UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended September 30, 2016
	or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period From ________ to ________.

 

Commission File Number 001-36493

 

Dakota Plains Holdings, Inc.

(Exact Name of Registrant as Specified in its Charter)

 

Nevada		20-2543857
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
294 Grove Lane East Wayzata, Minnesota		55391
(Address of principal executive offices)		(Zip Code)

 

(952) 473-9950

(Registrant’s telephone number, including area code)

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

 

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

 

     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 þ No ☐

 

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large Accelerated Filer ☐	Accelerated Filer þ
Non-accelerated Filer ☐ (Do not check if a smaller reporting company)	Smaller Reporting Company þ

 

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

 

As of November 4, 2016, the registrant had 54,930,696 shares of common stock issued and outstanding.

 

 

Item 1.

Financial Statements.

 

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 2016 AND DECEMBER 31, 2015

 

		September 30,				December 31,
		2016				2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	750,403			$	1,821,482
Trade Receivables, Net			6,227,363				8,936,062
Income Tax Receivable			9,648				9,648
Other Current Assets			815,262				439,309
Other Receivables			42,038				42,038
Deferred Tax Asset			157,000				110,000
Total Current Assets			8,001,714				11,358,539
PROPERTY AND EQUIPMENT
Land			3,191,521				3,191,521
Site Development			5,829,639				5,829,639
Terminal			21,437,077				21,437,077
Machinery			18,218,163				18,218,163
Storage Tanks			15,299,541				15,299,541
Other Property and Equipment			3,013,914				3,123,163
Total Property and Equipment			66,989,855				67,099,104
Less – Accumulated Depreciation			14,683,145				10,908,003
Total Property and Equipment, Net			52,306,710				56,191,101
RESTRICTED CASH			—				3,000,593
OTHER ASSETS			512,901				512,901
Total Assets		$	60,821,325			$	71,063,134
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES
Accounts Payable		$	3,679,599			$	4,791,157
Accrued Expenses			9,761,943				4,149,601
Promissory Notes, SunTrust, Net			55,256,632				3,225,000
Operational Override Liability			—				1,879,607
Notes Payable – Vehicles			59,655				57,623
Total Current Liabilities			68,757,829				14,102,988
LONG-TERM LIABILITIES
Promissory Notes, SunTrust, Net			—				51,253,799
Operational Override Liability			7,409,490				32,426,367
Notes Payable – Vehicles			123,270				168,270
Deferred Tax Liability			157,000				110,000
Other Non-Current Liabilities			—				2,917
Total Long-Term Liabilities			7,689,760				83,961,353
Total Liabilities			76,447,589				98,064,341
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS’ DEFICIT
Preferred Stock – Par Value $.001; 10,000,000 Shares Authorized; None Issued or Outstanding			—				—
Common Stock – Par Value $.001; 100,000,000 Shares Authorized; 54,930,696 and 55,175,363 Issued and Outstanding, Respectively			54,930				55,175
Additional Paid-In Capital			8,424,308				8,012,268
Accumulated Deficit			(24,105,502	)			(35,068,650	)
Total Stockholders’ Deficit			(15,626,264	)			(27,001,207	)
Total Liabilities and Stockholders’ Deficit		$	60,821,325			$	71,063,134

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2016				2015				2016				2015
REVENUES
Transloading Revenue		$	1,239,076			$	5,137,567			$	4,808,021			$	19,421,100
Sand Revenue			883,545				983,572				2,124,729				3,422,000
Rental Income			30,900				30,000				92,700				90,000
Other			81,000				—				271,000				1,316,700
Total Revenues			2,234,521				6,151,139				7,296,450				24,249,800
COST OF REVENUES (exclusive of items shown separately below)			741,648				1,303,801				2,630,841				5,594,297
OPERATING EXPENSES
Transloading Operating Expenses			417,707				837,646				3,271,630				3,241,892
General and Administrative Expenses			1,182,681				2,626,713				6,451,999				7,171,360
Depreciation and Amortization			1,260,994				1,256,837				3,786,143				3,505,177
Total Operating Expenses			2,861,382				4,721,196				13,509,772				13,918,429
INCOME (LOSS) FROM OPERATIONS			(1,368,509	)			126,142				(8,844,163	)			4,737,074
OTHER INCOME (EXPENSE)
Interest Expense (Net of Interest Income)			(2,684,713	)			(2,068,419	)			(7,089,173	)			(6,027,201	)
Change in Operational Override			20,131,112				9,987,725				26,896,484				10,469,736
Other Expense			—				—				—				(1,704,618	)
Total Other Income (Expense)			17,446,399				7,919,306				19,807,311				2,737,917
INCOME BEFORE TAXES			16,077,890				8,045,448				10,963,148				7,474,991
INCOME TAX PROVISION			—				29,233,284				—				29,029,784
NET INCOME (LOSS)		$	16,077,890			$	(21,187,836	)		$	10,963,148			$	(21,554,793	)
Net Income (Loss) Per Common Share – Basic and Diluted		$	0.29			$	(0.39	)		$	0.20			$	(0.40	)
Weighted Average Shares Outstanding – Basic			54,803,454				54,317,463				54,767,046				54,196,842
Weighted Average Shares Outstanding – Diluted			55,025,630				54,317,463				55,158,510				54,196,842

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015

 

		Nine Months Ended September 30,
		2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)		$	10,963,148		$	(21,554,793	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Used In Operating Activities:
Depreciation and Amortization			3,786,143			3,505,177
Amortization of Finance Costs			1,157,083			721,023
Loss on Disposal of Property and Equipment			4,301			—
Deferred Income Taxes			—			29,028,000
Decrease in Operational Override Liability			(26,896,484	)		(10,469,736	)
Provision for Losses on Accounts Receivable			1,403,253			—
Amortization of Deferred Rent			(5,250	)		(5,250	)
Non-Cash Compensation			33,681			—
Share-Based Compensation			508,141			1,884,485
Changes in Working Capital and Other Items:
Trade Receivables			1,305,446			(4,332,464	)
Other Receivables			—			(626,239	)
Income Taxes Receivable			—			5,155
Other Current Assets			(375,953	)		(1,309,781	)
Accounts Payable			(731,009	)		(156,000	)
Accrued Expenses			5,060,425			407,402
Restricted Cash			—			(444	)
Net Cash Used In Operating Activities			(3,787,075	)		(2,903,465	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Property and Equipment			(392,783	)		(4,221,839	)
Proceeds from Sale of Property and Equipment			2,500			—
Cash Paid for Deposits			—			(30,000	)
Tenant Improvements Reimbursed			70,000			—
Net Cash Used In Investing Activities			(320,283	)		(4,251,839	)
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Paid for Finance Costs			—			(43,124	)
Payments on Common Shares Surrendered			(96,346	)		(346,937	)
Decrease in Restricted Cash			3,000,593			—
Advances on Promissory Notes, SunTrust			1,500,000			5,000,000
Payments on Promissory Notes, SunTrust			(1,325,000	)		(562,500	)
Proceeds from Notes Payable – Vehicles			—			270,165
Payments on Notes Payable – Vehicles			(42,968	)		(30,278	)
Payments on Operational Override Liability			—			(46,518	)
Net Cash Provided By Financing Activities			3,036,279			4,240,808
NET DECREASE IN CASH AND CASH EQUIVALENTS			(1,071,079	)		(2,914,496	)
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD			1,821,482			4,690,706
CASH AND CASH EQUIVALENTS – END OF PERIOD		$	750,403		$	1,776,210
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest		$	710,351		$	4,320,449
Cash Paid During the Period for Income Taxes		$	—		$	1,784
Non-Cash Financing and Investing Activities:
Property and Equipment Included in Accounts Payable		$	—		$	1,114,772

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

 

Notes to Unaudited Condensed Consolidated Financial Statements 

September 30, 2016

 

1.	Organization and Nature of Business

 

Dakota Plains Holdings, Inc. (the “Company,” “we,” “our,” and words of similar import) is an integrated midstream energy company, principally focused on developing and owning transloading facilities and transloading crude oil and related products within the Williston Basin. 

 

Dakota Plains Transloading, LLC (“DPT”), a wholly owned subsidiary of the Company, was formed in August 2011 primarily to participate in the ownership and operation of a transloading facility near New Town, North Dakota through which producers, transporters and marketers may transload crude oil and related products from and onto the Canadian Pacific Railway.

  

Dakota Plains Marketing, LLC (“DPM”), a wholly owned subsidiary of the Company, was formed in April 2011 primarily to engage in the purchase, sale, storage, transport and marketing of hydrocarbons produced within North Dakota to or from refineries and other end-users or persons. Effective November 30, 2014, the Company ceased the purchase and sale of crude oil.

  

Dakota Plains Sand, LLC (“DPS”), a wholly owned subsidiary of the Company, was formed in May 2014 primarily to participate in the ownership and operation of a sand transloading facility near New Town, North Dakota.

  

The Company is governed by its board of directors and managed by its officers.

 

2.	Summary of Significant Accounting Policies

 

The financial information included herein is unaudited, except for the consolidated balance sheet as of December 31, 2015, which has been derived from the Company’s audited consolidated financial statements for the year ended December 31, 2015. However, such information includes all adjustments (consisting of normal recurring adjustments and changes in accounting principles), which are, in the opinion of management, necessary for a fair presentation of the consolidated financial position, results of operations and cash flows for the interim period. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.

  

Certain information, accounting policies, and footnote disclosures normally included in the consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (the “SEC”). The condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2015.

 

New Accounting Pronouncements

 

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the “FASB”) that are adopted by the Company as of the specified effective date. If not discussed, management believes that the recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

  

In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” The standard’s core principle is that an entity shall recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard generally requires an entity to identify performance obligations in its contracts, estimate the amount of variable consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. The standard will be effective for annual and interim periods beginning after December 15, 2017. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is evaluating the impact of the provisions of ASU 2014-09; however, the standard is not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

 

In November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classifications of Deferred Taxes,” which requires entities with a classified balance sheet to present all deferred tax assets and liabilities as non-current instead of separating them into current and non-current amounts. The standard will be effective for public companies for annual and interim periods beginning after December 15, 2016, with early adoption permitted. The Company is evaluating the impact of the provisions of ASU 2015-17; however, the standard is not expected to have a material effect on the Company’s consolidated balance sheet.

 

 

In February 2016, the FASB issued ASU 2016-02, “Leases,” effective for annual periods and interim periods within those periods beginning after December 15, 2018. The new guidance requires recognition of leased assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company is evaluating the impact of this standard on its consolidated financial statements.

 

In April 2016, the FASB issued ASU 2016-09, “Compensation – Stock Compensation (Topic 718) – Improvements to Employee Share-Based Payment Accounting,” effective for annual periods and interim periods within those periods beginning after December 15, 2016. The new guidance simplifies key components of share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The Company is evaluating the impact of this standard on its consolidated financial statements.

 

In April 2015, the FASB issued ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs.” In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” Under ASU 2015-03, debt issuance costs reported on the consolidated balance sheet will be reflected as a direct deduction from the related debt liability rather than as an asset. While ASU 2015-03 addresses costs related to term debt, ASU 2015-15 provides clarification regarding costs to secure revolving lines of credit, which are, at the outset, not associated with an outstanding borrowing. ASU 2015-15 provides commentary that the SEC staff will not object to an entity deferring and presenting costs associated with line of credit arrangements as an asset and subsequently amortizing them ratably over the term of the revolving debt arrangement. This new guidance was effective beginning January 1, 2016.

 

As of January 1, 2016, the Company adopted ASU 2015-03 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized finance costs associated with its promissory notes, which totaled $2.3 million as of December 31, 2015, from finance costs to a reduction of promissory notes in the long-term liabilities section on the condensed consolidated balance sheet. Adoption of ASU 2015-03 had no impact on the Company’s current and previously reported stockholders’ deficit, results of operations, or cash flows. The December 31, 2015 carrying amounts for the Company’s promissory notes presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-03.

 

Liquidity

 

As of September 30, 2016, the Company had cash and cash equivalents and trade receivables of approximately $7.0 million and accounts payable and accrued expenses of approximately $13.4 million. In addition, it had $56.9 million aggregate principal amount of promissory notes due within the next twelve months.

  

The Company is focused on increasing the throughput and reducing the expenses at the transloading facility, but the decline in crude oil prices and contraction of the price spread between Brent and WTI has materially reduced the revenues that the Company is able to generate from its transloading operations, which, in turn, has negatively affected the Company’s working capital and income (loss) from operations. The potential for future crude oil prices to remain at their current low levels raises substantial doubt about the Company’s ability to meet its obligations when they come due and continue as a going concern. As a result, the Company is considering whether to seek bankruptcy protection.

 

Despite the decline in demand and pricing for its services, the Company continues to pursue several actions including (i) actively engaging in discussions with SunTrust Bank focused on restructuring the existing promissory notes, (ii) minimizing capital expenditures, (iii) reducing general and administrative expenses, (iv) managing the operating costs at the transloading facility and (v) considering bankruptcy protection. The Company has engaged an advisor to assist with recapitalizing or restructuring the Company. These efforts continue in earnest, but the Company can provide no assurance that (x) its efforts will result in sufficient liquidity to satisfy the Company’s obligations as they come due or the ability to continue as a going concern or (y) it will not be forced to seek bankruptcy protection.

 

The accompanying condensed consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with the ability to meet obligations as they come due.

 

Cash and Cash Equivalents

 

The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than $250,000, the Company does not have FDIC coverage on the entire amount of bank deposits. The Company believes this risk of loss is minimal.

 

 

Segments

 

The Company has two principal operating segments, which are the crude oil and frac sand transloading operations. These operating segments were determined based on the nature of the products and services offered. Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision-maker in deciding how to allocate resources and in assessing performance. The Company’s chief executive officer has been identified as the chief operating decision-maker. The Company’s chief operating decision-maker directs the allocation of resources to operating segments based on the profitability and cash flows of each respective segment.

 

The Company has determined that there is only one reportable segment because the two segments discussed above have similar processes and purposes, customers, geographic locations and economic characteristics.

 

Accounts Receivable

 

Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. At September 30, 2016, the allowance for doubtful accounts was $87,000. At December 31, 2015, there was no allowance for doubtful accounts.

 

The Company recorded bad debt expense of $1.4 million during the nine months ended September 30, 2016 that primarily related to the Settlement Agreement (see Note 11, Settlement Agreement). Bad debt expense is accounted for in transloading operating expenses on the statement of operations.

 

Property and Equipment

 

Property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives.

 

Estimated useful lives are as follows:
Site Development	15 years
Terminal	13 years
Machinery	5-13 years
Tanks	13 years
Other Property and Equipment	3-5 years
Land	—

 

Expenditures for leasehold improvements, replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Depreciation expense was $1.3 million and $3.8 million for the three and nine months ended September 30, 2016, respectively, and $1.3 million and $3.5 million for the three and nine months ended September 30, 2015, respectively.

 

Impairment

 

Long-lived assets to be held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of impairment is based upon expectations of undiscounted future cash flows, before interest, of the related asset. If the carrying value of the asset exceeds the undiscounted future cash flows, the impairment would be computed as the difference between the carrying value of the asset and the fair value. There was no impairment identified during the nine months ended September 30, 2016 and 2015.

 

Environmental Accrual

 

Accruals for estimated costs for environmental obligations generally are recognized no later than the date when the Company identifies what cleanup measures, if any, are likely to be required to address the environmental conditions. Included in such obligations are the estimated direct costs to investigate and address the conditions and the associated engineering, legal and consulting costs. In making these estimates, the Company considers information that is currently available, existing technology, enacted laws and regulations, and its estimates of the timing of the required remedial actions. Such accruals are initially measured on a discounted basis — and are adjusted as further information becomes available or circumstances change — and are accreted up over time. The Company has recorded no liability for environmental obligations as of September 30, 2016 and December 31, 2015.

 

Income Taxes

 

Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.

 

 

Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future.  In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations.  In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences.  The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses.

 

The tax effects from an uncertain tax position can be recognized in the consolidated financial statements only if the position is more likely than not to be sustained if it were to be challenged by a taxing authority. The Company has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, the Company has recorded no uncertain tax liabilities in its condensed consolidated balance sheet.

  

For income tax purposes, the Company records Goodwill for the amount that the purchase price paid for an asset or group of assets exceeds the fair value of the assets acquired. Goodwill for income tax purposes is amortized over fifteen years.

 

Stock-Based Compensation

 

The Company records expenses associated with the fair value of stock-based compensation. For fully vested, restricted stock and restricted stock unit grants, the Company calculates the stock-based compensation expense using the estimated fair value on the date of grant. For stock warrants and options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

 

Stock Issuance

 

The Company records the stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable on the related measurement date.

 

Revenue Recognition

 

DPTS and DPTS Sand, LLC recognize revenues when the related services are performed, the sales price is fixed or determinable and collectability is reasonably assured. DPTS records transloading revenues for fuel-related services when the transloading of petroleum-related products is complete and records other revenues related to the Pioneer Terminal as they are earned based on agreements with customers. DPTS Sand, LLC records revenues for sand transloading services when the transloading of sand-related products is complete.

 

Concentration of Risk

 

The three largest customers of DPTS accounted for approximately 100% and 94% of the total revenues from crude oil transloading for the three and nine months ended September 30, 2016, respectively, and 89% and 97% of the total revenues from crude oil transloading for the same periods ended September 30, 2015, respectively.

 

For the three and nine months ended September 30, 2016 and 2015, UNIMIN Corporation was the sole customer of DPTS Sand, LLC and accounted for 100% of total revenues from frac sand transloading.

 

The loss of any one of these customers could have a material adverse impact on the Company.

 

Earnings Per Share

 

Basic earnings per share (“EPS”) excludes dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if common stock equivalents were exercised or converted to common stock. The dilutive effect of common stock equivalents is calculated using the treasury stock method. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and therefore excluded from the computation of diluted EPS. As the Company had losses for the three and nine month periods ended September 30, 2015, the potentially dilutive shares are anti-dilutive and thus excluded from the diluted EPS calculation.

 

 

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2016 and 2015 are as follows:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2016				2015				2016				2015
Weighted Average Common Shares Outstanding - Basic			54,803,454				54,317,463				54,767,046				54,196,842
Plus: Potentially Dilutive Common Shares, Stock Warrants, Restricted Stock, and Restricted Stock Units			222,176				—				391,464				—
Weighted Average Common Shares Outstanding - Diluted			55,025,630				54,317,463				55,158,510				54,196,842
Stock Warrants, Restricted Stock and Restricted Stock Units Excluded from EPS due to the Anti-Dilutive Effect			3,098,531				1,106,567				3,376,002				1,919,784

 

The following warrants, restricted stock and restricted stock units represented potentially dilutive shares as of September 30, 2016 and 2015:

 

		September 30,
		2016				2015
Restricted Stock			127,241				756,149
Restricted Stock Units			456,570				1,624,121
Stock Warrants			2,071,000				2,771,000
Total Potentially Dilutive Shares			2,654,811				5,151,270

 

Fair Value Measures

 

The Company measures fair value using a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, essentially an exit price, based on the highest and best use of the asset or liability. The levels of the fair value hierarchy are as follows:

 

	Level 1 – Quoted market prices in active markets that are accessible at measurement date for identical assets or liabilities;
	Level 2 – Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and
	Level 3 – Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and less observable from objective sources.

 

Use of Estimates

 

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Such significant estimates include recoverability of property and equipment, depreciable lives for property and equipment, fair value of the Operational Override liability, inputs in the valuation of certain equity transactions, and accounting for income taxes. Actual results may differ from those estimates.

 

Principles of Consolidation

 

The accompanying condensed consolidated financial statements include the accounts of Dakota Plains Holdings, Inc. and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

 

3.	Lease Agreement

 

In July 2013, the Company entered into an operating lease agreement with UNIMIN Corporation to lease certain land owned by the Company in New Town, North Dakota. The Company began receiving monthly lease payments of $10,000 in January 2014 and will continue to do so through December 2023, with annual increases of 3% starting January 2016. The lease agreement includes a provision that allows UNIMIN Corporation the option to renew and extend the term of the lease for four additional periods of five years each. In addition, all improvements to the land, including rail tracks and the sand facility, revert to the Company upon termination of the lease.

 

 

4.	Preferred Stock and Common Stock

 

The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001 per share. Shares of preferred stock may be issued in one or more series with rights and restrictions as may be determined by the board of directors of the Company. No shares of preferred stock have been issued as of September 30, 2016 or December 31, 2015.

 

On January 24, 2016, the board of directors of the Company declared a dividend of one right (a “Right”) for each issued and outstanding share of its common stock held by stockholders of record as of February 3, 2016. Each Right entitles the registered holder of the Company’s common stock, subject to the terms of the Rights Agreement dated January 24, 2016 (the “Rights Agreement”), to purchase one one-thousandth of a share of the Company’s Series A Junior Participating Preferred Stock at a price of $0.84, subject to certain adjustments. The description and terms of the Rights are set forth in the Rights Agreement.

 

At any time before a person or group (each such person or group, an “Acquiring Person”) becomes the beneficial owner of 10% or more of the Company’s common stock, the board of directors may redeem the Rights in whole, but not in part, at a price of $0.001 per Right, subject to certain adjustments. The Rights will not be exercisable until after a person or group becomes an Acquiring Person or after the commencement of a tender offer or exchange offer the consummation of which would result in any person becoming an Acquiring Person.

 

During the nine months ended September 30, 2016, a total of 586,042 shares of common stock were surrendered by certain executives and employees of the Company to satisfy tax obligations related to the vesting of restricted stock and restricted stock unit awards. The total value of these shares was $96,346, which was based on the closing market price on the date of surrender.

 

5.	Stock-Based Compensation and Warrants

 

The Company records expenses associated with the fair value of the stock-based compensation. The Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected volatility. Changes in these assumptions can materially affect the fair value estimate.

 

Warrants

 

The following table reflects the status of warrants outstanding at September 30, 2016:

 

		Warrants				Exercise Price				Expiration Date
February 1, 2011			1,000,000			$	0.285			January 31, 2021
November 1, 2012			50,000				3.28			November 1, 2016
November 2, 2012			921,000				4.00			October 31, 2017
January 1, 2013			100,000				3.25			February 15, 2018
Outstanding and Exercisable at September 30, 2016			2,071,000

 

Warrants to purchase 700,000 shares of common stock expired during the nine months ended September 30, 2016.

 

No warrants were forfeited or exercised during the nine months ended September 30, 2016.

 

The Company recorded no general and administrative expense for the three and nine months ended September 30, 2016 and 2015, related to these warrants. There is no further general and administrative expense that will be recognized in future periods related to any warrants that have been granted as of September 30, 2016, as the Company recognized the entire fair value upon vesting. 

 

Restricted Stock and Restricted Stock Unit Awards

 

The outstanding shares of restricted stock and restricted stock units vest over various terms with all shares of restricted stock and restricted stock units vesting no later than March 2018. The Company issued no shares of restricted stock and restricted stock units during the nine months ended September 30, 2016. As of September 30, 2016, there was $0.5 million of total unrecognized compensation expense related to unvested shares of restricted stock and restricted stock units. The Company has assumed a zero percent forfeiture rate on all grants. The Company recorded general and administrative expense related to shares of restricted stock and restricted stock units of $(200,469) and $508,141 for the three and nine months ended September 30, 2016, respectively, and $549,534 and $1,609,485 for the three and nine months ended September 30, 2015, respectively. The amounts recorded in general and administrative expense are net of forfeitures for all periods presented.

 

 

The following table reflects the outstanding restricted stock and restricted stock unit awards and activity related thereto for the nine months ended September 30, 2016:

 

		Nine Months Ended September 30, 2016
		Number of Shares				Weighted Average Grant Price
Restricted Stock and Restricted Stock Unit Awards:
Outstanding at the Beginning of Period			2,446,937			$	1.93
Shares Forfeited			(826,176	)			1.62
Lapse of Restrictions			(1,036,950	)			2.26
Restricted Stock and Restricted Stock Units Outstanding at September 30, 2016			583,811			$	1.77

 

6.	Promissory Notes

 

On December 5, 2014, the Company, DPT, DPM and DPS (collectively, the “Borrowers”) entered into a $57.5 million Revolving Credit and Term Loan Agreement (the “Credit Agreement”) with SunTrust Bank. The Credit Agreement provides for a revolving credit facility of $20 million (the “Revolving Loan Facility”) and one or more tranches of term loans in the aggregate amount of $37.5 million (the “Term Loans” and, together with the Revolving Loan Facility, the “Credit Facility”).

 

On August 6, 2015, the Credit Agreement was amended to revise the definition of continuing director in the Credit Agreement by removing the exclusion for individuals who would otherwise qualify as continuing directors but for the fact that they became directors as a result of an actual or threatened contest for proxies or consents regarding the election or removal of directors.

 

On December 4, 2015, the Borrowers entered into an Amendment No. 2 and Waiver to the Credit Agreement (the “Second Amendment”) to extend the maturity date of the second tranche of Term Loans (“Tranche B”), increase the interest rate margin on Tranche B by 25 basis points and modify the leverage ratio covenant for fiscal quarters ending prior to March 31, 2017. The Second Amendment also waived certain events of default and certain other provisions of the Credit Agreement as further described below. As required by the Second Amendment, the Company paid $950,000 against the principal balance of Tranche A in connection with the release of the previously restricted cash (see Note 11, Settlement Agreement).

 

On May 3, 2016, the Borrowers entered into a Forbearance Agreement (the “Forbearance Agreement”) with SunTrust Bank.  Pursuant to the Forbearance Agreement, from May 3, 2016, until July 25, 2016 (later extended to November 30, 2016 pursuant to Forbearance Amendment No. 3 (as defined below)), SunTrust Bank agreed to forbear from exercising its rights and remedies available under the Credit Agreement but only to the extent that such rights and remedies arise exclusively as a result of the occurrence of certain anticipated events of default. Default interest shall accrue in accordance with the Credit Agreement for any interest paid-in-kind or if any anticipated or other events of default occur. The Forbearance Agreement also enables the Loan Parties to elect during the term of the Forbearance Agreement to make interest payments either in cash or through the payment-in-kind of additional interest and provides additional reporting requirements for the Company. The description and terms of the requirements are set forth in the Forbearance Agreement.

 

On July 5, 2016, the Borrowers entered into Amendment No. 3 to Revolving Credit and Term Loan Agreement, Amendment No. 1 to Forbearance Agreement and One Time Waiver of Revolving Loan Borrowing Requirements (“Amendment No. 3”) to amend (i) the Credit Agreement and (ii) the Forbearance Agreement. Among other things, Amendment No. 3 (a) amended the Credit Agreement to increase the Aggregate Revolving Commitment Amount (as defined in the Credit Agreement) to $20.5 million and (b) amended the Forbearance Agreement to (1) extend the Forbearance Termination Date to August 31, 2016, and (2) require the Borrowers to submit a restructuring plan to SunTrust Bank on or before August 1, 2016, together with a timeline for completing the restructuring plan. The Borrowers have met their obligations regarding the restructuring plan. Also, pursuant to Amendment No. 3, the Lenders made a one-time waiver of certain revolving loan borrowing requirements and funded $0.5 million on July 6, 2016.

 

On August 5, 2016, the Borrowers entered into Amendment No. 4 to Revolving Credit and Term Loan Agreement and One Time Waiver of Revolving Loan Borrowing Requirements (“Amendment No. 4”). Among other things, Amendment No. 4 amended the Credit Agreement to increase the Aggregate Revolving Commitment Amount (as defined in the Credit Agreement) to $21.5 million. Also, pursuant to Amendment No. 4, the Lenders made a one-time waiver of certain revolving loan borrowing requirements and funded $1.0 million on August 5, 2016.

 

On September 1, 2016, the Borrowers entered into Amendment No. 2 to Forbearance Agreement (“Forbearance Amendment No. 2”). Among other things, Forbearance Amendment No. 2 amended the Forbearance Agreement to (1) extend the Forbearance Termination Date to September 15, 2016, (2) require the Borrowers to cooperate with the financial or restructuring advisor appointed by SunTrust Bank, and (3) require the Borrowers to submit an operating plan and budget to SunTrust Bank on or before September 9, 2016. The Borrowers have met their obligations regarding the operating plan and budget.

 

 

On September 20, 2016, the Borrowers entered into Amendment No. 3 to Forbearance Agreement (“Forbearance Amendment No. 3”). Among other things, Forbearance Amendment No. 3 amended the Forbearance Agreement to (1) extend the Forbearance Termination Date to November 30, 2016, (2) require the Borrowers to cooperate with the financial or restructuring advisor appointed by SunTrust Bank, and (3) require the Borrowers to receive one or more executed letters of intent for the purchase of all or substantially all of the Borrowers’ equity or assets (such transaction, a “Potential Transaction”) from potential purchasers with demonstrated ability to close a Potential Transaction (each such Potential Purchaser, a “Potential Purchaser”) on or before October 30, 2016 and enter into a definitive asset purchase agreement for a Potential Transaction on or before November 20, 2016. There was $56.9 million outstanding under the Credit Facility at September 30, 2016.

 

At the Borrowers’ option, borrowings under the Credit Facility may be either (i) “Base Rate” loans, which bear interest at the highest of (a) the rate which the Administrative Agent announces from time to time as its prime lending rate, as in effect from time to time, (b) 1/2 of 1% in excess of the federal funds rate and (c) Adjusted LIBOR (as defined in the Credit Agreement) determined on a daily basis with a one (1) month interest period, plus one percent (1.00%) or (ii) “Eurodollar” loans, which bear interest at Adjusted LIBOR, as determined by reference to the rate for deposits in dollars appearing on the Reuters Screen LIBOR01 Page for the respective interest period.

 

The Credit Agreement contains customary events of default, including nonpayment of principal when due; nonpayment of interest after stated grace period; fees or other amounts after stated grace period; material inaccuracy of representations and warranties; violations of covenants; certain bankruptcies and liquidations; any cross-default to material indebtedness; certain material judgments; certain events related to the Employee Retirement Income Security Act of 1974, as amended, or “ERISA,” actual or asserted invalidity of any guarantee, security document or subordination provision or non-perfection of security interest, and a change in control (as defined in the Credit Agreement). The Second Amendment then waives certain events of default that could be triggered in connection with the Company’s pursuit of remedies against subsidiaries of World Fuel Services Corporation for railcar sublease agreements and unpaid fees and costs for crude oil transloading services. In connection with the pursuit of those remedies and waiver of covenants, the Company has suspended payment of the Operational Override.

 

Pursuant to a Guaranty and Security Agreement, dated December 5, 2014 (the “Guaranty and Security Agreement”), made by the Borrowers, the Company, and certain subsidiaries of the Borrowers in favor of the Administrative Agent, the obligations of the Borrowers are guaranteed by the Company, each other Borrower and the guaranteeing subsidiaries of the Borrowers and are secured by all of the assets of such parties.

 

The Company incurred finance costs of $3,923,409 related to the Credit Agreement. These costs were capitalized and are being amortized over the term of the Credit Agreement. The Company recognized interest expense related to these finance costs of $450,901 and $1,157,083 for the three and nine months ended September 30, 2016, respectively, and $240,341 and $721,023 for the three and nine months ended September 30, 2015, respectively.

 

7.	Income Taxes

 

The income tax provision for the three and nine months ended September 30, 2016 and 2015 consists of the following:

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2016				2015				2016				2015
Current Income Taxes		$	—			$	(5,716	)		$	—			$	1,784
Deferred Income Taxes:
Federal			5,826,000				2,827,000				4,732,000				2,633,000
State			490,000				238,000				397,000				221,000
Valuation Allowance			(6,316,000	)			26,174,000				(5,129,000	)			26,174,000
Total Provision		$	—			$	29,233,284			$	—			$	29,029,784

 

The Company has no liabilities for unrecognized tax benefits.

 

The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within the income tax provision or benefit. For the nine months ended September 30, 2016 and 2015, the Company did not recognize any interest or penalties in the condensed consolidated statements of operations, nor did it have any interest or penalties accrued in the condensed consolidated balance sheets at September 30, 2016 and December 31, 2015.

 

 

In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the most recent three-year period.  Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future crude oil prices.  The markets for crude oil continue to be volatile.  Changes in crude oil prices have a significant impact on the Company’s cash flows.  Prices for crude oil may fluctuate widely in response to relatively minor changes in the supply of and demand for crude oil and a variety of additional factors that are beyond the Company’s control.  Due to these factors, including sustained decreases in crude oil prices, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance.

 

In determining whether to establish a valuation allowance on the Company’s deferred tax assets, management concluded that the objectively verifiable evidence of cumulative negative earnings for the most recent three-year period is difficult to overcome with any form of positive evidence that may exist. Accordingly, the valuation allowance against the Company’s deferred tax asset at September 30, 2016 and December 31, 2015, was $22.3 million and $27.4 million, respectively.

 

The 2015, 2014, and 2013 tax years remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject.

 

8.	Financial Instruments

 

The Company’s financial instruments include cash and cash equivalents, trade receivables, other receivables, accounts payable, and promissory notes. The carrying amount of cash and cash equivalents, trade receivables, other receivables and accounts payable approximate fair value due to their immediate or short-term maturities. The carrying amounts of the Company’s promissory notes outstanding approximate fair value because its current borrowing rates do not materially differ from market rates for similar borrowings.

 

9.	Fair Value

 

The following table summarizes the valuation of financial instruments measured at fair value on a recurring basis in the condensed consolidated balance sheets as of September 30, 2016 and December 31, 2015:

		Quoted Prices In Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
September 30, 2016:
Operational Override Liability – Current Liability		$	—			$	—			$	—
Operational Override Liability – Non-Current Liability			—				—				(7,409,490	)
Total Operational Override Liability		$	—			$	—			$	(7,409,490	)
December 31, 2015:
Operational Override Liability – Current Liability		$	—			$	—			$	(1,879,607	)
Operational Override Liability – Non-Current Liability			—				—				(32,426,367	)
Total Operational Override Liability		$	—			$	—			$	(34,305,974	)

The level 3 liability consists of the liability related to the Operational Override (see Note 10, Membership Purchase Agreement).

 

The following table presents changes for the liability measured at fair value using significant unobservable inputs (Level 3) during the nine months ended September 30, 2016:

 

		Level 3 Financial Liabilities
Balance at December 31, 2015		$	(34,305,974	)
Less: Reduction in Forecasted Volumes			26,896,484
Balance at September 30, 2016		$	(7,409,490	)

 

10.	Membership Purchase Agreement

 

On December 5, 2014, the Company entered into a Membership Interest Purchase Agreement with DPT, DPS, DPM and Petroleum Transport Solutions, LLC (“PTS”). Pursuant to the Membership Interest Purchase Agreement, in exchange for $43.0 million in cash and an Operational Override (as defined below), DPT acquired all of the limited liability company membership interests of DPTS owned by PTS, DPS acquired all of the limited liability company membership interests of DPTS Sand, LLC owned by PTS, and DPM acquired all of the limited liability company membership interests of DPTS Marketing LLC (“DPTSM”) owned by PTS. As a result of the transactions, through ownership of its wholly owned subsidiaries, the Company became the sole member of DPTS, DPTS Sand, LLC and DPTSM.

 

 

In addition to $43.0 million in cash paid to PTS at closing, the Company agreed to pay to PTS an amount equal to $0.225 per barrel of crude oil arriving at the current transloading facility located in New Town, North Dakota, up to a maximum of 80,000 barrels of crude oil per day through December 31, 2026 (the “Operational Override”). In the event such Operational Override payments, in the aggregate, are less than $10.0 million, then the Company is obligated to pay to PTS the difference on or before January 31, 2027.

 

At any time, the Company may pay to PTS an amount equal to the then-present value (using a nine percent (9.0%) discount rate) of the maximum remaining Operational Override payments assuming maximum volume for the period between the pre-payment date and December 31, 2026. If such early payment is made, the Company will have no further obligations related to the Operational Override.

 

Railcar Sublease Agreements

 

Concurrent with the Membership Interest Purchase Agreement, the Company, through DPTSM, entered into five Amended and Restated Railcar Sublease Agreements with Western Petroleum Company (the “Amended Sublease Agreements”). Under the Amended Sublease Agreements, DPTSM subleased a total of 872 railcars from Western Petroleum Company subject to the terms, covenants, provisions, conditions, and agreements contained in the master railcar leases between the original lessors and Western Petroleum Company. The term of the Amended Sublease Agreements is from December 5, 2014 (the “Effective Date”) until the end of the term of the applicable schedule to the respective master railcar lease. The last of the master railcar leases expires in August 2021.

 

Within thirty (30) days after the Effective Date, Western Petroleum Company was required to deliver to DPTSM a certain set of railcars as identified in a schedule included with the Amended Sublease Agreements. The Amended Sublease Agreements are being accounted for as operating leases.

 

DPTSM was to assume the responsibility for any charges incurred between the time of delivery of the railcars to DPTSM under the Amended Sublease Agreements and redelivery of the railcars to Western Petroleum Company at the conclusion of the term, including, but not limited to, charges resulting from demurrage, track storage, switching, detention, freight or empty movements made by the railcars upon each railroad over which the railcars shall move during the term of the Amended Sublease Agreements, as well as any other charges set forth in the master railcar leases.

 

11.	Settlement Agreement

 

On March 15, 2016, the Company and certain of its affiliates (together with the Company, the “DAKP Parties”) executed a Settlement Agreement (the “Settlement Agreement”) with World Fuel Services Corporation (“WFS”) and certain of its affiliates (together with WFS, the “WFS Parties”) resolving several pending issues between the DAKP Parties and the WFS Parties. Pursuant to the Settlement Agreement, the $3.0 million of previously restricted cash was released by WFS. The Company received approximately $1.9 million of the previously restricted cash, and $1.1 million of the previously restricted cash was paid to the WFS Parties as reimbursement for the Company’s portion of the legal and professional costs incurred in connection with the Indemnification and Release Agreement dated December 5, 2014 (the “Indemnification Agreement”). The DAKP Parties also released certain claims against the WFS Parties related to historical railcar storage fees of approximately $1.3 million and rights to indemnification under the Indemnification Agreement. As an additional condition of the Settlement Agreement, the Company also released 89,894 barrels of crude oil it had retained due to non-payment of outstanding railcar storage and crude oil transloading invoices.

 

12.	Commitments and Contingencies

 

Dakota Plains Holdings, Inc., Craig McKenzie and Jim Thornton

 

Ryan R. Gilbertson v. Dakota Plains Holdings, Inc., Craig McKenzie and Jim Thornton

 

On September 23, 2016, Ryan R. Gilbertson commenced a Minnesota state court lawsuit against Dakota Plains Holdings, Inc. and Messrs. McKenzie and Thornton, individually, asserting breach of contract, declaratory judgment, fraud in the inducement, common law fraud and unjust enrichment relating to a note restructuring by the Company in December 2013 and for failing to provide indemnification. On October 4, 2016, Mr. Gilbertson filed a motion for temporary restraining order and temporary injunction as well as a motion for speedy hearing. On October 13, 2016, the Company filed its answer denying Mr. Gilbertson’s allegations and a counterclaim asserting fraud in the inducement and unjust enrichment against Mr. Gilbertson. A hearing on the motion for temporary restraining order and temporary injunction was held on October 18, 2016. On November 1, 2016, the court denied Mr. Gilbertson’s motion for injunctive relief.

 

Dakota Petroleum Transport Solutions, LLC

 

Dakota Petroleum Transport Solutions, LLC v. World Fuel Services, Inc.

 

On October 13, 2015, DPTS commenced a Minnesota state court lawsuit against World Fuel Services, Inc., asserting claims for breach of contract and unjust enrichment relating to unpaid fees and costs for crude oil transloading services (the “Transloading Case”). On November 2, 2015, World Fuel Services, Inc. answered the complaint and filed a motion to consolidate the action with the lawsuit commenced by DPTS Marketing LLC (“DPTSM”) against Western Petroleum Company, which was denied. World Fuel Services, Inc. filed a motion to dismiss for improper venue arguing that the case should be heard in New York. On April 1, 2016, the court granted that motion, finding that the governing contracts required the case to be litigated in New York. It dismissed the case without prejudice. On April 19, 2016, DPTS re-filed the case in the United States District Court for the Southern District of New York. On May 25, 2016, World Fuel Services, Inc. filed an answer to the DPTS complaint, and a pretrial conference is scheduled for November 14, 2016.

 

 

DPTS Marketing LLC

 

DPTS Marketing LLC v. Western Petroleum Company

 

On October 13, 2015, DPTSM commenced a Minnesota state court lawsuit against Western Petroleum Company (“Western Petroleum”), asserting claims for fraud in the inducement, reckless misrepresentation, tortious interference with prospective economic advantage, breach of contract, unjust enrichment, and declaratory judgment relating to railcar sublease agreements signed between the parties. In initial motion practice, Western Petroleum moved to consolidate this case with the Transloading Case. The motion to consolidate was denied on December 29, 2015. Western Petroleum also moved to dismiss DPTSM’s claims, which the court denied on May 16, 2016. Following the court’s order denying Western Petroleum’s motion to dismiss, Western Petroleum filed its answer and a counterclaim for breach of contract against DPTSM. DPTSM filed a reply to that counterclaim denying any liability, and the pleadings were closed on June 15, 2016.  The parties have exchanged some document discovery, but no depositions have taken place.

 

On July 8, 2016, the court entered an order upon the agreement of the parties staying all proceedings until September 6, 2016. By order dated September 13, 2016, the stay was extended through October 21, 2016. On October 25, 2016, the Court again extended the stay through December 2, 2016. On or before that date, the parties are obligated to provide an update about the status of the case, and in the event that the action is still active after that date, the parties will meet and confer, and the court will issue an amended scheduling order based on the parties’ stipulation and on the court’s scheduling requirements.

 

Dakota Plains Holdings, Inc.; Dakota Plains Transloading, LLC; Dakota Plains Sand, LLC; Dakota Plains Marketing, LLC; DPTS Marketing, LLC; Dakota Petroleum Transport Solutions, LLC; and DPTS Sand, LLC

 

World Fuel Services Corporation v. Dakota Plains Holdings, Inc.; Dakota Plains Transloading, LLC; Dakota Plains Sand, LLC; Dakota Plains Marketing, LLC; DPTS Marketing, LLC; Dakota Petroleum Transport Solutions, LLC; and DPTS Sand, LLC

 

On April 13, 2016, World Fuel Services Corporation (“WFS”) filed an action in the United States District Court for the Southern District of New York against the above-referenced Dakota Plains entities (the “DAKP Parties”). The suit alleges claims for breach of a Guaranty Agreement and a Joinder Agreement. WFS seeks damages of at least $2,025,690 for the alleged failure to make an “operational override” payment, and an additional netted amount of $3,492,747 for the alleged failure to make railcar sublease payments. On May 25, 2016, the DAKP Parties filed a motion to dismiss the complaint; WFS has until November 7, 2016 to file its opposition to the motion to dismiss. A pretrial conference is scheduled for November 18, 2016.

 

13.	Subsequent Events

 

The Borrowers entered into Amendment No. 4 to Forbearance Agreement ("Forbearance Amendment No. 4") effective as of October 31, 2016. Among other things, Forbearance Amendment No. 4 amended the Forbearance Agreement to (1) extend the Forbearance Termination Date to January 3, 2017, and (2) require the Borrowers to receive one or more executed letters of intent for the purchase of all or substantially all of the Borrowers' equity or assets (such transaction, a "Potential Transaction") from potential purchasers with demonstrated ability to close a Potential Transaction (each such Potential Purchaser, a "Potential Purchaser") on or before November 18, 2016 and enter into a definitive asset purchase agreement for a Potential Transaction on or before December 13, 2016.

 

 

Item 2.

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

 

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related notes thereto included in this quarterly report and in our audited consolidated financial statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed with the United States Securities and Exchange Commission (SEC) and subsequent reports on Form 10-Q and Form 8-K, including amendments thereto.

 

Forward-Looking Statements

 

This report contains “forward-looking statements” within the meaning of the federal securities laws. Statements included in this quarterly report that are not historical facts (including any statements regarding plans and objectives of management for future operations or economic performance, or assumptions), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “anticipate,” “continue,” “believe,” “estimate,” “expect,” “hope,” “intend,” “may,” “potential,” “should,” “target,” “will,” or other similar words.

 

Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of the filing of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 and in “Part II, Item 1A. Risk Factors” of this filing.

 

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

 

Overview

 

Dakota Plains Holdings, Inc. (“we,” “us,” “our,” or “our Company”) is an integrated midstream energy company operating the Pioneer Terminal, with services that include outbound crude oil storage, logistics and rail transportation and inbound fracturing (“frac”) sand logistics. The Pioneer Terminal is located in Mountrail County, North Dakota, where it is uniquely positioned to exploit opportunities in the heart of the Bakken and Three Forks plays of the Williston Basin. The Williston Basin of North Dakota and Montana is the largest onshore crude oil production source in North America where the current lack of available pipeline capacity has provided a surplus of crude oil available for the core business of our Company. Our frac sand business provides services for UNIMIN Corporation (“UNIMIN”), a leading producer of quartz proppant and one of the largest suppliers of frac sand to exploration and production operating companies in the Williston Basin. Our Company is headquartered in Wayzata, Minnesota.

 

Because current crude oil production in North Dakota exceeds existing pipeline takeaway capacity, rail transloading facilities are necessary to efficiently capture the demand for transportation of supplies and products to and from the oil fields. As such, we adopted a crude by rail model and built the Pioneer Terminal, which has given us the ability to efficiently facilitate the loading and transporting of crude oil and related products to and from the Bakken oil fields. According to the North Dakota Pipeline Authority, as of August 2016, the crude by rail industry was transporting approximately 29% of the total crude oil takeaway, which was down from 47% as of August 2015.

 

In order to supplement our crude by rail business model and diversify our product mix, we expanded our service offerings in June 2014 to include inbound frac sand logistics. The U.S. Energy Information Administration (the “EIA”) stated in its March 15, 2016 edition of Today in Energy that it estimates about half of the total U.S. crude oil production comes from hydraulically fractured wells, “In 2000, approximately 23,000 hydraulically fractured wells produced 102,000 barrels per day (b/d) of oil in the United States, making up less than 2% of the national total. By 2015, the number of hydraulically fractured wells grew to an estimated 300,000, and production from those wells had grown to more than 4.3 million b/d, making up about 50% of the total oil output of the United States.” The combination of this rapidly growing market, the optimal location of the Pioneer Terminal, and UNIMIN’s expertise have allowed us to quickly become a leading provider of frac sand transloading services within the state of North Dakota.

 

 

New Town Facility

 

Our facility in New Town, North Dakota is centrally located in the heart of the Parshall Oil Field in Mountrail County, North Dakota. New Town is located at the entrance to a large peninsula, and our facility straddles the only road providing access to and from the peninsula. One of the geographic advantages to our facility is the Four Bears Bridge, which represents the only means to cross Lake Sakakawea for approximately 90 miles in either direction. The peninsula is approximately 150 square miles of land with 168 spacing units due to their water access to Lake Sakakawea. One spacing unit is the equivalent of one square mile and has the expectation for 12 to 16 wells. 168 spacing units equates to over 2,000 wells.

 

Some crude oil well operators continue to haul crude oil via semi-truck as far as 100 miles one way from New Town to various crude by rail facilities to load crude oil produced from wells located in the Parshall Oil Field onto railway systems at significant additional cost compared to the services offered by our facility. In August 2016, North Dakota produced 1.0 million barrels of crude oil per day. We estimate crude oil production within approximately a 75-mile radius of our facility to represent 80% of the volume, or approximately 800,000 barrels of crude oil per day.

 

In 2015, our facility experienced its highest daily average throughput to date of approximately 46,000 barrels of crude oil transloaded compared to a daily average throughput of approximately 38,800 barrels of crude oil in 2014 and approximately 23,600 barrels of crude oil in 2013. The year-over-year increases in barrels of crude oil transloaded can be explained by not only the geographical location of our facility but also its state-of-the-art design that includes the following features:

 

·

Private spur connecting the property to the Canadian Pacific Railway;

 

·

Approximately 192-acre site with two 8,300-foot loop tracks each capable of 120 car unit trains, 270,000 barrels of crude oil storage, a high-speed loading facility that can accommodate 10 rail cars simultaneously, two active gathering system pipelines and transfer stations to receive crude oil from 10 trucks simultaneously;

 

·

Fire suppression system, spill remediation and backup power generation solutions;

 

·

Automated terminal metering and accounting systems;

 

·

Four fully operational ladder tracks that can be utilized for inbound delivery and storage for commodities such as frac sand, aggregate, chemicals, diesel and pipe;

 

·

Fully enclosed electrical system between the existing tracks to provide maximum flexibility when powering transloading equipment; and

 

·

72 acres of industrial zoned land within the double loop tracks that provide the option to add storage or various industrial uses to the facility at any time.

 

We completed construction of a third 90,000-barrel crude oil storage tank in July 2015. The facility also can accommodate significant storage of tanker-trucks as well as drilling and other crude oil exploration equipment.

 

Current Business Drivers

 

As reported in the Annual Energy Outlook 2016 dated August 2016 (“AEO2016”), the EIA forecasts total U.S. crude oil production to reach its peak around the year 2040: “Total U.S. oil production in the AEO2016 Reference case falls from 9.4 million barrels per day (b/d) in 2015 to 8.6 million b/d in 2017. After 2017, the total production grows to 11.3 million b/d in 2040 as real (2016 dollars) crude oil prices recover from an annual average of less than $50/barrel (b) in 2017 to more than $130/b in 2040. The Lower 48 states lead the increase in crude oil production, which results largely from higher oil prices, continued advances in industry practices, and further development of technologies that reduce costs and allow for increased recovery of tight oil resources.” They go on to state, “The Bakken, Western Gulf Basin (including the Eagle Ford play), and Permian Basin lead the continued development of tight oil resources in the Lower 48 states in the Reference case. With the recent decline in oil prices, tight oil production shows the largest reduction, from 4.9 million b/d in 2015 to 4.2 million b/d in 2017, before increasing to 7.1 million b/d in 2040. After 2017, higher oil prices, as well as ongoing exploration, appraisal, and development programs that expand operator knowledge about producing reservoirs, could result in the identification of additional tight oil resources and the development of technologies that reduce costs and increase oil recovery.”

 

 

Throughout the year, the EIA monitors price and inventory levels as well as various global economic indicators and revises the forecast as necessary. In their most recent publication of the Short-Term Energy Outlook dated October 2016, the EIA maintained their AEO2016 U.S. crude oil production levels but highlighted the improved financial conditions of certain U.S. onshore oil producers: “Second quarter 2016 financial results for 46 publicly traded U.S. onshore oil producers showed improved financial conditions compared with the first quarter. Cash from operations increased from the first quarter to the second quarter of 2016, reflecting higher crude oil prices. Many companies improved operating efficiency, reduced costs, and improved their balance sheets as crude oil prices stabilized. Higher prices also provided the opportunity for these companies to hedge future production at more favorable price levels, with recent price increases likely encouraging additional hedging activity. Capital expenditures at these companies also rose in the second quarter from the first quarter, the only quarter-over-quarter increase since 2014. Even last year, when higher oil prices in the spring and summer also led to increased cash flow, these companies were still reducing capital expenditures. Rising active rig counts implied renewed drilling across U.S. basins, and several merger and acquisition announcements suggest that some companies were actively expanding investment budgets in the second quarter of this year.” Even though the EIA is forecasting short-term production declines, they expect production to begin to rise in late 2017 due to rig and well productivity improvements, forecasted crude oil price increases, and declining drilling and completion costs.

 

According to the NDIC Department of Mineral Resources October edition of the Director’s Cut publication, there were 33 active drilling rigs in North Dakota as of October 13, 2016, down from the all-time high of 218 in May 2012. The publication goes on to support the EIA’s recent assertions by stating, “Operators remain committed to running the minimum number of rigs while oil prices remain below $60/barrel WTI. The number of well completions rose from 44 in July to 59 (preliminary) in August. Oil price weakness is the primary reason for the slow-down and is now anticipated to last into at least the fourth quarter of this year and perhaps into the second quarter of 2017.” The publication adds, “Operators have a significant permit inventory should a return to the drilling price point occur in the next 12 months.”

 

The price at which crude oil trades in the open market has experienced significant volatility and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:

 

·

domestic and foreign demand for crude oil by both refineries and end users;

 

·

the introduction of alternative forms of fuel to replace or compete with crude oil;

 

·

domestic and foreign reserves and supply of crude oil;

 

·

competitive measures implemented by our competitors and domestic and foreign governmental bodies;

 

·

political climates in nations that traditionally produce and export significant quantities of crude oil (including military and other conflicts in the Middle East and surrounding geographic region) and regulations and tariffs imposed by exporting and importing nations;

 

·

weather conditions; and

 

·

domestic and foreign economic volatility and stability.

 

As of August 2016, North Dakota ranked second in the United States behind only Texas in terms of crude oil production, but the lack of capacity within the trunk pipelines and lack of geographical flexibility to serve many potential markets is driving competition within the crude oil transloading and storage industry. According to the North Dakota Pipeline Authority, as of August 2016, the crude by rail industry was transporting approximately 29% of the total crude oil takeaway, which was down from 47% as of August 2015. This competition is expected to become increasingly intense as production continues to decrease, margins tighten, and new pipelines are approved. On July 26, 2016, the Army Corps of Engineers gave their final approval to the Dakota Access pipeline, which will stretch more than 1,150 miles from North Dakota through South Dakota and Iowa and into Illinois where it will terminate near Patoka, Illinois. The pipeline will transport approximately 450,000 barrels of crude oil per day and have a maximum capacity of approximately 570,000 barrels of crude oil per day. It is expected to be operational by the end of 2016, which will result in the total pipeline takeaway capacity equaling or exceeding current crude oil production levels in North Dakota. Even if this does occur, railroads provide much more than just transportation capacity. They allow energy market participants to quickly shift deliveries to different markets, enabling producers to offer the most attractive price when they sell their product to the market. The rail industry has recognized this competitive advantage, as evidenced by the expenditure of billions of dollars on rail infrastructure and equipment in recent years.

 

 

Results of Operations

 

The following tables illustrate the statements of operations by operating segment for the three and nine months ended September 30, 2016 and 2015:

 

	September 30, 2016
			Dakota Plains Holdings, Inc.				Dakota Petroleum Transport Solutions, LLC				DPTS Sand, LLC				Eliminations				Consolidated
Three Months Ended:
REVENUES
Transloading Revenue		$	—			$	1,239,076			$	—			$	—			$	1,239,076
Sand Revenue			—				—				883,545				—				883,545
Rental Income			151,695				—				—				(120,795	)			30,900
Other			—				81,000				—				—				81,000
Total Revenues			151,695				1,320,076				883,545				(120,795	)			2,234,521
COST OF REVENUES (exclusive of items shown separately below)			—				782,770				73,364				(114,486	)			741,648
OPERATING EXPENSES
Transloading Operating Expenses			—				424,016				—				(6,309	)			417,707
General and Administrative Expenses			1,182,681				—				—				—				1,182,681
Depreciation and Amortization			52,013				1,208,981				—				—				1,260,994
Total Operating Expenses			1,234,694				1,632,997				—				(6,309	)			2,861,382
INCOME (LOSS) FROM OPERATIONS		$	(1,082,999	)		$	(1,095,691	)		$	810,181			$	—			$	(1,368,509	)
Nine Months Ended:
REVENUES
Transloading Revenue		$	—			$	4,808,021			$	—			$	—			$	4,808,021
Sand Revenue			—				—				2,124,729				—				2,124,729
Rental Income			455,085				—				—				(362,385	)			92,700
Other			—				271,000				—				—				271,000
Total Revenues			455,085				5,079,021				2,124,729				(362,385	)			7,296,450
COST OF REVENUES (exclusive of items shown separately below)			—				2,721,277				253,022				(343,458	)			2,630,841
OPERATING EXPENSES
Transloading Operating Expenses			—				3,285,774				4,783				(18,927	)			3,271,630
General and Administrative Expenses			6,451,999				—				—				—				6,451,999
Depreciation and Amortization			156,656				3,629,487				—				—				3,786,143
Total Operating Expenses			6,608,655				6,915,261				4,783				(18,927	)			13,509,772
INCOME (LOSS) FROM OPERATIONS		$	(6,153,570	)		$	(4,557,517	)		$	1,866,824			$	—			$	(8,844,163	)

 

 

	September 30, 2015
			Dakota Plains Holdings, Inc.				Dakota Petroleum Transport Solutions, LLC				DPTS Sand, LLC				Eliminations				Consolidated
Three Months Ended:
REVENUES
Transloading Revenue		$	—			$	5,137,567			$	—			$	—			$	5,137,567
Sand Revenue			—				—				983,572				—				983,572
Rental Income			150,795				—				—				(120,795	)			30,000
Total Revenues			150,795				5,137,567				983,572				(120,795	)			6,151,139
COST OF REVENUES (exclusive of items shown separately below)			—				1,287,174				131,113				(114,486	)			1,303,801
OPERATING EXPENSES
Transloading Operating Expenses			—				843,399				556				(6,309	)			837,646
General and Administrative Expenses			2,626,713				—				—				—				2,626,713
Depreciation and Amortization			50,820				1,206,017				—				—				1,256,837
Total Operating Expenses			2,677,533				2,049,416				556				(6,309	)			4,721,196
INCOME (LOSS) FROM OPERATIONS		$	(2,526,738)			$	1,800,977			$	851,903			$	—			$	126,142
Nine Months Ended:
REVENUES
Transloading Revenue		$	—			$	19,421,100			$	—			$	—			$	19,421,100
Sand Revenue			—				—				3,422,000				—				3,422,000
Rental Income			452,385				—				—				(362,385	)			90,000
Other			—				1,316,700				—				—				1,316,700
Total Revenues			452,385				20,737,800				3,422,000				(362,385	)			24,249,800
COST OF REVENUES (exclusive of items shown separately below)			—				4,866,851				1,070,904				(343,458	)			5,594,297
OPERATING EXPENSES
Transloading Operating Expenses			—				3,257,050				3,769				(18,927	)			3,241,892
General and Administrative Expenses			7,171,360				—				—				—				7,171,360
Depreciation and Amortization			150,445				3,354,732				—				—				3,505,177
Total Operating Expenses			7,321,805				6,611,782				3,769				(18,927	)			13,918,429
INCOME (LOSS) FROM OPERATIONS		$	(6,869,420)			$	9,259,167			$	2,347,327			$	—			$	4,737,074

 

Three Months Ended September 30, 2016 vs. Three Months Ended September 30, 2015

 

We experienced net income of $16.1 million for the three months ended September 30, 2016, compared to a net loss of $21.2 million for the three months ended September 30, 2015. The net income for the three months ended September 30, 2016 was driven by a $20.1 million gain realized from a revaluation of the Operational Override liability due to a material change in the estimated future volumes used to calculate its fair value and a $1.9 million reduction in total operating expenses due to recently implemented cost management initiatives. These gains were partially offset by the loss from operations resulting from decreases in both total barrels of crude oil transloaded and price per barrel as well as the interest expense recognized on the outstanding promissory notes. The net loss for the three months ended September 30, 2015 was driven by the valuation allowance on our deferred tax assets of approximately $26.2 million, which was partially offset by the gain realized from a revaluation of the Operational Override liability due to a decrease in the estimated future volume used to calculate the fair value of the liability and improved operating efficiencies in the crude oil and frac sand transloading entities.

 

Dakota Petroleum Transport Solutions, LLC (“DPTS”) experienced a net loss of $1.1 million for the three months ended September 30, 2016, compared to net income of $1.8 million for the same period of 2015. The decrease in net income was driven by an 76% decrease in revenue from crude oil transloading but was partially offset by a 39% decrease in cost of revenue. Total revenue from crude oil transloading for the three months ended September 30, 2016 was $1.2 million, compared to $5.1 million for the same period of 2015. The decrease in revenue was driven by continued downward pressure on the domestic crude oil market leading to depressed crude oil prices, a decrease in total crude oil production in North Dakota, and a decrease in the percent of total production being moved via rail. The aforementioned factors lead to a 24% decrease in revenue per barrel transloaded and a 68% decrease in volume as DPTS transloaded 1.5 million barrels of crude oil (16,000 barrels per day) during the three months ended September 30, 2016 compared to 4.6 million barrels of crude oil (50,000 barrels per day) during the same period of 2015. Total cost of revenue related to crude oil transloading for the three months ended September 30, 2016 was $0.8 million, compared to $1.3 million for the same period of 2015. The 39% decrease was the result of transloading fewer barrels of crude oil and cost management initiatives such as bringing the transloading services in-house.

 

The net income of DPTS Sand, LLC for the three months ended September 30, 2016 was $0.8 million, compared to $0.9 million for the same period of 2015. Revenue from frac sand transloading was $0.9 million for the three months ended September 30, 2016, compared to $1.0 million for the same period of 2015. Cost of revenue related to frac sand transloading was $0.1 million for the three months ended September 30, 2016 and 2015. The decrease in revenue was driven by a 21% decrease in volume as DPTS Sand, LLC transloaded 110,000 short tons of frac sand during the three months ended September 30, 2016 compared, to 141,000 short tons of frac sand during the same period of 2015.

 

 

Effective November 30, 2014, we acquired the remaining ownership interest in DPTSM from Petroleum Transport Solutions, LLC (“PTS”) and immediately discontinued the purchase and sale of crude oil. We initially planned to maintain the fleet of rail cars with the intent to sublease and/or utilize them in our operations if the need arose but have since returned the rail cars to Western Petroleum Company (“Western Petroleum”) and commenced a lawsuit against Western Petroleum, asserting claims for fraud in the inducement, reckless misrepresentation, tortious interference with prospective economic advantage, breach of contract, unjust enrichment, and declaratory judgment relating to railcar sublease agreements signed between the parties (see Note 12 to the Financial Statements).

 

Interest expense was $2.7 million for the three months ended September 30, 2016, compared to $2.1 million for the same period of 2015. The increase was driven by an increase in the amortization of finance costs resulting from the refinancing of debt with SunTrust Bank and the increased interest expense on the outstanding promissory notes due to additional borrowings and an increase in interest rates including the addition of default and paid-in-kind interest. The increases were partially offset by the decrease in interest expense related to the Operational Override liability resulting from the reductions in fair value recorded in the three months ended September 30, 2015 and the three months ended March 31, 2016.

 

The change in Operational Override liability was $20.1 million for the three months ended September 30, 2016, compared to $10.0 million for the same period of 2015. The increase in the change in Operational Override liability was due to an additional reduction in the long-term estimated daily crude oil transloading volume used to calculate the fair value of the liability recognized during the three months ended September 30, 2016. As reported in the Annual Energy Outlook 2016 dated August 2016 (“AEO2016”), the U.S. Energy Information Administration (the “EIA”) forecasts total U.S. crude oil production to decline from 9.4 million barrels per day in 2015 to 8.6 million barrels per day in 2017. The publication goes on to state, “The Bakken, Western Gulf Basin (including the Eagle Ford play), and Permian Basin lead the continued development of tight oil resources in the Lower 48 states in the Reference case. With the recent decline in oil prices, tight oil production shows the largest reduction, from 4.9 million b/d in 2015 to 4.2 million b/d in 2017.” The significant decline in our crude oil transloading volume during the second and third quarters of 2016 supports these sentiments as we transloaded 1.3 million barrels of crude oil (14,000 barrels per day) during the three months ended June 30, 2016 and 1.5 million barrels of crude oil (16,000 barrels per day) during the three months ended September 30, 2016 compared to 4.4 million barrels of crude oil (47,000 barrels per day) during the three months ended December 31, 2015 and 2.7 million barrels of crude oil (30,000 barrels per day) during the three months ended March 31, 2016. As a result of the continued downward pressure on the crude oil market from macro-economic factors and the material decrease in the actual barrels transloaded to date in 2016, we adjusted our long-term volume forecast during the third quarter of 2016. The change in Operational Override liability for the three months ended September 30, 2015 was $10.0 million, which also represented a decrease in the long-term estimated daily crude oil transloading volume used to calculate the fair value of the liability.

 

We did not have a provision for income taxes for the three months ended September 30, 2016 due to the valuation allowance placed on the net deferred tax asset in 2015. The valuation allowance also caused the effective tax rate for the three months ended September 30, 2016 to be different than the federal statutory rate of 35%.  We had a provision for income taxes of $29.2 million and an effective tax rate of 363.4% for the three months ended September 30, 2015, which differed from federal statutory tax rate of 35% due to the valuation allowance, permanent differences and state tax rates.

 

Nine Months Ended September 30, 2016 vs. Nine Months Ended September 30, 2015

 

We experienced net income of $11.0 million for the nine months ended September 30, 2016, compared to a net loss of $21.6 million for the nine months ended September 30, 2015. The net income for the nine months ended September 30, 2016 was primarily driven by a $26.9 million gain realized from the revaluation of the Operational Override liability due to a material change in the estimated future volumes used to calculate its fair value and a $1.9 million reduction in total operating expenses due to recently implemented cost management initiatives. The aforementioned gain and cost reductions were partially offset by the loss from operations resulting from decreases in both total barrels of crude oil and total tons of frac sand transloaded, a decrease in the price per barrel of crude oil transloaded, an increase the interest expense recognized on the outstanding promissory notes, and the recognition of $1.3 million of bad debt expense and $1.1 million in legal fees related to the Settlement Agreement (see Note 11 to the Financial Statements). The net loss for the nine months ended September 30, 2015 was driven by the valuation allowance on our deferred tax assets of approximately $26.2 million, which was partially offset by improved operating efficiencies in the crude oil and frac sand transloading entities and the gain realized from a revaluation of the Operational Override liability due to a material change in the estimated future cash outflows used to calculate the fair value of the liability.

 

 

Dakota Petroleum Transport Solutions, LLC (“DPTS”) experienced a net loss of $4.6 million for the nine months ended September 30, 2016, compared to net income of $9.3 million for the same period of 2015. The decrease in net income was driven by a 76% decrease in revenue from crude oil transloading and the recognition of $1.3 million of bad debt expense related to the Settlement Agreement but was partially offset by a 44% decrease in cost of revenue. Total revenue from crude oil transloading for the nine months ended September 30, 2016 was $4.8 million, compared to $19.4 million for the same period of 2015. The decrease in revenue was driven by continued downward pressure on the domestic crude oil market leading to depressed crude oil prices, a decrease in total crude oil production in North Dakota, and a decrease in the percent of total crude oil production being moved via rail. The aforementioned factors lead to a 44% decrease in revenue per barrel transloaded and a 56% decrease in volume as DPTS transloaded 5.5 million barrels of crude oil (20,000 barrels per day) during the nine months ended September 30, 2016, compared to 12.4 million barrels of crude oil (45,000 barrels per day) during the same period of 2015. Total cost of revenue related to crude oil transloading for the nine months ended September 30, 2016 was $2.7 million, compared to $4.9 million for the same period of 2015. The 44% decrease resulted from transloading fewer barrels of crude oil during the nine months ended September 30, 2016 and bringing the transloading services in-house during the second quarter of 2015.

 

The net income of DPTS Sand, LLC for the nine months ended September 30, 2016 was $1.9 million, compared to $2.3 million for the same period of 2015. Revenue from frac sand transloading was $2.1 million for the nine months ended September 30, 2016, compared to $3.4 million for the same period of 2015. Cost of revenue related to frac sand transloading was $0.3 million for the nine months ended September 30, 2016, compared to $1.1 million for the same period of 2015. The decreases in both revenue and cost of revenue were primarily driven by a 40% decrease in volume as DPTS Sand, LLC transloaded 266,000 short tons of frac sand during the nine months ended September 30, 2016, compared to 446,000 short tons of frac sand during the same period of 2015. The decrease in cost of revenue was also driven by bringing the transloading services in-house during the second quarter of 2015.

 

As previously noted, effective November 30, 2014, we acquired the remaining ownership interest in DPTSM from PTS and immediately discontinued the purchase and sale of crude oil. We initially planned to maintain the fleet of rail cars with the intent to sublease and/or utilize them in our operations if the need arose but have since returned the rail cars to Western Petroleum and commenced a lawsuit against Western Petroleum, asserting claims for fraud in the inducement, reckless misrepresentation, tortious interference with prospective economic advantage, breach of contract, unjust enrichment, and declaratory judgment relating to railcar sublease agreements signed between the parties (see Note 12 to the Financial Statements). 

 

Interest expense was $7.1 million for the nine months ended September 30, 2016, compared to $6.0 million for the same period of 2015. The increase was driven by an increase in the amortization of finance costs resulting from the refinancing of debt with SunTrust Bank and the increased interest expense on the outstanding promissory notes due to additional borrowings and an increase in interest rates including the addition of default and paid-in-kind interest. The increases were partially offset by the decrease in interest expense related to the Operational Override liability resulting from the reductions in fair value recorded in the third quarter of 2015 and the first quarter of 2016.

 

The change in Operational Override liability for the nine months ended September 30, 2016 was $26.9 million, compared to $10.5 million for the same period of 2015. The increase in the change in Operational Override liability was due to additional reductions in the long-term estimated daily crude oil transloading volume used to calculate the fair value of the liability recognized during the first and third quarters of 2016. As reported in the Annual Energy Outlook 2016 dated August 2016 (“AEO2016”), the U.S. Energy Information Administration (the “EIA”) forecasts total U.S. crude oil production to decline from 9.4 million barrels per day in 2015 to 8.6 million barrels per day in 2017. The publication goes on to state, “The Bakken, Western Gulf Basin (including the Eagle Ford play), and Permian Basin lead the continued development of tight oil resources in the Lower 48 states in the Reference case. With the recent decline in oil prices, tight oil production shows the largest reduction, from 4.9 million b/d in 2015 to 4.2 million b/d in 2017.” The significant decline in our crude oil transloading volume in 2016 supports these sentiments as we transloaded an average of 30,000 barrels per day during the three months ended March 31, 2016, 14,000 barrels per day during the three months ended June 30, 2016 and 16,000 barrels per day during the three months ended September 30, 2016 compared to an average transloading volume of 46,000 barrels per day in 2015. As a result of the continued downward pressure on the crude oil market from macro-economic factors and the material decrease in the actual barrels transloaded to date in 2016, we adjusted our long-term volume forecast during the third quarter of 2016.

 

We did not have a provision for income taxes for the nine months ended September 30, 2016 due to the valuation allowance placed on the net deferred tax asset in 2015. The valuation allowance also caused the effective tax rate for the nine months ended September 30, 2016 to be different than the federal statutory rate of 35%. We had a provision for income taxes of $29.0 million and an effective tax rate of 388.4% for the nine months ended September 30, 2015, which differed from federal statutory tax rate of 35% due to the valuation allowance, permanent differences and state tax rates.

 

 

Non-GAAP Financial Measures

 

We define Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation and amortization, (iv) non-cash expenses relating to share-based amounts recognized under ASC Topic 718, and (v) non-cash changes related to the Operational Override liability. Adjusted EBITDA was $(0.3) million and $(4.5) million for the three and nine months ended September 30, 2016, respectively, compared to $2.0 million and $8.4 million for the three and nine months ended September 30, 2015, respectively. The decrease in 2016 Adjusted EBITDA was primarily driven by the loss from operations for the nine months ended September 30, 2016 resulting from decreases in both total barrels of crude oil and total short tons of frac sand transloaded, a decrease in the price per barrel of crude oil transloaded, the recognition of $1.4 million of bad debt expense, and a $1.1 million increase in legal fees primarily related to the now completed, and previously disclosed, Lac Mégantic litigation.

 

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2016				2015				2016				2015
Net Income (Loss)		$	16,077,890			$	(21,187,836	)		$	10,963,148			$	(21,554,793	)
Add Back:
Income Tax Provision			—				29,233,284				—				29,029,784
Depreciation and Amortization			1,260,994				1,256,837				3,786,143				3,505,177
Share Based Compensation			(200,469	)			624,534				508,141				1,884,485
Interest Expense			2,684,713				2,068,419				7,089,173				6,027,201
Change in Operational Override Liability			(20,131,112	)			(9,987,725	)			(26,896,484	)			(10,469,736	)
Adjusted EBITDA		$	(307,984	)		$	2,007,513			$	(4,549,879	)		$	8,422,118

 

Adjusted EBITDA is a non-GAAP financial measure as defined by the SEC and is derived from net income (loss), which is the most directly comparable financial measure calculated in accordance with GAAP. We believe presenting Adjusted EBITDA provides useful information to our investors in order to gain an overall understanding of our current financial performance. Specifically, management believes the non-GAAP financial measure included herein provides useful information to investors by excluding certain expenses that are not indicative of our operating results. In addition, certain covenants in the Credit Agreement require the use of Adjusted EBITDA. Therefore, management uses Adjusted EBITDA for budgeting and forecasting as well as subsequently measuring its performance and believes it provides investors with a financial measure that most closely aligns with its internal measurement processes.

 

Liquidity and Capital Resources

 

Our principal sources of liquidity are cash and cash equivalents, a $59.0 million revolving credit and term loan agreement with SunTrust Bank (“SunTrust”), and our additional financing capacity, which is dependent on capital and credit market conditions and our financial performance. Our cash and cash equivalents were approximately $0.8 million at September 30, 2016. The cash for the nine months ended September 30, 2016 was primarily generated by the results of operations of DPTS Sand, LLC, additional borrowings on the revolving credit and term loan agreement, and the release and receipt of a portion of our previously restricted cash. The cash inflows were offset by the DPTS operating loss and our payments related to the principal and interest on the SunTrust debt and general and administrative expenses.

 

We had no available borrowings under the Revolving Credit Facility with SunTrust at September 30, 2016. We are focused on increasing the throughput and reducing the expenses at the transloading facility, but the decline in crude oil prices and contraction of the price spread between Brent and WTI has materially reduced the revenues that we are able to generate from our transloading operations, which, in turn, has negatively affected our working capital and income (loss) from operations. The potential for future crude oil prices to remain at their current low levels raises substantial doubt about our ability to meet our obligations when they come due and continue as a going concern. As a result, we are considering whether to seek bankruptcy protection.

 

As stated above, the EIA recently reduced their domestic crude oil production forecast. Despite the decline in demand and pricing for its services, we continue to pursue a number of actions including (i) actively engaging in discussions with SunTrust Bank focused on restructuring the existing promissory notes, (ii) minimizing capital expenditures, (iii) reducing general and administrative expenses, (iv) managing the operating costs at the transloading facility and (v) considering bankruptcy protection. We have engaged an advisor to assist with recapitalizing or restructuring our Company. These efforts continue in earnest, but we can provide no assurance that (x) our efforts will result in sufficient liquidity to satisfy our obligations as they come due or the ability to continue as a going concern or (y) we will not be forced to seek bankruptcy protection.

 

Cash Flows

 

Our cash flows depend, to a large degree, on the level of spending by oil companies on development and production activities. Sustained increases or decreases in the price of crude oil could have a material impact on these activities and could also materially affect our cash flows. Certain sources and uses of cash, such as the level of discretionary capital expenditures, purchases and sales of investments, issuances and repurchases of debt and of common shares are within our control and are adjusted as necessary, based on market conditions.

 

 

Cash Flows Used In Operating Activities

 

Net cash used in operating activities totaled $3.8 million and $2.9 million for the nine months ended September 30, 2016 and 2015, respectively, or an increase in cash used of approximately $0.9 million. The increase in cash used in operating activities was primarily due to the loss from operations for the nine months ended September 30, 2016, which was partially offset by collections on accounts receivable and an increase in accrued expenses.

 

Cash Flows Used In Investing Activities

 

Net cash used in investing activities totaled $0.3 million and $4.3 million for the nine months ended September 30, 2016 and 2015, respectively. The decrease of $4.0 million was due to a decrease in cash paid for property and equipment during the nine months ended September 30, 2016.

 

Cash Flows Provided By Financing Activities

 

Cash flows provided by financing activities totaled $3.0 million and $4.2 million for the nine months ended September 30, 2016 and 2015, respectively. The decrease in cash provided of $1.2 million was primarily driven by an increase in principal payments made on the promissory notes and a decrease in additional borrowings under the Revolving Loan Facility during the nine months ended September 30, 2016. During the nine months ended September 30, 2016, we received cash flows from financing activities of $3.0 million related to the release of the previously restricted cash as part of the Settlement Agreement and $1.5 million of additional borrowings under the Revolving Loan Facility. During the nine months ended September 30, 2015, we received cash flows from financing activities of $5.0 million related to additional borrowings under the Revolving Loan Facility.

 

Off Balance Sheet Arrangements

 

We have no off-balance sheet arrangements.

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

 

There have been no material changes to our interest rates or foreign currency risk since December 31, 2015. Please refer to our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 for a discussion of those risks.

 

Item 4.

Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

As of the end of the period covered by this report, we conducted an evaluation, under the supervision and with the participation of our management, including our chief executive officer and interim chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based upon that evaluation, our chief executive officer and interim chief financial officer concluded that our disclosure controls and procedures were effective. Disclosure controls and procedures are defined by Rules 13a-15(e) and 15d-15(e) of the Exchange Act as controls and other procedures that are designed to ensure that information required to be disclosed by us in reports filed with the Securities and Exchange Commission under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in applicable rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us in reports filed under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

 

Changes in Internal Control Over Financial Reporting

 

There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15 or 15d-15 of the Exchange Act that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.

 

 

PART II – OTHER INFORMATION

 

Item 1.

Legal Proceedings.

 

Dakota Plains Holdings, Inc., Craig McKenzie and Jim Thornton

 

Ryan R. Gilbertson v. Dakota Plains Holdings, Inc., Craig McKenzie and Jim Thornton

 

On September 23, 2016, Ryan R. Gilbertson commenced a Minnesota state court lawsuit against Dakota Plains Holdings, Inc. and Messrs. McKenzie and Thornton, individually, asserting breach of contract, declaratory judgment, fraud in the inducement, common law fraud and unjust enrichment relating to a note restructuring by our Company in December 2013 and for failing to provide indemnification. On October 4, 2016, Mr. Gilbertson filed a motion for temporary restraining order and temporary injunction as well as a motion for speedy hearing. On October 13, 2016, our Company filed its answer denying Mr. Gilbertson’s allegations and a counterclaim asserting fraud in the inducement and unjust enrichment against Mr. Gilbertson. A hearing on the motion for temporary restraining order and temporary injunction was held on October 18, 2016. On November 1, 2016, the court denied Mr. Gilbertson’s motion for injunctive relief.

 

Dakota Petroleum Transport Solutions, LLC

 

Dakota Petroleum Transport Solutions, LLC v. World Fuel Services, Inc.

 

On October 13, 2015, Dakota Petroleum Transport Solutions, LLC (“DPTS”) commenced a Minnesota state court lawsuit against World Fuel Services, Inc., asserting claims for breach of contract and unjust enrichment relating to unpaid fees and costs for crude oil transloading services (the “Transloading Case”). On November 2, 2015, World Fuel Services, Inc. answered the complaint and filed a motion to consolidate the action with the lawsuit commenced by DPTS Marketing LLC (“DPTSM”) against Western Petroleum Company, which was denied. World Fuel Services, Inc. filed a motion to dismiss for improper venue arguing that the case should be heard in New York. On April 1, 2016, the court granted that motion, finding that the governing contracts required the case to be litigated in New York. It dismissed the case without prejudice. On April 19, 2016, DPTS re-filed the case in the United States District Court for the Southern District of New York. On May 25, 2016, World Fuel Services, Inc. filed an answer to the DPTS complaint, and a pretrial conference is scheduled for November 14, 2016.

 

DPTS Marketing LLC

 

DPTS Marketing LLC v. Western Petroleum Company

 

On October 13, 2015, DPTSM commenced a Minnesota state court lawsuit against Western Petroleum Company (“Western Petroleum”), asserting claims for fraud in the inducement, reckless misrepresentation, tortious interference with prospective economic advantage, breach of contract, unjust enrichment, and declaratory judgment relating to railcar sublease agreements signed between the parties. In initial motion practice, Western Petroleum moved to consolidate this case with the Transloading Case. The motion to consolidate was denied on December 29, 2015. Western Petroleum also moved to dismiss DPTSM’s claims, which the court denied on May 16, 2016. Following the court’s order denying Western Petroleum’s motion to dismiss, Western Petroleum filed its answer and a counterclaim for breach of contract against DPTSM. DPTSM filed a reply to that counterclaim denying any liability, and the pleadings were closed on June 15, 2016.  The parties have exchanged some document discovery, but no depositions have taken place.

 

On July 8, 2016, the court entered an order upon the agreement of the parties staying all proceedings until September 6, 2016. By order dated September 13, 2016, the stay was extended through October 21, 2016. On October 25, 2016, the Court again extended the stay through December 2, 2016. On or before that date, the parties are obligated to provide an update about the status of the case, and in the event that the action is still active after that date, the parties will meet and confer, and the court will issue an amended scheduling order based on the parties’ stipulation and on the court’s scheduling requirements.

 

Dakota Plains Holdings, Inc.; Dakota Plains Transloading, LLC; Dakota Plains Sand, LLC; Dakota Plains Marketing, LLC; DPTS Marketing, LLC; Dakota Petroleum Transport Solutions, LLC; and DPTS Sand, LLC

 

World Fuel Services Corporation v. Dakota Plains Holdings, Inc.; Dakota Plains Transloading, LLC; Dakota Plains Sand, LLC; Dakota Plains Marketing, LLC; DPTS Marketing, LLC; Dakota Petroleum Transport Solutions, LLC; and DPTS Sand, LLC

 

On April 13, 2016, World Fuel Services Corporation (“WFS”) filed an action in the United States District Court for the Southern District of New York against the above-referenced Dakota Plains entities (the “DAKP Parties”). The suit alleges claims for breach of a Guaranty Agreement and a Joinder Agreement. WFS seeks damages of at least $2,025,690 for the alleged failure to make an “operational override” payment, and an additional netted amount of $3,492,747 for the alleged failure to make railcar sublease payments. On May 25, 2016, the DAKP Parties filed a motion to dismiss the complaint; WFS has until November 7, 2016 to file its opposition to the motion to dismiss. A pretrial conference is scheduled for November 18, 2016.

 

 

Item 1A.

Risk Factors.

 

Our business is subject to a number of risks, some of which are beyond our control. In addition to the other information set forth in this report, you should carefully consider the factors discussed in Item 1A – “Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, as filed with the SEC on March 11, 2016, that could have a material adverse effect on our business, results of operations, financial condition and/or liquidity and that could cause our operating results to vary significantly from period to period. As of September 30, 2016, there have been no material changes to the risk factors disclosed in our most recent Annual Report on Form 10-K, except as stated below. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may have a material adverse effect on our business, financial condition, or operating results in the future.

 

If we are unable to repay or refinance our existing and potential future debt as it becomes due, we may be unable to continue as a going concern.

  

Our existing and potential future debt agreements threaten our ability to continue as a going concern as interest payments become due and the debt matures. If we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the Credit Facility or other agreements governing our indebtedness, an event of default would result, which would permit acceleration of such debt and would permit our secured lender to foreclose on any of our assets securing such debt. Any accelerated debt would be immediately due and payable. While we will continue to pursue actions to minimize the risk of a default, including cost reductions, refinancing indebtedness prior to its maturity and extending maturity, there can be no assurance that these actions will be sufficient to avoid or cure a default, in which case we may be forced to sell all or a portion of our Company or its assets or seek protection under state or federal bankruptcy laws.

 

There is substantial doubt in our ability to maintain adequate liquidity.

 

The substantial reduction in crude oil prices has lowered our forecasted transloading volumes and, consequently, our forecasted cash from operations.  We may not be able to generate sufficient cash or otherwise have the liquidity to meet our anticipated working capital, debt service and other liquidity needs. We believe that our forecasted cash will not be sufficient to satisfy our obligations as they come due unless we are able to obtain funds from a third party source on acceptable terms.

 

We have engaged a consultant to assist with reviewing all available options. These efforts continue in earnest, and we are considering all available strategic alternatives and financing possibilities.  We cannot assure you that any of these efforts will result in terms acceptable to us or, if such transaction(s) occur, that they will result in sufficient cost reductions or additional cash flows to continue our operations.  We also cannot be certain of the timing of any such transactions or their resulting benefits, if any. If we are not successful in the foregoing efforts or if we are otherwise restricted from satisfying our scheduled debt service obligations, the resulting default would have a material adverse effect on our business, operations, financial condition and cash flows and could jeopardize our ability to continue as a going concern.

 

Our current financial condition and decline in crude oil prices have adversely affected our business operations and our business prospects. 

 

Our current financial condition and the decline in crude oil prices, along with the contraction of the spread between Brent and WTI and resulting uncertainty, have been disruptive to our business. Management has devoted substantial time and attention to improving our financial condition, thereby reducing its focus on operating the business.  We may also lose employees as a result of uncertainties related to our financial condition.  Further, our current financial condition and resulting uncertainty may cause operating partners to terminate their relationships with us or to tighten credit. These developments could have a material adverse effect on our business, operations, financial condition and cash flows.

 

The price of our common stock may fluctuate significantly.

 

The market price of our common stock is subject to significant fluctuations in response to, among other factors, variations in our operating results and market conditions specific to our business. Furthermore, in recent years the stock market has experienced significant price and volume fluctuations. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry. The changes frequently appear to occur without regard to the operating performance of the affected companies. As such, the price of our common stock could fluctuate based upon factors that have little or nothing to do with us, and these fluctuations could materially reduce the price of our common stock and materially affect the value of your investment.

 

 

Our common stock is eligible for quotation on the over-the-counter-market and not listed on any national securities exchange.

 

As of July 11, 2016, our shares of common stock ceased to be listed on the NYSE MKT and automatically became eligible for quotation on the over-the-counter markets under the symbol “DAKP.” Despite eligibility for quotation, no assurance can be given that any market for our common stock will be maintained. Quotation on the over-the-counter markets is generally understood to be a less active, and therefore less liquid trading market than other types of markets such as a national securities exchange. In comparison to a listing on a national securities exchange, quotation on the over-the-counter markets is expected to have an adverse effect on the liquidity of shares of our common stock, both in terms of the number of shares that can be bought and sold at a given price, but also through delays in the timing of transactions and reduction in analyst and media coverage. This may result in lower prices for our common stock than might otherwise be obtained and could also result in a larger spread between the bid and ask prices for our common stock.

 

Our common stock is a “penny stock,” which may make it difficult to sell shares of our common stock.

 

Our common stock is categorized as a “penny stock” as defined in Rule 3a51-1 of the Exchange Act and is subject to the requirements of Rule 15g-9 of the Exchange Act. Under this rule, broker-dealers who sell penny stocks must, among other things, provide purchasers of these stocks with a standardized risk-disclosure document prepared by the SEC. Under applicable regulations, our common stock will generally remain a “penny stock” until and for such time as its per-share price is $5.00 or more (as determined in accordance with SEC regulations), or until we meet certain net asset or revenue thresholds. These thresholds include the possession of net tangible assets (i.e., total assets less intangible assets and liabilities) in excess of $2 million or average revenues equal to at least $6 million for each of the last three years.

 

The penny-stock rules substantially limit the liquidity of securities in the secondary market, and many brokers choose not to participate in penny-stock transactions. As a result, there is generally less trading in penny stocks. If you become a holder of our common stock, you may not always be able to resell shares of our common stock in a public broker’s transaction, if at all, at the times and prices that you feel are fair or appropriate.

 

The protection provided by the federal securities laws relating to forward-looking statements does not apply to us. The lack of this protection could harm us in the event of an adverse outcome in a legal proceeding relating to forward-looking statements made by us.

 

Although federal securities laws provide a safe harbor for forward-looking statements made by a public company that files reports under the federal securities laws, this safe harbor is not available to certain issuers, including penny stock issuers. We believe we are not currently eligible for the statutory safe harbor included in the Exchange. As a result, we will not have the benefit of this statutory safe harbor protection in the event of certain legal actions based upon forward-looking statements. The lack of this protection in a contested proceeding could harm our financial condition and, ultimately, the value of our common stock.

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

 

Under our 2011 Equity Incentive Plan, employees and directors may elect for our Company to withhold shares to satisfy minimum statutory federal, state and local tax withholding obligations arising from the grant, vesting and/or settlement of equity awards, including stock awards, restricted stock awards and settled restricted stock units. No such shares were withheld during the three months ended September 30, 2016.

 

Item 3.

Defaults Upon Senior Securities.

 

None.

 

Item 4.

Mine Safety Disclosures.

 

Not applicable.

 

Item 5.

Other Information.

 

None.

 

 

Item 6.

Exhibits.

 

Unless otherwise indicated, all documents incorporated herein by reference to a document filed with the SEC pursuant to the Exchange Act are located under SEC file number 001-36493. 

	3.1	Amended and Restated Articles of Incorporation, as amended through March 23, 2012 (1)
	3.2	Composite Second Amended and Restated Bylaws, as amended through September 8, 2016 (2)
	3.3	Certificate of Designation of Series A Junior Participating Preferred Stock of Dakota Plains Holdings, Inc. (3)
	4.1	Rights Agreement dated as of January 24, 2016 between Dakota Plains Holdings, Inc. and Interwest Transfer Company, Inc., as Rights Agent (4)
	10.1	Amendment No. 3 to Revolving Credit and Term Loan Agreement, Amendment No. 1 to Forbearance Agreement and One Time Waiver Of Revolving Loan Borrowing Requirements, dated July 5, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders (5)
	10.2	Amendment No. 4 to Revolving Credit and Term Loan Agreement and One Time Waiver Of Revolving Loan Borrowing Requirements, dated August 5, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders (6)
	10.3	Amendment No. 2 to Forbearance Agreement, dated as of September 1, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders (7)
	10.4	Amendment No. 3 to Forbearance Agreement, dated as of September 20, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders (8)
	31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)
	31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)
	32	Section 1350 Certifications
	101.INS	XBRL Instance Document
	101.SCH	XBRL Taxonomy Extension Schema
	101.CAL	XBRL Extension Calculation Linkbase
	101.DEF	XBRL Taxonomy Extension Definition Linkbase
	101.LAB	XBRL Taxonomy Extension Label Linkbase
	101.PRE	XBRL Taxonomy Extension Presentation Linkbase

 

(1)	Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed March 23, 2012 (file no. 000-53390).
(2)	Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed September 14, 2016.
(3)	Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed January 25, 2016.
(4)	Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed January 25, 2016.
(5)	Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 8, 2016.
(6)	Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 8, 2016.
(7)	Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed September 6, 2016.
(8)	Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed September 26, 2016.

 

 

SIGNATURE

 

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

	Date:	November 7, 2016		DAKOTA PLAINS HOLDINGS, INC.
			By	/s/ Martin J. Beskow
				Martin J. Beskow
				Chief Financial Officer
				(on behalf of registrant and as principal financial and accounting officer)

 

 

 

EXHIBIT INDEX

Exhibit No.		Description		Manner of Filing
3.1		Amended and Restated Articles of Incorporation, as amended through March 23, 2012		Incorporated by Reference
3.2		Composite Second Amended and Restated Bylaws, as amended through September 8, 2016		Incorporated by Reference
3.3		Certificate of Designation of Series A Junior Participating Preferred Stock of Dakota Plains Holdings, Inc.		Incorporated by Reference
4.1		Rights Agreement dated as of January 24, 2016 between Dakota Plains Holdings, Inc. and Interwest Transfer Company, Inc., as Rights Agent		Incorporated by Reference
10.1		Amendment No. 3 to Revolving Credit and Term Loan Agreement, Amendment No. 1 to Forbearance Agreement and One Time Waiver Of Revolving Loan Borrowing Requirements, dated July 5, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders		Incorporated by Reference
10.2		Amendment No. 4 to Revolving Credit and Term Loan Agreement and One Time Waiver Of Revolving Loan Borrowing Requirements, dated August 5, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders		Incorporated by Reference
10.3		Amendment No. 2 to Forbearance Agreement, dated as of September 1, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders		Incorporated by Reference
10.4		Amendment No. 3 to Forbearance Agreement, dated as of September 20, 2016, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders from time to time party thereto, and SunTrust Bank, as administrative agent for the lenders		Incorporated by Reference
31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a)		Filed Electronically
31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a)		Filed Electronically
32		Section 1350 Certifications		Filed Electronically
101.INS		XBRL Instance Document		Filed Electronically
101.SCH		XBRL Taxonomy Extension Schema		Filed Electronically
101.CAL		XBRL Taxonomy Extension Calculation Linkbase		Filed Electronically
101.DEF		XBRL Taxonomy Extension Definition Linkbase		Filed Electronically
101.LAB		XBRL Taxonomy Extension Label Linkbase		Filed Electronically
101.PRE		XBRL Taxonomy Extension Presentation Linkbase		Filed Electronically