DAKOTA PLAINS HOLDINGS, INC. - FORM 10-K

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

FORM 10-K


(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2014
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period From ________ to ________.

Commission File Number 001-36493


	Dakota Plains Holdings, Inc.
	(Exact Name of Registrant as Specified in its Charter)


Nevada		20-2543857
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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)


	Securities registered pursuant to Section 12(b) of the Act:	None
	Securities registered pursuant to Section 12(g) of the Act:	Common Stock, par value $0.001 per share


Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.
	Yes o No þ

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
	Yes o No þ

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 o

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
	þ

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


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

The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $140,871,115, based on the closing sale price for the registrant’s common stock on that date. For purposes of determining this number, all officers and directors of the registrant are considered to be affiliates of the registrant. This number is provided only for the purpose of this report and does not represent an admission by either the registrant or any such person as to the status of such person.

As of March 16, 2015, the registrant had 54,926,227 shares of common stock issued and outstanding.

Documents Incorporated By Reference

Portions of the Registrant’s Proxy Statement for its 2015 Annual Meeting of Shareholders are incorporated by reference in Part III of this report.

Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the federal securities laws. Statements contained in this annual report that are not historical fact should be considered forward-looking statements. Forward-looking statements include, but are not limited to, statements regarding plans and objectives of management for future operations or economic performance, or assumptions. Words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “intend,” “may,” “should,” “will,” and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements.

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 this report. That list of factors is not exhaustive, however, and these or other factors, many of which are outside of our control, could have a material adverse effect on us and our results of operations. Therefore, you should consider these risk factors with caution and form your own critical and independent conclusions about the likely effect of these risk factors on our future performance.

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. You should carefully review the disclosures and the risk factors described in this and other documents we file from time to time with the Securities and Exchange Commission (the “SEC”), including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K. 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.

Jumpstart Our Business Startups Act Disclosure

Our Company qualifies as an “emerging growth company,” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended (the “Securities Act”), as amended by the Jumpstart Our Business Startups Act (the “JOBS Act”). An issuer qualifies as an “emerging growth company” if it has total annual gross revenues of less than $1.0 billion during its most recently completed fiscal year, and will continue to be deemed an emerging growth company until the earliest of:


	•	the last day of the fiscal year of the issuer during which it had total annual gross revenues of $1.0 billion or more;

	•	the last day of the fiscal year of the issuer following the fifth anniversary of the date of the first sale of common equity securities of the issuer pursuant to an effective registration statement;

	•	the date on which the issuer has, during the previous three-year period, issued more than $1.0 billion in non-convertible debt; or

	•	the date on which the issuer is deemed to be a “large accelerated filer,” as defined in Section 240.12b-2 of the Securities Exchange Act of 1934 (the “Exchange Act”).

As an emerging growth company, we are exempt from various reporting requirements. Specifically, Dakota Plains Holdings, Inc. is exempt from the following provisions:


	•	Section 404(b) of the Sarbanes-Oxley Act of 2002, which requires evaluations and reporting related to an issuer’s internal controls;

	•	Section 14A(a) of the Exchange Act, which requires an issuer to seek shareholder approval of the compensation of its executives not less frequently than once every three years; and


	•	Section 14A(b) of the Exchange Act, which requires an issuer to seek shareholder approval of its so-called “golden parachute” compensation, or compensation upon termination of an employee’s employment.

Under the JOBS Act, emerging growth companies may delay adopting new or revised accounting standards that have different effective dates for public and private companies until such time as those standards apply to private companies. We have elected to use the extended transition period for complying with these new or revised accounting standards. Since we will not be required to comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies, our financial statements may not be comparable to the financial statements of companies that comply with public company effective dates. If we were to elect to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

PART I


Item 1.	Business

BUSINESS

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 lack of available pipeline capacity provides a long-term and increasing 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 the largest supplier of frac sand to exploration and production operating companies in the Williston Basin. Our Company is headquartered in Wayzata, Minnesota. Below is an organizational chart of our Company.

(FLOW CHART)

Because current crude oil production in North Dakota exceeds existing pipeline takeaway capacity, we have adopted a crude by rail model. According to the North Dakota Pipeline Authority, as of December 2014, the crude by rail industry was transporting approximately 59% of the total crude oil takeaway. Current pipeline constraints are limiting the amount of crude oil takeaway from the Bakken oil fields. As such, rail transloading facilities are necessary to efficiently capture an increasing demand for transportation of supplies and products to and from the oil fields. The Pioneer Terminal has given us the ability to support the expected increases in demand for the loading and transporting of crude oil and related products to and from the Bakken oil fields.

On March 22, 2012, DP Acquisition Corporation, a wholly owned subsidiary of our Company, merged with and into Dakota Plains, Inc. (the “Initial Merger”). Dakota Plains, Inc. was originally incorporated under the laws of the State of Nevada in 2008 under the name Dakota Plains Transport, Inc. In June 2011, it merged with and into Dakota Plains, Inc., a Minnesota corporation, for purposes of reincorporating under the laws of Minnesota.

As of March 23, 2012, Dakota Plains, Inc., the surviving corporation from the Initial Merger and then a wholly owned subsidiary of our Company, merged with and into MCT Holding Corporation (the “Second Merger”). Pursuant to the plan of merger governing the Second Merger, we changed our name from “MCT Holding Corporation” to “Dakota Plains Holdings, Inc.”

On November 24, 2014, we sold our 50% ownership interest in the trucking joint venture, Dakota Plains Services, LLC (“DPS”) to our former trucking joint venture partner, JPND II, LLC (“JPND”). In addition, on December 5, 2014, we acquired from our then-joint venture partner, Petroleum Transport Solutions, LLC (“PTS”), all of the remaining ownership interests in the transloading joint venture, Dakota Petroleum Transport Solutions, LLC (“DPTS”), the frac sand transloading joint venture, DPTS Sand, LLC (“DPTSS”), and the crude oil marketing joint venture, DPTS Marketing LLC (“DPTSM”).

Transloading Business Segment

In 2009, we completed the acquisition and build-out of our New Town, North Dakota transloading facility, which is fully operational and consists of four rail tracks situated on approximately 27.46 acres serviced by Soo Line Railroad Company, doing business as Canadian Pacific. We extended the lengths of the rail tracks during 2010 and completed excavation and grading sufficient to allow for the construction of two additional rail tracks. We then completed the construction of the third and fourth tracks in the summer of 2011. In December 2011 and 2012, we acquired an additional 164 acres of property adjacent to the existing facility. We now own approximately 192 contiguous acres in New Town, North Dakota accessible by rail.

In March 2013, we and PTS, an indirect wholly owned subsidiary of World Fuel Services Corporation (“WFS”), announced the construction of the Pioneer Terminal. The Pioneer Terminal represents a significant expansion of the New Town transloading facility located in the heart of the Williston Basin. Crude oil supplying the transloading facility is currently sourced primarily from the Bakken formation that underlies parts of Montana, North Dakota, and Saskatchewan. The Pioneer Terminal provides two 8,300 foot loop tracks that can accommodate two 120 rail car unit trains and increases the throughput capacity to 60,000 barrels of crude oil per day, 180,000 barrels of crude oil storage, a high-speed loading facility that accommodates 10 rail cars simultaneously, and transfer stations to receive crude oil from local gathering pipelines and trucks. In October 2013, the first gathering system pipeline was connected to the Pioneer Terminal and began transporting crude oil to our 90,000 barrel crude oil storage tanks. The original four ladder tracks will be utilized for inbound delivery and storage for commodities such as frac sand, aggregate, chemicals, diesel, and pipe.

The Pioneer Terminal was commissioned in December 2013 and began loading cars and sending trains in January 2014. The total cost of the project was approximately $50 million and was initially funded equally by us and PTS. Our 50% share of the initial cost was funded with approximately $17.5 million cash on hand and by a $7.5 million credit facility drawdown.

In June 2014, our wholly owned subsidiary, Dakota Plains Sand, LLC, entered into a joint venture with PTS, DPTSS. We and PTS each owned 50% of the outstanding member units of DPTSS, which was formed to engage in the operation of a frac sand transloading facility near New Town, North Dakota and any other lawful activities as the board of governors may determine from time to time. The operations of DPTSS commenced in June 2014. The initial term of the joint venture was until December 31, 2026. Effective November 30, 2014, we acquired the remaining ownership interest in DPTSS from PTS.

In August 2014, we announced the execution of an interconnection agreement with Hiland Crude, LLC, a wholly owned subsidiary of Hiland Partners, LP (“Hiland”), that would link the Pioneer Terminal with Hiland’s Market Center Gathering System crude oil pipeline network (the “gathering system”). Construction for the final link was completed on November 4, 2014, and the gathering system was commissioned on November 5, 2014. Hiland’s gathering system is the largest in the Bakken oil fields, traversing through the heart of the oil field in Divide, Dunn, Mountrail, McKenzie and Williams counties in North Dakota, as well as Richland and Roosevelt counties in Montana. It has multiple connection points into pipeline outlets and crude by rail terminals with the Pioneer Terminal being the only Canadian Pacific Railway origin. The connection to the Pioneer Terminal is expected to have an initial capacity of greater than 15,000 barrels of crude oil per day and can be easily expanded to supply up to approximately 60,000 barrels of crude oil per day.

In September 2014, we announced the expansion of our on-site crude oil storage at the Pioneer Terminal, and the construction of a third 90,000 barrel crude oil storage tank began almost immediately. Regulatory permits and engineering designs have been completed, and we expect the storage tank to be operational in the summer of 2015. The addition of a third storage tank, the connection to Hiland’s gathering system, and the anticipated expanded rail service will facilitate increasing the sustainable throughput rate to a unit train per day, which is equivalent to 80,000 barrels of crude oil per day.

We continue to develop our inbound oilfield products business at the Pioneer Terminal. Construction was completed in mid-2014 on the $15.0 million frac sand terminal funded by UNIMIN. The frac sand terminal has a throughput capacity of approximately 750,000 tons per year and is composed of 8,000 tons of fixed frac sand storage, an enclosed transloading facility, twin high-speed truck loadouts, and four ladder tracks. The frac sand terminal supplies energy service companies with hydraulic frac sands sourced directly from UNIMIN’s newest and largest proppant production facility, in Tunnel City, Wisconsin. The frac sands are being transported on Canadian Pacific’s rail network. Under terms of the agreements between the parties, UNIMIN provides a direct marketing service to oilfield service companies and funded the construction of the four new ladder tracks, frac sand storage and transloading facility. We provided a land lease to UNIMIN for up to 30 years and receive monthly lease payments of $10,000 through December 2023, with an annual increase of 3.0% starting January 2016. DPTS has provided fee-based transloading services at the frac sand terminal since the operations began in June 2014.

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. The facility transloaded approximately 14.2 million barrels of crude oil in 2014 (or approximately 20,800 rail cars), which represented a 64% increase over the volume transloaded in 2013. In 2014, our facility experienced a daily average throughput of approximately 38,800 barrels of crude oil transloaded compared to a daily average throughput of approximately 23,600 barrels of crude oil in 2013. Our facility provides easy access to the railway via a spur that Canadian Pacific has constructed.

The facility became fully operational in 2009 and currently 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, 180,000 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 have commenced construction on a third 90,000 barrel crude oil storage tank that should be operational in the summer of 2015. The facility also can accommodate significant storage of tanker-trucks, drilling equipment and other crude oil exploration equipment. We continue to conceptualize future stages of expansion of the facility, which will be designed to increase on-site rail car traffic.

Oil well operators are currently hauling 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 December 2014, North Dakota produced 1.2 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 over 981,000 barrels of crude oil per day.

New Town is located at the entrance to a large peninsula in the heart of the Parshall Oil Field, and our facility straddles the only road providing access to and from the peninsula. One of the geographic advantages to our site 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 would equate to over 2,000 wells.

Transloading Joint Venture

In November 2009, we entered into a joint venture, DPTS, with PTS. Each member of DPTS was required to make an initial capital contribution of $50,000 in exchange for 1,000 member units, representing their respective 50% ownership interests of the newly formed entity. There were a total of 2,000 membership units outstanding until we acquired the remaining 50% ownership interest in DPTS from PTS, effective November 30, 2014.

We own the transloading facility and certain equipment acquired and lease the property to DPTS.

Under provisions of the member control agreement, the profits and losses of DPTS were split 50/50, pro rata based on the number of member units outstanding. The cash payments from the joint venture were also paid pro rata based on the number of member units outstanding.

In December 2011, our predecessor, Dakota Plains, Inc., transferred all of its assets and liabilities, excluding its equity interest in its wholly owned subsidiaries and its real property, to Dakota Plains Transloading, LLC (“DPT”). DPT is a wholly owned subsidiary of our Company that was formed in August 2011. The purpose of DPT is to participate in the ownership and operation of the 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.

We accounted for our investment in DPTS using the equity method of accounting through the end of business on December 31, 2013. Our share of income from DPTS is included in other income on the consolidated statements of operations for the years ended December 31, 2013 and 2012. The operations of DPTS for the year ended December 31, 2014 are incorporated into our consolidated statement of operations, and the balance sheets of DPTS are included in our consolidated balance sheets as of December 31, 2014 and 2013.

DPT acts as manager of the transloading facility and coordinates and manages the day-to-day operations. DPT is reimbursed on a monthly basis for costs associated with the Facility Management Activities as approved by the board of governors. Beginning in January 2014, $12,500 per month was paid to DPT in order to defray expenses related to the employment of the Chief Operating Officer of our Company, in recognition of his contribution to the Facility Management Activities.

Beginning in July 2011, DPTSM assumed the rail car leasing liability. PTS coordinated and managed all accounting and bookkeeping functions in connection with the operations of the transloading facility and charged a monthly accounting fee to DPTS $5,000 through December 31, 2013. The annual accounting fee paid to PTS was $190,000 for the year ended December 31, 2014. Prior to our purchase of PTS’s ownership interest in DPTS, PTS also coordinated and managed the trucking and rail logistics for the transloading facility, including the scheduling and monitoring of trains and trucks arriving to and departing from the transloading facility. After payment of the aforementioned fees, the rental fee to DPT and other monthly operating expenses, DPT shared all profits equally with PTS.

PTS and DPT were also required to assist DPTS through their respective contacts with producers, marketers, transporters, refiners and other end-users. The marketing joint venture was the sole client of DPTS in 2013. In January 2014, DPTS began transloading third party crude oil in order to supplement the joint venture marketed volumes. The Pioneer Terminal will be able to receive increased third party volumes going forward.

Under the terms of the joint venture agreement, PTS, our Company and all affiliates were restricted from participating as an owner, investor, manager or consultant in any crude oil transloading facility, anywhere in North Dakota, except through DPTS.

Effective November 30, 2014, we acquired the remaining ownership interest in DPTS from PTS. We will continue to review and analyze other opportunities in order to expand our footprint within the Williston Basin’s crude oil market. We believe the vertical integration of this business line has the potential to provide for increased profits as we continue to develop the business.

Crude Oil Marketing Business Segment

Our crude oil marketing business segment was comprised of our wholly owned subsidiary, Dakota Plains Marketing, LLC (“DPM”). In April 2011, DPM entered into a joint venture with PTS pursuant to which DPM acquired 50% of the outstanding ownership interests of a newly formed entity, DPTSM, and PTS acquired the remaining 50% ownership interest. DPTSM was formed 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 and to conduct trading activities.

Each member of DPTSM was required to make an initial capital contribution of $100 and received 1,000 member units, for a total of 2,000 member units.

Each member of DPTSM was also required to make an initial Member Preferred Contribution of $10 million to support the trading activities of DPTSM. All Member Preferred Contributions made entitled the member to receive a cumulative preferred return of 5% per annum, which was payable in cash on a quarterly basis subject to cash availability. DPM received a payment of $1.1 million related to the cumulative preferred return in September 2013. The payment represented the cumulative preferred return from the date of the initial $10 million contribution through June 30, 2013. The cumulative preferred return for the period from October 1, 2013 through November 30, 2014 and the initial $10 million contribution were distributed to DPM as part of its purchase of the 50% ownership interest of PTS that was effective on November 30, 2014.

DPTSM commenced operations in May 2011. Under provisions of the member control agreement, the profits and losses of DPTSM were allocated in proportion to the number of member units held by each member, or 50/50. Distributions from the marketing joint venture were also payable pro rata based on the number of member units held by each member. The Company received its only priority cash distribution payments in April and June 2013.

In the context of the petroleum industry, “marketing” is the process of purchasing crude oil from the wellhead, or in the “field,” and delivering it to the refinery. DPTSM began purchasing crude oil in July 2011 and ended the month with 56,192 barrels of crude oil purchased. DPTSM sold 7.5 million barrels of crude oil in 2014 compared to 9.4 million barrels of crude oil sold in 2013, a 20% decrease. Average daily barrels of crude oil sold in 2014 were approximately 22,000 compared to 25,800 in 2013.

PTS agreed to manage the marketing of crude oil on behalf of DPTSM. DPM shared expenses and profits equally with PTS after payment by DPTSM of a per-barrel trading and accounting fee to PTS.

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 plan to maintain the current fleet of rail cars with the intent to sublease the cars and/or charge a throughput fee for utilizing the tank cars to transport crude oil. The rail car sublease agreements are being accounted for as operating leases.

Trucking Business Segment

In August 2012, we, through our wholly owned subsidiary Dakota Plains Trucking, LLC, entered into a joint venture with JPND II, LLC (“JPND”). We and JPND each owned 50% of the outstanding member units of the new joint venture, Dakota Plains Services, LLC (“DPS”). DPS engaged in the transportation by road of hydrocarbons and materials used or produced in the extraction of hydrocarbons to or from refineries and other end-users or persons, wherever located, and any other lawful activities as the board of governors may determine from time to time. The initial term of the agreement was through December 31, 2021, unless earlier terminated.

JPND made an initial capital contribution of approximately $650,000 to DPS. Dakota Plains Trucking, LLC was not required to make a capital contribution. Each member received 1,000 member units, for a total of 2,000 member units.

The member control agreement of DPS included a provision that JPND would receive all distributions until the aggregate amount of distributions received was equal to its initial capital contribution. The cash distributions would be split in proportion to the number of member units outstanding after JPND had received distributions equal to its capital contribution. Dakota Plains Trucking, LLC received a tax distribution from DPS in June 2013. Under provisions of the member control agreement, the profits and losses of DPS were allocated in proportion to the number of member units outstanding.

DPS commenced operations in September 2012 and ended the year transporting approximately 400,000 barrels of crude oil, or approximately 3,200 barrels of crude oil per day. DPS transported approximately 5.9 million barrels of crude oil during the period from January 1, 2014 through November 24, 2014 compared to 5.7 million barrels of crude oil transported in 2013; a 5% increase. The average daily barrels of crude oil transported in 2014 were approximately 18,100 compared to 15,500 in 2013.

On November 24, 2014, we sold our 50% ownership interest in DPS to JPND for $1.15 million.

Gathering System Opportunity

In addition to the transloading operations, we continue to pursue other opportunities relating to the transportation of crude oil and related products within the Williston Basin. We anticipate investing in other ventures and assets in addition to our current transloading operations. In particular, we have been approached by several third parties interested in constructing a feeder pipeline, also known as a gathering system, to transport crude oil from wells directly to our facility. A gathering system would allow us to capture a significant volume of crude oil for our facility because we anticipate it would be more cost-effective to transport crude oil through a gathering system pipeline than utilizing semi-truck tankers. In October 2013, our first gathering pipeline was placed into service and provides approximately 5,000 barrels of crude oil per day to the Pioneer Terminal.

In August 2014, we announced the execution of an interconnection agreement with Hiland Crude, LLC, a wholly owned subsidiary of Hiland Partners, LP (“Hiland”), that would link the Pioneer Terminal with Hiland’s Market Center Gathering System crude oil pipeline network (the “gathering system”). Construction for the final link was completed on November 4, 2014, and the gathering system was commissioned on November 5, 2014. Hiland’s gathering system is the largest in the Bakken oil field traversing through the heart of the oil field in Divide, Dunn, Mountrail, McKenzie and Williams counties in North Dakota as well as Richland and Roosevelt counties in Montana. Hiland’s gathering system has multiple connection points into pipeline outlets and crude by rail terminals, with the Pioneer Terminal being the only Canadian Pacific Railway origin. The connection to the Pioneer Terminal is expected to have an initial capacity of greater than 15,000 barrels of crude oil per day and can be easily expanded to supply up to approximately 60,000 barrels of crude oil per day.

We are currently in discussions with several midstream firms in order to secure additional gathering lines into the Pioneer Terminal.

Gathering systems require onsite storage tanks. We believe our two 90,000 barrel crude oil storage tanks and the current construction of our third 90,000 barrel crude oil storage tank will provide three primary benefits:


	•	Increased consistency of delivery timing and significantly reduced risk of weather impacting our ability to operate the facility;

	•	Increased demand for use of the facility by parties considering gathering systems to enter the facility and trunk pipelines exiting the facility; and

	•	Increased opportunity to capitalize on short-term market conditions and other marketing opportunities.

Our Company’s Strengths

Low Overhead Business Model

The transloading operations are structured in a manner that minimizes overhead and leverages the experience and expertise of third parties to identify and develop appropriate opportunities. Utilizing third parties also gives us the ability to fully understand the tasks being outsourced so that we are better prepared if we deem it more cost effective to bring the service in-house. We believe that most operational and financial responsibilities can be handled by our current officers as well as the use of outside consultants.

Strategically Located

According to the U.S. Geological Survey, or “USGS,” the Bakken Shale play in North Dakota and Montana has an estimated 3.0 to 4.3 billion barrels of undiscovered, technically recoverable crude oil. The Bakken Formation estimate is larger than all other current USGS crude oil assessments in the lower 48 states and is the largest “continuous” crude oil accumulation ever assessed by the USGS. The North Dakota Industrial Commission (“NDIC”) Department of Mineral Resources reports that December 2014 daily crude oil production approximated 1.2 million barrels compared to approximately 927,000 barrels in December 2013; a 32% increase. In addition, there were 12,124 producing wells at the end of December 2014 compared to 10,042 producing wells at the end of December 2013; a 21% increase. As of the end of December 2014, in North Dakota, there were 173 completed wells, 181 wells being drilled, and approximately 750 wells awaiting completion services. The NDIC also reported that drilling permit activity was up in December 2014 as operators began positioning themselves for various 2015 budget scenarios.

Every horizontal drilling rig and well site in the Bakken oil field consumes numerous rail cars of inbound products each month. On average, approximately 40 railcars of materials are required to drill and complete a well. With several thousand drilling locations within 15 miles of our facility, we believe we have the opportunity to steadily grow our business organically while maintaining the flexibility to constantly pursue accretive investment opportunities. We anticipate investing in other ventures and assets in addition to our expanded facility, which will allow us to capture more volume from operators and marketers by making their crude oil transportation more cost-effective.

Significant Volume Growth

We believe that our deep market knowledge and strategic position will enable us to benefit from growth opportunities in the Bakken oil field transloading market by increasing current volumes of business with existing clients and building new relationships with leading local producers. As such, the recent completion of the Pioneer Terminal will enable us to market its increased capacity accordingly.

Continue to Grow Operating Profitability

We remain focused on profitable growth and believe we can continue to generate positive returns on invested funds by maintaining our focus on providing greater value to our customers, gaining contracts from leading producers and efficiently managing costs through our low overhead business model. As Williston Basin production continues to increase over the next several years, we expect that management’s focus on growing our market position by exploiting our strong geographic positioning will allow for our Company’s expansion and ability to meet the diverse crude oil transportation needs of our customers.

Our Customers

DPTS transloaded approximately 14.2 million barrels of crude oil in 2014, a 64% increase from 2013 volumes. DPTS exclusively transloaded crude oil for DPTSM until it began transloading crude oil for third parties in January 2014.

DPTSS initiated operations in June 2014 and transloaded approximately 170,000 tons of frac sand in 2014. UNIMIN was the sole customer of DPTSS in 2014.

Competition

The transportation industry is highly competitive. In mid-2012, companies began acquiring and finalized construction of transloading facilities in order to compete with our Company. According to the North Dakota Pipeline Authority, in December 2014 crude by rail accounted for 59% of the total takeaway of crude oil, down from approximately 73% in December 2013. We intend to initially focus on transporting crude oil via the Canadian Pacific system and compete directly with other parties transporting crude oil using Canadian Pacific, the Burlington Northern Railway, various trucking and similar concerns, the Enbridge and Tesoro pipeline and various other pipelines that are constructed and operated in North Dakota.

Thirteen crude by rail sites are currently operational with two additional terminals under construction. All thirteen terminals are capable of accepting and originating unit trains. A “unit train” carries only one commodity and consists of 81 to 120 rail cars. The thirteen terminals have an aggregate daily takeaway capacity of 1.4 million barrels of crude oil with on-site storage of approximately 4.3 million barrels of crude oil. The Bakken Oil Express in Dickinson, Savage Companies in Trenton, and Crestwood in Epping are three of the largest facilities currently operational. At full capacity, we believe their sites represent an additional 0.5 million barrels of crude oil per day in consistent takeaway capacity. The facilities also represent approximately 2.0 million barrels in on-site crude oil storage. Bakken Oil Express, the largest player as of December 2014, is capable of moving approximately 0.2 million barrels of crude oil per day with 0.65 million barrels in on-site crude oil storage. With Hess and EOG handling a great majority of their own crude oil and due to the distances between New Town and the Crestwood (Crestwood in Epping is the closest of the three to New Town and is approximately 85 miles away), Savage and Bakken Oil Express sites, Plains All American is the closest competitor and has .065 million barrels of crude oil takeaway capacity and 0.3 million barrels on site crude oil storage. We expect the Pioneer Terminal to provide a total solution, which will allow us to be competitive and capture much of the volume in the target geography.

Crude by rail also competes with pipeline infrastructure. The existing North Dakota and Montana Williston Basin pipeline infrastructure is capable of handling approximately 723,000 barrels of crude oil per day. The pipelines incorporated in this estimate are owned by Enbridge, Plains All American, Tesoro and True Companies (Butte Pipeline). In December 2014, the North Dakota Pipeline Authority reported that 35% of the Williston Basin crude oil transport was via pipeline, with an incremental 5% going through Tesoro’s system. The total North Dakota production is estimated to have been approximately 1.2 million barrels of crude oil per day for December 2014, for an aggregate pipeline infrastructure utilization of 430,000 barrels of crude oil per day for the same period. While pipeline projects continue to be contemplated, only two new pipelines were completed in 2014; the Plains Bakken North with a daily capacity of 40,000 barrels of crude oil per day and the Butte Expansion with a daily capacity of 100,000 barrels of crude oil per day. The Kinder Morgan Double H is the only pipeline scheduled to come online in 2015 and recently initiated operations with a capacity of 84,000 barrels of crude oil per day. With the increase in pipeline capacity in 2014 and 2015, pipelines continue to experience underutilization.

Additionally, other transportation companies may compete with us from time to time in obtaining capital from investors or in funding joint ventures with our prospective partners. Competitors include a variety of potential investors and larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, it may have a material adverse effect on our results of operation and financial condition.

Regulatory and Compliance Matters

Our operations are subject to extensive federal, state and local environmental laws and regulations concerning, among other things, emissions to the air; discharges to waters; the generation, handling, storage, transportation and disposal of waste and hazardous materials; and the cleanup of hazardous material or petroleum releases. Changes to or limits on carbon dioxide emissions could result in significant capital expenditures required to comply with these regulations with respect to our equipment, vehicles and machinery. Emission regulations could also adversely affect fuel efficiency and increase operating costs. Further, permit requirements or concerns regarding emissions and other forms of pollution could inhibit our ability to build facilities in strategic locations necessary to facilitate growth and increase the efficiency of our operations. Environmental liability can extend to previously owned or operated properties, leased properties and properties owned by third parties, as well as to properties currently owned and used by our subsidiaries. An accidental release of hazardous materials could result in a significant loss of life and extensive property damage. In addition, insurance premiums charged for some or all of the coverage currently maintained by us could increase dramatically or certain coverage may not be available to us in the future if there is a catastrophic event related to the transportation of hazardous materials. We could incur significant expenses to investigate and remediate environmental contamination and maintain compliance with licensing or permitting requirements related to the foregoing, any of which could adversely affect our operating results, financial condition or liquidity.

Employees

We currently have fourteen full-time employees but may hire additional employees to support the growth of the business. We believe that most operational responsibilities can be handled by our current employees as well as the use of independent consultants. We recently announced that we will be bringing our crude oil and frac sand transloading operations in-house effective June 1, 2015 and August 1, 2015, respectively.


Item 1A.	Risk Factors

RISK FACTORS

Investing in our common stock involves risks. You should carefully consider the risks described below, in addition to the other information contained in this report, before investing in our common stock. Realization of any of the following risks, or adverse results from any matter listed under “Forward-Looking Statements,” could have a material adverse effect on our business, financial condition, cash flows and results of operations and could result in a decline in the trading price of our common stock. If you invest in our common stock, then you might lose all or part of your investment. This report also contains forward-looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements, estimates and projections as a result of specific factors, including the risks described below.

Risks Related to Our Business

We are a company with limited operating history for you to evaluate our business.

We are engaged in the primary business of developing and operating a transloading facility and other means to support the loading and transporting of crude oil and related products from and into the North Dakota Williston Basin. We have limited operating history for you to consider in evaluating our business and prospects.

Our operations are subject to all of the risks, difficulties, complications and delays frequently encountered in connection with the formation of any new business, as well as those risks that are specific to the transportation and oil industries. Investors should evaluate us in light of the delays, expenses, problems and uncertainties frequently encountered by companies developing markets for new products, services and technologies. We may never overcome these obstacles.

Our business is speculative and dependent on the implementation of our business plan and our ability to enter into agreements with third parties for transloading and the leasing of our facility on terms that will be commercially viable for us. Our dependence on third parties also creates significant risks that such third parties may not fulfill their obligations under appropriate contracts and arrangements or may not be sufficiently staffed or funded to properly fulfill such obligations consistent with our needs and expectations.

Our lack of diversification increases the risk of an investment in our Company, and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business has initially focused on a single rail car transloading facility in New Town, North Dakota. Since inception, we have focused solely on generating income through transloading at the facility. We intend to continue to pursue additional business lines, including the additional business of transporting and storing frac sand, and other drilling-related products from and into the Williston Basin. Our ability to diversify our investments will depend on our access to additional capital and financing sources and the availability of real property and other assets required to allow us to load and transport crude oil and related products.

Larger companies have the ability to manage their risk by diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting the transportation and crude oil industries or the regions in which we operate than we would if our business were more diversified, enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully operate our transloading of crude oil and frac sand depends on developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable business arrangements and to consummate transactions in a highly competitive environment. These relationships are subject to change and may impair our ability to grow.

We are dependent on independent third parties to provide trucking and rail services and to report certain events to us including delivery information. We do not own or control the transportation assets that deliver our customer’s products.

Our reliance on third parties could cause delays in reporting certain events, including recognizing revenue and claims. If we are unable to secure sufficient equipment or other transportation services to meet our commitments to our customers, our operating results could be materially and adversely affected, and our customers could switch to our competitors temporarily or permanently. These risks include:


	• equipment shortages in the transportation industry, particularly among rail carriers and parties that lease rail cars transporting crude oil products;

	• potential substantial additional capital improvements required to maintain facility;

	• interruptions in service or stoppages in transportation as a result of labor or other issues;

	• Canadian Pacific’s capacity constraints;

	• competing facilities being constructed in close proximity;

	• impact of weather at origin (e.g. snow, flooding, cold temperatures) on all operations;

	• impact of weather at destinations (e.g. hurricanes, tornadoes, flooding);

	• congestion at offloading sites;

	• inadequate storage facilities;

	• changes in regulations impacting transportation; and

	• unanticipated changes in transportation rates.

Competition for the loading and transporting of crude oil and related products may impair our business.

The transportation industry is highly competitive. Per the Association of American Railroads September 2014 Moving Crude Oil by Rail report, in 2008, U.S. Class I railroads originated 9,500 carloads of crude oil. In 2012, Class I railroads originated nearly 234,000 carloads of crude oil, and in 2013 they originated 407,000 carloads of crude oil. In 2014, 530,000 carloads of crude oil were delivered, which is the equivalent of 1,040,000 barrels of crude oil per day moving by rail. According to rail industry statistics, in 2008, a train of 100 rail cars full of crude oil departed a terminal in North Dakota once every four days. By 2013, a unit train of crude oil was departing every 2.5 hours. As a result of the increase in crude oil moved via rail, other companies have recently acquired and constructed transloading facilities to compete with our Company. This competition is expected to become increasingly intense as the demand to transport crude oil in North Dakota has risen in recent years. We intend initially to focus on transporting crude oil through the Canadian Pacific system. We will also compete directly with other parties transporting crude oil using Canadian Pacific, the Burlington Northern Railway, various trucking and similar concerns, the Enbridge, Tesoro, PAA and Butte pipelines and any other pipelines that are constructed and operated in North Dakota. Any material increase in the capacity and quality of these alternative methods or the passage of legislation granting greater latitude to them could have an adverse effect on our results of operations, financial condition or liquidity. In addition, a failure to provide the level of service required by our customers could result in loss of business to competitors. Our ability to defend, maintain or increase prices for our products and services is in part dependent on the industry’s capacity relative to customer demand, and on our ability to differentiate the value delivered by our products and services from our competitors’ products and services.

Additionally, other transportation companies may compete with us from time to time in obtaining capital from investors or in funding joint ventures with our prospective partners. Competitors include a variety of potential investors and larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.

We may be subject to claims, costs and liabilities as a result of events resulting from the transportation of crude oil by or on behalf of our subsidiaries.

We and our subsidiaries may be subject to claims, costs and liabilities relating to events that may occur while the crude oil is en route to its destination. Such claims, costs and liabilities may result from actions of third parties outside our control and may include releases of crude oil and resulting environmental liabilities and damage to property, injury or loss of life resulting from exposure or ignition of crude oil in transit. In addition, we, our subsidiaries, and their affiliates contract from time to time with additional third parties in connection with the transportation of crude oil, including arrangements with third party rail carriers, road transportation providers, and railcar leasing companies.

On July 6, 2013, a freight train operated by Montreal, Maine and Atlantic Railway (“MMA”) with 72 tank cars carrying approximately 50,000 barrels of crude oil derailed in Lac-Mégantic, Quebec. The derailment resulted in significant loss of life, damage to the environment from spilled crude oil and extensive property damage. DPTSM, a crude oil marketing joint venture in which, at the time of the derailment, we indirectly owned a 50% membership interest, subleased the tank cars involved in the incident from an affiliate of our former joint venture partner. A different affiliate of our former joint venture partner owned title to the crude oil being carried in the derailed tank cars. DPTS, a crude oil transloading joint venture in which we also, at the time of the derailment, indirectly owned a 50% membership interest, arranged for the transloading of the crude oil for DPTSM into tank cars at DPTS’s facility in New Town, North Dakota. An affiliate of our former joint venture partner also contracted with Canadian Pacific Railway (“CPR”) for the transportation of the tank cars and the crude oil from New Town, North Dakota to a customer in New Brunswick, Canada. CPR subcontracted a portion of that route to MMA.

We, certain of our subsidiaries, DPTSM and DPTS, along with a number of third parties, including CPR, MMA and certain of its affiliates, as well as several manufacturers and lessors of tank cars, were named as defendants in lawsuits and proceedings related to the incident.

As a result of the Lac-Mégantic derailment, the Canadian Transportation Safety Board is conducting an investigation into the cause of the derailment and the events surrounding it. In addition, the Quebec police conducted a criminal investigation in conjunction with Canadian and U.S. law enforcement authorities.

Additional claims, lawsuits, proceedings, investigations and orders may be filed, commenced or issued with respect to the incident, which may involve civil claims for damages or governmental investigative, regulatory or enforcement actions against us. The adverse resolution of any proceedings related to these events could subject us and/or DPTSM or DPTS to monetary damages, fines and other costs, which could have a negative and material impact on our business, prospects, results of operations and financial condition.

While we and our joint ventures, DPTSM and DPTS, maintain insurance to mitigate the costs of environmental releases as well as other results of unexpected events, including loss of life, property damage and defense costs, there can be no guarantee that our insurance will be adequate to cover all liabilities that may be incurred as a result of this incident.

We are also evaluating potential claims that we may assert against third parties to recover costs and other liabilities that may be incurred as a result of this incident. We can provide no guarantee that any such claims, if brought by us, will be successful or, if successful, that the responsible parties will have the financial resources to address any such claims. Any losses not covered by insurance or otherwise not recoverable from third parties, if significant, could have a material adverse effect on our business, financial condition, results of operations or cash flows.

The train derailment in Lac-Mégantic may result in increased governmental regulation of shipments of crude oil and other fuel products and additional costs.

We rely in part on rail shipments to move crude oil and other fuel products in both the United States and Canada. The accident in Lac-Mégantic and its aftermath has led and could lead to additional governmental regulation of rail shipments of crude oil and other fuel products in Canada and the United States and to increased safety standards for the tanker-cars that transport these products. We cannot predict with any certainty what form any additional regulation or limitations would take. Any increased regulation that arises out of this incident could result in higher operating costs, which could adversely affect our operating results.

We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.

We likely will require additional capital to continue operating our business beyond our current opportunities. Future facility expansions will require additional capital and cash flow. There is no guarantee that we will be able to generate sufficient cash flow from our current operations to fund our proposed business opportunities.

Future arrangements with other crude oil marketing firms and operators will require us to expand our facility to meet the logistical and storage needs that accompany larger throughput commitments. Any additional capital raised through the sale of equity may dilute the ownership percentage of our shareholders. This could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. Given the attractive return profiles of our potential customer arrangements, we expect that any additional capital required to fulfill our transloading commitments would be funded through our current debt or cash flow. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

Our ability to obtain additional financing may be impaired by such factors as the capital markets (both generally and in the oil industry in particular), the single location near New Town, North Dakota that we currently operate (which limits our ability to diversify our activities) and/or the loss of key management. Further, if crude oil prices or the commodities markets continue to experience significant volatility or stagnation, such market conditions will likely adversely impact our income by decreasing demand for our services and simultaneously increasing our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our income from operations, is not sufficient to satisfy our capital needs (even if we reduce our operations), we may be required to cease our operations entirely.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which may adversely impact our financial condition.

We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions continued expansion of our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:


	• meet our capital needs;

	• expand our systems effectively or efficiently or in a timely manner;

	• allocate our human resources optimally;

	• identify and hire qualified employees or retain valued employees; or

	• incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.

Our business may suffer if we do not attract and retain talented personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting our business. We have a small management team, and the loss of a key individual or inability to attract suitably qualified staff could materially adversely impact our business.

Our success depends on the ability of our management and employees to interpret market data correctly and to interpret and respond to economic market and other conditions in order to locate and adopt appropriate investment opportunities, monitor such investments, and ultimately, if required, to successfully divest such investments. Further, no assurance can be given that our key personnel will continue their association or employment with us or that replacement personnel with comparable skills can be found. We will seek to ensure that management and any key employees are appropriately compensated; however, their services cannot be guaranteed. If we are unable to attract and retain key personnel, our business may be adversely affected.

We have elected to use the extended transition period for complying with new or revised accounting standards under Section 102(b)(1) of the JOBS Act.

Under the JOBS Act, emerging growth companies may delay adopting new or revised accounting standards that have different effective dates for public and private companies until such time as those standards apply to private companies. We have elected to use the extended transition period for complying with these new or revised accounting standards and as such we are not required to have auditor attestation on our internal control over financial reporting (ICFR). As an accelerated filer, we would otherwise be required to have auditor attestation of ICFR. Since we will not be required to comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for other public companies, our financial statements may not be comparable to the financial statements of companies that comply with public company effective dates. If we were to elect to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

Risks Related to Our Industry

Building and operating a transloading facility is risky and may not be commercially successful, and the advanced technologies we use cannot eliminate competition and environmental risk, which could impair our ability to generate income from our operations.

Our future success depends on our ability to manage and operate the Pioneer Terminal. We will be almost entirely dependent on the demand to transport crude oil from wells in relatively close proximity to New Town, North Dakota.

Our ability to generate a return on our investments, income and our resulting financial performance are significantly affected by the prices oil exploration and production companies receive for crude oil produced from their wells.

Especially in recent years, the prices at which crude oil trade in the open market have experienced significant volatility, including the expansion of the West Texas Intermediate to both the Brent and Light Louisiana Sweet spread, 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.

Demand for crude oil and crude oil related products is subject to factors beyond our control, which may adversely affect our operating results. Changes in the global economy, changes in the ability of our customers to access equity or credit markets and volatility in crude oil prices could impact our customers’ spending levels and our revenues and operating results.

The past slowdown in global economic growth and recession in the developed economies resulted in reduced demand for crude oil, increased spare productive capacity and lower energy prices. Weakness or deterioration of the global economy or credit market could reduce our customers’ spending levels and reduce our revenues and operating results. Incremental weakness in global economic activity will reduce demand for crude oil and result in lower crude oil prices. Incremental strength in global economic activity will create more demand for crude oil and support higher crude oil prices. In addition, demand for crude oil could be impacted by environmental regulation, including “cap and trade” legislation, carbon taxes and the cost for carbon capture and sequestration related regulations.

Volatility in crude oil prices can also impact our customers’ activity levels and spending for our products and services. Current energy prices are important contributors to cash flow for our customers and their ability to fund exploration and development activities. Expectations about future prices and price volatility are important for determining future spending levels.

Lower crude oil prices generally lead to decreased spending by our customers. While higher crude oil prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Any of these factors could affect the demand for crude oil and could have a material adverse effect on our results of operations. Prolonged periods of low crude oil prices could cause crude oil exploration and production to become economically unfeasible. Decreased drilling and/or production activities by crude oil exploration and production companies could reduce demand for transportation of crude oil and adversely impact our business. A decrease in crude oil prices could also adversely impact our ability to raise additional capital to pursue future diversification and expansion activities.

Our operations may be adversely affected by competition from other energy sources.

Crude oil competes with other sources of energy, some of which may be less costly on an equivalent energy basis. In addition, we cannot predict the effect that the development of alternative energy sources might have on our operations.

Our inability to obtain necessary facilities could hamper our operations.

Transloading crude oil and related products is dependent on the availability of real estate adjacent to railways and roadways, construction materials and contractors, transloading equipment, transportation methods, power and technical support in the particular areas where these activities will be conducted. Our access to these facilities may be limited. Demand for such limited real estate, equipment, construction materials and contractors or access restrictions may affect the availability of such real estate and equipment to us and may delay our business activities. The pricing and grading of appropriate real estate may also be unpredictable and we may be required to make efforts to upgrade and standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary construction materials, contractors and equipment may impair our activities, either by delaying our activities, increasing our costs or otherwise.

We may have difficulty obtaining crude oil to transport, which could harm our financial condition.

In order to transport crude oil, we depend on our ability to secure customers. We also rely on local infrastructure and the availability of transportation for storage and shipment of crude oil to our facility, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. Customers may also decide to utilize one or more of our competitors for a variety of reasons, and any lack of demand for use of our facility and related services would be particularly problematic.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we operate, or labor disputes may impair the distribution of crude oil and in turn diminish our financial condition or ability to maintain our operations.

Supplies of crude oil are subject to factors beyond our control, which may adversely affect our operating results.

Productive capacity for crude oil is dependent on our customers’ decisions to develop and produce crude oil reserves. The ability to produce crude oil can be affected by the number and productivity of new wells drilled and completed, as well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal drilling and hydraulic fracturing, improve total recovery but also result in a more rapid production decline.

Increases in our operating expenses will impact our operating results and financial condition.

Real estate acquisition, construction and regulatory compliance costs (including taxes) will substantially impact the net income we derive from the crude oil and frac sand that we transload. These costs are subject to fluctuations and variation in different locales in which we will operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of operations. In addition, we may not be able to earn net income at our predicted levels, which may impact our ability to satisfy our obligations.

A downturn in the economy or change in government policy could negatively impact demand for our services.

Significant, extended negative changes in economic conditions that impact the producers and consumers of the commodities transloaded by us may have an adverse effect on our operating results, financial condition or liquidity. In addition, changes in United States and foreign government policies could change the economic environment and affect demand for our services. For example, changes in clean air laws or regulation promoting alternative fuels could reduce the demand for crude oil. Also, United States and foreign government agriculture tariffs or subsidies could affect the demand for crude oil.

Penalties we may incur could impair our business.

Failure to comply with government regulations could subject us to administrative, civil or criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our third-party contractors and employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.

We and the oil and gas transportation industry in general are subject to stringent environmental laws and regulations, which may impose significant costs on its business operations.

Our operations are subject to extensive federal, state and local environmental laws and regulations concerning, among other things, emissions into the air; discharges into waters; the generation, handling, storage, transportation and disposal of waste and hazardous materials; and the cleanup of hazardous material or petroleum releases. Changes to or limits on carbon dioxide emissions could result in significant capital expenditures to comply with these regulations with respect to our equipment, vehicles and machinery. Emission regulations could also adversely affect fuel efficiency and increase operating costs. Further, permit requirements or concerns regarding emissions and other forms of pollution could inhibit our ability to build or operate our facilities in strategic locations to facilitate growth and efficient operations. Environmental liability can extend to previously owned or operated properties, leased properties and properties owned by third parties, as well as to properties currently owned and used by our subsidiaries. Environmental liabilities may arise from claims asserted by adjacent landowners or other third parties in toxic tort litigation. An accidental release of hazardous materials could result in a significant loss of life and extensive property damage. In addition, insurance premiums charged for some or all of the coverage currently maintained by us could increase dramatically or certain coverage may not be available to us in the future if there is a catastrophic event related to transportation of hazardous materials. We could incur significant expenses to investigate and remediate environmental contamination and maintain compliance with licensing or permitting requirements related to the foregoing, any of which could adversely affect our operating results, financial condition or liquidity.

Our insurance may be inadequate to cover liabilities we may incur.

Our involvement in the transloading of crude oil and related products may result in us becoming subject to liability for pollution, property damage, personal injury, death or other hazards. Although we expect to obtain insurance in accordance with industry standards to address such risks, such insurance and indemnification has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances, be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events, and we may not be able to continue to obtain insurance on commercially reasonable terms.

Our business will suffer if we cannot obtain or maintain necessary licenses.

Our operations require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors. Our inability to obtain, or our loss of or denial of extension, to any of these licenses or permits could hamper our ability to produce income from our operations.

Challenges to our properties may impact our financial condition.

Parties from whom we purchase real estate for our facilities, such as railways, may not provide warranty deeds ensuring we receive proper title to our properties. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our business activities may be impaired.

We will rely on technology to conduct our business and our technology could become ineffective, obsolete or temporarily unavailable.

We rely on technology, including transloading techniques and economic models, to operate our facilities and to guide our business activities. We will be required to continually enhance and update our technology to maintain its effectiveness and to avoid disuse. The costs of doing so may be substantial, and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the effectiveness of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

Future acts of terrorism or war, as well as the threat of war, may cause significant disruptions in our business operations.

Terrorist attacks and any government response to those types of attacks and war or risk of war may adversely affect our results of operations, financial condition or liquidity. Rail lines and facilities we utilize could be direct targets or indirect casualties of an act or acts of terror, which could cause significant business interruption and result in increased costs and liabilities and decreased revenues, which could have an adverse effect on its operating results and financial condition. Such effects could be magnified if releases of hazardous materials are involved. Any act of terror, retaliatory strike, sustained military campaign or war or risk of war may have an adverse impact on our operating results and financial condition by causing or resulting in unpredictable operating or financial conditions, including disruptions of rail lines, volatility or sustained increase of fuel prices, fuel shortages, general economic decline and instability or weakness of financial markets. In addition, insurance premiums charged for some or all of the coverage currently maintained by our Company could increase dramatically or certain coverage may not be available to us in the future.


Item 1B.	Unresolved Staff Comments

None.


Item 2.	Properties

Our Company maintains its principal executive offices at 294 Grove Lane East, Wayzata, Minnesota 55391. We have leased the office space through May 31, 2017.

We own approximately 192 contiguous acres of land in New Town, North Dakota. All 192 acres are subject to a mortgage in favor of SunTrust Bank pursuant to the Revolving Credit and Term Loan Agreement dated December 5, 2014. In addition, approximately 8 acres, constituting four ladder tracks and other improvements designed to transload inbound commodities, including frac sand, are leased to UNIMIN through an initial term ending December 2023. The recent Pioneer Terminal expansion consists of two 8,300 foot loop tracks that can accommodate two 120 rail car unit trains, two storage tanks with an aggregate capacity of 180,000 barrels of crude oil, a high-speed loading facility that can accommodate 10 rail cars simultaneously and transfer stations to receive crude oil from local gathering pipelines and trucks. The expanded facility was commissioned in December 2013. Based on remaining available space owned today, we estimate that the site can accommodate future expansions to increase its capacity.


Item 3.	Legal Proceedings

Lac-Mégantic, Quebec

As described in Note 15 to the Financial Statements, we, and certain of our subsidiaries, DPTS and DPTSM, are among the many defendants named in various lawsuits relating to the derailment of a Montreal Main & Atlantic Railroad, Ltd. (“MM&A”) train in Lac-Mégantic, Quebec. We believe all claims asserted against us and our subsidiaries are without merit and intend to vigorously defend against such claims.

On July 6, 2013, an unmanned freight train operated by MM&A with 72 tank cars carrying approximately 50,000 barrels of crude oil rolled downhill and derailed in Lac-Mégantic, Quebec. The derailment resulted in significant loss of life, damage to the environment from spilled crude oil and extensive property damage. DPTSM, a crude oil marketing joint venture in which, at the time of the derailment, we indirectly owned a 50% membership interest, and currently own 100% of the membership interest, subleased the tank cars involved in the incident from an affiliate of our former joint venture partner. An affiliate of our former joint venture partner owned title to the crude oil being carried in the derailed tank cars. DPTS, a crude oil transloading joint venture in which, at the time of the derailment, we also indirectly owned a 50% membership interest, and currently own 100% of the membership interest, arranged for the transloading of the crude oil for DPTSM into tank cars at DPTS’s facility in New Town, North Dakota. A different affiliate of our former joint venture partner contracted with Canadian Pacific Railway (“CPR”) for the transportation of the tank cars and the crude oil from New Town, North Dakota to a customer in New Brunswick, Canada. CPR subcontracted a portion of that route to MM&A.

On July 15, 2013, four named parties filed a petition in the Canadian Province of Quebec seeking permission from the court to pursue a class action seeking to recover compensatory and punitive damages along with costs. On June 18, 2014 the petitioners sought permission from the Quebec Superior Court to discontinue the proceedings without prejudice against us and our two subsidiaries Dakota Plains Marketing LLC and Dakota Plains Transloading LLC. The Court granted permission for the discontinuance, and consequently those companies have been removed from the proceeding; however, the most recent iteration of the petition, filed on July 7, 2014, still includes DPTS and DPTSM, along with over 30 third parties, including CPR, MM&A and certain of its affiliates, several manufacturers and lessors of tank cars, as well as the intended purchaser and certain suppliers of the crude oil. The petition generally alleges wrongful death and negligence in the failure to provide for the proper and safe transportation of crude oil. We believe these claims against DPTS and DPTSM are without merit and intend to vigorously defend against such claims and pursue any and all defenses available.

Around July 29, 2013, nineteen individuals filed lawsuits in Cook County, Illinois seeking unspecified damages for their injuries from the accident. The lawsuits assert claims for negligence against the eight defendants noted above. On August 7, 2013, MM&A filed a Chapter 11 voluntary petition in the bankruptcy court in Maine. On August 29, 2013, the defendants jointly removed the cases from state court in Cook County to the United States District Court in the Northern District of Illinois. On September 13, 2013, the bankruptcy trustee for MM&A, and WFS and PTS filed motions seeking to transfer the nineteen personal injury cases from federal court in Illinois to the United States District Court for the District of Maine (the “ME District Court”). On March 21, 2014, the ME District Court granted the transfer motion. On April 4, 2014, the plaintiffs filed a motion for reconsideration of the order granting the transfer motion and a motion requesting that the ME District Court abstain from exercising jurisdiction over the cases. The motion for reconsideration was denied and the motion for abstention remains pending. On May 1, 2014, the plaintiffs appealed the ME District Court’s order granting the transfer motion to the First Circuit Court of Appeals. On June 17, 2014, the ME District Court entered a consent order staying proceedings in the transferred cases pending the appeal. On September 25, 2014, the First Circuit Court of Appeals ordered plaintiffs to voluntarily dismiss their appeal or show cause why their appeal should not be dismissed for lack of jurisdiction. The parties have responded to the First Circuit’s order to show cause, and its decision is pending.

We believe these claims against us and certain of our subsidiaries, including DPTS and DPTSM, are without merit and intend to vigorously defend against such claims and pursue any and all defenses available.

As a result of the Lac-Mégantic derailment, the Canadian Transportation Safety Board is conducting an investigation into the cause of the derailment and the events surrounding it. In addition, the Quebec police are conducting a criminal investigation and are reported to be coordinating with Canadian and U.S. law enforcement authorities.

On December 5, 2014, we entered into an Indemnification and Release Agreement with WFS. Under this agreement, WFS, on behalf of itself and its direct and indirect subsidiaries, has agreed to indemnify us and each of our subsidiaries, including DPTS and DPTSM, for third party claims for bodily injury, death, property damage, economic loss, loss of consortium, loss of income and similar claims in connection with, relating to, or otherwise arising from the derailment, in each case solely to the extent not covered by insurance or otherwise paid for by third parties. In addition, we agreed to indemnify WFS for (i) fifty percent (50%) of the documented out-of-pocket costs and expenses incurred by any WFS party as a result of or arising out of certain obligations to railcar lessors; and (ii) fifty percent (50%) of the documented out-of-pocket defense costs and legal expenses incurred by any WFS party in connection with the derailment not otherwise covered by insurance. Our total exposure under this indemnification is limited to $10 million in the aggregate. All of the indemnification obligations are net of any insurance proceeds received.

We are currently unable to determine the probability of loss or reasonably estimate a range of potential losses related to the aforementioned proceedings. Accordingly, we have not made any provisions for these potential losses in our consolidated financial statements.

Dakota Petroleum Transport Solutions, LLC

TJMD, LLP v. Dakota Petroleum Transport Solutions, LLC

Since October 2012, DPTS has been involved in litigation with TJMD, LLP, a North Dakota limited liability partnership (“TJMD”), arising out of the termination of TJMD as operator of the transloading facility, in which DPTS leases the facility for the use and benefit of their business. TJMD alleges that a wrongful termination without cause on 90 days written notice occurred in June 2012 under the implied covenant of good faith and fair dealing, and a second wrongful termination occurred in September 2012, when DPTS finally terminated the contract before the end of the 90-day period. TJMD is seeking payment for work performed prior to the final, September termination, as well as, monetary damages for future losses, and other relief. Because the outcome of litigation is inherently uncertain, DPTS cannot estimate the possible loss or range of loss for this matter. DPTS intends to vigorously defend against this claim.

Dakota Petroleum Transport Solutions, LLC v. TJMD, LLP, et al.

Since April 2013, DPTS has been involved in litigation with TJMD, Rugged West Services, LLC, a foreign limited liability company (“Rugged West”), and JT Trucking, a foreign limited liability company (“JT”), arising out of crude oil spills that occurred at the transloading facility while TJMD was operating it. DPTS leases the facility for the use and benefit of their business. Trucks haul crude oil to the transloading facility where it is moved onto railcars and shipped to various locations across the country. DPTS has asserted a claim against TJMD for contractual liability because TJMD must indemnify DPTS for cleanup and remediation expenses incurred as the result of the crude oil spills, based on service agreements that provide for contractor indemnification. DPTS has asserted claims against TJMD, Rugged West and JT for negligence in causing or allowing the spills to occur which proximately caused damages to DPTS, entitling DPTS to recovery. DPTS has also asserted claims against TJMD, Rugged West and JT for trespass and nuisance, claiming the defendants exceeded the consent to be on the property, entitling DPTS to recovery.

TJMD has filed third-party complaints against several trucking companies for indemnification and contribution. Originally, thirteen third-party defendants were named – Deer Valley Trucking, Inc., Hofmann Trucking, LLC, LT Enterprises, Inc., Mad Dog Trucking, Inc., Mann Enterprises, LLC, Missouri Basin Materials, Inc., Nickelback, Inc., Red Rock Transportation, Inc., Safe Rack, LLC, Southern Energy Transportation, Inc., Taylor Trucking, Wylie Bice Trucking, LLC, and Basin Western, Inc. Third-party defendant LT Enterprises also sued Donald Compton d/b/a DC Express, as a fourth-party defendant, claiming DC Express must defend and indemnify LT Enterprises due to a contract entered into between the parties. However, that fourth-party defendant has now been dismissed. Deer Valley Trucking has also been dismissed without prejudice. Pursuant to settlement agreements and releases entered into between the parties, stipulations for dismissal have been filed with the Court for Nickelback, Inc. and Missouri Basin Materials, Inc. to be dismissed with prejudice. Nickelback and Missouri Basin have paid to DPTS the full amount of remediation costs associated with the spills attributable to them.

DPTS prevailed on a summary judgment motion against JT Trucking, LLC, due to JT’s failure to answer or otherwise appear in the matter. DPTS continues to actively attempt to recover cleanup and remediation costs on a spill-by-spill basis from each of the trucking companies involved in the specific spills as well as from TJMD. Because the outcome of litigation is inherently uncertain, we cannot estimate the possible recovery for this matter at this time. DPTS is vigorously pursuing its claims.


Item 4.	Mine Safety Disclosures

None.

PART II


Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock, $0.001 par value per share, has been listed on the NYSE MKT under the symbol “DAKP” since June 17, 2014. Previously, our stock was listed on the over-the-counter markets, including the OTC Bulletin Board of the Financial Industry Regulatory Authority and the OTCQB administered by OTC Markets Group, LLC. Prior to March 23, 2012, it had been quoted under the symbol “MTHL” since 2009.

Set forth below for each quarter of 2013 and 2014 are (i) for periods prior to our listing on the NYSE MKT, the high and low bid prices for our common stock as obtained from OTC Markets Group Inc. and (ii) for periods after our listing on the NYSE MKT, the high and low sales prices for our common stock. All prices obtained from OTC Markets Group reflect inter-dealer prices, without retail mark-up, mark-down or commissions and may not represent actual transactions.


Period	High		Low

Fiscal Year ended December 31, 2014

First Quarter	$	2.37	$	1.70
Second Quarter (through June 16, 2014)	$	2.35	$	1.61
Second Quarter (from June 17, 2014)	$	2.86	$	2.35
Third Quarter	$	2.84	$	1.99
Fourth Quarter	$	2.40	$	0.95

Fiscal Year ended December 31, 2013

First Quarter	$	4.17	$	3.26
Second Quarter	$	4.19	$	2.69
Third Quarter	$	2.70	$	1.52
Fourth Quarter	$	2.90	$	1.80

On March 10, 2015, the closing price per share of our common stock on the NYSE MKT was $2.08. As of the same date, our common stock was held by 134 shareholders of record.

We intend to retain our future earnings, if any, to finance the expansion and growth of our business. We do not expect to pay cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including our financial condition, operating results, current and anticipated cash needs, outstanding indebtedness and plans for expansion and restrictions imposed by lenders, if any.

Performance Graph

The following graph compares the cumulative total shareholder returns since completion of our merger on March 23, 2012, and the cumulative total returns of the Russell 3000 and the iPath S&P GSCI Crude Oil TR Index ETN for the same period. This graph assumes $100.00 was invested on March 23, 2012 and also assumes the reinvestment of dividends. We have not included a graph for any period prior to March 23, 2012, because there was no active trading in our common stock prior to March 23, 2012.

The following table sets forth the total returns utilized to generate the foregoing graph.


	3/23/2012		12/31/2012		12/31/2013		12/31/2014
DAKP	$	100.00	$	27.08	$	19.17	$	14.67
iPath S&P GSCI Crude Oil TR Index ETN		100.00		81.00		85.95		46.62
Russell 3000		100.00		102.20		133.83		147.81

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information about shares that may be issued under the 2011 Equity Incentive Plan as of December 31, 2014. We do not have any other equity compensation plans required to be included in this table.


^(*)	Consists of the 2011 Equity Incentive Plan, which allows for awards in the form of restricted or unrestricted stock, incentive or non-statutory stock options, stock appreciation rights, performance-based and other stock-based awards.

Recent Sales of Unregistered Securities

None.


Item 6.	Selected Financial Data

FIVE-YEAR SELECTED FINANCIAL DATA
Dakota Plains Holdings, Inc. and Subsidiaries

The financial statement information set forth below is derived from our consolidated balance sheets as of December 31, 2014, and 2013, and the related consolidated statements of operations, shareholders’ equity (deficit), and cash flows for the years ended December 31, 2014, 2013 and 2012 included elsewhere in this report. Balance sheet information at December 31, 2012, 2011 and 2010 and financial statement information for the years ended December 31, 2011 and 2010 is derived from audited financial statements not included in this report, which other than the Balance Sheet at December 31, 2012, were the historical financial statements of our Company prior to the Initial Merger and the Second Merger in March 2012.


	Year Ended December 31,
	2014			2013			2012			2011			2010
Income Statement Information:
Revenues
Transloading Revenues	$	28,161,157		$	-		$	-		$	-		$	-
Rental Income		120,000			-			-			-			-
Rental Income - Related Party		-			349,372			266,483			314,581			163,427
Total Revenues		28,281,157			349,372			266,483			314,581			163,427

Total Operating Expenses		24,303,972			8,628,671			3,067,220			4,056,341			200,988

Income (Loss) From Operations		3,977,185			(8,279,299	)		(2,800,737	)		(3,741,760	)		(37,561	)

Other Income (Expense)
Income from Investment in Dakota Petroleum Transport Solutions, LLC		-			4,312,394			3,511,999			4,236,779			1,117,608
Income (Loss) from Investment in DPTS Marketing LLC		(355,265	)		2,961,671			10,410,596			2,314,279			-
Income from Investment in Dakota Plains Services, LLC		606,977			130,305			-			-			-
Interest Expense (Net of Interest Income)		(2,793,190	)		(3,630,950	)		(29,211,978	)		(3,371,812	)		1,259
Gain (Loss) on Extinguishment of Debt		-			1,726,515			14,708,909			(4,552,500	)		-
Other Expense		(34,022	)		-			-			(2,777	)		-
Total Other Income (Expense)		(2,575,500	)		5,499,935			(580,474	)		(1,376,031	)		1,118,867

Income (Loss) Before Income Taxes		1,401,685			(2,779,364	)		(3,381,211	)		(5,117,791	)		1,081,306

Income Tax Provision (Benefit)		(854,993	)		(1,054,000	)		(1,380,541	)		(2,007,000	)		416,000

Net Income (Loss)		2,256,678			(1,725,364	)		(2,000,670	)		(3,110,791	)		665,306

Net Income Attributable to Non-Controlling Interests		5,520,752			-			-			-			-

Net Income (Loss) Attributable to Shareholders of Dakota Plains Holdings, Inc.	$	(3,264,074	)	$	(1,725,364	)	$	(2,000,670	)	$	(3,110,791	)	$	665,306

Net Income (Loss) Per Common Share – Basic and Diluted	$	(0.06	)	$	(0.04	)	$	(0.05	)	$	(0.09	)	$	0.02

Weighted Average Shares Outstanding - Basic and Diluted		53,971,183			42,338,999			39,792,973			35,214,940			30,122,634

Balance Sheet Information:
Total Assets	$	99,126,687		$	87,054,584		$	39,664,657		$	22,447,871		$	3,766,009
Total Liabilities	$	102,904,754		$	24,428,105		$	27,301,375		$	15,363,604		$	886,641
Stockholders’ Equity (Deficit)	$	(3,778,067	)	$	62,626,479		$	12,363,282		$	7,084,267		$	2,879,368

Statement of Cash Flows Information:
Net cash provided by (used in) operating activities	$	9,161,784		$	(8,074,812	)	$	(3,810,092	)	$	(2,095,727	)	$	427,686
Net cash provided by (used in) investing activities	$	(40,579,405	)	$	5,055,198		$	(1,003,027	)	$	(8,836,016	)	$	(925,485	)
Net cash provided by financing activities	$	23,096,719		$	13,691,139		$	5,399,537		$	12,110,118		$	412,500


Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and related notes included elsewhere in this report. This discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including those set forth under “Risk Factors” and elsewhere in this report. See also “Forward-Looking Statements.”

Overview

We are an integrated midstream energy company operating the Pioneer Terminal with services that include outbound crude oil storage and logistics and inbound frac sand logistics. We previously competed through our crude oil and frac sand transloading joint ventures, marketing joint venture, and trucking joint venture, of which we held a 50% membership interest in each. On November 24, 2014, we sold our 50% ownership interest in the trucking joint venture, Dakota Plains Services, LLC (“DPS” or the “trucking joint venture”), to our former trucking joint venture partner. On December 5, 2014, we acquired from Petroleum Transport Solutions, LLC (“PTS”) all of its ownership interests in the crude oil transloading joint venture, Dakota Petroleum Transport Solutions, LLC (“DPTS”), the frac sand transloading joint venture, DPTS Sand, LLC (“DPTSS”), and the marketing joi nt venture, DPTS Marketing LLC (“DPTSM”).

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 lack of available pipeline capacity provides a long-term and increasing surplus of crude oil available for the core business of our Company. Our frac sand business provides services for UNIMIN Corporation, a leading producer of quartz proppant and largest supplier of frac sand to crude oil exploration and production operating companies in the Williston Basin.

In November 2009, we entered into an operating lease agreement with DPTS. Under the lease, we receive monthly lease payments from DPTS. The lease includes provisions that allow us to collect additional rents if we incur certain additional costs related to the equipment and facility. DPTS generates income primarily from a per-barrel fee charged when crude oil is transloaded from one of our two storage tanks into railcars using our high-speed loading facility that can accommodate ten rail cars simultaneously. Semi-trailer trucks release crude oil into ten Leased Access Custody Transfer stations that feed the aforementioned storage tanks. Crude oil is also transferred into the storage tanks via gathering pipelines. Using these methods, our site has the capacity to transload approximately 60,000 barrels of crude oil per day.

DPTSM purchased barrels of crude oil from well operators at the wellhead and from first purchasers delivering to the Pioneer Terminal until we decided to cease its crude oil marketing activities effective November 30, 2014. DPTSM also coordinated the transportation of the purchased crude oil to a purchaser at a location determined by the purchaser. Potential purchasers included; storage facilities, blending facilities, distributors and refineries

In September 2012, our wholly owned subsidiary, Dakota Plains Trucking, LLC (“DP Trucking”), formed a joint venture with JPND. DP Trucking and JPND each owned 50% of DPS. The trucking joint venture was formed to engage in the transportation by road of hydrocarbons and materials used or produced in the extraction of hydrocarbons to or from refineries and other end-users or persons, wherever located, and any other lawful activities as the board of governors may determine from time to time. The initial term of the trucking joint venture was through December 31, 2022.

In March 2013, we and PTS announced the construction of the Pioneer Terminal. The Pioneer Terminal represents a significant expansion of the New Town transloading facility located in the heart of the Williston Basin. Crude oil supplying the transloading facility is currently sourced primarily from the Bakken formation that underlies parts of Montana, North Dakota, and Saskatchewan. The Pioneer Terminal provides two 8,300 foot loop tracks that can accommodate two 120 rail car unit trains and increased the throughput capacity from 30,000 barrels of crude oil per day to up to 60,000 barrels of crude oil per day, 180,000 barrels of on-site crude oil storage, a high-speed loading facility that can accommodate 10 rail cars simultaneously, and transfer stations to receive crude oil from local gathering pipelines and trucks. In October 2013, the first gathering system pipeline was connected to the Pioneer Terminal and began transporting crude oil to our 90,000 barrel crude oil storage tank.

The Pioneer Terminal was commissioned in December 2013 and began loading cars and sending trains in January 2014. Total cost of the project was approximately $50 million and was funded equally by us and World Fuel Services Corporation.

The existing four ladder tracks are intended to be utilized for inbound delivery, storage and trucking logistics services for commodities such as frac sand, chemicals, diesel, and pipe.

In August 2014, we announced the execution of an interconnection agreement with Hiland Crude, LLC, a wholly owned subsidiary of Hiland Partners, LP (“Hiland”), that would link the Pioneer Terminal with Hiland’s Market Center Gathering System crude oil pipeline network (the “gathering system”). Construction for the final link was completed on November 4, 2014, and the gathering system was commissioned on November 5, 2014. Hiland’s gathering system is the largest in the Bakken oil field, traversing through the heart of the oil field in Divide, Dunn, Mountrail, McKenzie and Williams counties in North Dakota, as well as Richland and Roosevelt counties in Montana. Hiland’s gathering system has multiple connection points into pipeline outlets and crude by rail terminals, with the Pioneer Terminal being the only Canadian Pacific Railway origin. The connection to the Pioneer Terminal is expected to have an initial capacity of greater than 15,000 barrels of crude oil per day and can be easily expanded to supply up to approximately 60,000 barrels of crude oil per day.

We also continue to develop our inbound oilfield products business at the Pioneer Terminal. Construction was completed in the summer of 2014 on a $15 million frac sand terminal funded by UNIMIN. The frac sand terminal has an annual throughput capacity of approximately 750,000 tons, 8,000 tons of fixed frac sand storage, an enclosed transloading facility, twin high-speed truck loadouts, and four ladder tracks with the capacity to land 70 loaded railcars while keeping one of those tracks dedicated to empty cars. We began frac sand transloading in June 2014. The frac sand terminal will supply energy service companies with hydraulic frac sands sourced directly from UNIMIN’s largest proppant production facility in Tunnel City, Wisconsin. The frac sands are being transported on Canadian Pacific’s rail network. Under the terms of the agreements between the parties, UNIMIN provides a direct marketing service to oilfield service companies. We have provided a land lease to UNIMIN for up to 30 years and receive monthly lease payments of $10,000 through December 2023, with annual increases of 3% starting January 2016. DPTS provides fee-based transloading services at the sand terminal.

Current Business Drivers

As reported by the USGS, the North Dakota Industrial Commission currently predicts that the Bakken’s production will increase for many years. A common date for a production plateau is between the years of 2022 to 2024. The USGS estimated that parts of North Dakota may contain as much as 7.4 billion barrels of crude oil. As of December 2014, North Dakota ranks second behind Texas in terms of production of natural resources in the United States.

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.

Lack of capacity within the trunk pipelines and lack of flexibility and geographic reach to serve many potential markets is driving competition within the crude oil transloading and storage industry. This competition is expected to become increasingly intense as the demand to transport crude oil in North Dakota has risen in recent years. Beyond providing transportation capacity, railroads offer energy market participants the ability to shift deliveries quickly to different markets, enabling producers to sell their product to the market offering the most attractive price. In the Williston Basin, 59% of crude oil production was being shipped via rail in December 2014, according to data from the North Dakota Pipeline Authority.

Critical Accounting Policies and Estimates

Joint Venture Equity Investment

We used the equity method to account for our investments in joint ventures where we had significant influence, representing equity ownership of not more than 50%. Effective November 24, 2014, we sold our 50% ownership interest in DPS. Also effective November 30, 2014, we purchased the remaining membership interests of PTS in DPTS, DPTSM and DPTSS. Prior to the aforementioned transactions, our investments accounted for using the equity method consisted of 50% owned DPTS joint venture, 50% owned DPTSM joint venture, 50% owned DPS joint venture and 50% owned DPTS Sand, LLC joint venture. All of our equity investments had December 31 fiscal year-ends, and we recorded our 50% share of the joint ventures’ net income or loss based on their most recent annual audited financial statements, if available, or unaudited financial statements if not significant, during the period the equity investments were accounted for using the equity method. Our share of the joint ventures’ operating results for each period was adjusted for our share of intercompany transactions, which primarily related to rental agreements. Any significant unrealized intercompany profits or losses were eliminated in applying the equity method of accounting.

Effective at the end of business on December 31, 2013, DPT was appointed the Facility Management Member of DPTS. The appointment as the Facility Management Member resulted in the consolidation of the accounts of DPTS with and into our consolidated financial statements as of December 31, 2013. Accordingly, the accompanying December 31, 2014 and 2013 consolidated balance sheet and the consolidated statements of operations for the year ended December 31, 2014 include the accounts and operations of DPTS. The operations of DPTS Sand, LLC commenced in June 2014, and the accompanying financial statements include its accounts and results of operations.

At December 31, 2014, we have no investments in joint ventures where we have significant influence, representing equity ownership of not more than 50%, and are not accounting for any investments using the equity method.

Our Company followed applicable equity method authoritative guidance whereby declines in estimated investment fair value below carrying value assessed as other than temporary were recognized as a charge to earnings to reduce carrying value to estimated fair value. We periodically evaluated our equity investments for possible declines in value and determined if declines were other than temporary based on, among other factors, the sufficiency and outcome of equity investee performed impairment assessments (which includes third party appraisals and other analyses), the amount and length of time that fair value may have been below carrying value, near-term and longer-term operating and financial prospects of equity investees, and our intent and ability to hold the equity investments for a period of time sufficient to allow for any anticipated recovery.

Stock-Based Compensation

We record expenses associated with the fair value of stock-based compensation. For fully vested and restricted stock grants, we calculate the stock based compensation expense based on the estimated fair value on the date of grant. For stock warrants, we use the Black-Scholes valuation model to calculate stock based compensation at the date of grant. Valuation 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

We record 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, using the measurement date guidelines enumerated in FASB ASC 505-50-30.

Operational Override

As part of the Membership Interest Purchase Agreement (discussed below), we agreed to pay a quarterly Operational Override payment to PTS through December 31, 2026. The payments are due within 45 days of the end of each calendar quarter. In the event such Operational Override payments, in the aggregate, are less than $10 million, then we are obligated to pay PTS the difference on or before January 31, 2027.

We calculated an initial liability of $45.3 million related to the Operational Override. The initial Operational Override was calculated based on our estimated daily throughput from December 1, 2014 through December 31, 2026; discounted at an interest rate of 9%.

Results of Operations

Fiscal Year Ended December 31, 2014 vs. Fiscal Year Ended December 31, 2013

We experienced a net loss attributable to shareholders of Dakota Plains Holdings, Inc. of $3.3 million for the fiscal year ended December 31, 2014 compared to a net loss of $1.7 million for the fiscal year ended December 31, 2013. The 2014 net loss was driven by a 112% decrease in income from our indirect ownership interest in DPTSM, which was a loss of $0.4 million in 2014 compared to income of $3.0 million in 2013. The loss was primarily due to a lower per-barrel margin resulting from a signficant narrowing of the price spread between Brent and WTI throughout 2014 and lower trading revenues. The net loss in 2014 was also driven by the 26% increase in general and administrative expenses due to an increase in legal fees of approximately $0.4 million and professional fees of approximately $0.6 million. In 2014, we realized a 56% increase in income from DPTS to $6.7 million compared to $4.3 million in 2013. The increase was driven by higher volumes transloaded, which was offset by a slight increase in professional fees. The net loss in 2013 of $1.7 million was driven by a 72% decrease in income from our indirect ownership interest in DPTSM, which was primarily driven by the narrowing of the spread between Brent and WTI crude oil prices experienced in early March through October. The loss was also driven by an increase in general and administrative expenses due to the recognition of non-cash expenses related to share issuances to the members of the board of directors and employees of our Company

There was no gain on extinguishment of debt in 2014. In 2013, the gain on extinguishment of debt of $1.7 million was due to the $1.9 million forgiveness of debt (less expenses) that occurred as part of the debt restructuring in December 2013.

The results of DPTS were included in the consolidated statement of operations for the fiscal year ended December 31, 2014 but reflected as income from investment in DPTS in other income on the statement of operations for the fiscal year ended December 31, 2013.

The net income of DPTS for the fiscal year ended December 31, 2014 was $12.0 million compared to $7.9 million for the fiscal year ended December 31, 2013. The increase in net income was driven by a 53% increase in revenue but was offset by an increase in depreciation expense due to the completion of the Pioneer Terminal. Total revenue for the fiscal year ended December 31, 2014 was $26.8 million compared to $17.5 million for the fiscal year ended December 31, 2013. The increase in revenue was driven by volume as DPTS transloaded 14.2 million barrels of crude oil (39,000 barrels per day) during the fiscal year ended December 31, 2014 compared to 8.6 million barrels of crude oil (23,600 barrels per day) during the fiscal year ended December 31, 2013; a 64% increase. The increase in barrels transloaded was primarily the result of securing third party transloading customers. Total cost of revenue for the fiscal year ended December 31, 2014 was $7.9 million compared to $7.6 million for the fiscal year ended December 31, 2013; a 4% increase.

Loss from our indirect investment in DPTSM was $0.4 million for fiscal year ended December 31, 2014 compared to income of $3.0 million for fiscal year ended December 31, 2013; a 112% decrease. DPTSM experienced a 20% decrease in barrels of crude oil sold as 2014 volume was 7.5 million barrels of crude oil compared to 9.4 million barrels of crude oil in 2013 and lower per-barrel margins as a result of the contraction in the price spread between Brent and WTI crude oil prices in 2014 and lower trading revenues.

Income from our indirect investment in DPS was $607,000 for the period from January 1, 2014 through November 24, 2014 compared to income of $130,000 for the fiscal year ended December 31, 2013. DPS hauled 5.9 million barrels of crude oil for period from January 1, 2014 through November 24, 2014 compared to 5.7 million barrels of crude oil hauled for fiscal year ended December 31, 2013; a 5% increase. On November 24, 2014, we sold our 50% ownership interests in DPS to JPND.

In June 2014, we initiated the operations of DPTSS. For the fiscal year ended December 31, 2014, net income was $420,000 with approximately 170,000 tons of sand transloaded.

Fiscal Year Ended December 31, 2013 vs. Fiscal Year Ended December 31, 2012

We experienced a net loss of $1.7 million for the fiscal year ended December 31, 2013 compared to a net loss of $2.0 million for the fiscal year ended December 31, 2012. The 2013 net loss was driven by a 72% decrease in income from our indirect ownership interest in DPTSM, which was $3.0 million in 2013 compared to $10.4 million in 2012. The decrease in income was primarily driven by the narrowing of the spread between Brent and WTI crude oil prices experienced in early May through October 2013. In addition, the net loss in 2013 was also driven by a 191% increase in general and administrative expenses due to the recognition of non-cash expenses related to share issuances to the members of the board of directors and employees of our Company, additional expenses related to employees hired in 2013, and an increase in professional fees of approximately $0.6 million. In 2013, the income from our indirect ownership interest in DPTS increased by 23% to $4.3 million compared to $3.5 million in 2012. The increase was driven by higher volumes transloaded and lower professional fees. The 2012 loss was primarily driven by the settlement of the embedded derivative, which was recorded as interest expense. We also recognized rental income of $349,000 in 2013 compared to $266,000 in 2012. The increase in rental income was mainly driven by the renegotiation of the lease agreeements with DPTS which recognized the additional land purchased by our Company in December 2012.

The gain on extinguishment of debt in 2013 was $1.7 million compared to $14.7 million in 2012. The 2013 gain on extinguishment of debt is due to the $1.9 million forgiveness of debt (less expenses), which occurred as part of the debt restructuring in December 2013. The gain in 2012 related to the forgiveness of debt that occurred with the restructuring and reduction of debt in November 2012.

Income from our indirect ownership interest in DPTS was $4.3 million in 2013 compared to $3.5 million in 2012; a 23% increase. The increase was volume driven as transloaded volume was 8.6 million barrels of crude oil in 2013 compared to 7.6 million barrels of crude oil in 2012; a 13% increase. The increase in income was also due to lower professional fees and no bad debt provision in 2013 since transloading revenues were generated from a single related party (DPTSM). Through December 31, 2013, we utilized the equity method to account for our indirect ownership interest in DPTS and, therefore, reported 50% of the net income on our consolidated statements of operations.

Income from our indirect ownership interest in DPTSM was $3.0 million for the fiscal year ended December 31, 2013 compared to $10.4 million for the fiscal year ended December 31, 2012; a 72% decrease. DPTSM experienced a 22% increase in barrels of crude oil sold as 2013 volume was 9.4 million compared to 7.7 million in 2012. The increase in volume sold was offset by lower per-barrel margins as a result of the contraction in the price spread between Brent and WTI crude oil prices from early March through October 2013 as well as lower trading revenues. The spread between Brent and WTI crude oil prices widened from mid-November through December 2013, which contributed to our portion of the net income of $2.7 million (or $3.34 per barrel) in December 31, 2013. We owned 50% of DPTSM during the aforementioned reporting periods and, therefore, reported 50% of the net income in our consolidated statements of operations.

Income from our indirect ownership interest in DPS was $130,000 for 2013, which included the unrecognized losses from 2012. DPS hauled 5.7 million barrels of crude oil in 2013 and ended the year with 27 trucks and 55 drivers. DPS continued to haul crude oil for DPTSM as well as several third parties. It commenced operations in September 2012 with 4 trucks and ended fiscal year ended December 31, 2012 with 8 trucks and 407,000 barrels of crude oil hauled.

The following tables illustrate the statements of operations by entity for the years ended December 31, 2014, 2013, and 2012:


	Year Ended December 31, 2014
	Dakota			Dakota Petroleum
	Plains			Transport		DPTS Sand,
	Holdings, Inc.			Solutions, LLC		LLC		Eliminations			Consolidated
REVENUES
Transloading Revenue	$	-		$	26,781,637	$	-	$	-		$	26,781,637
Sand Revenue		-			-		1,379,520		-			1,379,520
Rental Income		621,129			-		-		(501,129	)		120,000
Total Revenues		621,129			26,781,637		1,379,520		(501,129	)		28,281,157

COST OF REVENUES		-			7,870,925		646,619		(477,528	)		8,040,016
(exclusive of items shown separately below)
OPERATING EXPENSES
Transloading Operating Expenses		-			2,820,372		2,497		(23,601	)		2,799,268
General and Administrative Expenses		9,131,788			-		-		-			9,131,788
Depreciation and Amortization Expense		194,631			4,138,269		-		-			4,332,900
Total Operating Expenses		9,326,419			6,958,641		2,497		(23,601	)		16,263,956

INCOME (LOSS) FROM OPERATIONS	$	(8,705,290	)	$	11,952,071	$	730,404	$	-		$	3,977,185


	Year Ended December 31, 2013
	Dakota			Dakota Petroleum
	Plains			Transport		DPTS Sand,
	Holdings, Inc.			Solutions, LLC		LLC		Eliminations		Consolidated
REVENUES
Rental Income - Related Party	$	349,372		$	-	$	-	$	-	$	349,372
Total Revenues		349,372			-		-		-		349,372

COST OF REVENUES		-			-		-		-		-
(exclusive of items shown separately below)
OPERATING EXPENSES
General and Administrative Expenses		8,449,125			-		-		-		8,449,125
Depreciation and Amortization Expense		179,546			-		-		-		179,546
Total Operating Expenses		8,628,671			-		-		-		8,628,671

LOSS FROM OPERATIONS	$	(8,279,299	)	$	-	$	-	$	-	$	(8,279,299	)


	Year Ended December 31, 2012
	Dakota			Dakota Petroleum
	Plains			Transport		DPTS Sand,
	Holdings, Inc.			Solutions, LLC		LLC		Eliminations		Consolidated
REVENUES
Rental Income - Related Party	$	266,483		$	-	$	-	$	-	$	266,483
Total Revenues		266,483			-		-		-		266,483

COST OF REVENUES		-			-		-		-		-
(exclusive of items shown separately below)
OPERATING EXPENSES
General and Administrative Expenses		2,901,907			-		-		-		2,901,907
Depreciation and Amortization Expense		165,313			-		-		-		165,313
Total Operating Expenses		3,067,220			-		-		-		3,067,220

LOSS FROM OPERATIONS	$	(2,800,737	)	$	-	$	-	$	-	$	(2,800,737	)

Non-GAAP Financial Measures

We define Adjusted EBITDA Attributable to Shareholders of Dakota Plains Holdings, Inc. as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation and amortization, (iv) gain (loss) on extinguishment of debt, (v) non-cash expenses relating to share based amounts recognized under ASC Topic 718, and (vi) Adjusted EBITDA Attributable to Non-Controlling Interests. Adjusted EBITDA Attributable to Shareholders of Dakota Plains Holdings, Inc. was $3.4 million for 2014, $2.4 million for 2013 and $11.8 million for 2012. The increase in 2014 Adjusted EBITDA is primarily due to the increase in income from our indirect investment in DPTS, which was partially offset by the decrease in income from DPTSM.

Dakota Plains Holdings, Inc.

Reconciliation of Adjusted EBITDA


	Year Ended December 31,
	2014			2013			2012
Net Income (Loss)	$	2,256,678		$	(1,725,364	)	$	(2,000,670	)
Add back:
Income Tax Benefit		(854,993	)		(1,054,000	)		(1,380,541	)
Depreciation and Amortization		4,332,900			179,546			165,313
Share Based Compensation - Employees and Directors		2,330,651			2,753,817			502,604
Share Based Compensation - Consultants		-			299,288			-
Interest Expense		2,793,190			3,630,950			29,211,978
Gain on Extinguishment of Debt		-			(1,726,515	)		(14,708,909	)
Adjusted EBITDA	$	10,858,426		$	2,357,722		$	11,789,775

Adjusted EBITDA Attributable to Non-Controlling Interests		7,411,785			-			-

Adjusted EBITDA Attributable to Shareholders of Dakota Plains Holdings, Inc.	$	3,446,641		$	2,357,722		$	11,789,775

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, management uses Adjusted EBITDA for budgeting and forecasting as well as subsequently measuring its performance and believes that it is providing investors with a financial measure that most closely align with its internal measurement processes.

Liquidity and Capital Resources

Our principal sources of liquidity are cash and cash equivalents, a $57.5 million revolving credit and term loan agreement with SunTrust Bank, and our additional financing capacity, which is dependent upon capital and credit market conditions and our financial performance. Our cash and cash equivalents were $4.7 million at December 31, 2014. The cash in 2014 was primarily generated from the priority cash distributions from DPTS and DPTSS, member preferred returns from DPTSM, proceeds from the sale of our 50% ownership interest in the trucking joint venture and utilization of the credit facility provided by SunTrust Bank. These cash inflows were offset by our purchase of the remaining membership interests of PTS in DPTS, DPTSM and DPTSS for $43 million, which was effective as of November 30, 2014. As a result of the aforementioned purchase, we will no longer be dependent on the priority cash calculations mandated by the member control agreements of the former joint ventures and will now have complete control of the cash generated by these ventures. Cash and cash equivalents at December 31, 2013 were $13.0 million. The cash in 2013 was primarily generated from the priority cash distributions from DPTS and DPTSM, proceeds from both debt and equity issuances, and the consolidation of the DPTS balance sheet.

Under the Revolving Credit Facility with SunTrust, the Company has $9 million of available borrowings at December 31, 2014 that could be utilized to fund the payment of accounts payable and accrued expense in excess of cash and cash equivalents. The Company is currently focused on increasing the operations at the transloading facility and expects cash flows from operations to increase due to the fact that it currently owns 100% of DPTS and DPTS Sand, LLC. We believe that the cash flows from operations and the availability under the revolving credit facility will allow us to meet the current obligations of the company in ordinary course of business. However, the Company also plans to discuss with Sun Trust, the possibility of refinancing or restructuring the Tranche B portion of the Revolving Credit Facility if it cannot meet its current obligations. The Company may also need to secure financing through the capital markets, or otherwise, in order to fund future operations and satisfy obligations due. There is no guarantee that any such required financing will be available on terms satisfactory to the Company, if at all, or that the Company will be able to successfully refinance or restructure the Tranche B portion of the Revolving Credit Facility.

Promissory Notes

On December 5, 2014, our Company and our wholly owned subsidiaries (“Borrowers”) entered into a $57.5 million Revolving Credit and Term Loan Agreement (“Credit Agreement”) with SunTrust Bank (“Administrative Agent”). 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”). There was $48.5 million outstanding under the Credit Facility at December 31, 2014.

All borrowings under the Revolving Loan Facility must be repaid in full upon maturity, December 5, 2017. Outstanding borrowings under the Revolving Loan Facility may be reborrowed and repaid without penalty. The first tranche of Term Loans is payable in quarterly installments with the first payment due on March 31, 2015 and a maturity date of December 5, 2017. Repayment of the second tranche of Term Loans is due on December 5, 2015. Under the terms of the Credit Agreement, the Borrowers have the right to increase the commitments to the Revolving Loan Facility and/or the Term Loans in an aggregate amount not to exceed (x) $25,000,000 (such increased commitments, “Tranche B Replacement Commitments”) plus (y) solely after the full amount of all Tranche B Replacement Commitments have been made, $40,000,000, at any time on or before the final maturity date of the relevant facility.

At the Borrowers’ option, borrowings under the Credit Facility may be either (i) the “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 requires that we maintain a minimum fixed charge coverage ratio and a maximum total debt to EBITDA (earnings before income taxes, depreciation expense and amortization), or leverage ratio. The method of calculating all of the components used in the covenants is included in the Credit Agreement.

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).

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

The proceeds from the Credit Facility were utilized to pay in full the Senior Unsecured Promissory Notes due on October 31, 2015, the outstanding balance of the WFS credit facility, and the purchase of the remaining ownership interests of PTS in DPTS, DPTSM and DPTSS.

Senior Unsecured Promissory Notes

On November 1, 2011, we entered into an Exchange and Loan Agreement with the holders of certain senior and junior promissory notes (“Old Notes”). As part of the Exchange and Loan Agreement, the holders of the Old Notes agreed to exchange their notes for new promissory notes. The total value of these new notes was $9 million and all unpaid accrued interest and principal were payable on March 1, 2013 (the “New Notes”). The New Notes bore interest at the rate of 12% per annum, with interest payable in arrears on the last day of each fiscal quarter.

Private Placement of Debt

On November 2, 2012, we issued promissory notes in the amount of $6,140,000. The issuance of these promissory notes resulted in proceeds to our Company of approximately $5,945,000, net of commissions and finance costs paid. The promissory notes bore interest at the rate of 12% per annum.

Amended Election, Exchange and Loan Agreements

In addition, on November 2, 2012, pursuant to the Amended Election, Exchange and Loan Agreements, we repaid the outstanding principal to a holder of the New Notes in the amount of $500,000. The term of the remaining $8.5 million in New Notes was extended using two different maturity dates, $4,605,300 of the New Notes was extended to March 1, 2014 and $3,894,700 was extended to October 31, 2015. All of the holders of the New Notes agreed to surrender and void the $27,663,950 of promissory notes and 1,296,963 shares of our common stock received April 21, 2012, related to the additional payment provision in the New Notes.

As a result of the revaluation of the additional payment provision and revised elections of the holders, we issued promissory notes in the aggregate of $11,965,300 and 1,757,075 shares of our common stock. The promissory notes bore interest at the rate of 12% per annum.

Adjustment, Extension and Loan Agreement

On December 10, 2013, we entered into an Adjustment, Extension and Loan Agreement (“Loan Agreements”) with each of the holders of our New Notes, pursuant to which we issued new debt securities in connection with an extension and reduction of the outstanding debt.

Pursuant to the Loan Agreements, the holders of the New Notes due March 1, 2014 agreed to extend the maturity dates of such notes to September 30, 2014.

In addition, the holders of the promissory notes issued under the Amended Election, Exchange and Loan Agreements agreed to revalue the additional payment provision. This revaluation resulted in a reduction of the principal amount of the promissory notes by $1,945,156. In connection with the Loan Agreements, in exchange for the original promissory notes issued, we issued $10,020,143 principal amount of 12% amended and restated senior unsecured promissory notes due October 31, 2015. Additionally, the holders agreed to surrender 304,732 shares of our common stock issued as part of the Amended Election, Exchange and Loan Agreements. The amended and restated senior unsecured promissory notes bore interest at the rate of 12% per annum.

The Loan Agreements also provided that, if we complete a sale of not less than $5.0 million worth of capital stock, either registered or through a private placement (a “Qualified Equity Placement”), on or before December 10, 2015, we would use not less than 50% of the proceeds from such sale to repay, pro rata in order of maturity, all or a portion of the promissory notes due September 30, 2014 and $3,894,700 principal amount of New Notes due October 2015. Additionally, if we completed a Qualified Equity Placement on or before December 10, 2014, then, we could elect to convert $10,020,143 aggregate principal amount of the amended and restated senior unsecured promissory notes due October 2015 into shares of common stock at the per-share price used in the Qualified Equity Placement. The registered direct offering of our common stock, which closed on December 16, 2013, was a Qualified Equity Placement, and we exercised the right to convert the amended and restated senior unsecured promissory notes due October 2015, which resulted in the issuance of 4,660,535 additional shares of our common stock based on an offering price of $2.15 per share.

We also repaid the outstanding principal on the $4,605,300 of the promissory notes due September 30, 2014 and $2,317,383 of outstanding principal on New Notes with a maturity of October 31, 2015.

WFS Credit Facility

In June 2013, DPT entered into a credit agreement with WFS (the “WFS Credit Agreement”). The WFS Credit Agreement provided DPT with a $20 million delayed draw term loan facility (the “WFS Facility”) to finance DPT’s share of improvements to be made to the Pioneer Terminal. The WFS Facility was secured by a mortgage on a majority of the land owned by our Company in New Town, North Dakota as well as a pledge of the equity owned by DPT in DPTS and bore interest at a rate per annum equal to nine percent (9%).

The agreement contained customary affirmative and negative covenants, including covenants that restricted the right of the Borrower to incur indebtedness, merge, lease, sell or otherwise dispose of assets, make investments and grant liens on their assets.

The Senior Unsecured Promissory Notes and WFS Credit Agreement were paid in full and terminated when the Company entered into the Revolving Credit and Term Loan Agreement with SunTrust Bank on December 5, 2014.

Membership Interest Purchase Agreement

On December 5, 2014, we entered into a Membership Interest Purchase Agreement (the “Purchase Agreement”) with DPT, Dakota Plains Sand, LLC, DPM and PTS. Pursuant to the Purchase Agreement, in exchange for $43.0 million in cash and an Operational Override (described below), DPT acquired all of the limited liability company membership interests of DPTS owned by PTS, Dakota Plains Sand, LLC 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 DPTSM owned by PTS. As a result of the transactions, our wholly owned subsidiaries became the sole members of DPTS, DPTS Sand, LLC and DPTSM.

In addition to the cash paid to PTS at closing, we 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 million, then the Company is obligated to pay PTS the difference on or before January 31, 2027.

At any time we may pay PTS an amount equal to the then-present value (using a nine percent 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, we will have no further obligations related to the Operational Override.

The Membership Interest Purchase Agreement contains certain representations, warranties, covenants and indemnification obligations of the parties.

In connection with the Purchase Agreement, we entered into an Indemnification and Release Agreement dated December 5, 2014 with WFS (the “Indemnification and Release Agreement”). Pursuant to the Indemnification and Release Agreement, WFS, on behalf of itself and its direct and indirect subsidiaries, agreed to indemnify us, DPTS, DPTSM, and each of their respective officers, managers, directors, employees, affiliates, members, and stockholders, for third party claims in connection with, relating to, or otherwise arising from the train car derailment that occurred in Lac-Mégantic, Quebec, on July 6, 2013 (the “Derailment”). In addition, we, DPT and DPM, on behalf of itself and each such entity’s direct and indirect subsidiaries, agreed to indemnify WFS and WFS’s officers, managers, directors, employees, affiliates, members, and stockholders for (i) fifty percent (50%) of the documented out-of-pocket costs and expenses incurred by any WFS party as a result of or arising out of certain obligations to railcar lessors; and (ii) fifty percent (50%) of the documented out-of-pocket defense costs and legal expenses incurred by any WFS party in connection with the Derailment. Our Company and its affiliates’ total exposure under the indemnification is limited to $10 million in the aggregate. All of the indemnification obligations are net of any insurance proceeds received. To support its indemnification obligations, the Company placed $3 million in escrow, which is included on the consolidated balance sheet as of December 31, 2014.

In connection with the indemnification, our Company and WFS, on its behalf and on behalf of its affiliates, released the other party and its affiliates from any claims arising in connection with the Derailment, other than those for which indemnification is provided under the Indemnification and Release Agreement.

Pursuant to a Guaranty and Security Agreement, dated December 5, 2014 (the “Seller Guaranty and Security Agreement”), made by DPT, Dakota Plains Sand, LLC, DPM, our Company and certain subsidiaries of our Company, our obligations under Section 2.2(b) of the Membership Interest Purchase Agreement in respect of the Operational Override, our obligations in the Indemnification and Release Agreement and the obligations of DPTSM under five Amended and Restated Railcar Sublease Agreements between DPTSM and Western Petroleum Company are guaranteed by DPT, Dakota Plains Sand, LLC, DPM, us and certain of our subsidiaries, and are secured by a second priority lien on all of the assets of such parties.

In connection with the Purchase Agreement, the following agreements were terminated: (a) that certain Member Control Agreement of DPTS Sand, LLC, effective as of June 1, 2014, by and among Dakota Plains Sand, LLC, PTS, and DPTS Sand, LLC; (b) that certain Second Amended and Restated Member Control Agreement of DPTS effective as of December 31, 2013, by and among DPT, PTS and DPTS; and (c) that certain Second Amended and Restated Member Control Agreement of DPTSM, effective as of December 31, 2013, by and among DPM, PTS, and DPTSM; provided DPM and its affiliates will remain subject to the restrictions against purchasing, selling, storing, transporting or marketing crude oil originating from production fields anywhere in North Dakota, or conducting any trading activities related thereto, until June 5, 2015, but shall be permitted to sublease and lease-for-trip railcars to transport crude oil, and transport any other materials (including crude oil) by road.

Operational Override

As part of the Membership Interest Purchase Agreement (discussed above), we have agreed to pay a quarterly Operational Override payment to PTS through December 31, 2026. The payments are due within 45 days of the end of each calendar quarter. In the event the Operational Override payments, in the aggregate, are less than $10 million, then we will be obligated to pay PTS the difference on or before January 31, 2027.

We calculated an initial liability of $45.3 million related to the Operational Override. The initial Operational Override was calculated based on the Company’s estimated daily throughput from December 1, 2014 through December 31, 2026; discounted at an interest rate of 9%.

Capital Expenditures

Our short- and long-term future cash needs will involve supporting the loading and transporting of crude oil and related products from and into the Williston Basin oil fields. We intend to continue the expansion of our existing facility in order to meet the growing logistical and storage needs of existing and future arrangements.

Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2014:


	Payments Due by Period
	Total		Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years
Total Debt	$	48,500,000	$	23,250,000	$	25,250,000	$	-	$	-
Interest Expense		4,899,454		2,819,068		2,080,386		-		-
Office Lease		203,200		81,600		121,600		-		-
Railcar Lease		23,171,636		5,730,793		9,540,835		5,185,848		2,714,160
Operational Override		10,000,000		-		-		-		10,000,000
Total	$	86,774,290	$	31,881,461	$	36,992,821	$	5,185,848	$	12,714,160

As previously noted, On December 5, 2014, our Company and our wholly owned subsidiaries (“Borrowers”) entered into a $57.5 million Revolving Credit and Term Loan Agreement (“Credit Agreement”) with SunTrust Bank (“Administrative Agent”). 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”). There was $48.5 million outstanding under the Credit Facility at December 31, 2014.

The amount of the Operational Override shown above represents the minimum payment due under the Membership Interest Purchase Agreement. We 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 payments are due within 45 days of the end of each calendar quarter. In the event such Operational Override payments, in the aggregate, are less than $10 million, then the Company is obligated to pay PTS the difference on or before January 31, 2027.

Off Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Recent Accounting Pronouncements

See Note 2 to the consolidated financial statements starting on page F-1 for a discussion of recent accounting pronouncements.

Inflation

Management believes inflation has not had a material effect on its operations or on its financial condition. We cannot be sure that its business will not be affected by inflation in the future.


Item 7A.	Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Sensitivity Risk

For floating rate debt, interest rate changes generally do not affect the fair market value but do impact future earnings and cash flows, assuming other factors are held constant. The principal objectives of our investment activities are to preserve principal, provide liquidity and maximize income consistent with minimizing risk of material loss. The recorded carrying amounts of cash and cash equivalents approximate fair value due to their short maturities and do not have material market risk exposure. All of our outstanding debt as of December 31, 2014, has a floating interest rate. We therefore have exposure to any interest rate fluctuations.

Foreign Currency Exchange Risk

Our results of operations and cash flows are not materially affected by fluctuations in foreign currency exchange rates.

Seasonality

The industries in which we operate can be highly cyclical. The most critical factor in assessing the outlook for the oil industry is the worldwide supply and demand for crude oil. The peaks and valleys of demand are further apart than those of many other cyclical industries. This is primarily a result of the industry being driven by commodity demand and corresponding price fluctuations. As demand increases, producers raise their prices. Price escalation enables producers to increase their capital expenditures. Increased capital expenditures ultimately result in greater revenues and profits for services and equipment companies. Ultimately, increased capital expenditures also result in greater production which historically has resulted in increased supplies and reduced prices.

Historically, we have experienced our lowest utilization of our facility during the first quarter when weather conditions are least favorable for efficient operation of our facility. As is common in the industry, through the transloading and sand joint ventures, we typically bear the risk of delays caused by some, but not all, adverse weather conditions.


Item 8.	Financial Statements and Supplementary Data

The consolidated financial statements and notes thereto required pursuant to this Item begin on page F-1 of this report.


Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.


Item 9A.	Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time period specified in SEC rules and forms. These controls and procedures are also designed to ensure that such information is accumulated and communicated to its management, including its principal executive and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating disclosure controls and procedures, we have recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. Management is required to apply judgment in evaluating its controls and procedures.

We have performed an evaluation under the supervision and with the participation of our management, including our principal executive and principal financial officer, to assess the effectiveness of the design and operation of our disclosure controls and procedures under the Exchange Act. Based on that evaluation, management, including our principal executive and financial officer, concluded that our disclosure controls and procedures were effective as of December 31, 2014.

Management’s Report on Internal Controls and Procedures

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act). Our internal control system is designed to provide reasonable assurance to our management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:


	•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of assets;

	•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

	•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Company assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We performed an evaluation under the supervision and with the participation of our management, including our principal executive and principal financial officer, to assess the effectiveness of the design and operation of our disclosure controls and procedures under the Exchange Act as of December 31, 2014. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (1992). Based on that assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2014.


March 16, 2015

		/s/ Craig M. McKenzie
		Chief Executive Officer

		/s/ Timothy R. Brady
		Chief Financial Officer and Treasurer


Item 9B.	Other Information

None.

PART III

Certain information required by Part III is incorporated by reference from our definitive Proxy Statement for the Annual Meeting of Shareholders (the “Proxy Statement”), which we intend to file with the SEC pursuant to Regulation 14A within 120 days after December 31, 2014. Except for those portions specifically incorporated in this report by reference to our Proxy Statement, no other portions of the Proxy Statement are deemed to be filed as part of this report.


Item 10.	Directors, Executive Officers and Corporate Governance

Incorporated into this item by reference is the information appearing under the headings “Proposal No. 1 – Election of Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement.

Our executive officers are as follows:


Name	Age	Position
Craig M. McKenzie	51	Chief Executive Officer and Director
Gabriel G. Claypool	39	President, Chief Operating Officer and Director
Timothy R. Brady	53	Chief Financial Officer and Treasurer

Craig M. McKenzie was appointed to serve as Chairman of our board of directors and Chief Executive Officer of our Company on February 8, 2013. On February 28, 2015 Mr. McKenzie stepped down as Chairman of the Board, but continues to serve as a director. Mr. McKenzie is a highly accomplished executive with significant experience in the oil and gas industry. Prior to joining our Company, Mr. McKenzie had been the President and Chief Executive Officer of ZaZa Energy Corporation, an oil and gas company, since its combination with another oil and gas company, Toreador Resources Corporation, in February 2012. He served in the same positions with Toreador Resources from January 2009 until the combination. From September 2007 to December 2008, Mr. McKenzie served as Chief Executive Officer of Canadian Superior Energy Inc., an oil and gas company. He received his B.S. degree in petroleum engineering from Louisiana State University and his M.B.A. from the Kellogg School of Management at Northwestern University.

Gabriel G. Claypool was appointed to serve as Chief Operating Officer on February 8, 2013, and was elected director of our Company and appointed to serve as President in connection with the Initial Merger effective as of March 22, 2012. On February 28, 2015, Mr. Claypool notified us of his intent to resign from service as a member of the board of directors, effective May 1, 2015. He previously served as Chairman of our board of directors and as Chief Executive Officer and Secretary of our Company from March 2012 until February 2013. He also served as a director and Chief Executive Officer, President and Secretary of Dakota Plains since February 2011. On February 10, 2011, he was appointed to also serve as Chairman of the board of directors of Dakota Plains. Mr. Claypool was previously Regional Manager with Juniper Networks from 2009 to 2011 and prior to that was with AT&T, from 2004 to 2009. Mr. Claypool has been involved in the agriculture industry his entire life and has substantial experience from one of the largest century farms in northern Iowa. Mr. Claypool has numerous years’ experience with various forms of transportation logistics, as well as commodity marketing, trading and hedging through futures and other contracts. Mr. Claypool also brings strong business development and management experience from two Fortune 10 companies, handling relationships with Fortune 500 firms. Mr. Claypool holds a Bachelor of Business Administration degree from the University of Iowa.

Timothy R. Brady was appointed to serve as Chief Financial Officer and Treasurer in connection with the Initial Merger effective as of March 22, 2012. He had previously served as Chief Financial Officer and Treasurer of Dakota Plains since September 2011. Mr. Brady was instrumental in taking our Company public in March 2012. Before joining Dakota Plains, Mr. Brady served as one of three founders and Chief Financial Officer of Encore Energy, a privately held independent operator of oil and natural gas properties, from May 2011 through September 2011. Prior to that position, Mr. Brady served as the Chief Financial Officer from April 2010 through May 2011 of Allied Energy, a publicly traded oil and natural gas company, and served on its board of directors, where Mr. Brady was able to upgrade the firm to the highest grading level on the OTC Market tier. Prior to that position, Mr. Brady was an independent consultant for eight years. Mr. Brady has over 30 years of financial experience within the energy, financial services, and manufacturing industry. Mr. Brady has extensive experience with SEC reporting, balance sheet management, investor relations, treasury, mergers and acquisitions, audit, internal controls implementation, and compliance. Mr. Brady holds a Bachelor of Science degree in Finance from Indiana University and an MBA from Loyola University of Chicago.

Executive officers are elected annually by the board of directors and serve a one-year period or until their successors are elected.

None of the above executive officers is related to each other or to any of our directors.

The board of directors has adopted a code of business conduct and ethics relating to the conduct of its business by its employees officers and directors. A copy of the code of business conduct and ethics is available on our website at http://www.dakotaplains.com. We intend to post on our website any amendments to, or waivers from, our Code of Ethics and Conduct pursuant to the rules of the SEC.


Item 11.	Executive Compensation

Incorporated into this item by reference is the information appearing under the heading “Compensation of Executive Officers,” the information regarding compensation committee interlocks and insider participation under the heading “Corporate Governance” and the information regarding compensation of non-employee directors under the heading “Proposal No. 1 – Election of Directors” in our Proxy Statement.


Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Incorporated into this item by reference is the information appearing under the headings “Security Ownership of Principal Shareholders and Management” and “Equity Compensation Plan Information” in our Proxy Statement.


Item 13.	Certain Relationships and Related Transactions, and Director Independence

Incorporated into this item by reference is the information regarding director independence under the heading “Proposal No. 1 – Election of Directors” and the information regarding related person transactions under the heading “Corporate Governance” in our Proxy Statement.


Item 14.	Principal Accountant Fees and Services

Incorporated into this item by reference is the information under the heading “Proposal No. 3 – Ratification of Independent Registered Public Accounting Firm” in our Proxy Statement.

PART IV


Item 15.	*Exhibits and Financial Statement Schedules*

(a) Documents Filed as Part of this Annual Report on Form 10-K:


	1.	Dakota Plains Holdings, Inc. and subsidiaries Consolidated Financial Statements for the fiscal years ended December 31, 2014, 2013 and 2012.

	2.	Financial Statement Schedules:

		All other schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable and therefore have been omitted.

(b) Exhibits:

Unless otherwise indicated, all documents incorporated into this Annual Report on Form 10-K by reference to a document filed with the SEC pursuant to the Exchange Act are located under SEC file number 001-36493.


Exhibit No.		Description
2.1		Agreement and Plan of Merger, dated March 22, 2012, by and among MCT Holding Corporation, Dakota Plains, Inc. and DP Acquisition Corporation (incorporated by reference to Exhibit 2.1 to current report on Form 8-K filed March 23, 2012, file no. 000-53390)


Exhibit No.		Description
2.2		Plan of Merger of Dakota Plains, Inc. with and into MCT Holding Corporation (incorporated by reference to Exhibit 2.2 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

3.1		Amended and Restated Articles of Incorporation, effective March 23, 2012 (incorporated by reference to Exhibit 3.1 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

3.2		Second Amended and Restated Bylaws of Dakota Plains Holdings, Inc., effective February 1, 2015 (incorporated by reference to Exhibit 3.1 to current report on Form 8-K filed February 2, 2015)

4.1		Revolving Credit and Term Loan Agreement, dated December 5, 2014, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the lenders that become from time to time party thereto, and SunTrust Bank, as administrative agent (incorporated by reference to Exhibit 10.4 to current report on 8-K filed December 8, 2014)

4.2		Guaranty and Security Agreement, dated December 5, 2014, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., Dakota Petroleum Transport Solutions, LLC, DPTS Sand, LLC, and DPTS Marketing, LLC, in favor of SunTrust Bank, as administrative agent (incorporated by reference to Exhibit 10.5 to current report on 8-K filed December 8, 2014)

10.1*		Dakota Plains Holdings, Inc. 2011 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.2*		Form of Incentive Stock Option under 2011 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.3*		Form of Non-Statutory Stock Option under 2011 Equity Incentive Plan (incorporated by reference to Exhibit 10.3 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.4*		Form of Restricted Stock Agreement under 2011 Equity Incentive Plan (incorporated by reference to Exhibit 10.4 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.5*		Form of Restricted Stock Agreement under 2011 Equity Incentive Plan (for grants on or after February 8, 2013) (incorporated by reference to Exhibit 10.3 to current report on Form 8-K filed February 12, 2013; file no. 000-53390)

10.6*		Form of Warrant with Executive Officers (incorporated by reference to Exhibit 10.5 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.7		Form of Warrant (incorporated by reference to Exhibit 10.6 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.8		Form of Warrant (incorporated by reference to Exhibit 4.2 to current report on Form 8-K filed November 6, 2012; file no. 000-53390)

10.9		Form of Warrant (incorporated by reference to Exhibit 10.4 to quarterly report on Form 10-Q for the quarter ended March 31, 2013; file no. 000-53390)

10.10*		Dakota Plains Holdings, Inc. 2014 Omnibus Incentive Plan (incorporated by reference to Appendix A to our Proxy Statement for our 2014 annual meeting of shareholders, filed April 29, 2014; file no. 000-53390)

10.11*		Amended and Restated Employment Agreement with Craig M. McKenzie, dated March 12, 2014 (incorporated by reference to Exhibit 10.1 to current report on Form 8-K filed March 18, 2014; file no. 000-53390)

10.12*		Second Amended and Restated Employment Agreement with Gabriel G. Claypool, dated February 28, 2015 (incorporated by reference to Exhibit 10.1 to current report on Form 8-K filed March 2, 2015)

10.13*		Amended and Restated Employment Agreement with Timothy R. Brady, dated March 12, 2014 (incorporated by reference to Exhibit 10.3 to current report on Form 8-K filed March 18, 2014; file no. 000-53390)

10.14*		Employment Agreement with Nicholas Q. Dillon, April 18, 2013 (incorporated by reference to Exhibit 10.2 to current report on Form 8-K filed April 24, 2013; file no. 000-53390)


Exhibit No.		Description
10.15		Form of Exchange and Loan Agreement dated November 1, 2011 (incorporated by reference to Exhibit 10.10 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.16		Form of Exchange and Loan Agreement (Standby Credit Arrangement) dated November 1, 2011 (incorporated by reference to Exhibit 10.11 to current report on Form 8-K filed March 23, 2012; file no. 000-53390)

10.17		Form of Amended Election, Exchange and Loan Agreement (incorporated by reference to Exhibit 10.2 to current report on Form 8-K filed November 6, 2012; file no. 000-53390)

10.18		Form of Adjustment, Extension and Loan Agreement (incorporated by reference to Exhibit 10.1 to current report on Form 8-K filed December 11, 2013; file no. 000-53390)

10.19		Amended and Restated Lease Agreement (incorporated by reference to Exhibit 10.3 to current report on Form 8-K filed June 1, 2012; file no. 000-53390)

10.20		Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.1 to current report on Form 8-K filed June 12, 2014; file no. 000-53390)

10.21		Membership Interest Purchase Agreement, dated December 5, 2014, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., and Petroleum Transport Solutions, LLC (incorporated by reference to Exhibit 10.1 to current report on 8-K filed December 8, 2014)

10.22		Seller Guaranty and Security Agreement, dated December 5, 2014, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., Dakota Petroleum Transport Solutions, LLC, DPTS Sand, LLC, and DPTS Marketing, LLC, in favor of World Fuel Services Corporation (incorporated by reference to Exhibit 10.2 to current report on 8-K filed December 8, 2014)

10.23		Indemnification and Release Agreement, dated December 5, 2014, by and between Dakota Plains Holdings, Inc., and World Fuel Services Corporation (incorporated by reference to Exhibit 10.3 to current report on 8-K filed December 8, 2014)

21.1		List of Subsidiaries

23.1		Consent of BDO, USA, LLP

24.1		Powers of Attorney (incorporated by reference to signature page)

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

32.1**		Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase

101.DEF		XBRL Taxonomy Extension Definition Linkbase

101.LAB		XBRL Taxonomy Extension Label Linkbase

101.PRE		XBRL Taxonomy Extension Presentation Linkbase


*	Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Annual Report on Form 10-K.
**	The certifications furnished in Exhibit 32.1 hereto are deemed to accompany this Annual Report on Form 10-K and will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. Such certifications will not be deemed to be incorporated by reference into any filings under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the registrant specifically incorporates it by reference.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 16, 2015.


		DAKOTA PLAINS HOLDINGS, INC.

	By	/s/ Craig M. McKenzie
		Craig M. McKenzie,
		Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Craig M. McKenzie and Timothy R. Brady, or either of them, his/her true and lawful attorney-in-fact and agent, acting alone, with full power of substitution and resubstitution, for him/her and in his/her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Annual Report on Form 10-K for the year ended December 31, 2014, and to file the same, with all exhibits thereto, and other documents in connection wherewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent, each acting alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he/she might or could do in person, hereby ratifying and confirming all said attorney-in-fact and agent, acting alone, or his/her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:


Signature	Title	Date

/s/ Craig M. McKenzie
Craig M. McKenzie	Chief Executive Officer (Principal Executive Officer) and Director	March 16, 2015

/s/ Timothy R. Brady
Timothy R. Brady	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)	March 16, 2015

/s/ Gabriel G. Claypool
Gabriel G. Claypool	President, Chief Operating Officer and Director	March 16, 2015


/s/ K. Adam Kroloff
K. Adam Kroloff	Chairman of the Board of Directors	March 16, 2015

/s/ Steven A. Blank
Steven A. Blank	Director	March 16, 2015

/s/ Gary L. Alvord
Gary L. Alvord	Director	March 16, 2015

/s/ Paul M. Cownie
Paul M. Cownie	Director	March 16, 2015

/s/ David H. Fellon
David H. Fellon	Director	March 16, 2015

/s/ Terry H. Rust
Terry H. Rust	Director	March 16, 2015


Dakota Plains Holdings, Inc.
Consolidated Financial Statements as of December 31, 2014 and 2013 and for each of the three years in the Period Ended December 31, 2014

Report of Independent Registered Public Accounting Firm		F-2

Financial Statements

Consolidated Balance Sheets		F-3

Consolidated Statements of Operations		F-4

Consolidated Statements of Cash Flows		F-5

Consolidated Statements of Stockholders’ Equity (Deficit)		F-6

Notes to Consolidated Financial Statements		F-7-F-32

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Dakota Plains Holdings, Inc.
Wayzata, Minnesota

We have audited the accompanying consolidated balance sheets of Dakota Plains Holdings, Inc. as of December 31, 2014 and 2013 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Dakota Plains Holdings, Inc. at December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP
Houston, Texas
March 16, 2015

F-2

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2014 AND 2013

ASSETS


	December 31,
	2014			2013
CURRENT ASSETS
Cash and Cash Equivalents	$	4,690,706		$	13,011,608
Trade Receivables, Net		3,268,386			-
Income Tax Receivable		14,803			1,120,057
Other Current Assets		99,776			542,523
Due from Related Party		-			2,840,292
Other Receivables		781,135			68,896
Deferred Tax Asset		2,266,000			3,728,000
Total Current Assets		11,120,806			21,311,376

PROPERTY AND EQUIPMENT
Land		3,191,521			3,166,849
Site Development		5,829,640			5,498,501
Terminal		21,383,972			19,813,452
Machinery		18,133,754			12,702,655
Construction in Progress		1,886,470			7,551,187
Other Property and Equipment		11,910,987			6,747,349
Total Property and Equipment		62,336,344			55,479,993
Less - Accumulated Depreciation		6,143,159			1,810,259
Total Property and Equipment, Net		56,193,185			53,669,734

PREFERRED DIVIDEND RECEIVABLE		-			252,057

INVESTMENT IN DPTS MARKETING LLC		-			11,458,836

INVESTMENT IN DAKOTA PLAINS SERVICES, LLC		-			70,399

FINANCE COSTS, NET		1,537,795			123,280

RESTRICTED CASH		3,000,000			-

DFERRED TAX ASSET		26,762,000			153,000

OTHER ASSETS		512,901			15,902

Total Assets	$	99,126,687		$	87,054,584

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts Payable	$	7,387,612		$	8,286,489
Accrued Expenses		1,696,358			1,547,645
Accounts Payable - Related Parties		-			722
Promissory Notes, SunTrust		23,250,000			-
Operational Override Liability		715,497			-
Total Current Liabilities		33,049,467			9,834,856

LONG-TERM LIABILITIES
Promissory Notes, Net of Debt Discount		-			7,076,332
Promissory Note, Pioneer Project		-			7,500,000
Promissory Notes, SunTrust		25,250,000			-
Operational Override Liability		44,595,370			-
Other Noncurrent Liabilities		9,917			16,917
Total Long-Term Liabilities		69,855,287			14,593,249

Total Liabilities		102,904,754			24,428,105

STOCKHOLDERS’ EQUITY (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; 55,044,829 and 54,206,380 Issued and Outstanding, Respectively		55,044			54,206
Additional Paid-In Capital		6,267,788			43,836,032
Accumulated Deficit		(10,100,899	)		(6,836,825	)
Total Equity (Deficit) Dakota Plains Holdings, Inc.		(3,778,067	)		37,053,413
Non-controlling Interest in Subsidiaries		-			25,573,066
Total Stockholders’ Equity (Deficit)		(3,778,067	)		62,626,479

Total Liabilities and Stockholders’ Equity (Deficit)	$	99,126,687		$	87,054,584

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

F-3

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012


	Year Ended December 31,
	2014			2013			2012
REVENUES
Transloading Revenue	$	26,781,637		$	-		$	-
Sand Revenue		1,379,520			-			-
Rental Income		120,000			-			-
Rental Income - Related Party		-			349,372			266,483
Total Revenues		28,281,157			349,372			266,483

COST OF REVENUES		8,040,016			-			-
(exclusive of items shown separately below)

OPERATING EXPENSES
Transloading Operating Expenses		2,799,268			-			-
General and Administrative Expenses		9,131,788			8,449,125			2,901,907
Depreciation and Amortization Expense		4,332,900			179,546			165,313
Total Operating Expenses		16,263,956			8,628,671			3,067,220

INCOME (LOSS) FROM OPERATIONS		3,977,185			(8,279,299	)		(2,800,737	)

OTHER INCOME (EXPENSE)
Income from Investment in Dakota Petroleum Transport Solutions, LLC		-			4,312,394			3,511,999
Income (Loss) from Investment in DPTS Marketing LLC		(355,265	)		2,961,671			10,410,596
Income from Investment in Dakota Plains Services, LLC		606,977			130,305			-
Interest Expense (Net of Interest Income)		(2,793,190	)		(3,630,950	)		(29,211,978	)
Gain on Extinguishment of Debt		-			1,726,515			14,708,909
Other Income (Expense)		(34,022	)		-			-
Total Other Income (Expense)		(2,575,500	)		5,499,935			(580,474	)

INCOME (LOSS) BEFORE TAXES		1,401,685			(2,779,364	)		(3,381,211	)

INCOME TAX BENEFIT		(854,993	)		(1,054,000	)		(1,380,541	)

NET INCOME (LOSS)		2,256,678			(1,725,364	)		(2,000,670	)

NET INCOME ATTRIBUTABLE TO NON-CONTROLLING INTERESTS		5,520,752			-			-

NET LOSS ATTRIBUTABLE TO SHAREHOLDERS OF DAKOTA PLAINS HOLDINGS, INC.	$	(3,264,074	)	$	(1,725,364	)	$	(2,000,670	)

Net Loss Per Common Share – Basic and Diluted	$	(0.06	)	$	(0.04	)	$	(0.05	)

Weighted Average Shares Outstanding - Basic and Diluted		53,971,183			42,338,999			39,792,973

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

F-4

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012


	Year Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	2,256,678		$	(1,725,364	)	$	(2,000,670	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by (Used in) Operating Activities
Depreciation and Amortization		4,332,900			179,546			165,313
Amortization of Debt Discount		640,985			349,632			58,272
Amortization of Finance Costs		203,394			70,728			10,837
Gain on Extinguishment of Debt		-			(1,726,515	)		(14,708,909	)
Gain on Sale of Dakota Plains Services, LLC		(472,624	)		-			-
Loss on Derivative Liability		-			-			27,311,802
Deferred Income Taxes		(1,033,000	)		(26,000	)		(2,412,000	)
Share-Based Consulting Fees		-			299,288			-
Increase (Decrease) in Deferred Rental Income		-			(24,793	)		40,271
Income from Investment in Dakota Petroleum Transport Solutions, LLC		-			(4,312,394	)		(3,511,999	)
Loss (Income) from Investment in DPTS Marketing LLC		355,265			(2,961,671	)		(10,410,596	)
Income for Investment in Dakota Plains Services, LLC		(606,977	)		(130,305	)		-
Non-cash Rental Income		17,941			(12,169	)		(42,783	)
Amortization of Deferred Rent		(7,000	)		(4,083	)		-
Share-Based Compensation		2,330,651			2,753,817			502,604
Changes in Working Capital and Other Items, Net of Membership Interest and Consolidation of VIE:
Increase in Trade Receivables		(3,245,923	)		-			-
Increase in Other Recceivables		(712,239	)		-			-
Decrease (Increase) in Income Taxes Receivable		1,105,254			(1,120,057	)		-
Decrease (Increase) in Other Current Assets		460,724			(55,986	)		(13,876	)
Decrease (Increase) in Due from Related Party		1,676,006			46,018			(81,175	)
Increase in Accounts Payable		2,251,463			69,318			207,058
Increase (Decrease) in Income Taxes Payable		-			(1,028,000	)		1,028,000
Increase in Accrued Expenses		129,769			1,307,740			152,244
Decrease in Deferred Rental Income		-			(8,062	)		(104,485	)
Increase in Due from Related Party		(24,484	)		-			-
Increase in Other Assets		(496,999	)		(15,500	)		-
Net Cash Provided By (Used In) Operating Activities		9,161,784			(8,074,812	)		(3,810,092	)

CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Property and Equipment		(12,285,389	)		(159,621	)		(2,116,490	)
Cash Received from DPTS Marketing LLC		10,646,038			12,910,000			-
Preferred Dividends Received from DPTS Marketing LLC		709,589			1,065,753			-
Cash Received from Dakota Plains Services, LLC		-			59,906			-
Cash Received from Sale of Dakota Plains Service, LLC		1,150,000			-			-
Cash Paid for Investment in Dakota Petroleum Transport Solutions, LLC		-			(17,500,000	)		-
Cash Paid for Purchase of Non Controlling Interests		(44,196,600	)		-			-
Cash Received from Dakota Petroleum Transport Solutions, LLC		-			1,757,896			1,113,463
Cash Received from Consolidation of Dakota Petroleum Transport Solutions, LLC		-			6,921,264			-
Cash Received from Consolidation of DPTS Marketing LLC		3,396,957			-			-
Net Cash Provided By (Used In) Investing Activities		(40,579,405	)		5,055,198			(1,003,027	)

CASH FLOWS FROM FINANCING ACTIVITIES
Finance Costs Paid		(1,430,459	)		(9,783	)		(195,062	)
Common Shares Surrendered		(645,679	)		(568,058	)		-
Proceeds from Issuance of Common Stock - Net of Issuance Costs		-			13,910,305			-
Cash Distributions to Non-Controlling Interests		(5,110,826	)		-			-
Capital Contribution to DPTS Sand, LLC		1,000			-			-
Cash Paid for Debt Extinguishment Costs		-			(218,641	)		(45,401	)
Increase in Restricted Cash		(3,000,000	)		-			-
Repayment of Promissory Notes		(7,717,317	)		(6,922,684	)		(500,000	)
Proceeds from Promissory Notes		-			-			6,140,000
Proceeds from Promissory Note, Pioneer Project		-			7,500,000			-
Principal Payments on Promissory Note, Pioneer Project		(7,500,000	)		-			-
Proceeds from Promissory Notes, SunTrust		48,500,000			-			-
Net Cash Provided By Financing Activities		23,096,719			13,691,139			5,399,537

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(8,320,902	)		10,671,525			586,418

CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD		13,011,608			2,340,083			1,753,665

CASH AND CASH EQUIVALENTS – END OF PERIOD	$	4,690,706		$	13,011,608		$	2,340,083

Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	$	1,536,450		$	3,085,750		$	1,831,353
Cash Paid During the Period for Income Taxes	$	11,852		$	1,073,308		$	3,459

Non-Cash Financing and Investing Activities:
Purchase of Property and Equipment Paid Subsequent to Period End	$	754,815		$	10,215		$	30,800
Fair Value of Warrants Issued for Debt Discount	$	-		$	-		$	1,048,889
Satisfaction of Derivative Liability with Common Stock	$	-		$	-		$	6,132,192
Promissory Notes Issued to Satisfy Derivative Liability	$	-		$	-		$	11,965,300
Preferred Dividend Receivable	$	457,532		$	498,632		$	501,370
Satisfaction of Promissory Notes through issuance of Common Stock	$	-		$	10,020,143		$	-
Fair Value of Common Stock Issued for Finance Costs	$	187,450		$	-		$	-
Non Cash Amounts Related to Equity Transaction
Decrease in Additional Paid In Capital	$	39,439,828		$	-		$	-
Increase in Deferred Tax Asset	$	24,114,000		$	-		$	-
Increase in Operational Override Liability	$	45,310,867		$	-		$	-

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

F-5

DAKOTA PLAINS HOILDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012


	Common Stock						Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Non-controlling Interest In Subsidiary			Total Stockholders’ Equity (Deficit)
	Shares			Amount			Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Non-controlling Interest In Subsidiary			Total Stockholders’ Equity (Deficit)

Balance - December 31, 2011		37,014,018		$	37,014		$	10,158,044		$	(3,110,791	)	$	-		$	7,084,267
Acquisition of MCT Holding Corporation		640,200			640			(640	)		-			-			-
Issuance of Common Shares Pursuant to Exercise of Warrants		2,386,578			2,387			(2,387	)		-			-			-
Share-Based Compensation		-			-			477,604			-			-			477,604
Issuance of Restricted Common Shares		38,437			38			(38	)		-			-			-
Issuance of Common Shares Pursuant to Debt Restructure		1,757,075			1,757			6,130,435			-			-			6,132,192
Issuance of Common Shares to Board of Directors		3,125			3			24,997			-			-			25,000
Warrants Issued Included in Debt Discount		-			-			644,889			-			-			644,889
Net Loss		-			-			-			(2,000,670	)		-			(2,000,670	)

Balance - December 31, 2012		41,839,433			41,839			17,432,904			(5,111,461	)		-			12,363,282
Share- Based Compensation		-			-			1,469,442			-			-			1,469,442
Sale of Common Shares at $2.15 per share		7,000,000			7,000			15,043,000			-			-			15,050,000
Issuance of Common Shares Pursuant to Debt Restructure		4,660,535			4,660			10,015,483			-			-			10,020,143
Issuance of Restricted Common Shares		794,063			794			(794	)		-			-			-
Issuance of Shares to Executive		62,500			63			234,937			-			-			235,000
Issuance of Warrants Pursuant to Consulting Agreements		-			-			208,663			-			-			208,663
Issuance of Common Shares to Board of Directors		308,108			308			1,139,692			-			-			1,140,000
Common Shares Surrendered		(458,259	)		(458	)		(567,600	)		-			-			(568,058	)
Cost of Capital Raise		-			-			(1,139,695	)		-			-			(1,139,695	)
Creation of Non-controlling Interest in Subsidiary		-			-			-			-			25,573,066			25,573,066
Net Loss		-			-			-			(1,725,364	)		-			(1,725,364	)

Balance - December 31, 2013		54,206,380			54,206			43,836,032			(6,836,825	)		25,573,066			62,626,479
Share- Based Compensation		-			-			1,364,816			-			-			1,364,816
Issuance of Restricted Common Shares		589,483			590			(590	)		-			-			-
Issuance of Common Shares to Executives and Employees		287,237			287			641,957			-			-			642,244
Issuance of Common Shares to Board Directors		144,478			144			323,447			-			-			323,591
Issuance of Common Shares for Consulting Services		115,000			115			187,335									187,450
Common Shares Surrendered		(297,749	)		(298	)		(645,381	)		-			-			(645,679	)
Distributions Paid to Non-Controlling Interest		-			-			-			-			(5,110,826	)		(5,110,826	)
Increase in Joint Venture Ownership Pursuant to Equity Transaction		-			-			(39,439,828	)		-			(25,982,992	)		(65,422,820	)
Net Income (Loss)		-			-			-			(3,264,074	)		5,520,752			2,256,678
Balance - December 31, 2014		55,044,829		$	55,044		$	6,267,788		$	(10,100,899	)	$	-		$	(3,778,067	)

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

F-6

Dakota Plains Holdings, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


1.	Organization and Nature of Business

On March 22, 2012, Dakota Plains Holdings, Inc., formerly known as MCT Holding Corporation (“DP” or the “Company,” “our” and words of similar import), Dakota Plains, Inc., a Minnesota corporation engaged in the crude oil transportation business (“Dakota Plains”), and DP Acquisition Corporation, a Minnesota corporation (“Merger Subsidiary”) entered into an Agreement and Plan of Merger (the “Merger Agreement”). Under the Merger Agreement, the Merger Subsidiary merged with and into Dakota Plains (the “Initial Merger”), the separate corporate existence of the Merger Subsidiary ceased, and Dakota Plains continued as the surviving corporation and as a wholly owned subsidiary of the Company. See Note 14 for details of the Initial Merger.

Dakota Plains Holdings, Inc. 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 April 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 purchased the remaining ownership interest in DPTSM from PTS and immediately ceased the purchase and sale of crude oil.

Dakota Plains Trucking, LLC, a wholly owned subsidiary of the Company, was formed in September 2012 primarily to engage in the transportation by road of hydrocarbons and materials used or produced in the extraction of hydrocarbons to or from refineries and other end-users or persons, wherever located. Effective November 24, 2014, the Company sold its membership interest in Dakota Plains Services, LLC (“DPS”).

Dakota Plains Sand, LLC, 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

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

New Accounting Pronouncements

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

In July 2013, the FASB issued Accounting Standards Update (“ASU”) No. 2013-11 “Income Taxes – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carry Forward, a Similar Tax Loss, or a Tax Credit Carry Forward Exists” which provides that entities should present the unrecognized tax benefit as a reduction of the deferred tax asset for a net operating loss (“NOL”) or similar tax loss or tax credit carry forward rather than as a liability when the uncertain tax position would reduce the NOL or other carry forward under the tax law. The ASU is effective for annual and interim periods for fiscal years beginning on or after December 15, 2013. The Company adopted this ASU effective January 1, 2014. The adoption of this update did not have a material impact on the Company’s consolidated results of operations, financial position or disclosures.

F-7

In May 2014, the FASB issued 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, 2016. 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 currently 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 April 2014, the FASB issued ASU No. 2014-8, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”. This ASU changes the requirements for reporting discontinued operations to disposals of components of an entity that represent strategic shifts that have a major effect on an entity’s operations and financial results. The standard also expands the disclosures for discontinued operations and requires new disclosures related to individually material disposals that do not qualify for discontinued operations reporting. The guidance is effective for interim and annual periods beginning after December 15, 2014, and should be applied prospectively. Early adoption is permitted. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements.

In June 2014, the FASB issued ASU 2014-12, “Compensation - Stock Compensation” effective for annual periods and interim periods within those periods beginning after December 15, 2015. The amendments require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. The Company is currently evaluating the impact of the provisions of ASU 2014-12, however, the standard is not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

Liquidity

As of December 31, 2014, we had cash and cash equivalents and trade receivables of approximately $8.0 million and our accounts payable and accrued expenses were approximately $9.1 million. In addition, we have $24.0 million aggregate principal amount of promissory notes and Operational Override payments due prior to December 31, 2015.

Joint Venture Equity Investment

The Company used the equity method to account for investments in joint ventures where the Company had significant influence, representing equity ownership of not more than 50%. Effective November 24, 2014, the Company sold its 50% ownership in DPS. In addition, effective November 30, 2014, the Company purchased the remaining ownership interests in Dakota Petroleum Transport Solutions, LLC (“DPTS”), DPTS Marketing LLC (“DPTSM”) and DPTS Sand, LLC from its joint venture partner (See Note 13). Prior to the aforementioned transactions, the Company’s investments accounted for using the equity method consisted of 50% owned DPTS joint venture, 50% owned DPTSM joint venture, 50% owned DPS joint venture and 50% owned DPTS Sand, LLC joint venture. All of the Company’s equity investments had December 31 fiscal year-ends, and the Company recorded its 50% share of the joint ventures’ net income or loss based on their most recent annual audited financial statements, if available, or unaudited financial statements if not significant, during the period the equity investments were accounted for using the equity method. The Company’s share of the joint ventures’ operating results for each period were adjusted for its share of intercompany transactions, which primarily related to rental agreements. Any significant unrealized intercompany profits or losses were eliminated in applying the equity method of accounting.

Effective at the end of business on December 31, 2013, DPT was appointed the Facility Management Member of DPTS. The appointment as the Facility Management Member resulted in the consolidation of the accounts of DPTS with and into the consolidated financial statements of the Company as of December 31, 2014 and 2013. Accordingly, the accompanying December 31, 2013 consolidated balance sheet and the consolidated statements of operations for the year ended December 31, 2014 include the accounts and operations of DPTS. The operations of DPTS Sand, LLC commenced in June 2014, and the accompanying financial statements include its accounts and results of operations.

At December 31, 2014, the Company has no investments in joint ventures where it has significant influence, representing equity ownership of not more than 50%, and is not accounting for any investments using the equity method.

The Company followed applicable equity method authoritative guidance whereby declines in estimated investment fair value below carrying value assessed as other than temporary were recognized as a charge to earnings to reduce carrying value to estimated fair value. The Company periodically evaluated its equity investments for possible declines in value and determined if declines were other than temporary based on, among other factors, the sufficiency and outcome of equity investee performed impairment assessments (which includes third party appraisals and other analyses), the amount and length of time that fair value may have been below carrying value, near-term and longer-term operating and financial prospects of equity investees, and the Company’s intent and ability to hold the equity investments for a period of time sufficient to allow for any anticipated recovery.

F-8

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.

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 December 31, 2014 there was no allowance for doubtful accounts.

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
Other Property and Equipment		3-5 years
Land		—

Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Depreciation expense was $4,332,900, $179,546 and $165,313 for the years ended December 31, 2014, 2013 and 2012, respectively. The Company had fixed assets related to in-progress construction of $1,886,470 and $7,551,187 at December 31, 2014 and 2013, respectively. The Company believes the estimated cost to complete construction is approximately $1.8 million. The projects associated with the fixed assets related to in-progress construction at December 31, 2014 and 2013 were undertaken by the joint ventures that funded all endeavors through equity from its members. The Company’s policy is to capitalize interest when the construction time for a project is greater than one year.

Impairment

FASB Accounting Standards Codification (“ASC”) 360-10-35-21 requires that long-lived assets to be held and used be 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 at December 31, 2014, 2013 and 2012.

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 December 31, 2014 and 2013.

F-9

Income Taxes

The Company accounts for income taxes under FASB ASC 740-10-30. 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.

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 of being sustained if the position 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 consolidated balance sheet.

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

Stock-Based Compensation

The Company records expenses associated with the fair value of stock-based compensation. For fully vested and restricted stock grants, the Company calculates the stock-based compensation expense based upon 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.

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 the gross sale of fuel-related services when the transloading of petroleum-related products is complete. DPTS Sand, LLC records the gross sale when the transloading of sand-related products is complete.

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, using the measurement date guidelines enumerated in FASB ASC 505-50-30.

Earnings Per Share

Basic earnings per share (“EPS”) excludes dilution and is computed by dividing net income (loss) attributable to Company stockholders 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 a loss for the years ended December 31, 2014, 2013, and 2012, the potentially dilutive shares are anti-dilutive and thus not added into the diluted EPS calculation.

The following stock options, warrants and restricted stock represent potentially dilutive shares as of December 31, 2014, 2013 and 2012:


	December 31,
	2014		2013		2012
Restricted Stock		1,031,150		769,063		568,437
Stock Options		-		415,625		215,625
Stock Warrants		2,771,000		2,771,000		2,671,000

Total Potentially Dilutive Shares		3,802,150		3,955,688		3,455,062

F-10

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:


	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.

Non-Controlling Interest

ASC 810 “Consolidation” requires that a non-controlling interest, previously referred to as a minority interest, be reported as part of equity in the consolidated financial statements and that losses be allocated to the non-controlling interest even when such allocation might result in a deficit balance, reducing the losses attributable to the controlling interest. The Company’s non-controlling interest during the year ended December 31, 2014 is due to the non-controlling member of DPTS and DPTS Sand, LLC prior to the Company’s purchase of the 50% interest owned by the non-controlling member.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Dakota Plains Holdings, Inc. and its wholly owned subsidiaries. The accompanying consolidated balance sheet as of December 31, 2014 includes all of the accounts of DPTS, DPTS Sand, LLC and DPTSM. The accompanying consolidated balance sheet as of December 31, 2013 includes all of the accounts of DPTS. The accompanying consolidated statement of operations for the year ended December 31, 2014 includes the accounts of DPTS for the entire year, the accounts of DPTS Sand, LLC since inception and the accounts of DPTSM since the purchase of the 50% interest owned by the Company’s former joint venture partner. All significant intercompany accounts and transactions have been eliminated.


3.	Joint Ventures

Dakota Petroleum Transport Solutions, LLC

On November 9, 2009, the Company entered into a joint venture with Petroleum Transport Solutions, LLC (“PTS”). The Company and PTS each owned 50% of the outstanding member units of DPTS until the Company purchased the 50% ownership interest of PTS, effective November 30, 2014. The joint venture was formed to engage in the acquisition, construction and operation of a petroleum transloading facility in New Town, North Dakota (“Transloading Facility”).

Each of the members of DPTS was required to make an initial capital contribution of $50,000. Each member received 1,000 member units for their initial capital contribution.

As part of the joint venture agreement, the Company owns the Transloading Facility and certain equipment acquired and leases the property to DPTS.

The operations of the Transloading Facility commenced in November 2009. Under provisions of the member control agreement the profits and losses of DPTS were split 50/50, pro rata based on the number of member units outstanding. The cash payments from the joint venture also were paid pro rata based on the number of member units outstanding.

F-11

On June 1, 2012, DPT entered into an amended and restated member control agreement with DPTS and PTS. The amended and restated member control agreement, among other things, incorporated all previous amendments and supplements, extended the initial term through December 31, 2021, and provided for the initial term to automatically extend in two-year intervals unless and until terminated. On August 30, 2012, the parties amended the amended and restated member control agreement to permit certain other ventures. On June 17, 2013, the parties further amended the amended and restated member control agreement to, among other things, extend the initial term through December 31, 2026. On December 31, 2013, the parties entered into the Second Amended and Restated Member Control Agreement (“Revised MCA”) that, among other things, named DPT as the Facility Management Member.

As a result of the Revised MCA, the Company accounted for this joint venture using the equity method of accounting through the end of business on December 31, 2013, at which time it was consolidated. Beginning January 1, 2014, the Company began including the operations of DPTS in its consolidated statements of operations. The Company’s share of income from the joint venture is included in other income on the consolidated statements of operations for periods ended December 31, 2013 and 2012. At December 31, 2013, the Company reflected the assets and liabilities of DPTS at carryover basis as summarized in the following table:


	As of December 31, 2013
Current Assets
Cash and Cash Equivalents	$	6,921,264
Other Current Assets		455,905
Due From Related Party		2,840,292
Other Receivables		68,896
Total Current Assets		10,286,357
Property and Equipment
Total Property and Equipment		49,771,156
Less – Accumulated Depreciation		1,205,880
Total Property and Equipment, net		48,565,276
Other Assets		402

Total Assets	$	58,852,035

Current Liabilities
Accounts Payable	$	7,998,082
Accounts Payable – Related Parties		722
Total Current Liabilities		7,998,804
Total Liabilities	$	7,998,804

Supplemental Agreement

In September 2010, the Company entered into a Supplemental Agreement to the DPTS member control agreement (“Supplemental Agreement”). The purpose of the Supplemental Agreement was to obtain access to site improvements and certain additional transloading equipment necessary to fulfill certain transloading contracts. Under this Supplemental Agreement the Company agreed to provide funds for the site improvements. The total costs incurred for these site improvements were $1,299,201. These costs have been capitalized as property and equipment in the accompanying consolidated balance sheets.

As part of the Supplemental Agreement, PTS was required to pay all costs for the acquisition of four new transloaders. The total cost of these transloaders was $658,012, with an estimated residual value of $131,602 at the end of the initial Agreement term for a net cost incurred of $526,410.

To reflect the economics of the $526,410 of costs incurred, the Company recognized rental income of $12,169 and $42,783 for the years ended December 31, 2013 and 2012, respectively. The rental income for the year ended December 31, 2014 was eliminated upon consolidation. No cash was received related to this rental income. The rental income recorded was treated as an increase in the Company’s investment in the joint venture.

F-12

In order to render fair and equitable the leases for the additional expenditures by the members relating to the site improvements and new equipment, the Supplemental Agreement included a provision that the Company would receive 75% of the cash distributions from DPTS until the Company had been reimbursed. The additional expenditures would also incur interest at an interest rate of 7% per annum until paid in full. After the Company was reimbursed and received the required interest, the cash distributions reverted back to the 50/50 split as per the original agreement. Only the cash distributions were changed under the Supplemental Agreement. The profit and loss allocations remained the same as the original member control agreement. As of December 31, 2014, the Company had been fully reimbursed for the additional expenditures related to the Supplemental Agreement.

In the first quarter of 2013, the Company settled an outstanding invoice related to the costs incurred as part of the Supplemental Agreement. The invoice was settled for $21,546 less than the original invoice amount. Based on this the total additional expenditures incurred by the Company were $772,791.

Rental income related to the Supplemental Agreement was $11,310 and $64,214 for the years ended December 31, 2013 and 2012, respectively. The rental income for the year ended December 31, 2014 was eliminated upon consolidation.

The Revised MCA, among other things, named DPT as the Facility Management Member. This assumption of control of the day-to-day operations resulted in a change in the Company’s method of accounting for the joint venture. Effective December 31, 2013, the Company consolidated the accounts of DPTS into its consolidated balance sheet. Beginning January 1, 2014, the Company began including the operations of DPTS in its consolidated statements of operations.

Summarized financial information of DPTS when accounted for as an equity method investment is as follows:


	Year Ended December 31,
	2013		2012

Sales	$	17,475,294	$	15,884,822
Net Earnings		7,926,044		6,491,033
Company’s Share of Equity in Net Earnings		3,963,022		3,245,516

Total Assets		-		13,652,679
Total Liabilities		-		2,617,257
Share of Equity in Net Assets		-		5,517,711

The balance sheet information as of December 31, 2014 and 2013 and the statement of operations information for the year ended December 31, 2014 has been excluded as they are included in the consolidated financial statements of the Company.

Pro Forma Information

The assumption of the control of day-to-day management of the operations was effective end of business December 31, 2013. Therefore, the operating results of DPTS have not been included on the Company’s consolidated statements of operations for the years ended December 31, 2013 and 2012. The following audited pro forma results of operations assume that the change in control of day-to-day management of the operations had been effective for the aforementioned periods. Such results are not necessarily indicative of the actual results of operations that would have been realized nor are they necessarily indicative of future results of operations.

These pro forma amounts have been calculated after adjusting for intercompany amounts. In addition, the equity earnings from the Company’s former non-controlling interest in DPTS have been removed.


	Year Ended December 31,
	2013			2012
Revenues	$	17,475,294		$	15,884,822
Net Income (Loss)		735,658			(79,153	)
Net Income Attributable to Non-Controlling Interest		2,461,022			1,921,517
Net Loss Attributable to Shareholders of Dakota Plains Holdings, Inc.		(1,725,364	)		(2,000,670	)

F-13

DPTS Marketing LLC

The Company, through its wholly owned subsidiary Dakota Plains Marketing, LLC, entered into a joint venture with PTS. The Company and PTS each owned 50% of the outstanding member units of DPTSM until the Company purchased the 50% ownership interest of PTS, effective November 30, 2014. The joint venture was formed 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 and to conduct trading activities.

Each of the members of DPTSM was required to make an initial capital contribution of $100. Each member received 1,000 member units for their initial capital contribution.

Each of the members of DPTSM was also required to make an initial Member Preferred Contribution of $10 million to support the trading activities of the joint venture. The Member Preferred Contributions made entitled the member to receive a cumulative preferred return of 5% per annum. At December 31, 2013, the Company reported a preferred dividend receivable of $252,057 on its consolidated balance sheet. In September 2013, the Company received a payment of $1.1 million related to the cumulative preferred return. This payment was for the cumulative preferred return from the date of the initial $10 million contribution through September 30, 2013. The cumulative preferred return for the period from October 1, 2013 through November 30, 2014 and the initial $10 million contribution were distributed to the Company as part of the Company’s purchase of the 50% ownership interest of PTS that was effective on November 30, 2014.

The operations of DPTSM commenced in May 2011. Under the member control agreement, the profits and losses of DPTSM were split 50/50, pro rata based on the number of member units outstanding. The cash payments from the joint venture were also paid pro rata based on the number of member units outstanding. The Company received its only priority cash distribution payments in April and June 2013.

On June 1, 2012, DPM entered into an amended and restated member control agreement with DPTSM and PTS. The amended and restated member control agreement, among other things, incorporated all previous amendment and supplements, extended the initial term through December 31, 2021, and provided for the initial term to automatically extend in two-year intervals unless and until terminated. On August 30, 2012, the parties amended the amended and restated member control agreement to permit certain other ventures. On June 17, 2013, the parties further amended the amended and restated member control agreement to extend the initial term through December 31, 2026. On December 31, 2013, the parties entered into the Second Amended and Restated Member Control Agreement that, among other things, increased the operating and accounting fees paid to the member who performs and is solely responsible for purchasing, selling, storing, transporting, marketing and transacting trades in North Dakota crude oil, and entering into related agreements and conducting related activities on behalf of DPTSM (“Trading Member”) and amended the limitations on its trading activities.

The Company accounted for this joint venture using the equity method of accounting until the date it purchased the 50% ownership interest of PTS. The Company’s share of the income or loss from the joint venture is included in other income on the consolidated statements of operations, and the Company recorded an investment in DPTSM on its consolidated balance sheet as of December 31, 2013.

Summarized financial statements of DPTSM when accounted for as an equity method investment is as follows:


	Period Ended November 30,			Year Ended December 31,
	2014			2013		2012
Sales	$	56,193,717		$	55,729,970	$	79,008,731
Net Earnings (Loss)		(710,529	)		5,923,344		20,821,192
Company’s Share of Equity in Net Earnings (Loss)		(355,265	)		2,961,672		10,410,596

Total Assets					33,523,175		49,399,386
Total Liabilities					10,605,497		5,587,792
Share of Equity in Net Assets					11,458,839		21,905,797

F-14

The balance sheet information as of December 31, 2014 has been excluded as it has been included in the consolidated financial statements of the Company.

The Company has included $2,840,292 in due from related party on its consolidated balance sheet as of December 31, 2013 related to amounts due from DPTSM for transloading services provided in November and December 2013. Effective November 30, 2014, the Company acquired the remaining ownership interest in DPTSM from PTS and immediately discontinued the purchase and sale of crude oil. We plan to maintain the current fleet of rail cars with the intent to sublease the cars and/or charge a throughput fee for utilizing the tank cars to transport crude oil.

Pro Forma Information

The Company accounted for this joint venture using the equity method of accounting until the date it purchased the 50% ownership interest of PTS. The Company’s share of the equity method income or loss from the joint venture is included in other income on the consolidated statements of operations, and the Company recorded an investment in DPTSM on its consolidated balance sheet as of December 31, 2013.

These pro forma amounts have been calculated after adjusting for intercompany amounts. In addition, the equity earnings from the Company’s former non-controlling interest in DPTSM have been removed.


	Year Ended December 31,
	2014			2013			2012
Revenues	$	70,619,811		$	56,079,342		$	79,275,214
Net Income		1,901,413			1,236,307			8,409,926
Net Income Attributable to Non-Controlling Interest		5,165,487			2,961,671			10,410,596
Net Income (Loss) Attributable to Shareholders of Dakota Plains Holdings, Inc.		(3,264,074	)		(1,725,364	)		(2,000,670	)

Dakota Plains Services, LLC

The Company, through its wholly owned subsidiary Dakota Plains Trucking, LLC, entered into a joint venture with JPND II, LLC (“JPND”). The Company and JPND each owned 50% of the outstanding member units of DPS until the Company sold its 50% ownership to JPND on November 24, 2014. The joint venture was formed to engage in the transportation by road of hydrocarbons and materials used or produced in the extraction of hydrocarbons to or from refineries and other end-users or persons, wherever located, and any other lawful activities as the board of governors determined from time to time.

JPND made an initial capital contribution of $650,000 to DPS. The Company was not required to make a capital contribution. Each member received 1,000 member units in DPS.

The member control agreement of DPS included a provision that JPND would receive all distributions from the joint venture until the aggregate amount of distributions received was equal to their initial capital contribution. The Company received no distributions during the year ended December 31, 2014.

The operations of DPS commenced in September 2012. Under provisions of the member control agreement the profits and losses of DPS were split 50/50, pro rata based on the number of member units outstanding.

The initial term of the joint venture was until December 31, 2022.

Prior to selling its ownership interest, the Company accounted for this joint venture using the equity method of accounting. The income or loss from the joint venture is included in other income on the consolidated statements of operations, and the Company recorded an investment in Dakota Plains Services, LLC on its consolidated balance sheet as of December 31, 2013. As required by GAAP, the Company recognized its pro rata share of the net income from DPS for the year ended December 31, 2014 and 2013, less the unrecognized losses from the period ended December 31, 2012. The Company did not recognize its share of the loss from DPS for the period ended December 31, 2012 in its consolidated statement of operations for the year ended December 31, 2012.

F-15

The unaudited financial statements of DPS are summarized as follows:


	Period Ended November 24,		Year Ended December 31,
	2014		2013		2012
Sales	$	17,607,524	$	15,420,096	$	1,336,482
Net Earnings (Loss)		1,213,954		452,761		(192,151	)
Company’s Share of Equity in Net Earnings (Loss)		606,977		130,305		-

Total Assets		-		9,945,720		3,136,159
Total Liabilities		-		9,126,495		2,469,833
Share of Equity in Net Assets		-		70,399		-

The balance sheet information as of December 31, 2014, has been excluded as the Company sold its ownership interest in DPS effective November 24, 2014.

Effective November 24, 2014, the Company sold its ownership interest in DPS for $1,150,000. The Company recorded a gain of $472,624 on the sale of its DPS ownership interest. The gain is included in other income (expense) on the consolidated statement of operations.

DPTS Sand, LLC

The Company, through its wholly owned subsidiary Dakota Plains Sand, LLC, entered into a joint venture with PTS. The Company and PTS each owned 50% of the outstanding member units of DPTS Sand, LLC until the date it purchased the 50% ownership interest of PTS. The joint venture was formed to engage in the operation of a sand transloading facility near New Town, North Dakota and any other lawful activities as the board of governors may determine from time to time.

Each of the members of DPTS Sand, LLC was required to make an initial capital contribution of $1,000. Each member received 1,000 member units for their initial capital contribution.

The operations of DPTS Sand, LLC commenced in June 2014. Under the member control agreement, the profits and losses of DPTS Sand, LLC were split 50/50, pro rata based on the number of member units outstanding. The cash payments from the joint venture were also paid pro rata based on the number of member units outstanding.

The initial term of the joint venture was until December 31, 2026.

As part of the member control agreement, the Company was the Facility Management Member of DPTS Sand, LLC. As the Facility Management Member, the Company was responsible for the day-to-day operations of DPTS Sand, LLC. Accordingly, the Company has consolidated the accounts of DPTS Sand, LLC with and into its consolidated financial statements since the inception of DPTS Sand, LLC.


4.	Lease Agreement – Related Party

The Company has an operating lease agreement with DPTS (See Note 3). Under the lease agreement, the Company received monthly lease payments of $19,161 through May 2012. Effective June 1, 2012, the operating lease agreement was amended to increase the monthly lease payment to $31,881. Effective January 1, 2013, the Company and DPTS increased the monthly lease payment to $60,470. Effective July 1, 2013, the Company and DPTS decreased the monthly lease payment to $48,162. Effective January 1, 2014, the Company and DPTS decreased the monthly lease payment to $38,162. The lease agreement includes provisions which allow the Company to collect additional rents if the Company incurs certain additional costs related to the equipment and the transloading facility. DPTS is responsible for all personal property and real property taxes upon the alterations and trade fixtures on the premises and the property during the term of the lease. DPTS is also responsible for all costs and expenses to perform all maintenance and repairs of the premises, pay all utilities and miscellaneous expenses and to acquire expansion, improvements or additions to the premises.

Prior to January 1, 2014, in accordance with equity method requirements described in Note 3, 50% of the rent payments received were recognized as rental income and 50% were included in income from investment in DPTS. Accordingly, $325,896 of the $651,792 in rent payments was recognized as rental income and $325,896 was included in income from investment in DPTS for the year ended December 31, 2013 and $159,486 of the $318,972 in rent payments was recognized as rental income and $159,486 was included in income from investment in DPTS or the year ended December 31, 2012. The rental income for the year ended December 31, 2014 was eliminated upon consolidation.

F-16


5.	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.


6.	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 Company. No shares of preferred stock have been issued as of December 31, 2014 and 2013.

In August 2012, the Company issued 3,125 shares of common stock to a member of its board of directors. These shares were valued at $25,000 or $8.00 per share, the market value of the shares of common stock on the date of issuance, and expensed as general and administrative expenses.

In February 2013, the Company issued 12,500 shares of common stock to an executive. These shares were valued at $50,000 or $4.00 per share, the market value of the shares of common stock on the date of issuance, and expensed as general and administrative expenses.

In June 2013, the Company issued 50,000 shares of common stock to an executive. These shares were valued at $185,000 or $3.70 per share, the market value of the shares of common stock on the date of issuance, and expensed as general and administrative expenses.

In June 2013, the Company issued an aggregate 308,108 shares of common stock to its non-employee directors. These shares were valued at $1,140,000 or $3.70 per share, the market value of the shares of common stock on the date of issuance, and expensed as general and administrative expenses.

In June 2013, 153,527 shares of common stock were surrendered by certain non-employee directors and an executive of the Company to cover tax obligations in connection with their stock awards. The total value of these shares was $568,058, which was based on the market price on the date the shares were surrendered.

In December 2013, the Company completed a registered direct offering of 7,000,000 shares of common stock at a price of $2.15 per share for total gross proceeds of $15,050,000. The Company incurred costs of $1,139,695 related to this offering. These costs were netted against the proceeds of the offering through additional paid in capital.

In December 2013, the Company issued 4,660,535 shares of common stock to satisfy $10,020,143 of its outstanding promissory notes at a price of $2.15 per share, the value of shares issued through the registered direct offering.

In December 2013, as part of the restructuring of the Company’s promissory notes, certain note holders surrendered 304,732 shares of common stock previously issued pursuant to the November 2, 2012, Amended Election, Exchange and Loan Agreement. The surrender of these shares was accounted for as decrease in common stock and an increase in additional paid in capital based on the $.001 par value of the shares.

In January 2014, the Company issued 236,739 shares of common stock to its executives and an employee pursuant to its 2011 Equity Incentive Plan. These shares were valued at $532,663, or $2.25 per share, the market value of the shares of common stock on the date of issuance, and have been expensed as general and administrative expenses.

In March 2014, the Company issued 50,498 shares of common stock to an executive and an employee pursuant to its 2011 Equity Incentive Plan. These shares were valued at $109,581, or $2.17 per share, the market value of the shares of common stock on the date of issuance, and have been expensed as general and administrative expenses.

In June 2014, the Company issued an aggregate 130,436 shares of common stock to its non-employee directors pursuant to its 2011 Equity Incentive Plan. These shares were valued at $300,000 or $2.30 per share, the market value of the shares of common stock on the date of issuance, and have been expensed as general and administrative expenses.

In November 2014, the Company issued 14,042 shares of common stock to a member of its board of directors pursuant to its 2011 Equity Incentive Plan. These shares were valued at $23,591 or $1.68 per share, the market value of the shares of common stock on the date of issuance, and expensed as general and administrative expenses.

In December 2014, the Company issued an aggregate 115,000 shares of commons stock to certain consultants, pursuant to its 2011 Equity Incentive Plan, for services rendered to the Company. These shares were valued at $187,450 or $1.63 per share, which was the market value of the shares of common stock on the date of issuance. They have been capitalized as finance cost and will be amortized over the term of the promissory notes with SunTrust.

F-17

During the year ended December 31, 2014, 297,749 shares of common stock were surrendered by certain executives and employees of the Company to cover tax obligations in connection with their fully vested and restricted stock awards. The total value of these shares was $645,679, which was based on the market price on the date the shares were surrendered.


7.	Stock-Based Compensation and Warrants

The Company accounts for stock-based compensation under the provisions of FASB ASC 718-10-55. This standard requires the Company to record an expense 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. For warrants and options granted to employees and directors, the Company uses the simplified method to determine the expected term due to the lack of sufficient historical data. Changes in these assumptions can materially affect the fair value estimate. The fair value of the warrants and options are recognized as compensation or interest expense over the vesting term.

Warrants

Warrants Granted November 1, 2012

On November 1, 2012, the Company issued warrants to a consultant, pursuant to a consulting agreement, to purchase a total of 50,000 shares of common stock exercisable at $3.28 per share. The total fair value of the warrants was calculated using the Black-Scholes option valuation model based on factors present at the time the warrants were issued. The warrants can be exercised at any time until the warrants expire on November 1, 2016. The consulting agreement terminated on November 1, 2013. The Company recorded general and administrative expense of $62,788 for the year ended December 31, 2013, related to these warrants.

Warrants Granted November 2, 2012

On November 2, 2012, in conjunction with the private placement of promissory notes (see Note 8), the Company issued warrants to purchase a total of 921,000 shares of common stock exercisable at $4.00 per share. The fair value of the warrants was reported as a debt discount and netted against the amount due on the promissory notes on the consolidated balance sheet. The warrants can be exercised at any time until the warrants expire in October 31, 2017.

Using the Black-Scholes option valuation model the Company determined the fair value of the warrants to be $1,264,985 and allocated the debt proceeds in accordance with the relative fair value method. The Company recorded a $1,048,889 discount on the promissory notes representing the allocation of the relative fair value to the warrants. The debt discount was being amortized over the term of the promissory notes. The unamortized debt discount was written off in December 2014 when the promissory notes were satisfied. For the years ended December 31, 2014, 2013 and 2012, the Company recognized interest expense of $640,985, $349,632 and $58,272, respectively, related to the amortization of this debt discount.

Warrants Granted January 1, 2013

On January 1, 2013, the Company issued warrants to a consultant, pursuant to a consulting agreement, to purchase a total of 100,000 shares of common stock exercisable at $3.25 per share. The total fair value of the warrants was calculated using the Black-Scholes option valuation model based on factors present at the time the warrants were issued. The warrants can be exercised at any time until the warrants expire on February 15, 2018. The consulting agreement terminated on May 31, 2013. The Company recorded general and administrative expense of $145,875 for the year ended December 31, 2013.

The following table presents the impact on the Company’s consolidated statements of operations for stock-based compensation expense related to warrants granted for the years ended December 31, 2014, 2013, and 2012:


	Year Ended December 31,
	2014		2013		2012
General and Administrative Expenses	$	-	$	223,100	$	67,174
Interest Expense		640,985		349,632		58,272

F-18

A summary of warrants granted for the years ended December 31, 2014, 2013 and 2012 is as follows:


	Number of Warrants			Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at January 1, 2012		4,150,000		$	0.66		8.3	$	13,866,750
Granted		971,000			3.96		-		-
Exercised		(2,450,000	)		0.285		-		-
Outstanding at December 31, 2012		2,671,000			2.10		5.60		3,490,000
Granted		100,000			3.25		-		-
Exercised		-			-		-		-
Outstanding at December 31, 2013		2,771,000			2.24		4.95		2,015,000
Granted		-			-		-		-
Exercised		-			-		-		-
Outstanding at December 31, 2014		2,771,000		$	2.24		3.95	$	1,475,000

For the years ended December 31, 2014, 2013 and 2012, other information pertaining to warrants is as follows:


	2014		2013		2012
Weighted-average grant-date fair value of warrants granted	$	-	$	1.46	$	1.37
Total intrinsic value of warrants exercised	$	-	$	-	$	26,276,250
Total grant-date fair value of warrants vested during the year	$	-	$	280,223	$	1,327,773

The following assumptions were used for the Black-Scholes option valuation model to value the warrants granted during the years ended December 31, 2014, 2013 and 2012.


	2014		2013			2012
Risk free rates		-		0.72	%		0.73	%
Dividend yield		-		0.00	%		0.00	%
Expected Volatility		-		51.97	%		48.70-49.8	%
Weighted average expected life		-		5 yrs.			4 - 5 yrs.

The table below reflects the status of warrants outstanding at December 31, 2014:


	Warrants		Exercise Price		Expiration Date
February 1, 2011		1,000,000	$	0.285		January 31, 2021
February 22, 2011		600,000	$	2.50		February 22, 2016
April 5, 2011		100,000	$	2.50		April 5, 2016
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
Total		2,771,000

Stock Options

Effective January 16, 2014, certain executives and outside directors of the Company agreed to surrender the 415,625 stock options granted to them in prior periods. There are no options outstanding at December 31, 2014.

On August 14, 2012, the Company granted 15,625 options to a member of its board. The options were granted at a price of $8.00 and the optionee was fully vested on the grant date. The total fair value of the options was calculated using the Black-Scholes option valuation model based on factors present at the time the options were granted. The Company recognized $24,047 of expense related to these options in the year ended December 31, 2012.

In February 2013, the Company granted stock options under its 2011 Equity Incentive Plan to its Chief Executive Officer to purchase a total of 200,000 shares of common stock exercisable at $4.07 per share. The total fair value of the options was calculated using the Black-Scholes option valuation model based on factors present at the time the options were granted. The options were to vest over 36 months with 66,666 options vesting on February 8, 2014 and 66,667 vesting on February 8, 2015 and 2016. The Company recognized $169,939 of expense related to these options in the year ended December 31, 2013.

F-19

The following table presents the impact on the Company’s consolidated statements of operations for stock-based compensation expense related to options granted for the years ended December 31, 2014, 2013, and 2012:


	Year Ended December 31,
	2014		2013		2012
General and Administrative Expenses	$	-	$	169,939	$	24,047

A summary of options for the years ended December 31, 2014, 2013 and 2012 is as follows:


	Number of Options			Weighted Average Exercise Price		Remaining Contractual Term (in Years)		Intrinsic Value
Outstanding at January 1, 2012		250,000		$	2.50		4.8	$	1,375,000
Granted		15,625			8.00		-		-
Exercised		-			-		-		-
Forfeited or Expired		(50,000	)		2.50		-		-
Outstanding at December 31, 2012		215,625			2.90		3.9		150,000
Granted		200,000			4.07		-		-
Exercised		-			-		-		-
Forfeited or Expired		-			-		-		-
Outstanding at December 31, 2013		415,625			3.46		5.0		-
Granted		-			-		-		-
Exercised		-			-		-		-
Forfeited or Expired		(415,625	)		3.46		-		-
Outstanding at December 31, 2014		-		$	-		-	$	-

Stock Options Exercisable at December 31, 2012		215,625		$	2.90		3.9	$	150,000
Stock Options Exercisable at December 31, 2013		215,625		$	2.90		2.9	$	-
Stock Options Exercisable at December 31, 2014		-		$	-		-	$	-

For the years ended December 31, 2014, 2013, and 2012, other information pertaining to stock options was as follows:


	2014		2013		2012
Weighted-average per share grant-date fair value of stock options granted	$	-	$	1.63	$	1.54
Total grant-date fair value of stock options vested during the year	$	-	$	-	$	24,047

The following assumptions were used for the Black-Scholes option valuation model to value the options granted during the years ended December 31, 2014, 2013, and 2012:


	2014		2013			2012
Risk free rates		-		0.84	%		0.27	%
Dividend yield		-		0.00	%		0.00	%
Expected volatility		-		39.14-52.43	%		30.35	%
Weighted average expected life		-		4 - 5 yrs.			2.5 yrs.

Restricted Stock Awards

During the years ended December 31, 2014, 2013, and 2012 the Company issued 589,483, 794,063 and 38,437 restricted shares of common stock, respectively, as compensation to officers, employees and consultants of the Company. The restricted shares vest over various terms with all restricted shares vesting no later than March 2017. As of December 31, 2014, there was $1.9 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense will be recognized over the weighted average period of 1.5 years. The Company has assumed a zero percent forfeiture rate for restricted stock. The Company recorded general and administrative expense of $1,364,816, $1,285,066 and $384,376 for the years ended December 31, 2014, 2013 and 2012, respectively.

F-20

The following table reflects the outstanding restricted stock awards and activity related thereto for the years ended December 31, 2014, 2013 and 2012:


	For the Year Ended:
	December 31, 2014					December 31, 2013					December 31, 2012
	Number of Shares			Weighted Average Price		Number of Shares			Weighted Average Price		Number of Shares			Weighted Average Price
Restricted Shares Outstanding
Beginning of Year		769,063		$	3.82		568,437		$	1.36		550,000		$	1.02
Shares Granted		589,483			2.22		794,063			3.81		38,437			6.63
Lapse of Restrictions		(327,396	)		3.88		(593,437	)		1.46		(20,000	)		2.13
Restricted Shares Outstanding		1,031,150		$	2.89		769,063		$	3.82		568,437		$	1.36


8.	Promissory Notes

On December 5, 2014, the Company and its wholly owned subsidiaries (“Borrowers”) entered into a $57.5 million Revolving Credit and Term Loan Agreement (“Credit Agreement”) with SunTrust Bank (“Administrative Agent”). 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”). There was $48.5 million outstanding under the Credit Facility at December 31, 2014.

At the Borrowers’ option, borrowings under the Credit Facility may be either (i) the “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 requires the Company to maintain a minimum fixed charge coverage ratio and a maximum total debt to EBITDA (earnings before income taxes, depreciation expense and amortization), or leverage ratio. The method of calculating all of the components used in the covenants is included in the Credit Agreement. The Company was in compliance with all required covenants as of December 31, 2014.

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 proceeds from the Credit Facility were utilized to (i) pay in full the existing loans evidenced by those certain Senior Unsecured Promissory Notes due on October 31, 2015 and terminate the Company’s obligations thereunder, (ii) terminate the credit agreement dated as of June 17, 2013 between DPT and World Fuel Services Corporation (“WFS”) and pay in full the existing loan made pursuant thereto, and (iii) purchase the remaining membership interests of PTS in DPTS, DPTSM and DPTSS.

F-21

The Company incurred finance costs of $1,617,909 related to the Credit Agreement. These costs were capitalized and will be amortized over the term of the Credit Agreement using the straight-line method, which approximates the effective interest method. For the year ended December 31, 2014, the Company recognized interest expense of $80,144 related to these finance costs.

Senior Unsecured Promissory Notes

On November 1, 2011, the Company entered into an Exchange and Loan Agreement with the holders of certain senior and junior promissory notes (“Old Notes”). As part of the Exchange and Loan Agreement the holders of the Old Notes agreed to exchange their notes for new promissory notes. The total value of these new notes was $9 million and all unpaid accrued interest and principal were payable on March 1, 2013 (the “New Notes”). The New Notes bore interest at the rate of 12% per annum, with interest payable in arrears on the last day of each fiscal quarter.

The New Notes included an additional payment provision that was considered and embedded derivative. In May 2012, the embedded derivative was satisfied with the issuance of promissory notes in the aggregate amount of $27,663,950 and 1,296,963 shares of the Company’s common stock. The increase in the fair value of the embedded derivative during the year ended December 31, 2012, $27,311,800, was recorded as interest expense on the consolidated statement of operations.

Private Placement of Debt

On November 2, 2012, the Company issued promissory notes in the amount of $6,140,000. The issuance of these promissory notes resulted in proceeds to the Company of approximately $5,945,000, net of commissions and finance costs paid. The promissory notes bore interest at the rate of 12% per annum.

In conjunction with the issuance of the promissory notes, the Company issued warrants to purchase 921,000 shares of our common stock, exercisable at $4.00 per share. The warrants expire on October 31, 2017.

The Company recorded $1,048,889 of debt discount against these promissory notes representing the allocation of the relative fair value to the warrants issued (see Note 7). The debt discount was being amortized over the term of the promissory notes using the straight-line method, which approximated the effective interest method. The unamortized debt discount was written off in December 2014 when the promissory notes were satisfied. For the years ended December 31, 2014, 2013 and 2012, the Company recognized interest expense of $640,985, $349,632 and $58,272, respectively, related to this debt discount.

The Company incurred finance costs of $195,062 related to these notes, which was being amortized over the term of the notes and included in interest expense on the consolidated statement of operations. The unamortized finance cost was written off in December 2014 when the promissory notes were satisfied. The interest expense recorded for the years ended December 31, 2014, 2013 and 2012 was $119,202, $65,021 and $10,839, respectively.

Amended Election, Exchange and Loan Agreements

In addition, on November 2, 2012, pursuant to the Amended Election, Exchange and Loan Agreements, the Company repaid the outstanding principal to a holder of the New Notes in the amount of $500,000. The term of the remaining $8.5 million in New Notes was extended using two different maturity dates. $4,605,300 of the New Notes was extended to March 1, 2014 and $3,894,700 was extended to October 31, 2015. All of the holders of the New Notes agreed to surrender and void the $27,663,950 of promissory notes and 1,296,963 shares of the Company’s common stock received April 21, 2012, related to the additional payment provision in the New Notes.

As a result of the revaluation of the additional payment provision and revised elections of the holders, the Company issued promissory notes in the aggregate of $11,965,300 and 1,757,075 shares of its common stock. The promissory notes bore interest at the rate of 12% per annum.

Gain on Extinguishment of Debt – Year Ended December 31, 2012

The Company assessed the impact of the Amended Election, Exchange and Loan agreements and whether it should be accounted for as an extinguishment of debt and the issuance of new debt or a modification of the existing debt. The present value of the remaining payments was substantially different than the present value of the original agreements. Therefore, the Company reported the transaction as an extinguishment of debt. Since the exchange was accounted for as an extinguishment of debt, the decrease in fair value of the Company’s liabilities (net of cost incurred and the increased fair value of the common stock issued) was reported as gain on extinguishment of debt on the consolidated statement of operations.

F-22

Adjustment, Extension and Loan Agreement

On December 10, 2013, the Company entered into an Adjustment, Extension and Loan Agreement (“Loan Agreements”) with each of the holders of the Company’s New Notes, pursuant to which the Company issued new debt securities in connection with an extension and reduction of the outstanding debt.

Pursuant to the Loan Agreements, the holders of the New Notes due March 1, 2014 agreed to extend the maturity dates of such notes to September 30, 2014.

In addition, the holders of the promissory notes issued under the Amended Election, Exchange and Loan Agreements agreed to revalue the additional payment provision. This revaluation resulted in a reduction of the principal amount of the promissory notes by $1,945,156. In connection with the Loan Agreements, in exchange for the original promissory notes issued, the Company issued $10,020,143 principal amount of 12% amended and restated senior unsecured promissory notes due October 31, 2015. Additionally, the holders agreed to surrender 304,732 shares of the Company’s common stock issued as part of the Amended Election, Exchange and Loan Agreements. The surrender of these shares was accounted for as decrease in common stock and an increase in additional paid in capital based on the $.001 par value of the shares. The amended and restated senior unsecured promissory notes bore interest at the rate of 12% per annum.

The Loan Agreements also provided that, if the Company completes a sale of not less than $5.0 million worth of capital stock, either registered or through a private placement (a “Qualified Equity Placement”), on or before December 10, 2015, the Company would use not less than 50% of the proceeds from such sale to repay, pro rata in order of maturity, all or a portion of the promissory notes due September 30, 2014 and $3,894,700 principal amount of New Notes due October 2015. Additionally, if the Company completed a Qualified Equity Placement on or before December 10, 2014, then, the Company could elect to convert $10,020,143 aggregate principal amount of the amended and restated senior unsecured promissory notes due October 2015 into shares of common stock at the per-share price used in the Qualified Equity Placement. The registered direct offering of the Company’s common stock, which closed on December 16, 2013, was a Qualified Equity Placement, and the Company exercised the right to convert the amended and restated senior unsecured promissory notes due October 2015, which resulted in the issuance of 4,660,535 additional shares of the Company’s common stock based on an offering price of $2.15 per share.

The Company also repaid the outstanding principal on the $4,605,300 of the promissory notes due September 30, 2014 and $2,317,383 of outstanding principal on New Notes with a maturity of October 31, 2015.

Gain on Extinguishment of Debt – Year Ended December 31, 2013

The Company assessed the impact of the Adjustment, Extension and Loan Agreement and whether it should be accounted for as an extinguishment of debt and the issuance of new debt or a modification of the existing debt. The present value of the remaining payments was substantially different than the present value of the original agreements. Therefore, the Company reported the transaction as an extinguishment of debt. Since the exchange was accounted for as an extinguishment of debt, the decrease in fair value of the Company’s liabilities (net of cost incurred) was reported as gain on extinguishment of debt of $1,726,515, or $0.04 per share, on the consolidated statement of operations.

Pioneer Terminal

In June 2013, DPT (“Borrower”) entered into a credit agreement with WFS. The agreement provided the Borrower with a $20 million delayed draw term loan facility (the “Facility”) to finance the Borrower’s share of improvements to be made to the Pioneer Terminal in New Town, North Dakota. The Facility was secured by a mortgage on a majority of the land owned by the Company in New Town, North Dakota as well as a pledge of the equity owned by the Borrower in DPTS.

The Facility bore interest at a rate per annum equal to nine percent (9%). There was $7.5 million outstanding under the Facility at December 31, 2013.

The Company incurred finance costs of $9,783 related to the agreement, which was amortized and included in interest expense on the consolidated statement of operations. The interest expense recorded for the years ended December 31, 2014 and 2013 was $4,076 and $5,707, respectively.

F-23

The Senior Unsecured Promissory Notes and credit agreement with WFS were paid in full and terminated when the Company entered into the Revolving Credit and Term Loan Agreement with SunTrust Bank on December 5, 2014.

The annual maturities related to the Revolving Credit and Term Loan Agreement are as follows:


Year Ending December 31,	Amount
2015	$	23,250,000
2016		1,500,000
2017		23,750,000
Total		48,500,000
Less: Current Portion		23,250,000
Total Long-Term Portion	$	25,250,000


9.	Income Taxes

The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with FASB ASC 740-10-30. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

The income tax benefit for the years ended December 31, 2014, 2013, and 2012 consists of the following:


	2014			2013			2012
Current Income Taxes
Federal	$	-		$	(879,000	)	$	879,000
State		12,007			(149,000	)		152,459

Deferred Income Taxes
Federal		(1,148,000	)		(8,000	)		(2,188,000	)
State		(25,000	)		(18,000	)		(224,000	)
Increase in Valuation Allowance		306,000			-			-

Total benefit	$	(854,993	)	$	(1,054,000	)	$	(1,380,541	)

The following is a reconciliation of the reported amount of income tax benefit for the years ended December 31, 2014, 2013 and 2012 to the amount of income tax benefit that would result from applying the statutory rate to the pretax loss.

Reconciliation of reported amount of income tax benefit:


	Year Ended December 31,
	2014			2013			2012
Net income (loss) before taxes and NOL	$	1,401,685		$	(2,779,364	)	$	(3,381,211	)
Federal statutory rate		35	%		35	%		35	%
Tax provision (benefit) computed at federal statutory rates		490,000			(973,000	)		(1,183,000	)
State taxes, net of federal taxes		(121,000	)		(106,000	)		(120,000	)
Non-deductible compensation		169,000			-			-
Other		178,007			25,000			(77,541	)
Net income attributable to non-controlling interest		(1,877,000	)
Change in valuation allowance		306,000			-			-
Reported benefit	$	(854,993	)	$	(1,054,000	)	$	(1,380,541	)

F-24

The components of the Company’s deferred tax assets were as follows:


	Year Ended December 31,
	2014			2013
Deferred Tax Assets (Liabilities)
Current:
Deferred rent	$	-		$	10,000
Prepaid expenses		(30,000	)		(18,000	)
Net operating loss		1,897,000			3,866,000
Warrants issued as debt discount		-			(135,000	)
Goodwill		399,000			-
Other		-			5,000
Total Current		2,266,000			3,728,000

Non-Current:
Fixed assets		(3,864,000	)		(403,000	)
Share based compensation		695,000			632,000
Investment in Dakota Petroleum Transport Solutions, LLC		-			(3,677,000	)
Investment in Dakota Plains Services, LLC		-			(27,000	)
Warrants issued as debt discount		-			(113,000	)
Deferred rent		-			117,000
Net operating loss		7,500,000			3,618,000
Goodwill		5,791,000			-
Operational override liability		16,946,000			-
Other		-			6,000
Valuation allowance		(306,000	)		-
Total Non-Current		26,762,000			153,000

Total Deferred Tax Assets (Liabilities)	$	29,028,000		$	3,881,000

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 income tax benefit. For the years ended December 31, 2014, 2013 and 2012, the Company did not recognize any interest or penalties in the consolidated statement of operations, nor did it have any interest or penalties accrued in the consolidated balance sheet at December 31, 2014 and 2013 relating to unrecognized benefits.

The Company reported a net operating loss (“NOL”) carry forward for federal tax purposes of approximately $24.3 million and $19.3 million at December 31, 2014 and 2013, respectively. The net operating loss carry forward that was generated in the year ended December 31, 2013 was caused by the Company’s pro rata share of the bonus depreciation that DPTS recorded related to the Pioneer Terminal for income tax purposes. The Company anticipates taxable income beginning in the year ending December 31, 2015 and going forward based on its recent purchase of PTS’s ownership interests in DPTS and DPTS Sand, LLC and the more favorable terms of the debt with SunTrust. As part of the transaction to purchase the membership units owned by PTS, the Company recorded Goodwill for income tax purposes for the amount that the purchase price exceeded the fair value of the assets acquired. The Company has recorded a deferred tax asset for the tax Goodwill in the amount of $6.2 million at December 31, 2014. This deferred tax asset will be reduced as the Company amortizes the Goodwill. In addition, the Company has recorded a deferred tax asset of $16.9 million for the operational override liability. The liability will be reduced for book purposes when paid and recorded as a taxable deduction at the time of payment. The deferred tax asset will be reduced as these payments are made.

The Company reported a net deferred tax asset of $29,028,000 on its consolidated balance sheet as of December 31, 2014. GAAP requires 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. The Company reported a valuation allowance of $306,000 at December 31, 2014 related to state net operating loss carry forwards. The Company accumulated net operating losses in states other than North Dakota due to the operations of DPTSM. The Company will no longer file tax returns in these states now that the operations of DPTSM have been discontinued.

The 2013, 2012 and 2011 tax years remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject.


10.	Operating Lease

Effective May 1, 2013, the Company entered into an operating lease agreement on 3,781 square feet of office space. The lease requires initial base monthly lease payments of $6,302. The base annual lease payments increase by $1 per square foot on June 1 of 2014, 2015 and 2016. The lease expires on May 31, 2017. The Company is also responsible for a pro rata share of real estate taxes and general operating expenses. Total rent expense under the agreement was approximately $138,000 and $82,000 for the years ended December 31, 2014 and 2013, respectively.

F-25

Minimum future base lease payments under the building lease are as follows:

See Note 13 for additional operating lease commitments related to the Railcar Sublease Agreements.


11.	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 because of 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.


12.	Fair Value

FASB ASC 820-10-55 defines fair value, establishes a framework for measuring fair value under GAAP and enhances disclosures about fair value measurements. Fair value is defined under FASB ASC 820-10-55 as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value under FASB ASC 820-10-55 must maximize the use of observable inputs and minimize the use of unobservable inputs. The standard describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value.

As of December 31, 2013, the Company had no financial instruments measured at fair value on a recurring basis in the consolidated balance sheet. Level 2 liabilities consist of the promissory notes (see Note 8).

The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the consolidated balance sheet as of December 31, 2014:

Fair Value Measurements at December 31, 2014 Using


	Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Operational Override Liability - Current Liability	$	-	$	-	$	(715,497	)
Operational Override Liability – Non-Current Liability		-		-		(44,595,370	)
Total Operational Override Liability	$	-	$	-	$	(45,310,867	)

The level 3 liability consists of the contingent liability related to the Operational Override (See Note 13). There were no transfers between any of the fair value levels during the years ended December 31, 2014 and 2013.

The following table provides a reconciliation of the beginning and ending balances for the liability measured at fair value using significant unobservable inputs (Level 3) during the year ended December 31, 2014:

Fair Value Measurements at Reporting Date Using Significant Unobservable Inputs
(Level 3)


	Level 3 Financial Liabilities
Balance at December 31, 2013	$	-
Additions to – Operational Override Liability		(45,310,867	)
Balance at December 31, 2014	$	(45,310,867	)

F-26


13.	Membership Interest Purchase Agreement

On December 5, 2014, the Company entered into a Membership Interest Purchase Agreement with DPT, Dakota Plains Sand, LLC, DPM and PTS. Pursuant to the Membership Interest Purchase Agreement, in exchange for $43 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, Dakota Plains Sand, LLC 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 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 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 million, then the Company is obligated to pay PTS the difference on or before January 31, 2027.

At any time the Company may pay PTS an amount equal to the then-present value (using a nine percent (9%) 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.

The Membership Interest Purchase Agreement contains certain representations, warranties, covenants and indemnification obligations of the parties.

In connection with the Membership Interest Purchase Agreement, the Company entered into an Indemnification and Release Agreement dated December 5, 2014 with WFS (the “Indemnification and Release Agreement”). Pursuant to the Indemnification and Release Agreement, WFS, on behalf of itself and its direct and indirect subsidiaries, agreed to indemnify the Company, DPTS, DPTSM, and each of their respective officers, managers, directors, employees, affiliates, members, and stockholders, for third party claims in connection with, relating to, or otherwise arising from the train car derailment that occurred in Lac-Mégantic, Quebec, on July 6, 2013 (the “Derailment”). In addition, the Company, DPT and DPM, on behalf of itself and each such entity’s direct and indirect subsidiaries, agreed to indemnify WFS and WFS’s officers, managers, directors, employees, affiliates, members, and stockholders for (i) fifty percent (50%) of the documented out-of-pocket costs and expenses incurred by any WFS party as a result of or arising out of certain obligations to railcar lessors; and (ii) fifty percent (50%) of the documented out-of-pocket defense costs and legal expenses incurred by any WFS party in connection with the Derailment. The Company and its affiliates’ total exposure under the indemnification is limited to $10 million in the aggregate. The indemnification obligations are net of any insurance proceeds received. To support its indemnification obligations, the Company placed $3 million of cash in escrow, which is included on the consolidated balance sheet as of December 31, 2014.

In connection with the indemnification, each of the Company and WFS, on its behalf and on behalf of its affiliates, released the other party and its affiliates from any claims arising in connection with the Derailment, other than those for which indemnification is provided under the Indemnification and Release Agreement.

Pursuant to a Guaranty and Security Agreement, dated December 5, 2014 (the “Seller Guaranty and Security Agreement”), made by DPT, Dakota Plains Sand, LLC, DPM, the Company and certain subsidiaries of the Company, the Company’s obligations under Section 2.2(b) of the Membership Interest Purchase Agreement in respect of the Operational Override, the Company’s obligations in the Indemnification and Release Agreement and the obligations of DPTSM under five Amended and Restated Railcar Sublease Agreements between DPTSM and Western Petroleum Company are guaranteed by DPT, Dakota Plains Sand, LLC, DPM, the Company and certain subsidiaries of the Company, and are secured by a second priority lien on all of the assets of such parties.

F-27

In connection with the Membership Interest Purchase Agreement, the following agreements were terminated: (a) that certain Member Control Agreement of DPTS Sand, LLC, effective as of June 1, 2014, by and among Dakota Plains Sand, LLC, PTS, and DPTS Sand, LLC; (b) that certain Second Amended and Restated Member Control Agreement of DPTS effective as of December 31, 2013, by and among DPT, PTS and DPTS; and (c) that certain Second Amended and Restated Member Control Agreement of DPTSM, effective as of December 31, 2013, by and among DPM, PTS, and DPTSM; provided DPM and its affiliates will remain subject to the restrictions against purchasing, selling, storing, transporting or marketing crude oil originating from production fields anywhere in North Dakota, or conducting any trading activities related thereto, until June 5, 2015, but shall be permitted to sublease and lease-for-trip railcars to transport crude oil, and transport any other materials (including crude oil) by road.

Operational Override

As part of the Membership Interest Purchase Agreement, the Company agreed to pay a quarterly Operational Override payment to PTS through December 31, 2026. The payments are due within 45 days of the end of each calendar quarter. In the event such Operational Override payments, in the aggregate, are less than $10 million, then the Company is obligated to pay PTS the difference on or before January 31, 2027.

The Company calculated an initial liability of $45.3 million related to the Operational Override. The initial Operational Override was calculated based on the Company’s estimated daily throughput from December 1, 2014 through December 31, 2026; discounted at an interest rate of 9%.

Annual maturities of the Operational Override are as follows:


	Year Ending December 31,	Amount
2015		$	715,497
2016			1,383,232
2017			2,792,970
2018			3,054,970
2019			3,341,547
Thereafter			34,022,651
Total			45,310,867
Less: Current Portion			715,497
Total Long-Term Portion		$	44,595,370

Railcar Sublease Agreements

As part of the Membership Interest Purchase Agreement, the Company, through DPTSM, entered into five Amended and Restated Railcar Sublease Agreements with Western Petroleum Company (“Amended Sublease Agreements”). Under the Amended Sublease Agreements, DPTSM will sublease 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 shall be 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 delivered to DPTSM a certain set of railcars as identified in a schedule included with the Amended Sublease Agreements. For the period (the “Suspension Period”) beginning on the Effective Date and ending on June 1, 2015 (the “Suspension Termination Date”), the Amended Sublease Agreements as they relate to certain other railcars identified in an additional schedule (the “Suspended Cars”) shall be temporarily suspended to permit Western Petroleum Company to retain the Suspended Cars. No later than 30 days after the Suspension Termination Date, Western Petroleum Company will deliver the Suspended Cars to DPTSM at the Company’s transloading facility located in New Town, North Dakota, unless an alternate location is agreed to. The Amended Sublease Agreements are being accounted for as operating leases.

DPTSM assumes and accepts 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. The total lease expense under the Amended Sublease Agreements was approximately $275,000 for the year ended December 31, 2014.

Minimum future base lease payments under the Amended Sublease Agreements are as follows:


	Year Ending December 31,	Amount
2015		$	5,731,000
2016			6,295,000
2017			3,246,000
2018			2,836,000
2019			2,350,000
2020-2021			2,714,000
Total		$	23,172,000

F-28

Equity Transaction

There was no value assigned to the Company’s purchase of DPTSM. The Company’s purchase of PTS’s membership interest in DPTS and DPTS Sand, LLC was accounted for as an equity transaction in accordance with FASB ASC 810-45-23. Under ASC 810-45-23, changes in a parent’s ownership interest while the parent retains its controlling interest in its subsidiary shall be accounted for as equity transactions. As an equity transaction, the Company reported any difference between the fair value of the consideration paid and the amount by which the non-controlling interest of DPTS and DPTS Sand, LLC was adjusted was recognized in additional paid-in capital. The amount recognized in additional paid-in capital as of December 31, 2014 was calculated as follows:


Cash Consideration Paid	$	43,000,000
Direct Cost of Transaction		1,225,953
Fair Value of Contingent Liability		45,310,867
Total Purchase Price		89,536,820

Deferred Tax Asset Recorded		24,114,000
Fair Value of Consideration Paid		65,422,820

Non-Controlling Interest – DPTS		25,982,992
Non-Controlling Interest – DPTS Sand, LLC		-
Total Adjustment to Additional Paid-In Capital	$	39,439,828


14.	Merger Agreement

As of March 22, 2012, the issued and outstanding common stock of Dakota Plains before the Initial Merger was converted into the right to receive an aggregate of 37,014,018 shares of the Company’s common stock, all of which were “restricted securities” under Rule 144. Of those shares, 530,000 were restricted shares of the Company’s common stock issued under certain employment agreements in exchange for 530,000 shares of similarly restricted Dakota Plains’ common stock. In addition, the outstanding options issued by Dakota Plains before the Initial Merger were converted into options to purchase an aggregate of 250,000 shares of the Company’s common stock and the outstanding warrants issued by Dakota Plains before the Initial Merger were converted into warrants to purchase an aggregate of 4,150,000 shares of the Company’s common stock. The shareholders of the Company before the Initial Merger retained 640,200 shares of common stock, representing approximately 1.7% of its outstanding shares of common stock immediately after the Initial Merger.

In March 2012, Dakota Plains Holdings, Inc., the surviving corporation from the Initial Merger and then a wholly owned subsidiary of the Company, merged with and into MCT Holding Corporation (the “Second Merger”). Pursuant to the plan of merger governing the Second Merger, the Company changed its name from “MCT Holding Corporation” to “Dakota Plains Holdings, Inc.”


15.	Commitments and Contingencies

Lac-Mégantic, Quebec

We and certain of our subsidiaries, including DPTS and DPTSM, are among the many defendants named in various lawsuits relating to the derailment of a Montreal Main & Atlantic Railroad, Ltd. (“MM&A”) train in Lac-Mégantic, Quebec. We believe all claims asserted against us and our subsidiaries are without merit and we intend to vigorously defend against such claims.

F-29

Around July 29, 2013, nineteen individuals filed lawsuits in Cook County, Illinois seeking unspecified damages for their injuries from the accident. The lawsuits assert claims for negligence against the eight defendants noted above. On August 7, 2013, MM&A filed a Chapter 11 voluntary petition in the bankruptcy court in Maine. On August 29, 2013, the defendants jointly removed the cases from state court in Cook County to the United States District Court in the Northern District of Illinois. On September 13, 2013, the bankruptcy trustee for MM&A, and WFS and Petroleum Transport Solutions, LLC filed motions seeking to transfer the nineteen personal injury cases from federal court in Illinois to the United States District Court for the District of Maine (the “ME District Court”). On March 21, 2014, the ME District Court granted the transfer motion. On April 4, 2014, the plaintiffs filed a motion for reconsideration of the order granting the transfer motion and a motion requesting the ME District Court abstain from exercising jurisdiction over the cases. The motion for reconsideration was denied and the motion for abstention remains pending. On May 1, 2014, the plaintiffs appealed the ME District Court’s order granting the transfer motion to the First Circuit Court of Appeals. On June 17, 2014, the ME District Court entered a consent order staying proceedings in the transferred cases pending the appeal. On September 25, 2014, the First Circuit Court of Appeals ordered plaintiffs to voluntarily dismiss their appeal or show cause why their appeal should not be dismissed for lack of jurisdiction. The parties have responded to the First Circuit’s order to show cause, and its decision is pending.

As a result of the Lac-Mégantic derailment, the Canadian Transportation Safety Board is conducting an investigation into the cause of the derailment and the events surrounding it. In addition, the Quebec police are conducting a criminal investigation and are reported to be coordinating with Canadian and U.S. law enforcement authorities.

On December 5, 2014, we entered into an Indemnification and Release Agreement with WFS. Under this agreement, WFS, on behalf of itself and its direct and indirect subsidiaries, has agreed to indemnify us, each of our subsidiaries, including DPTS and DPTSM, for third party claims for bodily injury, death, property damage, economic loss, loss of consortium, loss of income and similar claims in connection with, relating to, or otherwise arising from the derailment, in each case solely to the extent not covered by insurance or otherwise paid for by third parties. In addition, we agreed to indemnify WFS for (i) fifty percent (50%) of the documented out-of-pocket costs and expenses incurred by any WFS party as a result of or arising out of certain obligations to railcar lessors; and (ii) fifty percent (50%) of the documented out-of-pocket defense costs and legal expenses incurred by any WFS party in connection with the derailment not otherwise covered by insurance. However, our total exposure under this indemnification is limited to $10 million in the aggregate. All of the indemnification obligations are net of any insurance proceeds received.

F-30

Dakota Petroleum Transport Solutions, LLC

TJMD, LLP v. Dakota Petroleum Transport Solutions, LLC

Since October 2012, DPTS has been involved in litigation with TJMD, LLP, a North Dakota limited liability partnership (“TJMD”) arising out of the termination of TJMD as operator of the transloading facility, which DPTS leases for the use and benefit of their business. TJMD alleges that a wrongful termination without cause on 90-days written notice occurred in June 2012 under the implied covenant of good faith and fair dealing, and a second wrongful termination occurred in September 2012, when DPTS finally terminated the contract before the end of the 90-day period. TJMD is seeking payment for work performed prior to the final, September termination, as well as, monetary damages for future losses, and other relief. Because the outcome of litigation is inherently uncertain, DPTS cannot estimate the possible loss or range of loss for this matter. DPTS intends to vigorously defend against this claim. As of December 31, 2014, DPTS has not recorded any accruals associated with this legal claim.

Dakota Petroleum Transport Solutions, LLC v. TJMD, LLP, et al.

Since April 2013, DPTS has been involved in litigation with TJMD, Rugged West Services, LLC, a foreign limited liability company (“Rugged West”), and JT Trucking, a foreign limited liability company (“JT”), arising out of crude oil spills that occurred at DPTS’s transloading facility while TJMD was operating the facility. DPTS leases the facility for the use and benefit of their business. Trucks haul crude oil to the transloading facility where crude is moved onto railcars and shipped to various locations across the country. DPTS has asserted a claim against TJMD for contractual liability because TJMD must indemnify DPTS for cleanup and remediation expenses incurred as the result of the crude oil spills, based on Service Agreements TJMD entered into with DPTS which provide for contractor indemnification. DPTS has asserted claims against TJMD, Rugged West and JT for negligence in causing or allowing the spills to occur which proximately caused damages to DPTS, entitling DPTS to recovery. DPTS has also asserted claims against TJMD, Rugged West and JT for trespass and nuisance, claiming the defendants exceeded the consent to be on the property, entitling DPTS to recovery.

DPTS prevailed on a summary judgment motion against JT Trucking, LLC, due to JT’s failure to Answer or otherwise appear in the matter. DPTS continues to actively attempt to recover cleanup and remediation costs on a spill-by-spill basis from each of the trucking companies involved in the specific spills, and also from TJMD. Because the outcome of litigation is inherently uncertain, we cannot estimate the possible recovery for this matter at this time. DPTS is vigorously pursuing its claims.

See Notes 10 and 13 for discussion of lease commitments and Operational Override commitment.

F-31


16.	Subsequent Events

In connection with preparing the audited consolidated financial statements for the year ended December 31, 2014, the Company has evaluated subsequent events for potential recognition and disclosure through the date of this filing and determined that there were no subsequent events which required recognition or disclosure in the financial statements.


17.	Quarterly Results of Operations (Unaudited)

Quarterly data for the years ended December 31, 2014, 2013, and 2012 is as follows:


	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
2014
Total Revenues	$	5,485,458		$	7,504,748		$	6,936,670		$	8,354,281
Operating Expenses		6,151,692			5,298,990			5,339,557			7,513,733
Income (Loss) From Operations		(666,234	)		2,205,758			1,597,113			840,548
Other Income (Expense)		(294,050	)		(1,870,864	)		(42,667	)		(367,919	)
Income Tax Provision (Benefit)		(514,885	)		(647,000	)		19,737			287,155
Net Income (Loss)		(445,399	)		981,894			1,534,709			185,474

Net Income Attributable to Non-Controlling Interest		890,864			2,018,943			1,521,295			1,089,650
Net Income (Loss) Attributable to Shareholders of Dakota Plains Holdings, Inc.		(1,336,263	)		(1,037,049	)		13,414			(904,176	)
Net Income (Loss) Per Common Share – Basic		(0.02	)		(0.02	)		0.00			(0.02	)
Net Income (Loss) Per Common Share – Diluted		(0.02	)		(0.02	)		0.00			(0.02	)


	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
2013
Total Revenues	$	95,199		$	99,570		$	76,758		$	77,845
Expenses		1,485,375			2,589,326			1,987,443			2,566,527
Loss From Operations		(1,390,176	)		(2,489,756	)		(1,910,685	)		(2,488,682	)
Other Income (Expense)		2,352,073			1,506,954			(1,413,078	)		3,053,986
Income Tax Provision (Benefit)		373,000			(389,000	)		(1,266,000	)		228,000
Net Income (Loss)		588,897			(593,802	)		(2,057,763	)		337,304
Net Income (Loss) Per Common Share – Basic		0.01			(0.01	)		(0.05	)		0.01
Net Income (Loss) Per Common Share – Diluted		0.01			(0.01	)		(0.05	)		0.01


	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
2012
Total Revenues	$	80,279		$	77,932		$	51,407		$	56,865
Expenses		800,669			626,423			845,421			794,707
Loss From Operations		(720,390	)		(548,491	)		(794,014	)		(737,842	)
Other Income (Expense)		(24,624,885	)		5,908,414			1,071,146			17,064,851
Income Tax Provision (Benefit)		(9,475,400	)		2,004,385			105,474			5,985,000
Net Income (Loss)		(15,869,875	)		3,355,538			171,658			10,342,009
Net Income (Loss) Per Common Share – Basic		(0.43	)		0.08			0.00			0.25
Net Income (Loss) Per Common Share – Diluted		(0.43	)		0.08			0.00			0.24

F-32

Plan Category

Number of Securities to Be
Issued upon Exercise of
Outstanding Options,
Warrants and Rights

Weighted Average Exercise
Price of Outstanding
Options, Warrants and
Rights ($)

Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans

Equity compensation plans approved by security holders ^(*)