbi (“RMB”) (CAD$889) bearing interest at the 6 month People’s Bank of China rate plus 2.5% and a sub-limit bank guarantee line of 5,000 RMB. The aggregate of the balances in the lines cannot exceed 5,000 RMB.
(vii) A 16,750 Bangladeshi Taka (CAD$235) operating line of credit bearing interest at 14%.
(viii) A 170,000 Colombian Peso (CAD$95) operating line of credit bearing interest at the Colombia benchmark rate plus 7 to 12%.
The IMW Lines of Credit are secured by a general security agreement providing a first priority security interest in all present and after acquired personal property of IMW (the “Security”). The IMW Lines of Credit contain no fixed repayment terms or mandatory principal payments and are due on demand. Based on the relevant accounting guidance, the Company has classified this debt pursuant to the IMW Lines of Credit as short-term given that it is due on demand.
The Assumption Agreement with HSBC sets forth certain financial covenants with which IMW must comply, including: 1) its ratio of debt to tangible net worth must be no greater than 3.0 to 1.0, 2) it must maintain a tangible net worth of at least CAD$7,000 and 3) its ratio of current assets to current liabilities may not be less than 1.25 to 1.0. IMW was in compliance with the financial covenants as of March 31, 2014.
Chesapeake Notes (7.5% Notes)
On July 11, 2011, the Company entered into a Loan Agreement (the “CHK Agreement”) with Chesapeake NG Ventures Corporation (“Chesapeake”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation, whereby Chesapeake agreed to purchase from the Company up to $150,000 of debt securities (the “CHK Financing”) pursuant to the issuance of three convertible promissory notes, each having a principal amount of $50,000 (each a “CHK Note” and collectively the “CHK Notes”). The first CHK Note was issued on July 11, 2011 and the second CHK Note was issued on July 10, 2012. The Company and Chesapeake also entered a registration rights agreement (the “CHK Registration Rights Agreement” and collectively with the CHK Notes and the CHK Agreement, the “CHK Loan Documents”) pursuant to which the Company agreed, subject to the terms and conditions of the CHK Registration Rights Agreement, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of shares of the Company’s common stock (“Shares”) issuable upon conversion of the CHK Notes and (ii) at the request of Chesapeake, participate in one or more underwritten offerings of Shares issuable upon conversion of the CHK Notes. Pursuant to the terms of the CHK Registration Rights Agreement, if the Company does not meet certain of its obligations thereunder with respect to the registration of the Shares issuable upon conversion of the CHK Notes, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the CHK Note represented by the Shares included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met, not to exceed 4% of the aggregate principal amount of the CHK Notes per annum.
On June 14, 2013 (the “Transfer Date”), Chesapeake, Boone Pickens and Green Energy Investment Holdings, LLC, an affiliate of Leonard Green & Partners, L.P. (collectively, the “Buyers”), entered into a note purchase agreement (“Note Purchase Agreement”) pursuant to which Chesapeake sold the outstanding CHK Notes (the “Sale”) to the Buyers. Chesapeake assigned to the Buyers all of its right, title and interest under the CHK Loan Documents (the “Assignment”), and each Buyer severally assumed all of the obligations of Chesapeake under the CHK Loan Documents arising after the Sale and the Assignment including, without limitation, the obligation to advance an additional $50,000 to the Company in June 2013 (the “Assumption”). The Company also entered into the Note Purchase Agreement for the purpose of consenting to the Sale, the Assignment and the Assumption.
Contemporaneously with the execution of the Note Purchase Agreement, the Company entered into a loan agreement with each Buyer (collectively, the “Amended Agreements”). The Amended Agreements have the same terms as the CHK Agreement, other than changes to reflect the change in ownership of the CHK Notes. In addition, the Company and the Buyers entered a registration rights agreement (the “Amended Registration Rights Agreement”) with the same terms as the CHK Registration Rights Agreement, including the liquidated damages provisions therein, other than changes to reflect the change in ownership of the CHK Notes. Immediately following execution of the Amended Agreements, the Buyers delivered $50,000 to the Company in satisfaction of the funding requirement they had assumed from Chesapeake (the “June Advance”). In addition, the Company cancelled the existing CHK Notes and re-issued replacement notes, and the Company also issued notes to the Buyers in exchange for the June Advance (the re-issued replacement notes and the notes issued in exchange for the June Advance are referred to herein as the “7.5% Notes”).
The 7.5% Notes have the same terms as the original CHK Notes, other than the changes to reflect their different holders. They bear interest at the rate of 7.5% per annum and are convertible at the option of the holder into Shares at a conversion price of $15.80 per Share (the “7.5% Notes Conversion Price”). Upon written notice to the Company, the holders of the 7.5% Notes have the right to exchange all, or a portion of, the principal and accrued and unpaid interest under each such note for Shares at the 7.5% Notes Conversion Price. Additionally, subject to certain restrictions, the Company can force conversion of each 7.5% Note into Shares if, following the second anniversary of the issuance of a 7.5% Note, the Shares trade at a 40% premium to the 7.5% Notes Conversion Price for at least 20 trading days in any consecutive 30 trading day period. The entire principal balance of each 7.5% Note is due and payable seven years following its issuance, and the Company may repay each 7.5% Note in Shares or cash. The Amended Agreements restrict the use of the proceeds of the 7.5% Notes to financing the development, construction and operation of liquefied natural gas stations and payment of certain related expenses. The Amended Agreements also provide for customary events of default which, if any of them occurs, would permit or require the principal of, and accrued interest on, the 7.5% Notes to become, or to be declared, due and payable.
On August 27, 2013, Green Energy Investment Holdings, LLC transferred $5,000 in principal amount of the 7.5% Notes to certain third parties.
As a result of the foregoing transactions, (i) Mr. Pickens holds 7.5% Notes in the aggregate principal amount of $65,000, which 7.5% Notes are convertible into approximately 4,113,924 Shares, and (ii) Green Energy Investment Holdings, LLC holds 7.5% Notes in the aggregate principal amount of $80,000, which 7.5% Notes are convertible into approximately 5,063,291 Shares.
At March 31, 2014, none of the proceeds from the 7.5% Notes were included in restricted cash as the Company had used the funds primarily to build LNG fueling stations. As of March 31, 2014, the Company has met its obligations under the Amended Registration Rights Agreement.
SLG Notes
On August 24, 2011, the Company entered into Convertible Note Purchase Agreements (each, an “SLG Agreement” and collectively the “SLG Agreements”) with each of Springleaf Investments Pte. Ltd., a wholly-owned subsidiary of Temasek Holdings Pte. Ltd., Lionfish Investments Pte. Ltd., an investment vehicle managed by Seatown Holdings International Pte. Ltd., and Greenwich Asset Holding Ltd., a wholly-owned subsidiary of RRJ Capital Master Fund I, L.P. (each, a “Purchaser” and collectively, the “Purchasers”), whereby the Purchasers agreed to purchase from the Company $150,000 of 7.5% convertible notes due in August 2016 (each a “SLG Note” and collectively the “SLG Notes”). The transaction closed and the SLG Notes were issued on August 30, 2011. On March 1, 2012, Springleaf Investments Pte. LTD transferred $24,000 principal amount of the SLG Notes to Baytree Investments (Mauritius) Pte Ltd.
The SLG Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year) and are convertible at each Purchaser’s option into Shares at a conversion price of $15.00 per share (the “SLG Conversion Price”). Upon written notice to the Company, the holders of the SLG Notes have the right to exchange all or any portion of the principal and accrued and unpaid interest under each such note for Shares at the SLG Conversion Price. Additionally, subject to certain restrictions, the Company can force conversion of each SLG Note into Shares if, following the
second anniversary of the issuance of the SLG Notes, the Company’s Shares trade at a 40% premium to the SLG Conversion Price for at least 20 trading days in any consecutive 30 trading day period. The entire principal balance of each SLG Note is due and payable five years following its issuance, and the Company may repay the principal balance of each SLG Note in Shares or cash. The SLG Agreements also provide for customary events of default which, if any of them occurs, would permit or require the principal of, and accrued interest on, the SLG Notes to become, or to be declared, due and payable. In April 2012, $1,003 of principal and accrued interest under an SLG Note was converted by the holder thereof into 66,888 Shares. In January and February 2013, $4,030 of principal and accrued interest under an SLG Note was converted by the holder thereof into 268,664 Shares. Such conversions were not included in the condensed consolidated statements of cash flows as they are a non-cash financing activity.
In connection with the SLG Agreements, the Company also entered into a Registration Rights Agreement, dated August 30, 2011, with each of the Purchasers (the “SLG Registration Rights Agreements”) pursuant to which the Company agreed, subject to the terms and conditions of the SLG Registration Rights Agreements, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of the Shares issuable upon conversion of the SLG Notes, and (ii) at the request of the Purchasers, participate in one or more underwritten offerings of the Shares issuable upon conversion of the SLG Notes. If the Company does not meet certain of its obligations under the SLG Registration Rights Agreements with respect to the registration of the Shares issuable upon conversion of the SLG Notes, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the SLG Note represented by the Shares included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met, not to exceed 4% of the aggregate principal amount of the SLG Notes per annum. As of March 31, 2014, the Company has met its obligations under the SLG Registration Rights Agreement.
GE Loans
On November 7, 2012, the Company, through two wholly owned subsidiaries (the “Borrowers”), entered into a financing arrangement with General Electric Capital Corporation (“GE,” and the agreement governing such arrangement, the “GE Credit Agreement”). Pursuant to the GE Credit Agreement, GE agreed to loan to the Borrowers up to an aggregate of $200,000 to finance the development, construction and operation of two LNG production facilities (individually a “Project” and together the “Projects”), each with an expected production capacity of approximately 250,000 LNG gallons per day. The Company expects to sell the LNG produced by the Projects through America’s Natural Gas Highway (“ANGH”), a nationwide network of natural gas truck fueling stations.
The Borrowers’ ability to obtain loans under the GE Credit Agreement for the Projects (collectively, “Loans” and, with respect to each Project “Tranche A Loans” and “Tranche B Loans”) is subject to the satisfaction of certain conditions, including each of the (i) acquisition of title to, or leasehold interests in, the sites upon which the Projects will be constructed, (ii) receipt of all governmental approvals necessary in connection with the design, development, ownership, construction, installation, operation and maintenance of the Projects, (iii) commitment of all utility services necessary for the construction and operation of the Projects, and (iv) execution of an engineering, procurement and construction contract for each Project by the Company and GE Oil & Gas, Inc.
The GE Credit Agreement further provides that (i) if initial Loans are not made prior to December 31, 2014, the GE Credit Agreement will automatically terminate, (ii) each Project must be completed by the earlier of (a) the date thirty months after the funding of the initial Loans with respect to such Project and (b) December 31, 2016 (with respect to each Project, the “Date Certain”), (iii) the then existing Loans with respect to each Project must be converted into term loans with eight year amortization schedules (“Term Loans”) on or before the Date Certain with respect to such Project (the date of such conversion with respect to each Project, the “Conversion Date”), provided that if such Loans are not converted into Term Loans by the applicable Date Certain, such Loans must be repaid by the applicable Date Certain, (iv) each Term Loan will be due and payable on the eighth anniversary of the Conversion Date with respect to such Term Loan, and (v) at any time prior to the applicable Conversion Date, the Loans may be prepaid in whole, and at any time after the applicable Conversion Date, the Loans may be prepaid in whole or in part. The Company expects the Loans to bear interest at an annual rate equal to the then-current LIBOR rate plus 7.00%, provided that for purposes of the GE Credit Agreement, the then-current LIBOR rate will always be at least 1.00%. The GE Credit Agreement includes various customary covenants, including debt service coverage ratios, a commitment fee on the unutilized loan amounts of 0.5% per annum, and also provides for customary events of default which, if such events occur, would permit or require the Loans to become or to be declared due and payable. As of March 31, 2014, the Company has not drawn any money under the GE Credit Agreement and was in compliance with the financial covenants. The commitment fee, which is charged to interest expense in the condensed consolidated statements of operation, was $244 and $250 for the three months ended March 31, 2013 and 2014, respectively.
The Loans are secured by (i) a first priority security interest in all of the Borrowers’ assets, including the Projects, and (ii) a pledge of the Borrowers’ outstanding ownership interests. In addition, the Company has executed a guaranty in favor of GE (“Guaranty”), pursuant to which the Company has guaranteed all of the Borrowers’ obligations under the GE Credit Agreement, including repayment of all Loans.
The Company and GE also entered an equity contribution agreement (the “EC Agreement”) pursuant to which the Company agreed to pay at least 25% of the budgeted cost of the Projects and all additional costs that exceed such expected budgeted costs, in each case, in the form of equity contributions to the Borrowers (“Equity Contributions”). The EC Agreement also requires Clean Energy to provide, concurrent with GE’s extension of the initial Loans under the GE Credit Agreement, letter(s) of credit in an amount equal to the Company’s then-current unfunded Equity Contributions.
Concurrently with the execution of the GE Credit Agreement, the Company issued to GE a warrant (“GE Warrant”) to purchase up to 5,000,000 shares of the Company’s common stock (see note 13), and entered into the GE Registration Rights Agreement.
Mavrix Note
On April 25, 2013, Mavrix, LLC (“Mavrix”), a newly-formed special purpose vehicle subsidiary of Clean Energy Renewable Fuels, LLC (“CERF”), a wholly owned subsidiary of the Company, entered into a note purchase agreement (“NPA”) with Massachusetts Mutual Life Insurance Company (the “Mavrix Note Purchaser”). Mavrix owns all of the equity interests in Canton Renewables, LLC (“Canton”) and 70% of the equity interests in Dallas Clean Energy, LLC, which owns all of the equity interests in DCEMB (together with Canton, the “Project Companies”). Canton owns a RNG extraction and processing project at the Sauk Trail Hills Landfill in Canton, Michigan and DCEMB owns the RNG extraction and processing project at the McCommas Bluff Landfill in Dallas, Texas.
Pursuant to the NPA, on April 25, 2013 (the “Mavrix Issuance Date”), the Mavrix Note Purchaser (i) purchased a secured multi-draw promissory note (the “Mavrix Note”) from Mavrix in the maximum aggregate principal amount of $30,000 (the “Maximum Principal Amount”), and (ii) funded an initial advance of $5,000. In addition, in September and December 2013, the Mavrix Note Purchaser funded an additional advance of $5,000 each, and therefore an aggregate of $15,000 was outstanding under the Mavrix Note at March 31, 2014. Subject to Mavrix and the Project Companies satisfying certain conditions described in the NPA, the Mavrix Note Purchaser will make additional advances under the Mavrix Note, up to the Maximum Principal Amount. Mavrix will use the proceeds from the sale of the Mavrix Note and any advances thereunder to (x) pay any transaction costs and fees related to the NPA and the issuance of the Mavrix Note and (y) make distributions to its direct and indirect parent companies. Mavrix’s direct and indirect parent companies plan to use such distributions to finance construction of additional RNG extraction and processing projects and for working capital purposes.
The Mavrix Note matures 12 years from the Mavrix Issuance Date and bears cash interest at the rate of 12% per annum and paid in kind interest at the rate of 2.0% per annum. The principal amount of the Mavrix Note will be repaid in 28 quarterly installments commencing on June 30, 2018, provided that the NPA requires mandatory prepayment of such principal amount upon certain casualty or condemnation events, asset sales or extraordinary transactions. In addition, Mavrix may not voluntarily repay the Mavrix Note until January 25, 2017 and, subject to the foregoing restriction, Mavrix must pay a prepayment premium if it prepays the Mavrix Note prior to July 30, 2021.
The Mavrix Note is secured by (i) a first priority security interest in all of Mavrix’s assets and (ii) a pledge of Mavrix’s outstanding equity interests. In addition, the NPA includes various customary affirmative and negative covenants and also provides for customary events of default which, if such events occur, would permit or require the Mavrix Note to become, or to be declared, due and payable. The Mavrix Note is non-recourse to the Company.
5.25% Notes
In September 2013, the Company completed a private offering of 5.25% Convertible Senior Notes due 2018 (the “5.25% Notes”) and entered into an indenture governing the 5.25% Notes (the “Indenture”).
The net proceeds from the sale of the 5.25% Notes after the payment of certain debt issuance costs of $7,805 were approximately $242,195. The Company intends to use the net proceeds from the sale of the 5.25% Notes to fund capital expenditures and for general corporate purposes.
The 5.25% Notes bear interest at a rate of 5.25% per annum, payable semi- annually in arrears on October 1 and April 1 of each year, beginning on April 1, 2014. The 5.25% Notes will mature on October 1, 2018, unless earlier purchased, redeemed or converted prior to such date in accordance with their terms and the terms of the Indenture.
Holders may convert their 5.25% Notes, at their option, at any time prior to the close of business on the business day immediately preceding the maturity date of the 5.25% Notes. Upon conversion, the Company will deliver a number of shares of its common stock, per $1 principal amount of 5.25% Notes, equal to the conversion rate then in effect (together with a cash payment in lieu of any fractional shares). The initial conversion rate for the 5.25% Notes is 64.1026 shares of the Company’s common stock per $1 principal amount of Notes (which is equivalent to an initial conversion price of approximately $15.60 per share of the Company’s common stock). The conversion rate is subject to adjustment upon the occurrence of certain specified events as described in the Indenture.
Upon the occurrence of certain corporate events prior to the maturity date of the 5.25% Notes, the Company will, in certain circumstances, in addition to delivering the number of shares of the Company’s common stock deliverable upon conversion of the 5.25% Notes based on the conversion rate then in effect (together with a cash payment in lieu of any fractional shares), pay holders that convert their 5.25% Notes a cash make-whole payment in an amount as described in the Indenture. The Company may, at its option, irrevocably elect to settle its obligation to pay any such make-whole payment in shares of its common stock instead of in cash. The amount of any make-whole payment, whether it is settled in cash or in shares of the Company’s common stock upon the Company’s election, will be determined based on the date on which the corporate event occurs or becomes effective and the stock price paid (or deemed to be paid) per share of the Company’s common stock in the corporate event, as described in the Indenture.
The Company may not redeem the 5.25% Notes prior to October 5, 2016. On or after October 5, 2016, the Company may, at its option, redeem for cash all or any portion of the 5.25% Notes if the closing sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period ending on, and including, the trading day immediately preceding the date on which notice of redemption is provided, exceeds 160% of the conversion price on each applicable trading day. In the event of the Company’s redemption of the 5.25% Notes, the redemption price will equal 100% of the principal amount of the 5.25% Notes to be redeemed, plus accrued and unpaid interest to, but excluding, the redemption date. No sinking fund is provided for in the 5.25% Notes.
If the Company undergoes a fundamental change (as defined in the Indenture) prior to the maturity date of the 5.25% Notes, subject to certain conditions as described in the Indenture, holders may require the Company to purchase, for cash, all or any portion of their 5.25% Notes at a repurchase price equal to 100% of the principal amount of the 5.25% Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change purchase date.
The Indenture contains customary events of default with customary cure periods, including, without limitation, failure to make required payments or deliveries of shares of its common stock when due under the Indenture, failure to comply with certain covenants under the Indenture, failure to pay when due or acceleration of certain other indebtedness of the Company or certain of its subsidiaries, and certain events of bankruptcy and insolvency of the Company or certain of its subsidiaries. The occurrence of an event of default under the Indenture will allow either the trustee or the holders of at least 25% in principal amount of the then-outstanding 5.25% Notes to accelerate, or upon an event of default arising from certain events of bankruptcy or insolvency of the Company, will automatically cause the acceleration of, all amounts due under the 5.25% Notes. No events of default have occurred as of March 31, 2014.
The 5.25% Notes are senior unsecured obligations of the Company and rank senior in right of payment to the Company’s future indebtedness that is expressly subordinated in right of payment to the 5.25% Notes; equal in right of payment to the Company’s unsecured indebtedness that is not so subordinated; effectively junior to any of the Company’s secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all indebtedness (including trade payables) of the Company’s subsidiaries.
Canton Bonds
On March 19, 2014, Canton completed the issuance of Solid Waste Facility Limited Obligation Revenue Bonds (Canton Renewables, LLC — Sauk Trail Hills Project) Series 2014 in the aggregate principal amount of $12,400 (the “Bonds”).
The Bonds were issued by the Michigan Strategic Fund (the “Issuer”) and the proceeds of such issuance were loaned by the Issuer to Canton pursuant to a loan agreement that became effective on March 19, 2014 (the “Loan Agreement”). The Bonds are expected to be repaid from revenue generated by Canton from the sale of RNG and are secured by the revenue and assets of Canton. The Bond repayments will be amortized through July 1, 2022, the average coupon interest rate on the Bonds is 6.6%, and all but $1,000 of the principal amount of the Bonds is non-recourse to Canton’s parent companies, including the Company.
Canton used the Bond proceeds primarily to (i) refinance the cost of constructing and equipping its RNG extraction and production project in Canton, Michigan and (ii) pay a portion of the costs associated with the issuance of the Bonds. The refinancing described in the prior sentence was accomplished through distributions to the Borrower’s direct and indirect parent companies who provided the financing for the RNG production facility, and such companies plan to use such distributions to finance construction of additional RNG extraction and processing projects and for working capital purposes.
The Loan Agreement contains customary events of default, with customary cure periods, including without limitation, failure to make required payments when due under the Loan Agreement, failure to comply with certain covenants under the Loan Agreement, certain events of bankruptcy and insolvency of Canton, and the existence of an event of default under the indenture governing the Bonds that was entered between the Issuer and The Bank of New York Mellon Trust Company, N.A., as trustee. The occurrence of an event of default under the Loan Agreement will allow the Issuer or the trustee to accelerate all amounts due under the Loan Agreement.
Long-term debt and capital lease obligations at December 31, 2013 and March 31, 2014 consisted of the following:
|
|
|
December 31, |
|
March 31, |
| ||
|
IMW Notes |
|
$ |
12,121 |
|
$ |
— |
|
|
Northstar future payments |
|
1,274 |
|
1,297 |
| ||
|
DCEMB notes |
|
585 |
|
585 |
| ||
|
DCEMB Revenue Bonds (non-recourse to the Company) |
|
36,500 |
|
36,500 |
| ||
|
7.5% Notes |
|
150,000 |
|
150,000 |
| ||
|
SLG Notes |
|
145,000 |
|
145,000 |
| ||
|
5.25% Notes |
|
250,000 |
|
250,000 |
| ||
|
Weaver future payments |
|
714 |
|
721 |
| ||
|
IMW assumed debt |
|
6,036 |
|
8,542 |
| ||
|
Mavrix Note (non-recourse to the Company) |
|
15,097 |
|
15,172 |
| ||
|
Canton Bonds ($11,400 non-recourse to the Company) |
|
— |
|
12,400 |
| ||
|
Capital lease obligations |
|
3,091 |
|
2,646 |
| ||
|
Total debt and capital lease obligations |
|
620,418 |
|
622,863 |
| ||
|
Less amounts due within one year and short-term borrowings |
|
(23,401 |
) |
(14,543 |
) | ||
|
Total long-term debt and capital lease obligations |
|
$ |
597,017 |
|
$ |
608,320 |
|
Note 13—Earnings Per Share
Basic earnings per share is based upon the weighted-average number of shares outstanding during each period. Diluted earnings per share reflects the impact of assumed exercise of dilutive stock options and warrants. In the three months ended March 31, 2014, 5,000,000 shares of common stock related to the GE Warrant were included in the basic and dilutive net loss per share calculation. The information required to compute basic and diluted earnings per share is as follows:
|
|
|
Three Months Ended |
| ||
|
|
|
2013 |
|
2014 |
|
|
Basic and diluted: |
|
|
|
|
|
|
Weighted-average number of common shares outstanding |
|
93,132,454 |
|
94,676,325 |
|
Certain securities were excluded from the diluted earnings per share calculations for the three months ended March 31, 2013 and 2014, respectively, as the inclusion of the securities would be anti-dilutive to the calculations. The amounts outstanding as of March 31, 2013 and 2014 for these instruments are as follows:
|
|
|
March 31, |
| ||
|
|
|
2013 |
|
2014 |
|
|
Options |
|
11,994,610 |
|
11,978,192 |
|
|
Warrants |
|
2,130,682 |
|
2,130,682 |
|
|
Convertible Notes |
|
15,995,781 |
|
35,185,979 |
|
|
Restricted Stock Units |
|
1,545,000 |
|
2,080,336 |
|
Note 14—Stock-Based Compensation
The following table summarizes the compensation expense and related income tax benefit related to the stock-based compensation expense recognized during the periods:
|
|
|
Three Months Ended |
| ||||
|
|
|
2013 |
|
2014 |
| ||
|
Stock-based compensation expense |
|
$ |
6,212 |
|
$ |
3,420 |
|
|
Stock-based compensation expense, net of tax |
|
$ |
6,212 |
|
$ |
3,420 |
|
Stock Options
The following table summarizes the Company’s stock option activity during the three months ended March 31, 2014:
|
|
|
Number of |
|
Weighted |
|
Weighted |
|
Aggregate |
| ||
|
Outstanding, December 31, 2013 |
|
11,526,998 |
|
$ |
11.79 |
|
|
|
|
| |
|
Options granted |
|
674,500 |
|
11.93 |
|
|
|
|
| ||
|
Options exercised |
|
(160,146 |
) |
3.13 |
|
|
|
|
| ||
|
Options forfeited |
|
(63,160 |
) |
13.71 |
|
|
|
|
| ||
|
Outstanding, March 31, 2014 |
|
11,978,192 |
|
$ |
11.91 |
|
4.82 |
|
$ |
0 |
|
|
Exercisable, March 31, 2014 |
|
8,561,659 |
|
$ |
11.66 |
|
4.10 |
|
$ |
0 |
|
As of March 31, 2014, there was $13,005 of total unrecognized compensation cost related to non-vested shares. That cost is expected to be recognized over a weighted average period of 1.2 years. The total fair value of shares vested during the three months ended March 31, 2014 was $4,020.
The Company is obligated to issue shares of its common stock upon the exercise of stock options. The intrinsic value of all options exercised during the three months ended March 31, 2013 and 2014 was $252 and $1,387, respectively.
The fair value of each stock option is estimated as of the date of grant using the Black-Scholes option pricing model using the following weighted-average assumptions for grants in 2014:
|
|
|
Three Months Ended |
|
|
Dividend yield |
|
0.00 |
% |
|
Expected volatility |
|
52.3 |
% |
|
Risk-free interest rate |
|
1.8 |
% |
|
Expected life in years |
|
6.0 |
|
The weighted-average grant date fair values of options granted during the three months ended March 31, 2014 was $6.04. The Company did not grant any stock options during the three month period ended March 31, 2013. The volatility amounts used during these periods were estimated based on the Company’s historical volatility and the Company’s implied volatility of its traded options for such periods. The expected lives used during the period was based on historical exercise periods and the Company’s anticipated exercise periods for its outstanding options. The risk free rates used during the period were based on the U.S. Treasury yield curve for the expected life of the options at the time of grant. The Company recorded $4,007 and $1,782 of stock option expense during the three months ended March 31, 2013 and 2014, respectively. The Company has not recorded any tax benefit related to its stock option expense.
Market-Based Restricted Stock Units
The Company issued 1,545,000 and 489,500 market-based restricted stock units (“Market-Based RSUs”) to certain key employees during 2012 and the three months ended March 31, 2014, respectively. A holder of Market-Based RSUs will receive one share of the Company’s common stock for each Market-Based RSU he holds if (i) between two years and four years from the date of grant of the Market-Based RSU, the closing price of the Company’s common stock equals or exceeds, for twenty consecutive trading days, 135% of the closing price of the Company’s common stock on the Market-Based RSU grant date (the “Stock Price Condition”) and (ii) the holder is employed by the Company at the time the Stock Price Condition is satisfied. If the Stock Price Condition is not satisfied prior to four years from the date of grant, the Market-Based RSUs will be automatically forfeited. The Market-Based RSUs are subject to the terms and conditions of the Company’s Amended and Restated 2006 Equity Incentive Plan and a Notice of Grant of Restricted Stock Unit and Restricted Stock Unit Agreement.
The following table summarizes the Company’s Market-Based RSU activity during the three months ended March 31, 2014:
|
|
|
Number of |
|
Weighted |
|
Weighted |
| |
|
Outstanding, December 31, 2013 |
|
1,545,000 |
|
$ |
11.32 |
|
|
|
|
RSUs granted |
|
489,500 |
|
8.26 |
|
|
| |
|
Outstanding and non-vested, March 31, 2014 |
|
2,034,500 |
|
$ |
10.66 |
|
2.2 |
|
As of March 31, 2014, there was $3,774 of total unrecognized compensation cost related to non-vested units. That cost is expected to be recognized over a weighted average period of 1.9 years.
The Company recorded $2,205 and $1,204 of expense during the three months ended March 31, 2013 and 2014, respectively, related to the Market-Based RSUs. The Company has not recorded any tax benefit related to its market-based RSU expense.
The fair value of the RSUs granted during the three month period ended March 31, 2014 was estimated on the date of grant using the Monte Carlo Method with the following assumptions:
|
|
|
February 2, 2014 |
|
|
Dividend yield |
|
0.00 |
% |
|
Expected volatility |
|
47.0 |
% |
|
Risk-free interest rate |
|
1.1 |
% |
|
Expected life in years |
|
2.0 |
|
Service-Based Restricted Stock Units
During September 2013, the Company issued service-based restricted stock units (“Service-Based RSUs”) to a key employee which vest annually over three years from the date of issuance at a rate of 34%, 33% and 33%, respectively, if the holder is then in service to the Company. The fair value of each Service-Based RSU is estimated using the closing stock price of the Company’s common stock on the date of grant.
The following table summarizes the Company’s Serviced-Based RSU activity during the three months ended March 31, 2014:
|
|
|
Number of |
|
Weighted |
|
Weighted |
| |
|
Nonvested at December 31, 2013 |
|
45,836 |
|
$ |
13.09 |
|
|
|
|
RSUs granted |
|
— |
|
— |
|
|
| |
|
Nonvested at March 31, 2014 |
|
45,836 |
|
$ |
13.09 |
|
2.5 |
|
As of March 31, 2014, there was $498 of total unrecognized compensation cost related to non-vested Service-Based RSUs. That cost is expected to be recognized evenly over a period of 2.5 years.
The Company recorded $102 of expense during the three months ended March 31, 2014 related to the Service-Based RSUs. The Company has not recorded any tax benefit related to its Service-Based RSU expense.
Employee Stock Purchase Plan
On May 7, 2013, the Company adopted an employee stock purchase plan (the “ESPP”), pursuant to which eligible employees may purchase shares of the Company’s common stock at 85% of the fair market value of the common stock on the last trading day of two consecutive, non-concurrent offering periods each year. The Company has reserved 2,500,000 shares of its common stock for issuance under the ESPP.
The Company recorded $27 of expense during the three months ended March 31, 2014 related to the ESPP. The Company has not recorded any tax benefits related to its ESPP expense. At March 31, 2014, the Company had sold an aggregate of 14,934 shares pursuant to the ESPP.
Non-qualified Non-public Subsidiary Unit Options
In September 2013, the Company’s wholly owned subsidiary, CERF, adopted the Clean Energy Renewable Fuels, LLC 2013 Unit Option Plan (the “CERF Plan”). 150,000 Class B units representing membership interests in CERF were initially reserved for issuance under the CERF Plan.
The following table summarizes CERF’s unit option activity during the three months ended March 31, 2014:
|
|
|
Number of |
|
Weighted |
|
Weighted |
|
Aggregate |
| ||
|
Outstanding, December 31, 2013 |
|
115,000 |
|
$ |
40.80 |
|
|
|
|
| |
|
Options granted |
|
— |
|
— |
|
|
|
|
| ||
|
Outstanding and non-vested, March 31, 2014 |
|
115,000 |
|
$ |
40.80 |
|
9.47 |
|
$ |
0 |
|
As of March 31, 2014, there was $3,005 of total unrecognized compensation cost related to non-vested unit options issued pursuant to the CERF Plan. That cost is expected to be recognized over a weighted average period of 2.5 years.
CERF recorded $305 of unit option expense during the three months ended March 31, 2014. CERF has not recorded any tax benefit related to its unit option expense.
Note 15—Environmental Matters, Litigation, Claims, Commitments and Contingencies
The Company is subject to federal, state, local, and foreign environmental laws and regulations. The Company does not anticipate any expenditures to comply with such laws and regulations which would have a material impact on the Company’s condensed consolidated financial position, results of operations, or liquidity. The Company believes that its operations comply, in all material respects, with applicable federal, state, local and foreign environmental laws and regulations.
The Company may become party to various legal actions that arise in the ordinary course of its business. During the course of its operations, the Company is also subject to audit by tax authorities for varying periods in various federal, state, local and foreign tax jurisdictions. Disputes may arise during the course of such audits as to facts and matters of law. It is impossible at this time to determine the ultimate liabilities that the Company may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing of these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon the Company’s condensed consolidated financial position or results of operations. However, the Company believes that the ultimate resolution of such actions will not have a material adverse affect on the Company’s condensed consolidated financial position, results of operations, or liquidity.
Note 16—Income Taxes
The Company’s income tax provision for the three months ended March 31, 2013 and March 31, 2014 was $1,805 and $962, respectively, which comprised of taxes due on the Company’s U.S. and foreign operations. The effective tax rate for the three months ended March 31, 2013 and 2014 are different from the federal statutory tax rate primarily as a result of losses for which no tax benefit has been recognized.
The Company did not record a change in its liability for unrecognized tax benefits or penalties in the three months ended March 31, 2013 or March 31, 2014, and the net interest incurred was immaterial for such periods.
Note 17—Fair Value Measurements
The Company follows the authoritative guidance for fair value measurements with respect to assets and liabilities that are measured at fair value on a recurring basis and nonrecurring basis. Under the standard, fair value is defined as the exit price, or the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants, as of the measurement date. The standard also establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.
Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. The hierarchy consists of the following three levels: Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities; Level 2 inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and inputs (other than quoted prices) that are observable for the asset or liability, either directly or indirectly; Level 3 inputs are unobservable inputs for the asset or liability. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.
During the three months ended March 31, 2014, the Company’s financial instruments consisted of available-for-sale securities, debt instruments, a contingent consideration obligation, and its Series I warrants. For securities available-for-sale, the fair value is determined by the most recent trading prices available for each security or for comparable securities, and thus represent Level 2 fair value measurements. The Company uses projected financial results for the respective entity, discounted to reflect the time value of money, to value its contingent consideration obligation, which is considered to be a Level 3 fair value measurement. The fair values of the Company’s debt instruments approximated their carrying values at December 31, 2013 and March 31, 2014. The Company uses the Black-Scholes model to value the Series I warrants. The Company believes the best method to approximate the market participant’s view of the volatility of its Series I warrants has been to use the implied volatilities of its short-term (i.e. 3 to 9 month) traded options and extrapolate the data over the remaining term of the Series I warrants, which was approximately 2.1 years as of March 31, 2014. This method has been utilized consistently in the periods presented. Given that the extrapolation beyond the term of the short term exchange traded options is not based on observable market inputs for a significant portion of the remaining term of the warrants, the Series I warrants have been classified as a Level 3 fair value measurement in the table below.
The following tables provide information by level for assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2013 and March 31, 2014, respectively:
|
Description |
|
Balance at |
|
Level 1 |
|
Level 2 |
|
Level 3 |
| ||||
|
Assets: |
|
|
|
|
|
|
|
|
| ||||
|
Available-for-sale securities(1): |
|
|
|
|
|
|
|
|
| ||||
|
Certificate of deposits |
|
$ |
35,621 |
|
$ |
— |
|
$ |
35,621 |
|
$ |
— |
|
|
Municipal bonds and notes |
|
59,795 |
|
— |
|
59,795 |
|
— |
| ||||
|
Corporate bonds |
|
42,824 |
|
— |
|
42,824 |
|
— |
| ||||
|
Liabilities: |
|
|
|
|
|
|
|
|
| ||||
|
Contingent consideration obligation(2) |
|
384 |
|
— |
|
— |
|
384 |
| ||||
|
Series I warrants(3) |
|
7,164 |
|
— |
|
— |
|
7,164 |
| ||||
|
Description |
|
Balance at |
|
Level 1 |
|
Level 2 |
|
Level 3 |
| ||||
|
Assets: |
|
|
|
|
|
|
|
|
| ||||
|
Available-for-sale securities(1): |
|
|
|
|
|
|
|
|
| ||||
|
Certificate of deposits |
|
$ |
35,722 |
|
$ |
— |
|
$ |
35,722 |
|
$ |
— |
|
|
Municipal bonds and notes |
|
66,933 |
|
— |
|
66,933 |
|
— |
| ||||
|
Corporate bonds |
|
61,827 |
|
— |
|
61,827 |
|
— |
| ||||
|
Liabilities: |
|
|
|
|
|
|
|
|
| ||||
|
Contingent consideration obligation(2) |
|
384 |
|
— |
|
— |
|
384 |
| ||||
|
Series I warrants(3) |
|
2,709 |
|
— |
|
— |
|
2,709 |
| ||||
(1) Included in short-term investments in the condensed consolidated balance sheets. See note 4 for further information.
(2) Included in accrued liabilities in the condensed consolidated balance sheets.
(3) Included in other long-term liabilities in the condensed consolidated balance sheets.
The following tables provide a reconciliation of the beginning and ending balances of items measured at fair value on a recurring basis in the table above that used significant unobservable inputs (Level 3).
|
Liabilities: Contingent Consideration |
|
March 31, |
|
March 31, |
| ||
|
Beginning Balance |
|
$ |
1,516 |
|
$ |
384 |
|
|
Total gain included in SG&A expense |
|
— |
|
— |
| ||
|
Ending Balance |
|
$ |
1,516 |
|
$ |
384 |
|
|
Liabilities: Series I Warrants |
|
March 31, |
|
March 31, |
| ||
|
Beginning Balance |
|
$ |
8,102 |
|
$ |
7,164 |
|
|
Total (gain) loss included in earnings |
|
466 |
|
(4,455 |
) | ||
|
Ending Balance |
|
$ |
8,568 |
|
$ |
2,709 |
|
Valuation processes for Level 3 fair value measurements and sensitivity to changes in significant unobservable inputs
Fair value measurements of liabilities, which fall within Level 3 of the fair value hierarchy, are determined by the Company’s accounting department, who report to the Company’s Chief Financial Officer. The fair value measurements are compared to those of the prior reporting periods to ensure that changes are consistent with expectations of management based upon the sensitivity and nature of the inputs.
Contingent Consideration
Pursuant to the terms of our asset purchase agreement with the IMW Seller, the Company may be obligated to pay the IMW Seller additional consideration if IMW achieves certain minimum gross profit targets in fiscal years 2011 through 2014. Therefore, the Company estimated the fair value of the contingent consideration using a discounted cash flow model that considers the payout structure based on the following inputs as of March 31, 2014:
|
Unobservable Input |
|
Range or Weighted Average |
|
Gross profit projection |
|
$16,321–$19,041 |
|
Probability of reaching target gross profit |
|
10.0%–90.0% |
Generally, a positive change in the assumptions used for the probability of achieving a higher gross profit target threshold would result in a directionally similar change in the estimated fair value of the contingent consideration, and thus an increase in the associated liability.
Series I Warrant Liability
The Company estimated the fair value of its Series I warrant liability using the Black-Scholes Model based on the following inputs as of March 31, 2014:
|
Unobservable Input |
|
Range or Weighted Average |
| |
|
Current market price of the Company’s common stock |
|
$ |
8.94 |
|
|
Exercise price of the warrant |
|
$ |
12.68 |
|
|
Dividend yield |
|
0.00 |
% | |
|
Remaining term of the warrant |
|
2.08 |
| |
|
Implied volatility of the Company’s common stock |
|
46.1 |
% | |
|
Assumed discount rate |
|
Simple average 0.4 |
% | |
Significant changes in any of those inputs in isolation can result in a significant change in the fair value measurement. Generally, a positive change in the market price of the Company’s common stock, an increase in the volatility of the Company’s common stock, or an increase in the remaining term of the warrant would result in a directionally similar change in the estimated fair value of the Company’s Series I warrants and thus an increase in the associated liability. An increase in the assumed discount rate or a decrease in the positive differential between the warrant’s exercise price and the market price of the Company’s common stock would result in a decrease in the estimated fair value measurement of the Series I warrants and thus a decrease in the associated liability. The Company has not, nor plans to, declare dividends on its common stock, and thus, there is no directionally similar change in the estimated fair value of the warrants due to the dividend assumption.
Non-financial assets
No impairments of long-lived assets measured at fair value on a non-recurring basis have been incurred during the three months ended March 31, 2013 and 2014. The Company’s use of these nonfinancial assets does not differ from their highest and best use as determined from the perspective of a market participant.
Note 18—Recently Adopted Accounting Changes and Recently Issued Accounting Standards
Accounting standards that have been issued or proposed by the FASB that do not require adoption until a future date are not expected to have a material impact on the financial statement presentation or disclosures upon adoption.
Note 19—Volumetric Excise Tax Credit (VETC)
From October 1, 2006 through December 31, 2011, the Company was eligible to receive a federal fuel tax credit (“VETC”) of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that it sold as vehicle fuel. Based on the service relationship with its customers, either the Company or its customers claimed the credit. The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax liabilities to be received. The American Taxpayer Relief Act, signed into law on January 2, 2013, reinstated VETC for calendar year 2013 and also made it retroactive to January 1, 2012. VETC revenues recognized during the three months ended March 31, 2013 was $26,217, which included $20,800 for CNG and LNG the Company sold in 2012 that was recognized in January 2013 when the legislation was signed into law. The program under which the Company received VETC expired on December 31, 2013.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (this “MD&A”) should be read together with the unaudited condensed consolidated financial statements and the related notes included elsewhere in this report. For additional context with which to understand our financial condition and results of operations, refer to the MD&A for the fiscal year ended December 31, 2013 contained in our 2013 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission (“SEC”) on February 27, 2014, as well as the consolidated financial statements and notes contained therein (collectively, the “2013 10-K”). Unless the context indicates otherwise, all references to “Clean Energy,” the “Company,” “we,” “us,” or “our” in this MD&A and elsewhere in this report refer to Clean Energy Fuels Corp. together with its majority and wholly owned subsidiaries.
Cautionary Statement Regarding Forward Looking Statements
This MD&A and other sections of this report contain forward looking statements. We make forward-looking statements, as defined by the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, and in some cases, you can identify these statements by forward-looking words such as “if,” “shall,” “may,” “might,” “will likely result,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “project,” “intend,” “goal,” “objective,” “predict,” “potential” or “continue,” or the negative of these terms and other comparable terminology. These forward-looking statements, which are based on various underlying assumptions and expectations and are subject to risks, uncertainties and other unknown factors, may include projections of our future financial performance based on our growth strategies and anticipated trends in our business. These statements are only predictions based on our current expectations and projections about future events that we believe to be reasonable. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the historical or future results, level of activity, performance or achievements expressed or implied by such forward-looking statements. These factors include, but are not limited to, those discussed under the caption “Risk Factors” in this report and in our 2013 10-K. In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2013 10-K pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.
We are the leading provider of natural gas as an alternative fuel for vehicle fleets in the United States and Canada, based on the number of stations operated and the amount of gasoline gallon equivalents of compressed natural gas (“CNG”) and liquefied natural gas (“LNG”) delivered. We design, build, operate and maintain fueling stations and supply our customers with CNG fuel for light, medium and heavy-duty vehicles and LNG fuel for medium and heavy-duty vehicles. We also sell non-lubricated natural gas compressors and other equipment used in CNG stations and LNG stations, provide operation and maintenance services (“O&M”) to customers, offer solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, produce renewable natural gas (“RNG”), which can be used as vehicle fuel or sold for renewable power generation, and sell tradable credits we generate by selling natural gas and RNG as a vehicle fuel, including credits we generate under the California Low Carbon Fuel Standard (“LCFS Credits”) and Renewable Identification Numbers (“RIN Credits” or “RINs”) we generate under the federal Renewable Fuel Standard (“RFS”) Phase 2. In addition, we help our customers acquire and finance natural gas vehicles and obtain local, state and federal grants and incentives. We previously owned BAF Technologies, Inc. and its wholly owned subsidiary, ServoTech Engineering, Inc. (BAF Technologies, Inc. and ServoTech Engineering Inc. are collectively referred to as “BAF”). BAF converted light and medium duty vehicles to run on natural gas and provided design and engineering services for natural gas engine systems. On June 28, 2013, we sold BAF to Westport Innovations (U.S.) Holdings Inc., a wholly owned subsidiary of Westport Innovations Inc.
Overview
This overview discusses matters on which our management primarily focuses in evaluating our financial condition and operating performance.
Sources of revenue. We generate revenues by selling CNG and LNG, providing O&M services to our vehicle fleet customers, designing and constructing fueling stations and selling those stations to our customers, selling RNG, selling non-lubricated natural gas fueling compressors and other equipment for CNG and LNG fueling stations, providing maintenance services, offering solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, providing financing for our customers’ natural gas vehicle purchases and selling tradable credits, including LCFS Credits and RIN Credits. In addition, through June 28, 2013, we generated revenues, through BAF, by selling converted natural gas vehicles and providing design and engineering services for natural gas engine systems.
Key operating data. In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as (i) the volume of gasoline gallon equivalents we sell to our customers, plus (ii) the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide O&M services, but do not sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold as CNG by our joint venture in Peru (through March 2013 when we sold our interest in the joint venture in Peru), plus (iv) our proportionate share of the gasoline gallon equivalents of RNG produced and sold as pipeline quality natural gas by our RNG production facilities, (2) our gross margin (which we define as revenue minus cost of sales), and (3) net income (loss) attributable to us. The following table, which you should read in conjunction with our condensed consolidated financial statements and notes contained elsewhere in this quarterly report on Form 10-Q and our consolidated financial statements and notes contained in our 2013 10-K, presents our key operating data for the years ended December 31, 2011, 2012, and 2013 and for the three months ended March 31, 2013 and 2014:
|
Gasoline gallon equivalents |
|
Year Ended |
|
Year Ended |
|
Year Ended |
|
Three Months Ended |
|
Three Months Ended |
| |||||
|
CNG |
|
101.8 |
|
130.5 |
|
143.9 |
|
34.0 |
|
39.4 |
| |||||
|
RNG |
|
6.7 |
|
8.9 |
|
10.5 |
|
2.2 |
|
3.2 |
| |||||
|
LNG |
|
47.1 |
|
55.5 |
|
60.0 |
|
13.7 |
|
16.7 |
| |||||
|
Total |
|
155.6 |
|
194.9 |
|
214.4 |
|
49.9 |
|
59.3 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating data |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Gross margin |
|
$ |
76,033 |
|
$ |
80,324 |
|
$ |
127,713 |
(1) |
$ |
42,302 |
(1) |
$ |
23,644 |
|
|
Net loss attributable to Clean Energy Fuels. Corp |
|
(47,633 |
) |
(101,255 |
) |
(66,968 |
)(1) |
(3,871 |
)(1) |
(28,593 |
) | |||||
(1) Includes $26.2 million and $45.4 million for the three months ended March 31, 2013 and the year ended December 31, 2013, respectively, of VETC revenue. See discussion under “Operations — Government Incentives” below.
Key trends. According to the U.S. Department of Energy, Energy Information Administration (“EIA”), demand for natural gas fuels in the United States increased by approximately 38% during the period January 1, 2011 through December 31, 2013. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during this period, as well as increasingly stringent environmental regulations affecting vehicle fleets and increased availability of natural gas.
The number of fueling stations we owned, operated, maintained and/or supplied grew from 224 at January 1, 2011 to 494 at March 31, 2014 (a 120.5% increase). Included in this number are all of the CNG and LNG fueling stations we own, maintain or with which we have a fueling supply contract. The amount of CNG, RNG, and LNG gasoline gallon equivalents we delivered from 2011 to 2013 increased by 37.8%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during 2011, 2012 and 2013. In addition, in 2012, we sold four large transit stations for $40.3 million, which contributed to our revenue amount during the year. Also, in 2013, revenues included $20.8 million in federal fuel tax credits (“VETC”) related to 2012 due to the reinstatement of such credits in January 2013. This increase was partially offset by a reduction in revenues in 2013 due to our sale of BAF on June 28, 2013. Our revenue can vary between periods for various reasons, including the timing of equipment sales, station construction and natural gas sale activity.
Our fuel cost of sales also increased during these periods, which was attributable primarily to increased costs related to delivering more CNG, RNG and LNG to our customers in 2011 through 2013. The increase was partially offset in 2013 by a reduction in cost of sales due to our sale of BAF on June 28, 2013. Our cost of sales can vary between periods for various reasons, including the timing of equipment sales, station construction and natural gas sale activity.
During 2013 and the first three months in 2014, prices for oil, gasoline, and diesel fuel were generally substantially higher than the price for natural gas. Oil hit a high of $107.65 per barrel, or $19.39 per one million Btus (“MMbtu”), in August 2013 and was $101.58 per barrel, or $18.30 per MMbtu, on March 31, 2014. In California, the average retail price for gasoline was $3.89 per gallon in 2013, hit a high of $4.13 per gallon in February 2013, and was $4.05 per gallon at March 31, 2014. Average retail prices for diesel fuel in California were $4.13 per diesel gallon in 2013, hit a high of $4.33 per diesel gallon in February 2013, and was $4.06 per diesel gallon at March 31, 2014. Higher gasoline and diesel prices improve our margins on fuel sales to the extent we price our fuel at a relatively consistent discount to gasoline or diesel and natural gas prices do not increase by a corresponding amount. During this time period, the price for natural gas increased slightly. The NYMEX price for natural gas ranged from $3.35 per MMbtu in January 2013 to $4.86 per MMbtu in March 2014. The average retail sales price of our CNG fuel sold in the Los Angeles metropolitan area ranged from $2.75 per gallon during January 2013 to $2.80 per gallon for the month of March 2014. The average retail sales price of our LNG fuel sold in the Los Angeles metropolitan area ranged from $2.70 per gallon during January 2013 to $2.64 per gallon for the month of March 2014.
Recent developments. In January 2014, we completed the purchase of 67 CNG-In-A-Box units, which consist of relatively small, turnkey self-contained CNG stations, from Peake Fuel Solutions, L.L.C. for $18.4 million. In March 2014, our subsidiary Canton Renewables, LLC (“Canton”) completed the issuance of Solid Waste Facility Limited Obligation Revenue Bonds (Canton Renewables, LLC — Sauk Trail Hills Project) Series 2014 in the aggregate principal amount of $12.4 million.
Anticipated future trends. We anticipate that, over the long term, the prices for gasoline and diesel will continue to be significantly higher than the price of natural gas as a vehicle fuel, which will continue to make natural gas vehicle fuel an attractive alternative to gasoline and diesel. Our belief that natural gas will continue, over the long term, to be a cheaper vehicle fuel than gasoline or diesel is based in large part on the growth in United States natural gas production in recent years.
We believe there will be significant growth in the consumption of natural gas as a vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. With our acquisitions in 2010 of the natural gas compressor development and manufacturing business of IMW Industries, Ltd. (“IMW”) and of Wyoming Northstar Incorporated (“Northstar”), a leading provider of LNG station design, construction, operation and maintenance services, we are a fully integrated provider of advanced compression technology, CNG and LNG station design and construction, and CNG and LNG fueling. We anticipate expanding our sales of CNG and LNG in each of the markets in which we operate, including trucking, refuse hauling, airports, taxis and public transit, and plan to enter additional markets, including marine and rail. Consistent with the anticipated growth of our business, we also expect that our operating costs and capital expenditures will increase, primarily from the anticipated expansion of our station network and LNG production capacity, as well as the logistics of delivering more CNG and LNG to our customers. We also anticipate that we will continue to seek to acquire assets and/or businesses that are in the natural gas fueling infrastructure or RNG production business that may require us to raise and expend additional capital. Additionally, we have increased, and will continue to increase, our sales and marketing team and other necessary personnel as we seek to expand our existing markets and enter new markets, which will also result in increased costs.
We anticipate the commercial roll-out of natural gas engines that are well-suited for the U.S. heavy-duty truck market, together with the economic and environmental benefits of natural gas fuel, will result in increased adoption of natural gas fueled trucks by the U.S. trucking industry. We estimate that there are approximately three million heavy-duty trucks on the road in the U.S., and that such trucks collectively consume approximately 25 billion gallons of fuel each year. As a result, we believe this market has the potential to become our largest. We have made a significant commitment of capital and other resources to build a nationwide network of natural gas truck fueling stations, which we refer to as “America’s Natural Gas Highway” or “ANGH.” Our objective in building America’s Natural Gas Highway is to enable natural gas fueled freight trucking coast to coast and border to border along key transportation corridors. Our ANGH stations have primarily been initially built to provide LNG. However, we believe operators will adopt heavy-duty trucks that run on both LNG and CNG, so to meet the needs of our customers, we have designed our ANGH stations to be capable of dispensing both fuels. We will need to invest additional capital in our ANGH stations to the extent we decide to add CNG fueling capability to our ANGH stations.
Some ANGH stations are located at Pilot Flying J Travel Centers, one of the largest truck fueling operators in the U.S. Under our agreement with Pilot, we own the ANGH stations we build at Pilot locations and pay rent to Pilot for the use of its property. In addition, we are entitled to recoup all of our investments in ANGH stations we build at Pilot locations plus a defined return, after which we share a portion of the station profits with Pilot.
Sources of liquidity and anticipated capital expenditures. Liquidity is the ability to meet present and future financial obligations either through operating cash flows, the sale or maturity of existing assets, or by the acquisition of additional funds through capital management. Historically, our principal source of liquidity has consisted of cash provided by financing activities.
Our business plan calls for approximately $40.0 million in capital expenditures from April 1, 2014 through the end of 2014, primarily related to construction of CNG and LNG fueling stations. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production, and to make capital expenditures to build additional LNG production facilities or to otherwise secure future LNG supply. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raise may depend on various factors, including our rate of new station construction and any potential merger or acquisition activity. We may not be able to raise capital, when needed, on terms that are favorable to us or existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and may reduce our ability to grow our business and generate increased revenues.
Business risks and uncertainties. Our business and prospects are exposed to numerous risks and uncertainties. For more information, see “Risk Factors” in Part II, Item 1A of this report.
Operations
We generate revenues principally by selling CNG, LNG and RNG, and providing O&M services to our vehicle fleet customers. For the three month period ended March 31, 2014, CNG and RNG (together) represented 72% and LNG represented 28% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. We also generate revenues through sales of advanced natural gas fueling compressors and other natural gas fueling station equipment, providing station modification and maintenance services, providing financing for our customers’ natural gas vehicle purchases, and selling RIN and LCFS Credits.
CNG Sales
We sell CNG through fueling stations located on our customers’ properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers’ vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is principally determined on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. CNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at public access stations based on prevailing market conditions.
LNG Production and Sales
We obtain LNG from our own plants as well as through relationships with suppliers. We own and operate LNG liquefaction plants near Houston, Texas and Boron, California, and we plan to build two new LNG plants in connection with our strategic collaboration with General Electric Capital Corporation (“GE”) (see note 12 to our condensed consolidated financial statements). We expect that these additional plants, as well as our planned expansion of our Boron, California plant, and other plants to be built by us or third parties in the future, will be necessary to secure sufficient sources of LNG in the future.
We sell LNG on a bulk basis to fleet customers, who often own and operate their fueling stations, and we also sell LNG to fleet and other customers at our public-access LNG stations. During 2012 and 2013, we procured 44% and 33%, respectively, of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. We expect to enter additional purchase contracts with third party LNG producers in the future. For LNG that we purchase from third parties, we have entered into, and may enter into additional “take or pay” contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 88 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. For LNG customers who own and operate their fueling stations, we sell LNG through supply contracts that are priced on an index-plus basis. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied. We also sell LNG on a per fill-up basis at prices we set at public access stations based on prevailing market conditions. LNG generally costs more than CNG as LNG must be liquefied and transported, and the U.S. government imposes higher fuel taxes on LNG.
Government Incentives
From October 1, 2006 through December 31, 2011, we were eligible to receive a federal fuel tax credit (“VETC”) of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sold as vehicle fuel. Based on the service relationship with our customers, either we or our customers claimed the credit. We recorded these tax credits as revenues in our condensed consolidated statements of operations as the credits are fully refundable and do not need to offset tax liabilities to be received. As such, the credits are not deemed income tax credits under the accounting guidance applicable to income taxes. In addition, we believe the credits are properly recorded as revenue because we often incorporate the tax credits into our pricing with our customers, thereby lowering the actual price per gallon we charge them.
The American Taxpayer Relief Act, signed into law on January 2, 2013, reinstated VETC for calendar year 2013 and also made it retroactive to January 1, 2012. VETC revenues recognized during the three month period ended March 31, 2013 was $26.2 million, which includes $20.8 million for CNG and LNG we sold in 2012 that we recognized in January 2013.
Operation and Maintenance
We generate a portion of our revenue from our performance of O&M for CNG and LNG fueling stations where we do not supply the fuel. At these fueling stations the customer contracts directly with a local broker or utility to purchase natural gas. For O&M services, we do not sell the fuel itself, but generally charge a per-gallon fee based on the volume of fuel dispensed at the station. We include the volume of fuel dispensed at the stations at which we provide O&M services in our calculation of aggregate gasoline gallon equivalents delivered.
Station Construction
We generate a portion of our revenue from designing and constructing fueling stations and selling or leasing the stations to our customers. For these projects, we act as general contractor or supervise qualified third-party contractors. We charge construction fees or lease rates based on the size and complexity of the project
Vehicle Acquisition and Finance
We offer vehicle finance services for some of our customers’ purchases of natural gas vehicles. We loan to certain qualifying customers a portion of, and on occasion up to 100% of, the purchase price of their natural gas vehicles. We may also lease natural gas vehicles to certain of our customers in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. To help accelerate the conversion of heavy-duty truck fleets to natural gas, in 2013, we entered a strategic alliance with GE’s Transportation Finance business. Fleet operators are eligible for loans and leases, including fair market value leases, from GE to acquire trucks from OEMs. In exchange for committing to purchase natural gas fuel from our stations, we then help offset a portion of the monthly cost of the vehicles to make it consistent with the cost of a diesel truck. Our goal is to work with fleet operators to achieve a one to two-year payback on the incremental cost of natural gas heavy-duty trucks, and we consider our alliance with GE to be an important tool in achieving this goal. Through March 31, 2014, we have not generated significant income from vehicle financing activities.
RNG
We own a 70% interest in a RNG production facility at the McCommas Bluff landfill located in Dallas, Texas. We sell specified levels of RNG produced at the facility to Shell Energy North America (US) L.P. under a gas sale agreement and, depending upon RNG production volumes, we have the ability to sell RNG produced by that facility as a vehicle fuel. We own a second RNG production facility located at a Republic Services landfill in Canton, Michigan. This facility was completed in 2012, and we have entered into a ten-year fixed-price sale contract for the majority of the RNG that we expect the facility to produce. We completed the third RNG facility at a Republic Services landfill in North Shelby, Tennessee, during the last week of March 2014. We are seeking to expand our RNG business by pursuing additional RNG production projects. We sell some of the RNG we currently produce, and expect to sell a significant amount of the RNG we produce at the facilities we plan to build, through our natural gas fueling infrastructure for use as a vehicle fuel. In addition, we purchase RNG from third party producers, and sell that RNG for vehicle use through our fueling infrastructure. The RNG we sell for vehicle fuel use is distributed under the name Redeem.
Vehicle Conversions
Prior to June 28, 2013, we owned BAF, a provider of natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support and research and development. BAF’s vehicle conversions included taxis, vans, pick-up trucks and shuttle buses. BAF owned ServoTech Engineering, Inc. (“ServoTech”), which provided, among other services, design and engineering services for natural gas engine systems. We generated revenues through the sale of natural gas vehicles that had been converted to run on natural gas by BAF, and design and engineering services for natural gas engine systems by ServoTech. For the three months ended March 31, 2013, BAF and ServoTech contributed approximately $4.2 million to our revenue. On June 28, 2013, we sold our ownership interest in BAF and its ServoTech subsidiary for approximately $27.2 million.
Natural Gas Fueling Compressors
Our subsidiary, IMW, manufactures and services non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. IMW is headquartered near Vancouver, British Columbia, has other manufacturing facilities near Shanghai, China, and in Ferndale, Washington, and has sales and service offices in Bangladesh, Colombia, Peru and the U.S. For the three months ended March 31, 2013 and 2014, IMW contributed approximately $17.6 million and $22.3 million, respectively, to our revenue.
Sales of RIN and LCFS Credits
We generate LCFS Credits when we sell RNG and conventional natural gas for use as a vehicle fuel in California, and we generate RIN Credits when we sell RNG for use as a vehicle fuel. We can sell these credits to third parties who need the RIN and LCFS Credits to comply with federal and state requirements. During the first three months of 2013, we realized $0.7 million and $0.2 million in revenue through the sale of LCFS and RIN Credits, respectively. During the three months period ended March 31, 2014, we realized $0.7 million and $0.4 million in revenue through the sale of LCFS and RIN Credits, respectively. We anticipate that we will generate and sell increasing numbers of RIN and LCFS Credits as we grow our business and sell increasing amounts of CNG, LNG and RNG for use as a vehicle fuel. The market for RINs Credits and LCFS Credits is volatile, and the prices for such credits may be subject to significant fluctuations. Further, the value of RINs Credits and LCFS Credits will be adversely affected by any changes to the state and federal programs under which such credits are generated and sold.
Volatility of Earnings and Cash Flows
During 2013 our futures contracts qualified for hedge accounting, so we had no derivative gains or losses recognized in our consolidated statements of operations for that period. We did not have any futures contracts in place during the first three months of 2014. In accordance with our natural gas hedging policy, we plan to structure all futures contracts as cash flow hedges under the applicable derivative accounting guidance, but we cannot be certain that they will qualify. See “Risk Management Activities” below. If any of our futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.
Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At March 31, 2014, we had no margin deposits or futures contracts in place.
Volatility of Earnings Related to Series I Warrants
Under Financial Accounting Standards Board (“FASB”) authoritative guidance, we are required to record the change in the fair market value of our Series I warrants in our consolidated financial statements. We have recognized a loss of $0.5 million and a gain of $4.5 million, respectively, related to recording the estimated fair value changes of our Series I warrants in the three months ended March 31, 2013 and 2014. See note 17 to our condensed consolidated financial statements contained elsewhere herein. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of valuing our Series I warrants. As of March 31, 2014, 2,130,682 of the Series I warrants remained outstanding.
Volatility of Earnings Related to Contingent Consideration
Under business combination accounting guidance, we are required to record the change in the value of the contingent consideration related to our acquisition of IMW in our financial statements through the contingency period, which expires on March 31, 2014. During the first three months of 2013 and 2014, we did not recognize any gains or losses related to the estimated change in value of the IMW contingent consideration.
Debt Compliance
In connection with our acquisition of IMW, we entered into a credit agreement with HSBC Bank Canada that requires IMW to comply with certain financial covenants (see note 12 to our condensed consolidated financial statements). If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the credit agreement would be due and payable. IMW was in compliance with these covenants as of March 31, 2014.
The loan agreement entered into by Dallas Clean Energy McCommas Bluff, LLC (“DCEMB”), our 70% owned subsidiary, as part of issuing its Revenue Bonds, as defined and disclosed in note 12 to our condensed consolidated financial statements, has certain non-financial debt covenants with which DCEMB must comply. As of March 31, 2014, we were in compliance with these debt covenants.
The loan agreements relating to the 7.5% Notes, as discussed in note 12 to our condensed consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of March 31, 2014, we were in compliance with these debt covenants.
The convertible note purchase agreements relating to the SLG Notes, as discussed in note 12 to our condensed consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of March 31, 2014, we were in compliance with these covenants.
The GE Credit Agreement, as discussed in note 12 to our condensed consolidated financial statements, contains certain covenants with which we must comply. As of March 31, 2014, we were in compliance with these covenants.
The Mavrix Note, as discussed in note 12 to our condensed consolidated financial statements, contains certain debt covenants with which we must comply. As of March 31, 2014, we were in compliance with these covenants.
The indenture relating to the 5.25% Notes, as discussed in note 12 to our condensed consolidated financial statements, has certain non-financial debt covenants with which we must comply. As of March 31, 2014, we were in compliance with these debt covenants.
The Canton Bonds, as discussed in note 12 to our condensed consolidated financial statements, contain certain debt covenants with which we must comply. As of March 31, 2014, we were in compliance with these covenants.
Risk Management Activities
Our risk management activities are discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of our 2013 10-K. For the quarter ended March 31, 2014, there were no material changes to our risk management activities.
Critical Accounting Policies
For the three months ended March 31, 2014, there were no material changes to the “Critical Accounting Policies” discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of our 2013 10-K.
Recently Issued Accounting Pronouncements
For a description of recently issued accounting pronouncements, see note 18 to our condensed consolidated financial statements contained elsewhere herein.
Results of Operations
The following is a more detailed discussion of our financial condition and results of operations for the periods presented:
|
|
|
Three Months |
| ||
|
|
|
2013 |
|
2014 |
|
|
Statement of Operations Data: |
|
|
|
|
|
|
Revenue: |
|
|
|
|
|
|
Product revenues |
|
89.7 |
% |
90.0 |
% |
|
Service revenues |
|
10.3 |
|
10.0 |
|
|
Total revenues |
|
100.0 |
|
100.0 |
|
|
Operating expenses: |
|
|
|
|
|
|
Cost of sales: |
|
|
|
|
|
|
Product cost of sales |
|
50.3 |
|
71.2 |
|
|
Service cost of sales |
|
4.2 |
|
4.0 |
|
|
Derivative (gains) losses on Series I warrant valuation |
|
0.5 |
|
(4.7 |
) |
|
Selling, general and administrative |
|
35.3 |
|
35.2 |
|
|
Depreciation and amortization |
|
10.9 |
|
12.1 |
|
|
Total operating expenses |
|
101.2 |
|
117.8 |
|
|
Operating loss |
|
(1.2 |
) |
(17.8 |
) |
|
Interest expense, net |
|
(5.5 |
) |
(10.0 |
) |
|
Other expense, net |
|
(0.4 |
) |
(1.3 |
) |
|
Loss from equity method investment |
|
(0.1 |
) |
— |
|
|
Gain from sale of equity method investment |
|
5.1 |
|
— |
|
|
Loss before income taxes |
|
(2.1 |
) |
(29.1 |
) |
|
Income tax expense |
|
(1.9 |
) |
(1.0 |
) |
|
Net loss |
|
(4.0 |
) |
(30.1 |
) |
|
(Income) loss of noncontrolling interest |
|
0.0 |
|
0.1 |
|
|
Net loss attributable to Clean Energy Fuels Corp. |
|
(4.0 |
) |
(30.0 |
) |
Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2014
Revenue. Revenue increased by $2.3 million to $95.3 million in the three months ended March 31, 2014, from $93.0 million in the three months ended March 31, 2013. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 49.9 million gasoline gallon equivalents to 59.3 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 5.4 million gallons. Our net increase in CNG volume was primarily from 31 new refuse customers, four new transit customers and two new trucking customers, which together accounted for 5.5 million gallons of the CNG volume increase between periods. We also experienced an increase of 3.0 million gallons in CNG volume between periods from our existing airport, refuse and trucking customers. These CNG gallons increases were offset by a decline of 2.2 million gallons associated with the sale of our 49% interest in our Peruvian joint venture in March 2013 and 0.9 million gallons related to the loss of three CNG O&M stations for one transit customer. Further, we experienced an increase of 3.0 million gallons in LNG volume between periods, which was primarily due to 1.6 million gallons from six new trucking customers, three new industrial customers, and one new transit customer. We also experienced an increase of 1.4 million gallons in LNG volume between periods from our existing industrial, refuse and trucking customers. We experienced a 1.0 million gallons increase between periods increase in our RNG sales, primarily due to increased RNG production at our DCEMB and Canton facilities. Our effective price per gallon charged was $0.94 in the three months ended March 31, 2014, which represents a $0.11 per gallon increase from $0.83 per gallon in the three months ended March 31, 2013. We experienced a $13.4 million increase in station construction revenues between periods, primarily due to the completion of five new CNG stations for new refuse customers, one new CNG station for a new transit customer, and one new LNG station for an existing transit customer. Revenue attributable to IMW increased between periods by $4.7 million. These increases were offset by a $26.2 million decrease in VETC revenue between periods as the fuel tax credit expired on December 31, 2013, and we recorded $26.2 million related to VETC in the first quarter of 2013. Revenue also decreased by $4.2 million between periods due to decreased sales of natural gas vehicle equipment and emission control services by BAF (we sold BAF in June 2013).
Cost of sales. Cost of sales increased by $20.9 million to $71.6 million in the three months ended March 31, 2014, from $50.7 million in the three months ended March 31, 2013. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers. Our effective cost per gallon increased by $0.12 per gallon, from $0.55 per gallon to $0.67 per gallon, in the three months ended March 31, 2014. We also experienced a $10.7 million increase in station construction costs between periods due to increased activity. Cost of sales that IMW incurred increased between periods by $2.1 million due to their increased sales between periods. These increases were offset by the $3.6 million decrease in costs related to BAF’s vehicle equipment sales and emission control services between periods as we sold BAF in June 2013.
Derivative (gain) loss on Series I warrant valuation. Derivative (gain) loss increased by $5.0 million to a $4.5 million gain in the three months ended March 31, 2014, from a $0.5 million loss in the three months ended March 31, 2013. The amounts represent the non-cash impact with respect to valuing our outstanding Series I warrants based on our mark-to-market accounting for the warrants during the periods. (See note 17 to our condensed consolidated financial statements contained elsewhere herein.)
Selling, general and administrative. Selling, general and administrative increased by $0.6 million to $33.5 million in the three months ended March 31, 2014, from $32.9 million in the three months ended March 31, 2013. The increase was partially related to our continued business growth. Salaries and employee benefits increased by $1.6 million between periods, primarily due to higher average salaries and benefits per employee during the first quarter of 2014 compared to the first quarter of 2013, as we increased our sales force by 10 and hired more management level positions to help support America’s Natural Gas Highway and our continued business expansion. We also experienced a $1.8 million increase in consulting, bad debt, business insurance, and employee recruiting expenses between periods. Offsetting these increases was a decrease of $2.8 million in our stock based compensation expense in the three months ended March 31, 2014.
Depreciation and amortization. Depreciation and amortization increased by $1.3 million to $11.5 million in the three months ended March 31, 2014, from $10.2 million in the three months ended March 31, 2013. This increase was primarily due to additional depreciation expense in the three months ended March 31, 2014 related to increased property and equipment balances between periods, primarily related to our expanded station network, including our build-out efforts of America’s Natural Gas Highway.
Interest expense, net. Interest expense, net, increased by $4.4 million to $9.5 million for the three months ended March 31, 2014, from $5.1 million for the three months ended March 31, 2013. This increase was primarily the result of an increase in interest expense related to the $50.0 million of convertible notes we issued in June 2013, the aggregate $15.0 million advanced under the Mavrix Note in April, September and December 2013, and the $250.0 million of convertible notes we issued in September 2013 (see note 12 to our condensed consolidated financial statements for a description of our outstanding debt).
Other expense, net. Other expense, net, increased by $0.9 million to $1.3 million for the three months ended March 31, 2014, compared to $0.4 million for the three months ended March 31, 2013. This increase was primarily due to a $0.5 million write down of the value of the remaining shares we expect to receive from Westport Innovations, Inc. in connection with the sale of BAF and $0.4 million of foreign currency exchange rate changes between periods related to IMW.
Loss from equity method investment. During the three months ended March 31, 2013, we recorded $0.1 million of equity in the loss of our 49% interest in our Peruvian joint venture. We sold our interest in our Peruvian joint venture in March 2013.
Gain from sale of equity method investment. During the three months ended March 31, 2013, we recorded a $4.7 million gain from sale of our 49% interest in our Peruvian joint venture.
Loss (income) of noncontrolling interest. During the three months ended March 31, 2014, we recorded $0.07 million for the noncontrolling interest in the net loss of DCEMB, compared to $0.04 million for the noncontrolling interest in the net income of DCEMB in the three months ended March 31, 2013. The noncontrolling interest represents the 30% interest of our joint venture partner.
Seasonality and Inflation
To some extent, we experience seasonality in our results of operations. Natural gas vehicle fuel amounts consumed by some of our customers tends to be higher in summer months when buses and other fleet vehicles use more fuel to power their air conditioning systems. Natural gas commodity prices tend to be higher in the fall and winter months due to increased overall demand for natural gas for heating during these periods.
Since our inception, inflation has not significantly affected our operating results. However, costs for construction, repairs, maintenance, electricity and insurance are all subject to inflationary pressures and could affect our ability to maintain our stations adequately, build new stations, build new LNG plants and expand our existing facilities, or materially increase our operating costs.
Liquidity and Capital Resources
We require cash to fund our capital expenditures, operating expenses and working capital requirements, including outlays for the construction of CNG and LNG fueling stations, construction of LNG production facilities, the purchase of new LNG tanker trailers, investment in RNG production, mergers and acquisitions, the financing of natural gas vehicles for our customers and general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, support of legislative and regulatory initiatives and for working capital. Our principal sources of liquidity are cash on hand and cash provided by financing activities.
Liquidity
Cash used in operating activities was $14.5 million for the three months ended March 31, 2014, compared to $16.9 million for the three months ended March 31, 2013. Operating cash flows increased between periods primarily due to increased fuel sales and station construction sales between periods. These increased cash flows were offset by increased selling, general and administrative expenses and interest charges incurred in the first quarter of 2014. We also experienced other working capital changes between periods due to timing differences related to various cash flows.
Cash used in investing activities was $78.0 million for the three months ended March 31, 2014, compared to $2.9 million for the three months ended March 31, 2013. We purchased property and equipment of $46.9 million in the three months ended March 31, 2014, which is an increase of $25.2 million from the $21.7 million in the three months ended March 31, 2013. The increase was largely driven by the purchase of 67 CNG-In-A-Box units from Peake Fuel Solutions, L.L.C. for $18.4 million. We also had an increase in purchases of short-term investments, net of maturities, of $27.2 million in the first quarter of 2014. Restricted cash increased between periods by $3.5 million, primarily from the restricted cash we added in connection with the issuance of the Canton Bonds on March 19, 2014. We sold our interest in our Peruvian Joint Venture in the first quarter of 2013 for $6.1 million.
Cash provided by financing activities for the three months ended March 31, 2014 was $6.2 million, compared to cash used in financing activities of $5.9 million for the three months ended March 31, 2013. This increase was primarily from the issuance of the Canton Bonds for $12.4 million, before issuance costs of $0.9 million. The additional increase in funds provided by financing activities was primarily from the incremental borrowings on our line of credit of $3.3 million to fund IMW’s working capital requirements. We also paid an additional $3.8 million in the three months ended March 31, 2014 on the IMW Notes.
Our financial position and liquidity are, and will be, influenced by a variety of factors, including our ability to generate cash flows from operations, the level of any outstanding indebtedness and the interest we are obligated to pay on our indebtedness, our capital expenditure requirements (which consist primarily of station construction, LNG plant construction costs, RNG plant construction costs and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.
Sources of Cash
Historically, our principal sources of liquidity have consisted of cash provided by financing activities. At March 31, 2014, we had total cash and cash equivalents and short term investments of $318.8 million, compared to $378.3 million at December 31, 2013.
On November 7, 2012, we, through two wholly owned subsidiaries (the “Borrowers”), entered into a credit agreement with GE. Pursuant to that agreement, GE agreed to loan to the Borrowers up to an aggregate of $200.0 million to finance the development, construction and operation of two LNG production facilities, each with an expected production capacity of approximately 250,000 LNG gallons per day. At March 31, 2014, the Borrowers had not drawn any amounts under the agreement.
Capital Expenditures
Our business plan calls for approximately $40.0 million in capital expenditures from April 1, 2014 through end of 2014, primarily related to construction of CNG and LNG fueling stations. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production, and to make capital expenditures to build additional LNG production facilities or to otherwise secure future LNG supply. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raise may depend on various factors, including our rate of new station construction and any potential merger or acquisition activity. We may not be able to raise capital, when needed, on terms that are favorable to us or existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and may reduce our ability to grow our business and generate increased revenues.
Off-Balance Sheet Arrangements
At March 31, 2014, we had the following off-balance sheet arrangements that had, or are reasonably likely to have, a material effect on our financial condition:
· outstanding surety bonds for construction contracts and general corporate purposes totaling $77.6 million,
· four take-or-pay contracts for the purchase of LNG, and
· operating leases where we are the lessee.
We provide surety bonds primarily for construction contracts in the ordinary course of business, as a form of guarantee. No liability has been recorded in connection with our surety bonds as we do not believe, based on historical experience and information currently available, that it is probable that any amounts will be required to be paid under these arrangements for which we will not be reimbursed.
We have four contracts that require us to purchase minimum volumes of LNG at index based prices. One contract expires in June 2014, two contracts expire in December 2015, and one contract expires in October 2017.
We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2021. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we built our California LNG liquefaction plant. The lease is for an initial term of thirty years and requires payments of $0.2 million per year, plus up to $0.1 million per year for each 30 million gallons of production capacity utilized, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as a fee for certain other services that the landlord will provide.
Item 3.—Quantitative and Qualitative Disclosures about Market Risk
In the ordinary course of business, we are exposed to various market risk factors, including changes in general economic conditions, domestic and foreign competition, commodity price risk and foreign currency exchange rates.
Commodity Risk. We are subject to market risk with respect to our sales of natural gas, which has historically been subject to volatile market conditions. Our exposure to market risk is heightened when we have a fixed price sales contract with a customer that is not covered by a futures contract, or when we are otherwise unable to pass through natural gas price increases to customers. Natural gas prices and availability are affected by many factors, including weather conditions, overall economic conditions and foreign and domestic governmental regulation and relations.
Natural gas costs represented 25% (or 31% excluding BAF, IMW and Northstar) of our cost of sales for 2013 and 28.8% (or 33.9%, excluding IMW and Northstar) for the three months ended March 31, 2014.
To reduce price risk caused by market fluctuations in natural gas, we may enter into exchange traded natural gas futures contracts. These arrangements also expose us to the risk of financial loss in situations where the other party to the contract defaults on its contract or there is a change in the expected differential between the underlying price in the contract and the actual price of natural gas we pay at the delivery point.
We account for these futures contracts in accordance with FASB authoritative guidance on derivatives. The accounting under this guidance for changes in the fair value of a derivative depends upon whether it has been specified in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained.
The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets, which are then discounted to reflect the time value of money for contracts applicable to future periods. The fair value of these futures contracts is continually subject to change due to market conditions. In an effort to mitigate the volatility in our earnings related to futures activities, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and to offer fixed price sales contracts to our customers. We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under the FASB guidance, but we cannot be certain they will qualify. For more information, please refer to our 2013 10-K as indicated under “Risk Management Activities”.
In prior years, we have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the futures contracts we held as of the end of our latest fiscal year to hedge the fixed price component of our supply contracts. That sensitivity analysis generally reflects the expected fluctuation in the value of any such contracts if the price of natural gas were to fluctuate (increase or decrease) by a specified percentage from the price quoted on NYMEX as of the end of our latest fiscal year. We did not perform such a sensitivity analysis as of March 31, 2014 because we did not have any futures contract outstanding at March 31, 2014.
Foreign exchange rate risk. Because we have foreign operations, we are exposed to foreign currency exchange gains and losses. Since the functional currency of our foreign operations is in their local currency, the currency effects of translating the financial statements of those foreign subsidiaries, which operate in local currency environments, are included in the accumulated other comprehensive income (loss) component of consolidated equity and do not impact earnings. However, foreign currency transaction gains and losses not in our subsidiaries’ functional currency do impact earnings and resulted in approximately $0.9 million of loss for the three months ended March 31, 2014. During the three months ended March 31, 2014, our primary exposure to foreign currency rates related to our Canadian operations that had certain outstanding notes payable denominated in the U.S. dollar which were not hedged.
We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our monetary transactions denominated in a foreign currency. If the exchange rate on these assets and liabilities were to fluctuate by 10% from the rate as of March 31, 2014, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $1.0 million.
Item 4.—Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. We carried out an evaluation, under the supervision of and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.
There were no changes in our internal control over financial reporting that occurred during the period covered by this quarterly report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
We are party to various legal actions that have arisen in the ordinary course of our business. During the course of our operations, we are also subject to audit by tax authorities for varying periods in various federal, state, local, and foreign tax jurisdictions. Disputes have arisen, and may continue to arise, during the course of such audits as to facts and matters of law. It is impossible at this time to determine the ultimate liabilities that we may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing of these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon our consolidated financial position or results of operations. However, we believe that the ultimate resolution of such actions will not have a material adverse effect on our consolidated financial position, results of operations, or liquidity.
An investment in our Company involves a high degree of risk of loss. You should carefully consider the risk factors discussed below and all of the other information included in this quarterly report on Form 10-Q before you decide to purchase shares of our common stock. We believe the risks and uncertainties described below are the most significant we face. The occurrence of any of the following risks could harm our business. In that case, the trading price of our common stock could decline. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our operations.
We have a history of losses and may incur additional losses in the future.
For the three months ended March 31, 2014, we incurred pre-tax losses of $27.7 million, which included a derivative gain of $4.5 million related to marking to market the value of our Series I warrants. In 2011, 2012 and 2013, we incurred pre-tax losses of $48.2 million, $99.6 million and $63.2 million, respectively. Our losses for 2011, 2012 and 2013 included derivative gains of $2.7 million, $3.4 million and $0.9 million, respectively, relating to marking to market the value of our Series I warrants. See note 18 of our consolidated financial statements in our 2013 10-K. During 2011 and 2013, our losses were substantially decreased by approximately $17.9 million and $45.4 million of revenue, respectively, from federal fuel tax credits. The program under which we received such credits expired on December 31, 2013. To build our business and improve our financial performance, we must continue to invest in developing the natural gas vehicle fuel market and offer our customers competitively priced natural gas vehicle fuel and other products and services. If we do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits and other government incentive programs, our business will suffer and the price of our common stock may drop. In addition, if the price of our common stock increases during future periods when our Series I warrants are outstanding, we may be required to recognize material losses based on the valuation of the outstanding Series I warrants.
Servicing our debt requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our debt.
At March 31, 2014, our total consolidated indebtedness was $622.9 million, including an aggregate of $295.0 million principal amount of convertible notes we issued in July 2011, August 2011, July 2012, and June 2013 (the “Series 2011 Notes”) and an aggregate of $250.0 million principal amount of convertible notes we issued in September 2013 (the “Series 2013 Notes”). We expect our interest payment obligations under the Series 2011 Notes and the Series 2013 Notes to be approximately $22.4 million and $13.3 million, respectively, for the year ending December 31, 2014. Our ability to make scheduled payments of the principal of, to pay interest on, or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and 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 selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms or at the desirable time, which could result in a default on our debt obligations. Additionally, our existing and future indebtedness may contain various restrictive covenants, and any failure by us to comply with any of those covenants could also cause us to be in default under the agreements governing the indebtedness. In the event of any such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder, together with accrued and unpaid interest, to be due and payable, thereby causing all of our available cash flow to be used to pay such indebtedness and/or we could be forced into bankruptcy or liquidation. In addition, the amount of our significant indebtedness, combined with our other financial obligations and contractual commitments, could have important consequences. For example, it could make us more vulnerable to adverse changes in general U.S. and worldwide economic, industry and competitive conditions and adverse changes in government regulation, limit our flexibility and planning for, or reacting to, changes in our business and industry, or place us at a competitive disadvantage compared to our competitors who have less debt and limit our ability to borrow additional amounts.
If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline and diesel, potential customers will have less incentive to purchase natural gas vehicles, which would decrease demand for CNG and LNG and limit our growth.
Natural gas vehicles cost more than comparable gasoline or diesel powered vehicles because the components needed for a vehicle to use natural gas adds to a vehicle’s base cost. If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline or diesel, operators may be unable to recover the additional costs of acquiring or converting to natural gas vehicles in a timely manner, and they may choose not to use natural gas vehicles. Our ability to offer CNG and LNG fuel to our customers at lower prices than gasoline and diesel depends in part on natural gas prices remaining lower, on an energy equivalent basis, than oil prices. If the price of oil, gasoline and diesel declines, it will make it more difficult for us to offer our customers discounted prices for CNG and LNG as compared to gasoline and diesel prices and maintain an acceptable margin on our sales. Additionally, reduced prices for gasoline and diesel fuel may cause potential customers to delay or decide not to convert their fleets to run on natural gas. Recent and significant volatility in oil and gasoline prices demonstrate that it is difficult to predict future transportation fuel costs. In addition, any new regulations imposed on natural gas extraction or transportation in the United States, particularly on production of natural gas through hydraulic fracturing or horizontal drilling techniques, could increase the costs of domestic gas production or make it more costly to produce natural gas in the United States, which could lead to substantial increases in the price of natural gas. In that event, our sales of natural gas fuel may decrease and our business would suffer.
The volatility of natural gas prices could adversely impact the adoption of CNG and LNG vehicle fuel and our business.
In the recent past, the price of natural gas has been volatile, and this volatility may continue. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we cannot pass the increased costs on to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost as much as or more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel and consequently our business. Conversely, lower natural gas prices reduce our revenues due to the fact that in a significant number of our customer agreements, the commodity cost is passed through to the customer. Among the factors that can cause fluctuations in natural gas prices are changes in domestic and foreign supplies of natural gas, domestic storage levels, crude oil prices, the price difference between crude oil and natural gas, price and availability of alternative fuels, weather conditions, negative publicity surrounding drilling techniques, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions. In particular, there have been recent efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing of shale gas reservoirs and on transporting or dispensing natural gas. Hydraulic fracturing and horizontal drilling techniques has resulted in a substantial increase in the proven natural gas reserves in the United States, and any changes in regulations that make it more expensive or unprofitable to produce natural gas through hydraulic fracturing or horizontal drilling, as well as any changes to the regulations relating to transporting or dispensing natural gas, could lead to increased natural gas prices.
If the Cummins Westport ISX 12G natural gas engine (or a comparable engine) is not adopted by truck operators to the extent we anticipate, our results of operations and business prospects will be adversely affected.
We believe that our entry into the heavy-duty truck market, and the execution of our ANGH initiative, depends upon the successful adoption of the Cummins Westport ISX 12G natural engine (or a comparable engine that we believe would be well-suited for the U.S. heavy-duty truck market). Such natural gas engines may not be adopted and deployed by heavy-duty truck operators in meaningful numbers. Heavy-duty trucks powered by natural gas engines cost more, as compared to comparable diesel trucks, and may experience operational or performance issues. If meaningful numbers of natural gas heavy-duty truck engines are not deployed, or if a meaningful number of the engines that are deployed are not fueled at our stations, our business and financial results would be harmed.
The failure of our America’s Natural Gas Highway initiative and our effort to obtain a substantial share of the natural gas heavy-duty truck market would materially and adversely affect our financial results and business.
We are seeking to capture a substantial share of the natural gas heavy-duty truck market, and in connection with that effort we are building America’s Natural Gas Highway, a network of natural gas truck fueling stations. Our initiative to obtain a substantial share of the heavy-duty truck market and build America’s Natural Gas Highway requires a significant commitment of capital and other resources, and our ability to successfully execute our plan faces substantial risks, including:
· Our ANGH stations have primarily been initially built to provide LNG and LNG typically costs more than CNG. If CNG becomes the preferred fuel for truck operators, we would be required to spend significant additional capital to add CNG fueling capability to our ANGH stations, and we may not have sufficient capital for that purpose;
· Truck and vehicle operators may not fuel at our stations;
· We have no influence over the development, production or availability of natural gas trucks powered by engines that are well-suited for the United States heavy-duty truck market (including the Cummins Westport ISX 12G engine);
· Operators may not adopt heavy-duty natural gas trucks due to cost, actual or perceived performance issues, or other factors that are outside our control;
· We may not be able to obtain acceptable margins on fuel sales at ANGH stations;
· We may not be able to identify, obtain and retain sufficient rights to use suitable locations for ANGH stations;
· Necessary additional capital may not be available on terms favorable to us or at all;
· We may experience delays in building stations, including delays in obtaining necessary permits and approvals;
· We may not be able to hire and retain the necessary qualified personnel, and our operational infrastructure and systems may be inadequate;
· Many ANGH stations have been completed before there are sufficient numbers of customers who will fuel at the stations, and if such customers do not materialize, we will continue to have substantial investments in assets that do not produce revenues and we may lose money on LNG that is supplied to the ANGH stations but is not purchased by customers;
· We may not be able to acquire and transport sufficient volumes of LNG; and
· Building ANGH imposes significant added responsibilities on our management team and will divert their attention from other areas of our business.
We must effectively manage these risks and any other risks that may arise in connection with the ANGH build-out to successfully execute our business plan. Failure to successfully execute our ANGH initiative and obtain a substantial share of the natural gas heavy-duty truck market will materially and adversely affect our financial results, operations and business, and our ability to repay our debt.
Automobile and engine manufacturers currently produce very few originally manufactured natural gas vehicles and engines for the United States and Canadian markets, which may restrict our sales of CNG, LNG and RNG.
Limited availability of natural gas vehicles and engine sizes restricts their wide scale introduction and narrows our potential customer base. Original equipment manufacturers currently produce a small number of natural gas engines and vehicles in the U.S. and Canadian markets, they may not make adequate investments to expand their natural gas engine and vehicle product lines, and/or they may discontinue or curtail their natural gas engine and vehicle product lines. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our natural gas fuel sales will be restricted.
Natural gas vehicles may require servicing and further technology refinements to address performance issues that may occur as vehicles are deployed in large numbers. If heavy-duty natural gas truck purchasers are not satisfied with truck performance, additional heavy-duty truck engine manufacturers do not enter the market for natural gas engines, or natural gas engines are not otherwise developed, produced and adopted in greater numbers, our ANGH investments and natural gas fueling business may be significantly impaired, which would adversely affect our financial performance.
We may need to raise additional debt or equity capital to continue to fund the growth of our business.
At March 31, 2014, we had total cash and cash equivalents of $154.3 million and short-term investments of $164.5 million. Our business plan calls for approximately $40.0 million in capital expenditures from April 1, 2014 through the end of 2014, as well as substantial capital expenditures thereafter. We may also require capital for unanticipated expenses, mergers and acquisitions and strategic investments. In addition, we have committed to future payments that we will be required to make in connection with prior acquisitions that at March 31, 2014 totaled $2.4 million.
Equity or debt financing options may not be available when needed or on terms favorable to us, or at all. Additional sales of our common stock or securities convertible into our common stock will dilute existing stockholders and may result in a decline in our stock price. We may also pursue debt financing options including, but not limited to, equipment financing, the sale of convertible notes, high yield debt, asset based loans, term loans, project finance debt, municipal bond financing or commercial bank financing. Any debt financing we obtain may require us to make significant interest payments and to pledge some or all of our assets as security. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated expenses, capital expenditures, mergers, acquisitions or strategic investments, we will be forced to suspend or curtail these capital expenditures or postpone or delay potential acquisitions or other strategic transactions, which would harm our business, results of operations, and future prospects.
We have the ability to incur substantially more debt.
Despite our current consolidated debt levels, we and our subsidiaries may be able to incur substantial additional debt in the future, some of which may be secured debt. The agreements governing our Series 2011 Notes and our Series 2013 Notes do not restrict our ability to incur additional indebtedness or require us to maintain financial ratios or specified levels of net worth or liquidity. If we incur substantial additional indebtedness in the future, these higher levels of indebtedness may adversely affect our ability to pay the principal of and interest on our debt, or make other required payments, increase the risks relating to our ability to service our indebtedness described above, and/or adversely affect our creditworthiness generally, which could restrict our flexibility in responding to changing business and economic conditions and negatively impact our business.
Our business is influenced by government incentives and mandates for clean burning fuels and alternative fuel vehicles.
Our business is influenced by federal, state and local government tax attributes, credits, rebates, grants and similar incentives that promote the use of natural gas and RNG as a vehicle fuel, as well as by laws, rules and regulations that require reductions in carbon emissions. Some government programs and incentives have recently expired, such as the VETC federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle fuel use, which expired December 31, 2013 and may not be reinstated. In 2011 and 2013 we recorded approximately $17.9 million and $45.4 million of revenue, respectively, related to VETC fuel tax credits, representing approximately 6.1% and 12.9%, respectively, of our total revenue during the periods. If expired incentives are not reinstated or extended, or if new incentives are not passed, our revenue and financial performance may be adversely affected. Furthermore, the failure of proposed federal, state or local government incentives that promote the use of natural gas and RNG as a vehicle fuel to pass into law could result in a negative perception of our industry and business by the market generally and a decline in the market price of our common stock. Changes to or the repeal of laws, rules and regulations that mandate reductions in carbon emissions and/or the use of renewable fuels, including the California Low Carbon Fuel Standard and the Federal Renewable Fuel Standard Phase 2, would adversely affect our business and ability to operate a profitable RNG business. In addition, if grant funds are not available under government programs for the purchase and construction of natural gas vehicles and stations, those activities could slow and our business and results of operations may be adversely affected.
Our growth depends in part on environmental regulations and programs mandating the use of cleaner burning fuels, and modification or repeal of these regulations may adversely impact our business.
Our business depends in part on environmental regulations and programs in the United States that promote or mandate the use of cleaner burning fuels, including natural gas and RNG for vehicles. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we have, invest significant time and money in efforts to influence environmental regulations in ways that delay or repeal requirements for cleaner vehicle emissions. Further, economic difficulties may result in the delay, amendment or waiver of environmental regulations due to the perception that they impose increased costs on the transportation industry that cannot be absorbed in a challenging economy. The delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles could also have a detrimental effect on the United States natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.
The use of natural gas as a vehicle fuel may not become sufficiently accepted for us to expand our business.
To expand our business, we must develop new customers and sell increasing amounts of natural gas vehicle fuel and the other products and services we offer, which we may not be able to do. Whether we will be able to expand our customer base will depend on a number of factors, including the level of acceptance and availability of natural gas vehicles, the growth in our target markets of fueling station infrastructure that supports CNG and LNG sales, our ability to supply CNG and LNG at prices that are lower than gasoline and diesel and acceptance of our technology, products and services. A decline in oil, diesel fuel and gasoline prices may result in decreased interest in alternative fuels like CNG and LNG. Also, if vehicle operators perceive that greenhouse gas emissions of natural gas vehicles are greater than those of gasoline or diesel vehicles, then such operators may not adopt natural gas vehicles. Further, potential customers may not find our product or service offerings acceptable, may not like the natural gas fueling experience or may encounter operational difficulties with natural gas vehicles or natural gas fueling infrastructure. In addition, users may experience issues with the content of the natural gas supplied to CNG stations we own and/or operate. Such issues may adversely affect the adoption of CNG as a vehicle fuel and may result in claims against us.
We face increasing competition from oil and gas companies, fuel providers, refuse companies, industrial gas companies, natural gas utilities, fuel station and truck stop owners, and other organizations that have far greater resources and brand awareness than we have.
A significant number of established businesses, including oil and gas companies, refuse collectors, natural gas utilities and their affiliates, industrial gas companies, truck stop and station owners, fuel providers and other organizations have entered or are planning to enter the natural gas fuels market. For example, Love’s Travel Stops is adding CNG refueling infrastructure to its travel-center network. Many of these current and potential competitors have substantially greater financial, marketing, research and other resources than we have. Further, new technologies and improvements to existing technologies may give existing competitors and new market entrants competitive advantages. In addition, in the heavy-duty truck market, we compete with market participants who advocate the adoption of CNG over LNG, and operators may prefer the CNG offering provided by such competitors. Natural gas utilities, particularly in California, continue to own and operate natural gas fueling stations that compete with our stations. The California Public Utilities Commission has approved a compression services tariff application by the Southern California Gas Company, allowing the utility to compete with us by building and owning natural gas fueling infrastructure on customer property and by providing O&M services to customers. Further, utilities in several other states, including Michigan, Illinois, New Jersey, North Carolina, Oregon, Maryland, Washington, Kentucky and Georgia, either have or are preparing to enter the natural gas vehicle fuel business. Utilities, in particular, have unique competitive advantages, including that they typically have a lower cost of capital, substantial and predictable cash flows, long-standing customer relationships, greater brand awareness and large and well-trained sales and marketing organizations.
We expect competition to intensify in the near term in the market for natural gas vehicle fuel as the use of natural gas vehicles and the demand for natural gas vehicle fuel increases. Increased competition will lead to amplified pricing pressure, reduced operating margins and fewer expansion opportunities. Our failure to compete successfully in the markets in which we operate, including the heavy-duty truck market, would adversely affect our business and financial results.
We are subject to risks associated with cost overruns, delays, regulatory compliance and other contingencies in connection with our station construction activities, any of which could have a material adverse effect on our business and results of operations.
In connection with our station construction and facility modification projects, we act as the general contractor and construction manager and typically rely on licensed subcontractors to perform the construction work. We may be liable for any damage we or our subcontractors cause during the course of our projects. Shortages of skilled subcontractor labor for our projects could significantly delay a project or otherwise increase our costs. Our profit on our projects is based in part on assumptions as to the cost of such projects. Cost overruns, delays or other execution issues may, in the case of projects that we complete and sell to customers, cause us to not achieve our expected margins or cover our costs, and in the case of projects that we build and own, cause us to not achieve an acceptable rate of return.
In addition, our station construction and facility modification activities are subject to oversight and regulation in accordance with national, state and local laws and ordinances relating to building codes, safety, environmental protection, and related matters. It is difficult and costly to manage the requirements of every individual authority having jurisdiction over our various construction projects and to comply with these varying standards. Any new government regulations pertaining to our station construction and facility modification activities may result in significant additional expenses to us and our customers.
Our warranty reserves may not adequately cover our warranty obligations and increased or unexpected product warranty claims could adversely impact our financial condition and results of operations.
We provide product warranties with varying terms and durations for the majority of our products and we establish reserves for the estimated liability associated with our product warranties. Our warranty reserves are based on historical trends as well as our understanding of specifically identified warranty issues. The amounts estimated could differ materially from actual warranty costs that may ultimately be realized. An increase in the rate of warranty claims or the occurrence of unexpected warranty claims could have a material adverse effect on our financial condition or results of operations.
Increased IT security threats and more sophisticated and targeted computer crime could pose a risk to our systems, networks, products, solutions and services.
Increased global IT security threats and more sophisticated and targeted computer crime pose a risk to the security of our systems and networks and the confidentiality, availability and integrity of our data. Depending on their nature and scope, such threats could potentially lead to the compromising of confidential information, improper use of our systems and networks, manipulation and destruction of data and operational disruptions, which in turn could adversely affect our reputation, competitiveness and results of operations.
Our global operations expose us to additional risk and uncertainties.
We have operations in a number of countries, including the United States, Canada, China, Colombia, Bangladesh and Peru. Our natural gas compression equipment is primarily manufactured in Canada and sold globally, which exposes us to a number of risks that can arise from international trade transactions, local business practices and cultural considerations. In addition to the other risks described herein, our global operations may be subject to risks and uncertainties that may limit our ability to operate our business, including:
· compliance with the United States Foreign Corrupt Practices Act;
· political unrest, terrorism and economic and financial instability;
· unexpected changes in regulatory requirements and uncertainty related to developing legal and regulatory systems governing economic and business activities, real property ownership and application of contract rights;
· import-export regulations;
· difficulties in enforcing agreements and collecting receivables;
· difficulties in ensuring compliance with the laws and regulations of multiple jurisdictions;
· difficulties in ensuring that health, safety, environmental and other working conditions are properly implemented and/or maintained by the local office;
· differing employment practices and/or labor issues, including wage inflation, labor unrest and unionization policies;
· limited intellectual property protection;
· longer payment cycles by international customers;
· inadequate local infrastructure and disruptions of service from utilities or telecommunications providers, including electricity shortages; and
· potentially adverse tax consequences.
In addition to the above, we also face risks associated with currency exchange and convertibility, inflation and repatriation of earnings as a result of our foreign operations. In some countries, economic, monetary and regulatory factors could affect our ability to convert funds to United States dollars or move funds from accounts in these countries. We are also vulnerable to appreciation or depreciation of foreign currencies against the United States dollar.
We may encounter challenges managing our growth, which may divert resources and limit our ability to successfully expand our operations.
We have been and expect to continue to be engaged in a period of rapid and substantial growth, which places a strain on our operational infrastructure and imposes significant added responsibilities on members of our management. Our ability to manage our operations and growth effectively requires us to hire, train and integrate necessary personnel to further develop our operational, financial and management controls, expand and improve our financial reporting and legal compliance systems, and improve management of our natural gas station construction, maintenance and operations projects. If we are not able to manage our business growth and operations in a cost-effective manner, our operating results, sales and revenues may be negatively impacted.
We depend on key personnel to operate our business, and if we are unable to retain our current personnel or hire additional personnel, our ability to develop and successfully market our business would be harmed.
We believe that our future success is highly dependent on the contributions of our executive officers, as well as our ability to attract and retain highly skilled managerial, sales, technical and finance personnel. Qualified individuals are in high demand, and we may incur significant costs to attract and retain them. All of our executive officers and other United States employees may terminate their employment relationships with us at any time, and their knowledge of our business and industry would be extremely difficult to replace. If we are unable to attract and retain our executive officers and key employees, our business, operating results and financial condition could be harmed. In addition, our management team has a long history of working together, and we believe that our key executives have developed highly successful and effective working relationships. If one or more of these individuals leave, we may not be able to fully integrate new executives or replicate the current dynamic, which may cause our operations to suffer.
A significant portion of the purchase price of IMW was allocated to intangibles, including goodwill, and a write-off of all or part of these intangibles, including goodwill, could adversely affect our operating results.
Under business combination accounting standards, we allocated the total purchase price of IMW to its net tangible assets and liabilities and intangible assets based on their fair values as of the date of the acquisition and recorded the excess of the purchase price over those values as goodwill. Our estimates of the fair value of the assets and liabilities of IMW were based upon certain assumptions, including assumptions regarding new business, believed to be reasonable, but which are inherently uncertain. Pursuant to the applicable accounting standards, we initially allocated $126.4 million of the purchase price for IMW to intangibles, including goodwill. Our intangibles, including goodwill, could be impaired if developments affecting the acquired compressor manufacturing operations or the markets in which IMW produces and/or sells compressors lead us to conclude that the cash flows we expect to derive from its manufacturing operations will be substantially reduced. An impairment of all or part of our intangibles, including goodwill, could adversely affect our results of operations.
We have significant contracts with federal, state and local government entities that are subject to unique risks.
We have, and will continue to seek, long-term CNG and LNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately 21% of our revenues for the three months ended March 31, 2014 and approximately 21%, 33% and 19% of our annual revenues in 2011, 2012 and 2013, respectively. In addition to our normal business risks, our contracts with these government entities are often subject to unique risks, some of which are beyond our control. Long- term government contracts and related orders are subject to cancellation if appropriations for subsequent performance periods are not made. The termination of funding for a government program supporting any of our CNG or LNG operations could result in a loss of anticipated future revenues attributable to that program, which could have a negative impact on our operations. In addition, government entities with whom we contract are often able to modify, curtail or terminate contracts with us without prior notice at their convenience, and are only liable for payment for work done and commitments made at the time of termination. Modification, curtailment or termination of significant contracts could have a material adverse effect on our results of operations and financial condition.
Further, government contracts are frequently awarded only after competitive bidding processes, which have been and may continue to be protracted. In many cases, unsuccessful bidders for government agency contracts are provided the opportunity to formally protest certain contract awards through various agency, administrative and judicial channels. The protest process may substantially delay a successful bidder’s contract performance, result in cancellation of the contract award entirely and distract management. We may not be awarded contracts for which we bid, and substantial delays or cancellation of contracts may follow our successful bids as a result of such protests.
We may encounter difficulties building the GE Plants and such facilities may never be completed. If we commence construction of either GE Plant we will need to comply with significant obligations to GE.
Our ability to commence construction of the GE Plants financed under the credit agreement we entered into with GE in November 2012, will depend on a number of conditions, including the availability of sites upon which to construct the GE Plants and our ability to acquire title to, or leasehold interests in, such sites and the receipt of all governmental approvals necessary to design, develop, own, construct, install, operate and maintain the GE Plants. If we do not satisfy all of the conditions by December 31, 2014, GE’s obligation to fund the GE Plants will terminate. This may result in us not being able to satisfy our LNG supply needs, and may adversely affect our business, financial condition and operational results.
If we commence construction of either GE Plant, we may not be able to comply with all of our obligations to GE. For example, we may not complete one or both of the GE Plants within the required time period, or we may not make our required equity contributions to the plants. The GE Plants may cost more than we expect, and we may not be able to pay the additional cost. If the GE Plants are completed, they may not generate enough cash flow to pay our obligations to GE because they may experience operational difficulties or inefficiencies or we may not be able to sell enough of the LNG the plants produce. If we do not fulfill our obligations, we may lose some or all of our investments in the GE plants.
If there are advances in other alternative vehicle fuels or technologies, or if there are improvements in gasoline, diesel or hybrid engines, demand for natural gas vehicles may decline and our business may suffer.
Technological advances in the production, delivery and use of alternative fuels that are, or are perceived to be, cleaner, more cost-effective or more readily available than CNG or LNG have the potential to slow adoption of natural gas vehicles. Advances in gasoline and diesel engine technology, especially hybrids, may offer a cleaner, more cost-effective option and make fleet customers less likely to convert their fleets to natural gas. Technological advances related to ethanol or biodiesel, which are increasingly used as an additive to, or substitute for, gasoline and diesel fuel, may slow the need to diversify fuels and affect the growth of the natural gas vehicle market. Use of electric heavy-duty trucks, or the perception that electric heavy-duty trucks may soon be widely available and provide satisfactory performance in heavy-duty applications, may reduce demand for heavy-duty natural gas trucks. In addition, hydrogen and other alternative fuels in experimental or developmental stages may eventually offer a cleaner, more cost-effective alternative to gasoline and diesel than natural gas. Advances in technology that slow the growth of or conversion to natural gas vehicles, or which otherwise reduce demand for natural gas as a vehicle fuel, will have an adverse effect on our business. Failure of natural gas vehicle technology to advance at a sufficient pace may also limit its adoption and our ability to compete with other alternative fuels and alternative fuel vehicles.
Our ability to obtain LNG is constrained by fragmented and limited production and increasing competition for LNG supply.
Production of LNG in the United States is fragmented and limited. It may be difficult for us to obtain LNG without interruption and near our current or target markets at competitive prices, when needed, or at all. If LNG liquefaction plants we own, or if any of those from which we purchase LNG, are damaged by severe weather, earthquake or other natural disaster, or otherwise experience prolonged down time, or if any such plants cannot produce LNG meeting applicable composition specifications and requirements, or if we or others do not build additional LNG liquefaction plants, our LNG supply will be restricted. In 2013, we entered the Eagle LNG Partners consortium, aimed at developing regional LNG projects to meet growing demand for LNG. However, the efforts of this consortium may be unsuccessful and the LNG supply may remain insufficient to meet demands, and our participation in the consortium may prove to be an ineffective use of our management and other resources. If we are unable to supply enough LNG that satisfies applicable specifications (either from our own plants or by purchasing it from third parties) to meet customer demand, we may be liable to our customers for penalties and damages and may lose customers. Competition for LNG supply is escalating. For example, we increasingly compete to purchase LNG with third parties that use LNG to fuel equipment deployed in oil and gas production activities and other industrial applications. In addition, the execution of our business plan will require substantial growth in the available LNG supply across the United States, and if this supply is unavailable, it will constrain our ability to increase the market for LNG fuel, including supplying LNG fuel to heavy-duty truck customers, and will adversely affect our investments in America’s Natural Gas Highway. If we experience an LNG supply interruption or LNG demand that exceeds available supply, or if we have difficulty entering or maintaining relationships with contract carriers to deliver LNG on our behalf, our ability to expand LNG sales to new customers will be limited, our relationships with existing customers may be disrupted, and our results of operations may be adversely affected. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG from distant locations and cannot pass these costs through to our customers, our operating margins will decrease on those sales due to our increased transportation costs.
LNG supply purchase commitments may exceed demand causing our costs to increase.
We are a party to four LNG supply agreements that have a take-or-pay commitment, and we may enter into additional take-or-pay commitments. Take-or-pay commitments require us to pay for the LNG that we have agreed to purchase irrespective of whether we can sell the LNG. Should the market demand for LNG decline, if we lose significant LNG customers, if demand under any existing or any future LNG sales contract does not maintain its volume levels or grow, or if future demand for LNG does not meet our expectations, these commitments may cause our operating and supply costs to increase and our margins may be negatively impacted.
Compliance with potential greenhouse gas regulations affecting our LNG plants or fueling stations may prove costly and negatively affect our financial performance.
California has adopted legislation, AB 32, which calls for a cap on greenhouse gas emissions throughout California and a statewide reduction to 1990 levels by 2020 and an additional 80% reduction below 1990 levels by 2050. Other states and the federal government are considering passing measures to regulate and reduce greenhouse gas emissions. Any of these regulations, when and if implemented, may regulate the greenhouse gas emissions produced by our LNG production plants, our CNG and LNG fueling stations or our RNG production facilities and require that we obtain emissions credits or invest in costly emissions prevention technology. We cannot currently estimate the potential costs associated with federal or state regulation of greenhouse gas emissions from our LNG plants, CNG and LNG stations or RNG production facilities, if any, and these unknown costs are not contemplated by our current customer agreements. These unanticipated costs may have a negative impact on our financial performance and may impair our ability to fulfill customer contracts at an operating profit.
Our operations entail inherent safety and environmental risks that may result in substantial liability to us.
Our operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas, which is a potent greenhouse gas, and LNG related methane emissions may in the future be regulated by the U.S. Environmental Protection Agency or by state regulations. Additionally, CNG fuel tanks, if damaged or improperly maintained or installed, may rupture and the contents of the tank may rapidly decompress and result in death or injury. These risks may expose us to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. We may incur substantial liability and cost if damages are not covered by insurance or are in excess of policy limits.
We provide financing to fleet customers for natural gas vehicles, which exposes our business to credit risks.
We directly lend to certain qualifying customers a portion of, and occasionally up to 100% of, the purchase price of natural gas vehicles. We may also lease vehicles to customers in the future. There are risks associated with providing financing or leasing that could cause us to lose money. These risks include the following: (i) the equipment financed consists mostly of vehicles that are mobile and easily damaged, lost or stolen, (ii) the borrower may default on payments, enter bankruptcy proceedings and/or liquidate, (iii) we may not be able to bill properly or track payments in adequate fashion to sustain growth of this service, and (iv) the amount of capital available to us is limited and may not allow us to make loans required by customers. Some of our customers, such as taxi owners, may depend on the CNG vehicles that we finance or lease to them as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy proceeding. As of March 31, 2014, we had $6.8 million outstanding in loans provided to customers to finance natural gas vehicle purchases.
Our business is subject to a variety of governmental regulations that may restrict our business and may result in costs and penalties.
We are subject to a variety of federal, state and local laws and regulations relating to foreign business practices, the environment, health and safety, labor and employment, construction, land use and taxation, among others. These laws and regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties and the imposition of corrective requirements. From time to time, as part of the regular overall evaluation of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities. In addition, any failure to comply with regulations related to the government procurement process at the federal, state or local level or restrictions on political activities and lobbying may result in administrative or financial penalties including being barred from providing services to governmental entities.
In connection with our operations, we often need facility permits or licenses to address, among other things, storm water or wastewater discharges, waste handling, and air emissions. This may subject us to permitting conditions that may be onerous or costly. Compliance with laws and regulations and enforcement policies by regulatory agencies could require us to make material expenditures and may distract our officers, directors and employees from the operation of our business.
Our RNG business may not be successful.
We completed RNG production facilities in Canton, Michigan and near Memphis, Tennessee in 2012 and March 2014, respectively, and we own a RNG production facility at the McCommas Bluff landfill outside of Dallas, Texas. We are also seeking to increase our RNG business by pursuing additional projects. We may not be successful in developing and operating these projects and generating a financial return from our investment. Historically, projects that produce pipeline quality RNG have often failed due to the volatile prices of conventional natural gas, unpredictable RNG production levels, technological difficulties and costs associated with operating the production facilities, and the absence of government programs and regulations that support such activities. The success of our RNG business depends on our ability to obtain necessary financing, successfully manage the construction and operation of RNG production facilities and our ability to either sell the RNG at substantial premiums to current conventional natural gas prices or to sell, at favorable prices, credits we may generate under federal or state laws, rules and regulations, including RIN and LCFS Credits. If we are unable to accomplish one or more of these items, our business and financial results may be materially and adversely affected.
In addition, due to recent regulatory and legislative changes in California, our ability to sell RNG produced by projects outside of California to California power plants for use as a Renewable Portfolio Standard (“RPS”) compliant fuel is limited. If we cannot sell RNG we produce to California power plants for use as a RPS compliant fuel, we may not be able to obtain long-term, fixed premium prices for RNG.
The market for RINs Credits and LCFS Credits is volatile, and the prices for such credits may be subject to significant fluctuations. Further, the value of RINs Credits and LCFS Credits will be adversely affected by any changes to the state and federal programs under which such credits are generated and sold. For example, in November 2013, the EPA proposed lowering the 2014 RFS standards, which negatively affected the value of RIN Credits.
In the absence of state and federal programs that support premium prices for RNG, or that allow us to generate and sell LCFS and RIN Credits and other credits, or if our customers are not otherwise willing to pay a premium for RNG, we may be unable to generate reasonable profits and financial returns from these investments, and our financial results could be materially and adversely affected.
We may experience difficulties producing RNG.
We have experienced difficulty producing the expected volumes of RNG at our currently operational RNG plants. The contractor we hired to perform expansion work at the McCommas Bluff plant was not able to cause the expanded plant to meet the performance standards specified in our design-build agreement. This performance failure has resulted in lower than expected RNG production at the plant. We are working to improve performance of the plant and are pursuing our remedies under our agreements with the contractor. These actions, however, are costly and time consuming and may not ultimately be successful. In addition, we have experienced problems with key equipment at our Canton, Michigan production facility, and such problems have resulted in lower than expected RNG production at the plant. We are likely to incur significant additional costs to fix equipment at that plant.
Our financial results and operations will be negatively impacted if we continue to experience difficulties producing RNG. Our ability to produce RNG may be adversely affected by a number of factors beyond our control, including but not limited to, limited availability or unfavorable composition of collected landfill gas, failure to obtain and renew necessary permits, landfill mismanagement, problems with our critical equipment, and adverse or severe weather conditions. In addition, we may seek to upgrade, expand or service our RNG facilities, which may result in plant shutdowns or cause delays that reduce the amount of RNG we produce.
If certain of our subsidiaries do not comply with their financing agreements, we may lose our interest in our RNG production facilities located in Dallas, Texas and Canton, Michigan.
Three of our subsidiaries, Dallas Clean Energy McCommas Bluff, LLC (“DCEMB”) (in which we indirectly own a 70% interest), Canton Renewables, LLC (“Canton”) and Mavrix, LLC (“Mavrix”) have issued debt instruments to third parties. DCEMB and Canton directly own our RNG production facilities located in Dallas, Texas and Canton, Michigan, and Mavrix indirectly owns such facilities because it holds our interests in DCEMB and Canton. If DCEMB, Canton and Mavrix do not comply with their obligations and covenants under these debt instruments (including their obligations to pay principal and interest), we may lose our interests in the RNG production projects they own, and our business and results of operations may be adversely affected.
Our strategic relationship with Mansfield could produce less beneficial results than we currently expect.
On May 6, 2013, in connection with our acquisition of MGES, we entered into a strategic partnership with Mansfield, which is designed to offer customers the most comprehensive natural gas solution in the industry. Pursuant to the partnership arrangement, both our sales team and Mansfield’s sales team will offer our natural gas fueling station construction and operational services to current and potential customers. The intent is that our offered services will be supported by Mansfield’s large-scale fuel supply capabilities and fuel management systems, in order to provide a comprehensive solution to current and prospective customers. This relationship may not achieve the degree of success we aim to achieve, and could prove to be wholly unsuccessful. If we are not able to capitalize on this partnership, our prospects, competitive position in our industry and operational results could be harmed.
We may never receive the full value of the consideration for our sale of BAF, and we could be subject to future liability in connection with that transaction.
In connection with our sale of our former subsidiary BAF, we entered into a stock purchase agreement in which we made customary representations and warranties regarding BAF and various aspects of its business, operations and financial condition. Pursuant to the indemnification provisions in that stock purchase agreement, we are subject to certain obligations to the purchaser of BAF if any of those representations and warranties should prove to be untrue and in certain other circumstances. The stock purchase agreement provides that the purchaser of BAF is entitled to hold back $3.0 million worth of the consideration due to us for a period of one year, and use such held back amount to satisfy any losses it may incur that are covered by our indemnification obligations. As a result, we may never receive the portion of the consideration that has been held back. In December 2013, we wrote down the value of these shares by $1.4 million. During the three months ended March 31, 2014, we wrote down the value of the shares an additional $0.5 million. Further, with respect to certain specified representations and warranties in the stock purchase agreement, the purchaser of BAF could pursue amounts from us in addition to the value of the held back consideration, in the event that its losses are greater than the value of the held back consideration. Accordingly, we could be subject to monetary liability as a result of our indemnification obligations. Any of those results could distract our management team and/or require us to devote our resources to the matter, and could harm our business and financial condition.
Our quarterly results of operations have not been predictable in the past and have fluctuated significantly and may not be predictable and may fluctuate in the future.
Our quarterly results of operations have historically experienced significant fluctuations. Our net losses were approximately $9.8 million, $5.6 million, $11.4 million, $20.9 million, $31.9 million, $11.3 million, $16.3 million, $41.7 million, $3.9 million, $11.9 million, $18.8 million, $32.3 million, and $28.6 million for the three months ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013, September 30, 2013, December 31, 2013, and March 31, 2014, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. In particular, if our stock price increases or decreases in future periods during which our Series I warrants are outstanding, we will be required to recognize corresponding losses or gains related to the valuation of the Series I warrants that could materially impact our results of operations. If our quarterly results of operations fall below the expectations of securities analysts or investors, the price of our common stock could decline substantially. Fluctuations in our quarterly results of operations may be due to a number of factors, including, but not limited to, our ability to increase sales to existing customers and attract new customers, the addition or loss of large customers, receipt of fuel tax credits and other government incentives, construction delays and/or cost overruns, down time at our facilities, the amount and timing of operating costs, unanticipated expenses, capital expenditures related to the maintenance and expansion of our business, operations and infrastructure, our debt service obligations, changes in the price of natural gas, changes in the prices of CNG and LNG relative to gasoline and diesel, changes in our pricing policies or those of our competitors, difficulties producing LNG and/or RNG from our facilities, challenges acquiring LNG and/or RNG from third parties, the costs related to the acquisition of assets or businesses, regulatory changes, increasing competition, geopolitical events such as war, threat of war or terrorist actions, and the occurrence of any of the additional risks discussed in this report. Investors in our stock should not rely on the results of one quarter as an indication of future performance as our quarterly revenues and results of operations may vary significantly in the future. Therefore, period-to-period comparisons of our operating results may not be meaningful.
Sales of shares could cause the market price of our stock to drop significantly, even if our business is doing well.
As of March 31, 2014, there were 89,858,816 shares of our common stock outstanding, 11,978,192 shares underlying outstanding options, 2,080,336 shares underlying restricted stock units, 2,130,682 shares underlying outstanding Series I warrants (all of which were sold in our registered direct offering that closed in November 2008), 5,000,000 shares underlying a warrant we issued in November 2012 to GE, an aggregate of 19,160,338 shares underlying our Series 2011 Notes and an aggregate of 16,025,641 shares underlying our Series 2013 Notes. All of our outstanding shares are eligible for sale in the public market, subject in certain cases to the requirements of Rule 144 of the Securities Act. Also, shares subject to outstanding options, warrants and convertible notes are eligible for sale in the public market to the extent permitted by the provisions of the applicable option, warrant and convertible note agreements and Rule 144, or if such shares have been registered for resale under the Securities Act. If these shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our common stock could decline.
As of March 31, 2014, 18,139,720 shares of our common stock held by our co-founder and board member T. Boone Pickens are subject to pledge agreements with banks. Should one or more of the banks sell the shares subject to the pledge, the trading price of our stock could also decline. In addition, a number of our directors and executive officers have entered into Rule 10b5-1 Sales Plans with a broker to sell shares of our common stock that they hold or that may be acquired upon the exercise of stock options. Sales under these plans will occur automatically without further action by the director or officer once the price and/or date parameters of the particular selling plan are achieved. As of March 31, 2014, 468,897 shares in the aggregate were subject to future sales by our named executive officers and directors under these selling plans. Sales of shares under these plans could also cause the trading price of our common stock to fall.
A significant portion of our stock is beneficially owned by a single stockholder whose interests may differ from yours and who will be able to exert significant influence over our corporate decisions, including a change of control.
As of March 31, 2014, T. Boone Pickens beneficially owned in the aggregate approximately 24.2% of our outstanding shares of common stock (including 18,139,720 shares of common stock, 1,901,800 shares underlying stock options exercisable within 60 days of March 31, 2014, and 4,113,923 shares underlying convertible promissory notes he holds). As a result, Mr. Pickens is able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers, acquisitions or other extraordinary transactions. Mr. Pickens may have interests that differ from yours and may vote in a way with which you disagree and that may be adverse to your interests. This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their stock as part of a sale of our company, and might ultimately affect the market price of our stock. Conversely, this concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.
Our stock price may be volatile.
The market price of our common stock has experienced, and may continue to experience, volatility and could be subject to fluctuations in price in response to various factors, some of which are beyond our control. In addition to the other factors discussed in this Item 1A, factors that may cause volatility in our stock price include:
· our actual or perceived ability to capture a substantial share of the anticipated growth in the market for natural gas as a vehicle fuel;
· successful implementation of our business plans, including our plan to build America’s Natural Gas Highway;
· the development, commercial availability and market adoption of natural gas as a vehicle fuel and engines that operate on natural gas, particularly natural gas engines that are well-suited for the heavy-duty truck market, including the Cummins Westport ISX 12G engine, and the mix of such engines between CNG and LNG;
· production, sourcing and supply of LNG and RNG;
· changes in the worldwide prices for natural gas and for traditional vehicle fuels, such as gasoline and diesel;
· actual or perceived fluctuations in our operating results;
· sales of our common stock by us or our stockholders;
· a decline in demand for our common stock;
· the potential for oil and gas companies, natural gas utilities and others to enter the natural gas fuel market;
· changes in our key personnel;
· competitive developments;
· investor perception of our industry or our prospects; and
· changes in general economic and market conditions.
In addition, the securities markets have from time to time experienced significant price and volume fluctuations that are unrelated to the operating performance of particular companies, and in such instances, have affected the market prices of those companies’ securities. These market fluctuations may also materially and adversely affect the market price of our common stock.
Item 2.—Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3.—Defaults upon Senior Securities
None.
Item 4.—Mine Safety Disclosures
None.
None.
(a) Exhibits
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3.2.1 |
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Amendment No. 1 to Amended and Restated Bylaws (filed as Exhibit 3.2.1 to Form 8-K, as filed with the Securities and Exchange Commission on February 27, 2014, and incorporated herein by reference). |
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10.93 |
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Loan Agreement, dated March 1, 2014, between Canton Renewables, LLC and Michigan Strategic Fund (filed as Exhibit 10.93 to Form 8-K, as filed with the Securities and Exchange Commission on March 21, 2014, and incorporated herein by reference). |
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31.1* |
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Certification of Andrew J. Littlefair, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2* |
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Certification of Richard R. Wheeler, Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1* |
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Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, executed by Andrew J. Littlefair, President and Chief Executive Officer, and Richard R. Wheeler, Chief Financial Officer. |
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101 |
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The following materials from the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, formatted in XBRL (eXtensible Business Reporting Language): |
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(i) Condensed Consolidated Balance Sheets at December 31, 2013 and March 31, 2014; |
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(ii) Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2014; |
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(iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2013 and 2014; |
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(iv) Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2014; and |
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(v) Notes to Condensed Consolidated Financial Statements. |
* Filed herewith.
SIGNATURE
Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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CLEAN ENERGY FUELS CORP. | |
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Date: May 8, 2014 |
By: |
/s/ RICHARD R. WHEELER |
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Richard R. Wheeler |
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Chief Financial Officer (Principal financial officer and duly authorized to sign on behalf of the registrant) |