Attached files

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EX-23.2 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - DAKOTA PLAINS HOLDINGS, INC.dakota160906_ex23-2.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 302 - DAKOTA PLAINS HOLDINGS, INC.dakota160906_ex31-2.htm
EX-21.1 - LIST OF SUBSIDIARIES - DAKOTA PLAINS HOLDINGS, INC.dakota160906_ex21-1.htm
EX-10.14 - AMENDED AND RESTATED EMPLOYMENT AGREEMENT - DAKOTA PLAINS HOLDINGS, INC.dakota160906_ex10-14.htm
EX-31.1 - CERTIFICATION OF CEO PURSUANT TO SECTION 302 - DAKOTA PLAINS HOLDINGS, INC.dakota160906_ex31-1.htm
EX-32.1 - CERTIFICATION OF CEO/CFO PURSUANT TO SECTION 906 - DAKOTA PLAINS HOLDINGS, INC.dakota160906_ex32-1.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - DAKOTA PLAINS HOLDINGS, INC.dakota160906_ex23-1.htm

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, 2015
  or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ________ to ________.

 

Commission File Number 001-36493

 

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

 

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

  

  (952) 473-9950  
(Registrant’s telephone number, including area code)
     
(Former name, former address and former fiscal year,
if changed since last report)

 

Title of Each Class   Name of Each Exchange on Which Registered
Common Stock, par value $0.001 per share   NYSE MKT
Preferred Stock Purchase Rights   NYSE MKT

 

Securities registered pursuant to Section 12(g) of the Act: None

 

 

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 ☐ 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 ☐ 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 ☐

 

 

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 ☐

 

 

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

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No þ

   

The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $63,041,663, 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 10, 2016, the registrant had 55,158,201 shares of common stock issued and outstanding.

 
 

 

Documents Incorporated By Reference

 

Portions of the Registrant’s Proxy Statement for its 2016 Annual Meeting of Stockholders 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;

 

i
 

 

  · Section 14A(a) of the Exchange Act, which requires an issuer to seek stockholder 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 stockholder 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.

 

ii
 

 

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 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 2015, the crude by rail industry was transporting approximately 41% of the total crude oil takeaway, which was down from 59% as of December 2014. 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 efficiently facilitate 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”).

 

1 

 

 

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 consisted 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 December 2013, we commissioned the Pioneer Terminal and began loading cars and sending trains in January 2014. The total cost of the project was approximately $50 million. 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. Initially, the Pioneer Terminal provided two 8,300-foot loop tracks that can accommodate two 120 rail car unit trains and increased 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 have been utilized for inbound delivery of and storage for frac sand.

 

In June 2014, our wholly owned subsidiary, Dakota Plains Sand, LLC, entered into a joint venture, DPTSS, with PTS. 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. 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 had an initial capacity of approximately 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 and became operational in July 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 short tons per year and is composed of 8,000 short 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.

 

 

2 

 

 

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 16.8 million barrels of crude oil in 2015 (or approximately 24,700 rail cars), which represented a 19% increase over the volume transloaded in 2014. In 2015, our facility experienced a daily average throughput of approximately 46,000 barrels of crude oil transloaded compared to a daily average throughput of approximately 38,800 barrels of crude oil in 2014. Our facility provides easy access to the railway via a spur that Canadian Pacific has constructed.

 

The facility 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, 270,000 barrels of crude oil storage, a high-speed loading facility that can accommodate 10 rail cars simultaneously, two active gathering system pipelines and transfer stations to receive crude oil from 10 trucks simultaneously;

 

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

 

·Automated terminal metering and accounting systems;

 

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

 

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

 

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

 

We completed construction of a third 90,000-barrel crude oil storage tank in July 2015. The facility also can accommodate significant storage of tanker-trucks, 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 and improve loading efficiency.

 

Some oil well operators continue to haul crude oil via semi-truck as far as 100 miles one way from New Town to various crude by rail facilities to load crude oil produced from wells located in the Parshall Oil Field onto railway systems at significant additional cost compared to the services offered by our facility. In December 2015, 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 960,000 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 equates 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.

 

We own the transloading facility and certain equipment and lease the property to DPTS. The rental income and expense related to the lease have been eliminated in the consolidation on the statements of operations for the years ended December 31, 2015 and 2014. For the year ended December 31, 2013, 50% of the rental income was eliminated through consolidation.

 

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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.

 

Dakota Plains Transloading, LLC (“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, which is when 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, 2014. Our share of income from DPTS is included in other income on the consolidated statement of operations for the year ended December 31, 2013. The operations of DPTS for the years ended December 31, 2015 and 2014 are incorporated into our consolidated statements of operations, and the balance sheets of DPTS are included in our consolidated balance sheets as of December 31, 2015 and 2014.

 

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

 

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. 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.

 

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 issued.

 

Each member of DPTSM was also required to make an initial Member Preferred Contribution of $10.0 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 $10.0 million contribution through June 30, 2013. The cumulative preferred return for the period from October 1, 2013 through November 30, 2014 and the initial $10.0 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. DPM shared expenses and profits equally with PTS after payment by DPTSM of a per-barrel trading and accounting fee to PTS. 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.

 

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. See Item 3, Legal Proceedings, for additional information regarding pending litigation.

 

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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.

 

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 issued.

 

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 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 was 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 and storage 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, a gathering system allows us to capture 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 (the Pelican pipeline) was placed into service and provided approximately 5,000 barrels of crude oil per day to the Pioneer Terminal. In 2015, we averaged in excess of 7,300 barrels of crude oil per day through the Pelican pipeline.

 

In August 2014, we announced the execution of an interconnection agreement with Hiland Crude, LLC, a wholly owned subsidiary of Hiland Partners, LP n/k/a Kinder Morgan, Inc. following the February 2015 acquisition of Hiland Partners (“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 had an initial capacity of approximately 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 2015, we averaged approximately 8,000 barrels of crude oil per day through the Hiland pipeline.

 

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 three 90,000-barrel crude oil storage tanks 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.

 

5 

 

 

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 2015 daily crude oil production approximated 1.2 million barrels, which was flat compared to December 2014. In addition, there were 13,119 producing wells at the end of December 2015 compared to 12,124 producing wells at the end of December 2014; an 8% increase. As of December 2015, in North Dakota, there were 76 completed wells, 64 wells being drilled, and approximately 945 wells awaiting completion services compared to 173 completed wells, 181 wells being drilled and 750 wells awaiting completion services at December 2014. In the February 2016 Director’s Cut publication, the NDIC reported that drilling permit activity was down to 95 permits in December 2015, compared to 125 drilling permits in November 2015, as operators began positioning themselves for low price scenarios in 2016. It also highlighted the fact that operators have significant permit inventory in anticipation of the return of drilling prices.

 

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.

 

Multiple Products & Services

 

We believe that our extensive market knowledge, strategic position, and ability to provide inbound and outbound services for both crude oil and frac sand will enable us to quickly capture growth opportunities in the Bakken oil field as crude oil prices and drilling activity begin to rebound. This diversity allows us to quickly respond to changing market conditions by simply adjusting the product and service mix. Also, the completion of the third crude oil storage tank 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, securing contracts from leading producers, refiners, and marketers, and efficiently managing costs through our low overhead business model. With Williston Basin production expected to increase over the next several years, we anticipate 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 16.8 million barrels of crude oil in 2015, a 19% increase from 2014 volumes. DPTS exclusively transloaded crude oil for DPTSM until it began transloading crude oil for third parties in January 2014. During the year ended December 31, 2015, DPTS solely transloaded crude oil for third parties.

 

6 

 

 

DPTSS initiated operations in June 2014 and transloaded approximately 170,000 short tons of frac sand in 2014. During the year ended December 31, 2015, DPTSS transloaded approximately 605,000 short tons of frac sand. UNIMIN was the sole customer of DPTSS in 2014 and 2015.

 

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 2015 crude by rail accounted for 41% of the total takeaway of crude oil, down from approximately 59% in December 2014. We intend to continue transporting crude oil via the Canadian Pacific system and compete directly with other parties transporting crude oil using the Canadian Pacific network, the Burlington Northern Railway, various trucking and similar concerns, the Enbridge and Tesoro pipelines, and various other pipelines that are constructed and operated in North Dakota.

 

There are fifteen crude by rail terminals in North Dakota, but only eleven are currently operational. All operating 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 eleven operating terminals have an aggregate daily takeaway capacity of 1.3 million barrels of crude oil with on-site storage of approximately 5.0 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 0.5 million barrels of crude oil per day in consistent takeaway capacity. The facilities also represent approximately 2.3 million barrels in on-site crude oil storage. Bakken Oil Express, the largest player as of December 2015, 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 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 per day takeaway capacity and 0.3 million barrels in on-site crude oil storage. The Pioneer Terminal provides a total solution that allows 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 827,000 barrels of crude oil per day. The pipelines incorporated in this estimate are owned by Enbridge, Plains All American, Tesoro, Kinder Morgan, and True Companies (Butte Pipeline). In December 2015, the North Dakota Pipeline Authority reported that 52% of the Williston Basin crude oil transport was via pipeline, with an incremental 6% 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 2015, for an aggregate pipeline infrastructure utilization of 624,000 barrels of crude oil per day for the same period. While pipeline projects continue to be contemplated, the Kinder Morgan Double H (“Double H”), with a capacity of 84,000 barrels of crude oil per day, was the only new pipeline completed in 2015. With the Double H providing only a slight increase in pipeline capacity in 2015, pipelines continue to experience underutilization. In February 2016, Enbridge Energy Partners LP stated that its 225,000 barrels of crude oil per day Sandpiper and Line 3 replacement pipeline projects have been delayed to 2019 in order to allow for completion of environmental reviews and further permitting in the state of Minnesota. The 616 mile, $2.6 billion Sandpiper project involves two new pipeline legs that will originate in North Dakota and stretch across northern Minnesota to Enbridge’s terminal in Superior, Wisconsin. In addition, regulators in Iowa have yet to approve Energy Transfer Partners’ Dakota Access pipeline, which is expected to move 450,000 barrels of crude oil per day to Patoka, Illinois where it would connect to its ETCO pipeline.

 

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.

 

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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 forty-nine full-time employees between our corporate headquarters and New Town, North Dakota facility. We believe that most operational responsibilities can be handled by our current employees as well as the use of independent consultants. We successfully brought our crude oil and frac sand transloading operations in-house effective June 1, 2015. In February 2016, we reduced our New Town staff by approximately 24%.

 

Available Information

 

Our principal executive offices are located at 294 Grove Lane East, Wayzata, Minnesota 55391, and our telephone number is (952) 473-9950. Our website address is www.dakotaplains.com. Information on our website does not constitute part of this Annual Report on Form 10-K or any other report we file or furnish with the SEC. We provide free access to various reports that we file with or furnish to the SEC through our website as soon as reasonably practicable after they have been filed or furnished. These reports include, but are not limited to, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports. Our SEC reports can be accessed through the investor relations section of our website or through the SEC’s website at www.sec.gov.

  

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

 

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 crude oil and frac sand transloading at the facility. We intend to continue to pursue additional business lines, including the additional business of transporting and storing 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 region 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.

 

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

 

Our ability to successfully transload crude oil and frac sand depends on developing and maintaining close working relationships with industry participants, selecting and evaluating suitable business arrangements, and being able 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 customers’ 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 2015, 410,249 carloads of crude oil were originated compared to 493,146 carloads of crude oil in 2014; a 16.8% decrease. 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 November 2015 marked the first month since June 2012 that a higher percentage of crude oil was moved out of North Dakota via pipeline, a shift caused by the narrowing price spread between WTI and Brent, which has made imports of foreign crude oil cheaper for East Coast refineries than Bakken sourced crude oil shipped by rail. 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.

 

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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 conducted 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.

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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 stockholders. 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 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 energy 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.

 

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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.

 

Our common stock may be delisted from the NYSE MKT if we cannot maintain compliance with NYSE’s continued listing requirements.

  

Currently, we are not in compliance with NYSE’s stockholders’ equity requirement and minimum bid price requirement but have submitted a compliance plan that outlines the actions we intend to take in order to regain compliance with the continued listing standards on or before April 14, 2017. If we fail to regain compliance with the applicable requirements, our stock may be delisted. Delisting from the NYSE MKT could make trading our common stock more difficult for investors, potentially leading to declines in our share price and liquidity. Without a NYSE MKT listing, stockholders may have a difficult time getting a quote for the sale or purchase of our stock, the sale or purchase of our stock would likely be made more difficult and the trading volume and liquidity of our stock could decline. Delisting from the NYSE MKT could also result in negative publicity and could also make it more difficult for us to raise additional capital. The absence of such a listing may adversely affect the acceptance of our common stock as currency or the value accorded by other parties. Further, if we are delisted, we would also incur additional costs under state blue sky laws in connection with any sales of our securities. These requirements could severely limit the market liquidity of our common stock and the ability of our stockholders to sell our common stock in the secondary market. If our common stock is delisted by NYSE, our common stock may be eligible to trade on an over-the-counter exchange. We cannot assure you that our common stock, if delisted from the NYSE MKT, will be listed on another national securities exchange or quoted on an over-the counter exchange.

  

If we are delisted from the NYSE MKT, your ability to sell your shares of our common stock would also be limited by the penny stock restrictions, which could further limit the marketability of your shares.

  

If our common stock is delisted, it would come within the definition of “penny stock” as defined in the Securities Exchange Act of 1934, or the Exchange Act, and would be covered by Rule 15g-9 of the Exchange Act. That rule imposes additional sales practice requirements on broker-dealers who sell securities to persons other than established customers and accredited investors. For transactions covered by Rule 15g-9, the broker-dealer must make a special suitability determination for the purchaser and receive the purchaser’s written agreement to the transaction prior to the sale. Consequently, Rule 15g-9, if it were to become applicable, would affect the ability or willingness of broker-dealers to sell our securities, and accordingly, would affect the ability of stockholders to sell their securities in the public market. These additional procedures could also limit our ability to raise additional capital in the future.

 

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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 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 or lead to a decrease in the transloading fee per barrel that we are able to charge our customers. 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.

 

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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 and, in turn, the transloading thereof. Also, United States and foreign government agriculture tariffs or subsidies could affect the demand for crude oil and, in turn, the transloading thereof.

 

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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 have obtained 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.

 

15 

 

 

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 they involve the release of hazardous materials. 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 June 30, 2018.

 

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 and amended on December 4, 2015. 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, three storage tanks with an aggregate capacity of 270,000 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. 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 stated in Note 14 to the Financial Statements, we and certain of our subsidiaries, including DPTS and DPTSM, were 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. 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”). 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.

 

16 

 

 

Between 2013 and 2015, we, certain of our subsidiaries, DPTS and DPTSM, along with a number of third parties, were sued in various actions in both the United States and Canada, by multiple third parties seeking economic, compensatory and punitive damages allegedly caused by the Derailment.

 

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.

 

On June 8, 2015, we entered into a settlement agreement (the “Settlement Agreement”) with the Trustee, Montreal, Maine and Atlantic Canada Co. (“MMAC”), and the monitor (the “Monitor”) in MMAC’s Canadian bankruptcy (collectively, the “MMA Parties”) resolving all claims arising out of the Derailment. On December 22, 2015, the effective date of the bankruptcy plans filed by the Trustee in the U.S. and by MMAC in Canada (the “U.S. Bankruptcy Plan” and the “CCAA Plan” respectively, each a “Plan” and collectively the “Plans”), the Settlement Agreement became final and effective. Under the terms of the Settlement Agreement, WFS contributed $110 million (the “Settlement Payment”) to a compensation fund established to compensate parties who suffered losses as a result of the derailment. As part of the settlement, we also assigned to the Trustee and MMAC certain claims we have against third parties arising out of the Derailment.

 

In consideration of the Settlement Payment and the assignment of claims to the Trustee and MMAC, we and certain of our subsidiaries, including DPTS and DPTSM (collectively, the “DAKP Parties”), received, and will continue to receive, the benefit of the global releases and injunctions set forth in the Plans. These global releases and injunctions bar all claims which may exist now or in the future against the DAKP Parties arising out of the Derailment, other than criminal claims which by law may not be released.

 

Dakota Petroleum Transport Solutions, LLC

 

TJMD, LLP v. Dakota Petroleum Transport Solutions, LLC

 

Since October 2012, DPTS had 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 alleged 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 sought payment for work performed prior to the final, September termination, as well as, monetary damages for future losses, and other relief. On October 9, 2015, we entered into a settlement agreement with TJMD resolving all claims between the parties.

 

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

 

Since April 2013, DPTS had been involved in litigation with TJMD, Rugged West Services, LLC (“Rugged West”), and JT Trucking (“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 its business. Trucks hauled crude oil to the transloading facility where crude oil was moved onto railcars and shipped to various locations across the country. DPTS had asserted a claim against TJMD for contractual liability based on Service Agreements TJMD entered into with DPTS that provided for contractor indemnification. DPTS asserted claims against TJMD, Enterprise Crude and JT for negligence in causing or allowing the spills to occur which proximately caused damages to DPTS. DPTS also asserted claims against TJMD, Enterprise Crude and JT for trespass and nuisance, claiming the defendants exceeded the consent to be on the property, entitling DPTS to recovery. TJMD filed third-party complaints against several trucking companies for indemnification and contribution. In October 2015, we entered into settlement agreements with TJMD and the remaining trucking companies resolving the claims between the parties. 

 

 

 17

 

 

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

 

On October 13, 2015, DPTS commenced a Minnesota state court lawsuit against World Fuel Services, Inc., asserting claims for breach of contract and unjust enrichment relating to unpaid fees and costs for crude oil transloading services (the “Transloading Case”). On November 2, 2015, World Fuel Services, Inc. answered the complaint and filed a motion to consolidate the action with the lawsuit commenced by DPTSM against Western Petroleum Company, which was denied. At present, World Fuel Services, Inc. has filed a motion to dismiss for improper venue arguing that the case should be heard in New York. A hearing on this issue is scheduled for March 1, 2016.

 

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

 

On December 29, 2015, World Fuel Services, Inc. brought suit against DPTS and Gabriel Claypool in the United States District Court of North Dakota. World Fuel Services, Inc. sought emergency relief for conversion and replevin of crude oil held by DPTS at the Pioneer Terminal pending the ongoing litigation for failure to pay for crude oil transloading services. DPTS filed a motion to dismiss and, in the alternative, to stay the case in deference to the Transloading Case. On January 20, 2016, the court approved the motion to stay pending the proceedings in the Transloading Case.

 

DPTS Marketing, LLC

 

DPTS Marketing, LLC v. Western Petroleum Company

 

On October 13, 2015, DPTSM commenced a Minnesota state court lawsuit against Western Petroleum Company, asserting claims for fraud in the inducement, reckless misrepresentation, tortious interference with prospective economic advantage, breach of contract, unjust enrichment, and declaratory judgment relating to railcar sublease agreements signed between the parties. On November 2, 2015, Western Petroleum Company filed a motion to dismiss and a motion to consolidate the action with the Transloading Case. The motion for consolidation was denied on December 29, 2015, and the hearing for the motion to dismiss was held on February 16, 2016, but at present no ruling has been made.

 

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.

 

Set forth below for each quarter of 2014 and 2015 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, 2015          
First Quarter  $2.24   $1.47 
Second Quarter  $1.97   $1.00 
Third Quarter  $1.65   $0.64 
Fourth Quarter  $0.85   $0.16 
           
Fiscal Year Ended December 31, 2014          
First Quarter  $2.37   $1.70 
Second Quarter (through June 16, 2014)  $2.51   $1.56 
Second Quarter (from June 17, 2014)  $2.86   $2.35 
Third Quarter  $2.84   $1.99 
Fourth Quarter  $2.40   $0.95 

 

 18

 

 

On March 10, 2016, the closing price per share of our common stock on the NYSE MKT was $0.18. As of the same date, our common stock was held by 120 stockholders 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 stockholder 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.

 

 GRAPH

 

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

 

12/31/2015  

Dakota Plains Holdings, Inc.

 

$

100.00

 

$

27.08

 

$

19.17

 

$

14.67

 

$ 2.08  

iPath S&P GSCI Crude Oil TR Index ETN

 

 

100.00

 

 

81.00

 

 

85.95

 

 

46.62

 

  23.16  

Russell 3000

 

 

100.00

 

 

102.20

 

 

133.83

 

 

147.81

 

  145.64  

 

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, 2015. We do not have any other equity compensation plans required to be included in this table.

 

 19

 

 

             
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 (*)
    N/A   2,003,311  
               

  

(*) Consists of the 2011 Equity Incentive Plan as Amended and Restated through June 18, 2015, 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

 

Under our 2011 Equity Incentive Plan as Amended and Restated through June 18, 2015, employees and directors may elect for the Company to withhold shares to satisfy minimum statutory federal, state and local tax withholding obligations arising from the grant, vesting and/or settlement of equity awards, including stock awards, restricted stock awards and settled restricted stock units. The following table provides information with respect to shares withheld by the Company to satisfy these obligations to the extent employees and directors elected for the Company to withhold such shares. These repurchases were not part of any publicly announced stock repurchase program.

       
Period  Total Number of
Shares Purchased
   Average Price
Paid per Share
 
  October 1-31     $  
  November 1-30          
 December 1-31    12,633    0.24 
 Total    12,633   $0.24 

 

 20

 

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, 2015, and 2014, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the years ended December 31, 2015, 2014, and 2013 included elsewhere in this report. Balance sheet information at December 31, 2013, 2012 and 2011 and financial statement information for the years ended December 31, 2012 and 2011 is derived from audited financial statements not included in this report, which other than the Balance Sheet at December 31, 2013 and 2012 and the financial statements for the year ended 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, 
   2015   2014   2013   2012   2011 
Income Statement Information:                         
Revenues                         
Transloading Revenue  $23,161,752   $26,781,637   $-   $-   $- 
Sand Revenue   4,532,393    1,379,520    -    -    - 
Rental Income   120,000    120,000    -    -    - 
Rental Income - Related Party   -    -    349,372    266,483    314,581 
Other   1,398,950    -    -    -    - 
Total Revenues   29,213,095    28,281,157    349,372    266,483    314,581 
                          
Total Operating Expenses   26,081,536    24,303,972    8,628,671    3,067,220    4,056,341 
                          
Income (Loss) From Operations   3,131,559    3,977,185    (8,279,299)   (2,800,737)   (3,741,760)
                          
Other Income (Expense)                         
Income from Investment in Dakota Petroleum Transport Solutions, LLC   -    -    4,312,394    3,511,999    4,236,779 
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)   (8,071,283)   (2,793,190)   (3,630,950)   (29,211,978)   (3,371,812)
Gain (Loss) on Extinguishment of Debt   -    -    1,726,515    14,708,909    (4,552,500)
Change in Operational Override   10,958,375    -    -    -    - 
Other Income (Expense)   (1,704,618)   (34,022)   -    -    (2,777)
Total Other Income (Expense)   1,182,474    (2,575,500)   5,499,935    (580,474)   (1,376,031)
                          
Income (Loss) Before Income Taxes   4,314,033    1,401,685    (2,779,364)   (3,381,211)   (5,117,791)
                          
Income Tax Provision (Benefit)   29,281,784    (854,993)   (1,054,000)   (1,380,541)   (2,007,000)
                          
Net Income (Loss)   (24,967,751)   2,256,678    (1,725,364)   (2,000,670)   (3,110,791)
                          
Net Income Attributable to Non-Controlling Interests   -    5,520,752    -    -    - 
                          
Net Loss Attributable to Shareholders of Dakota Plains Holdings, Inc.  $(24,967,751)  $(3,264,074)  $(1,725,364)  $(2,000,670)  $(3,110,791)
                          
Net Loss Per Common Share – Basic and Diluted  $(0.46)  $(0.06)  $(0.04)  $(0.05)  $(0.09)
                          
Weighted Average Shares Outstanding - Basic and Diluted   54,228,266    53,971,183    42,338,999    39,792,973    35,214,940 
                          
Balance Sheet Information:                         
Total Assets  $73,338,335   $99,126,687   $87,054,584   $39,664,657   $22,447,871 
Total Liabilities  $100,339,542   $102,904,754   $24,428,105   $27,301,375   $15,363,604 
Stockholders’ Equity (Deficit)  $(27,001,207)  $(3,778,067)  $62,626,479   $12,363,282   $7,084,267 
                          
Statement of Cash Flows Information:                         
Net cash provided by (used in) operating activities  $(5,192,410)  $9,161,784   $(8,074,812)  $(3,810,092)  $(2,095,727)
Net cash provided by (used in) investing activities  $(5,136,844)  $(40,579,405)  $5,055,198   $(1,003,027)  $(8,836,016)
Net cash provided by financing activities  $7,460,030   $23,096,719   $13,691,139   $5,399,537   $12,110,118 

 

 21

 

  

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 joint 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 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 the 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 three 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 80,000 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. On November 24, 2014, we sold our 50% ownership interest in the trucking joint venture to JPND for $1.15 million.

 

In March 2013, we and PTS announced the construction of the Pioneer Terminal. The Pioneer Terminal represents a significant expansion of the New Town, North Dakota 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 80,000 barrels of crude oil per day, 270,000 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.

 

 22

 

 

The Pioneer Terminal began loading cars and sending trains in January 2014. The total cost of the project was approximately $50 million and was funded equally by us and World Fuel Services Corporation. The original four ladder tracks are being utilized by UNIMIN for the inbound delivery and storage frac sand.

 

In August 2014, we announced the execution of an interconnection agreement with Hiland Crude, LLC, a wholly owned subsidiary of Hiland Partners, LP (“Hiland”) and now Kinder Morgan, Inc. as a result of the February 2015 acquisition of Hiland Partners, 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 had an initial capacity of approximately 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 2015, we averaged approximately 8,000 barrels of crude oil per day through the Hiland pipeline.

 

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 were completed, and the third storage tank became operational in July 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 short tons per year and is composed of 8,000 short 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.

 

Current Business Drivers

 

As reported in the Annual Energy Outlook 2015 dated April 14, 2015, the U.S. Energy Information Administration (the “EIA”) forecasts total U.S. crude oil production reaching its peak between the years of 2020 to 2039: “Production from tight formations leads the growth in U.S. crude oil production across all AEO2015 cases. The path of projected crude oil production varies significantly across the cases, with total U.S. crude oil production reaching high points of 10.6 million barrels per day (bbl/d) in the Reference case (in 2020), 13.0 million bbl/d in the High Oil Price case (in 2026), 16.6 million bbl/d in the High Oil and Gas Resource case (in 2039), and 10.0 million bbl/d in the Low Oil Price case (in 2020).” The EIA estimated that U.S. crude oil production totaled approximately 9.2 million barrels per day in January 2016. As of December 2015, 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

 

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·domestic and foreign economic volatility and stability.

 

Lack of capacity within the trunk pipelines and lack of geographical flexibility to serve many potential markets is driving competition within the crude oil transloading and storage industry. 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 offer the most attractive price when they sell their product to the market. The railroads recognize this competitive advantage and have spent billions of dollars on infrastructure and equipment in recent years. In the Williston Basin, 41% of crude oil production was being shipped via rail in December 2015, 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 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 in DPS. In addition, effective November 30, 2014, we purchased the remaining ownership interests in DPTS, DPTS Marketing LLC (“DPTSM”) and DPTS Sand, LLC from its joint venture partner. Prior to the aforementioned transactions, we accounted for our investments in DPS and DPTSM using the equity method. 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 its share of intercompany transactions. 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, 2014. Accordingly, the accompanying consolidated statements of operations for the year ended December 31, 2014 includes 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, 2015 and 2014, we had no investments in joint ventures where we had significant influence, representing equity ownership of not more than 50%, and were not accounting for any investments using the equity method.

 

We 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, restricted stock and restricted stock unit grants, we calculate the stock-based compensation expense based upon estimated fair value on the date of grant. For stock warrants and options, we use the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

 

Stock Issuance

 

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.

 

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Operational Override

 

As part of the Membership Interest Purchase Agreement, 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%. In 2015, the Company adjusted its estimate due to lower expected volumes. The Operational Override at December 31, 2015 is $34.3 million.

 

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Results of Operations

 

The following tables illustrate the statements of operations by operating segment for the years ended December 31, 2015, 2014, and 2013:

 
Year Ended December 31, 2015  
Dakota Plains
 Holdings, Inc.
Dakota Petroleum
Transport
Solutions, LLC
DPTS Sand,
LLC
Eliminations Consolidated
REVENUES
Transloading Revenue $ - $ 23,161,752 $ - $ - $ 23,161,752
Sand Revenue - - 4,532,393 - 4,532,393
Rental Income 603,180 - - (483,180 ) 120,000
Other - 1,398,950 - - 1,398,950
Total Revenues 603,180 24,560,702 4,532,393 (483,180 ) 29,213,095
COST OF REVENUES - 6,036,613 1,218,104 (457,945 ) 6,796,772
(exclusive of items shown separately below)
OPERATING EXPENSES
Transloading Operating Expenses - 4,198,215 3,678 (25,235 ) 4,176,658
General and Administrative Expenses 10,343,262 - - - 10,343,262
Depreciation and Amortization Expense 202,900 4,561,944 - - 4,764,844
Total Operating Expenses 10,546,162 8,760,159 3,678 (25,235 ) 19,284,764
                                 
INCOME (LOSS) FROM OPERATIONS $ (9,942,982 ) $ 9,763,930 $ 3,310,611 $ - $ 3,131,559
 
Year Ended December 31, 2014
Dakota
Plains
Holdings, Inc.
Dakota Petroleum
Transport
Solutions, LLC
DPTS Sand,
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
Plains
Holdings, Inc.
Dakota Petroleum
Transport
Solutions, LLC
DPTS Sand,
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 )

  

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Fiscal Year Ended December 31, 2015 vs. Fiscal Year Ended December 31, 2014

 

We experienced a net loss attributable to stockholders of Dakota Plains Holdings, Inc. of $25.0 million for the fiscal year ended December 31, 2015 compared to a net loss of $3.3 million for the fiscal year ended December 31, 2014. The 2015 net loss was driven by the valuation allowance on our deferred tax assets of approximately $27.4 million, which was partially offset by record high crude oil (16.8 million barrels of crude oil) and frac sand (605,000 short tons) transloading throughput, the recognition of revenues from storing clients’ rail cars at our facility, successfully bringing the transloading services in-house, and the gain realized from a revaluation of the Operational Override liability due to a material change in the estimated future cash outflows used to calculate the fair value of the liability. The net loss in 2014 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.

 

The net income of DPTS for the fiscal year ended December 31, 2015 was $9.8 million compared to $12.0 million for the fiscal year ended December 31, 2014. The decrease in net income was driven by a 14% decrease in revenue and 232% increase in insurance expense but was partially offset by a 23% decrease in cost of revenue related to crude oil transloading due to successfully bringing the transloading services in-house. Total revenue for the fiscal year ended December 31, 2015 was $24.6 million compared to $26.8 million for the fiscal year ended December 31, 2014. The decrease in revenue was driven by continued downward pressure on the domestic crude oil market leading to lower crude oil prices, fewer long-term contracts, and increased volatility in the transloading fee per barrel. The impact of the depressed crude oil prices was partially offset by volume as DPTS transloaded 16.8 million barrels of crude oil (46,000 barrels per day) during the fiscal year ended December 31, 2015 compared to 14.2 million barrels of crude oil (39,000 barrels per day) during the fiscal year ended December 31, 2014; a 19% increase. The increase in barrels transloaded was primarily the result of securing additional third party transloading customers. Total cost of revenue related to crude oil transloading for the fiscal year ended December 31, 2015 was $6.0 million compared to $7.9 million for the fiscal year ended December 31, 2014; a 23% decrease driven by successfully bringing the transloading services in-house.

 

The net income of DPTS Sand, LLC for the fiscal year ended December 31, 2015 was $3.3 million compared to $0.7 million for the fiscal year ended December 31, 2014. Revenue from frac sand transloading was $4.5 million for the fiscal year ended December 31, 2015 compared to $1.4 million for the fiscal year ended December 31, 2014. Cost of revenue related to frac sand transloading was $1.2 million for the fiscal year ended December 31, 2015 compared to $0.6 million for the fiscal year ended December 31, 2014. The increases in both revenue and cost of revenue were due to the fact that the frac sand transloading operations did not commence until June 2014, which contributed to the large increase in volume as we transloaded 605,000 short tons of frac sand during the fiscal year ended December 31, 2015 compared to 172,000 short tons of frac sand during the same period of 2014. The 46% decrease in cost of revenue per short ton transloaded during the year ended December 31, 2015 was primarily the result of bringing the transloading services in-house during the second quarter of 2015.

 

As previously noted, effective November 30, 2014, we acquired the remaining ownership interest in DPTSM from PTS and immediately discontinued the purchase and sale of crude oil. We plan to maintain the current fleet of rail cars with the intent to sublease and/or utilize them in our operations if the need arises. The loss from our indirect investment in DPTSM was $0.4 million for fiscal year ended December 31, 2014.

 

On November 24, 2014, we sold our 50% ownership interest in the trucking joint venture to our then trucking partner. Income from our indirect investment in the trucking joint venture was $607,000 for the period from January 1, 2014 through November 24, 2014.

 

Interest expense was $8.1 million for the fiscal year ended December 31, 2015 compared to $2.8 million for the fiscal year ended December 31, 2014. The increase was primarily driven by the interest expense related to the Operational Override liability and the additional debt with SunTrust resulting from the acquisition of 50% of the outstanding interests of the transloading, sand and marketing joint ventures in the fourth quarter of 2014.

 

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The change in Operational Override liability was $11.0 million for the fiscal year ended December 31, 2015 due to a decrease in the long-term estimated daily crude oil transloading volume used to calculate the liability. According to the NDIC Department of Natural Resources most recent Director’s Cut publication dated February 17, 2016, “Operators are now even more committed to running fewer rigs as oil prices remain at very low levels. Oil price weakness is now anticipated to last into at least the third quarter of this year and is the main reason for the continued slowdown.” This lead the Company to believe that operators will be able to continue producing at the current crude oil price levels, which was substantiated by the North Dakota Pipeline Authority Monthly Update published on October 13, 2015 that showed the 2015 North Dakota Williston Basin oil production remaining constant at approximately 1.2 million barrels of crude oil per day. The Short-Term Energy and Winter Fuels Outlook published by the U.S. Energy Information Administration (EIA) on October 6, 2015 was more uncertain about the outlook for the domestic crude oil industry stating, “EIA’s crude oil price forecast remains subject to significant uncertainties as the oil market moves toward balance. During this period of price discovery, oil prices could continue to experience periods of heightened volatility. The oil market faces many uncertainties heading into 2016, including the pace and volume at which Iranian oil reenters the market, the strength of oil consumption growth, and the responsiveness of non-OPEC production to low oil prices.” In their most recent publication of the Short-Term Energy and Winter Fuels Outlook dated February 17, 2016, the EIA stated, “The focus of drilling and production activities will be on the core areas of major tight oil plays. Despite the significant decline in total rig counts in 2015, rig counts have largely stabilized in the core counties of the Bakken, Eagle Ford, Niobrara, and Permian. In these areas, falling costs and ongoing technological and process improvements in rig, labor, and well productivity are anticipated to lead to faster rates of well completions and less-rapid production declines relative to other Lower 48 onshore areas. The ongoing gains in learning-by-doing, cost reductions, and rig and well productivity are expected to enhance the economic viability of these areas and to be adopted in other regions, incrementally reducing the breakeven costs of oil production in more marginal areas.” We were confident in the operators’ ability to continue producing in the current environment in the short-term but believed the third quarter of 2015 was an appropriate time to adjust the long-term volume forecast due to the continued downward pressure on the crude oil market from macro-economic factors.

 

The provision for income taxes was $29.3 million for the fiscal year ended December 31, 2015 compared to a benefit from income taxes of $0.9 million for the fiscal year ended December 31, 2014. The effective tax rate for the fiscal year ended December 31, 2015 was 678.8% compared to an effective tax rate of 20.8% for the fiscal year ended December 31, 2014. The increase in the effective tax rate was primarily due to the valuation allowance placed on the net deferred tax asset in 2015 and the effect of permanent differences between book and tax income. The effective tax rate was different than the federal statutory rate of 35% due to the valuation allowance.

 

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

 

We experienced a net loss attributable to stockholders 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 significant 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.

 

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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 the 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 172,000 tons of sand transloaded.

 

Non-GAAP Financial Measures

 

We define Adjusted EBITDA Attributable to Stockholders of Dakota Plains Holdings, Inc. as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation and amortization, (iv) gain on extinguishment of debt, (v) non-cash expenses relating to share based amounts recognized under ASC Topic 718, (vi) non-cash change related to Operational Override Liability, and (vii) Adjusted EBITDA Attributable to Non-Controlling Interests. Adjusted EBITDA Attributable to Stockholders of Dakota Plains Holdings, Inc. was $8.7 million for 2015, $3.4 million for 2014, and $2.4 million for 2013. The increase in 2015 Adjusted EBITDA was primarily driven by record high crude oil and frac sand transloading throughput, the recognition of revenues from storing clients’ rail cars at our facility, and improved operating efficiencies in the crude oil and frac sand transloading entities from successfully bringing the transloading services in-house.

  

Dakota Plains Holdings, Inc. 

Reconciliation of Adjusted EBITDA

 
Year Ended December 31,
2015 2014 2013
Net Income (Loss) $ (24,967,751 ) $ 2,256,678 $ (1,725,364 )
    Add back:
        Income Tax Provision (Benefit) 29,281,784 (854,993 ) (1,054,000 )
        Depreciation and Amortization 4,764,843 4,332,900 179,546
        Share Based Compensation – Employees and Directors 2,513,258 2,330,651 2,753,817
        Share Based Compensation – Consultants - - 299,288
        Interest Expense 8,071,283 2,793,190 3,630,950
        Decrease in Operational Override Liability (10,958,374 ) - -
        Gain on Extinguishment of Debt - - (1,726,515 )
Adjusted EBITDA $ 8,705,043 $ 10,858,426 $ 2,357,722
                     
Adjusted EBITDA Attributable to Non-Controlling Interests - 7,411,785 -
                     
Adjusted EBITDA Attributable to Stockholders of Dakota Plains Holdings, Inc. $ 8,705,043 $ 3,446,641 $ 2,357,722  

 

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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 approximately $1.8 million at December 31, 2015. The cash in 2015 was primarily generated by the results of operations of DPTS and DPTS Sand, LLC and utilization of the credit facility provided by SunTrust Bank. These cash inflows were offset by our payments related to the principal and interest on the SunTrust debt, the Operational Override, the completion of Tank 3, general and administrative expenses, and the True-up payment to WFS. As a result of the Membership Interest Purchase Agreement dated December 5, 2014, we were no longer dependent on the priority cash calculations mandated by the member control agreements of the former joint ventures and had complete control of the cash generated by these ventures in 2015. Cash and cash equivalents at December 31, 2014 were $4.7 million. The cash in 2014 was primarily generated by the results of operations of DPTS and DPTS Sand, LLC, proceeds from the sale of our 50% ownership interest in the trucking joint venture and utilization of the credit facility provided by SunTrust Bank.

 

The Company had no available borrowings under the Revolving Credit Facility with SunTrust at December 31, 2015. The Company is focused on increasing the throughput and reducing the expenses at the transloading facility. We believe that the cash flows from operations will allow us to meet the current obligations of the Company in ordinary course of business. We 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 us, if at all.

 

Revolving Credit and Term Loan Agreement

 

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 two tranches of term loans in the aggregate amount of $37.5 million (the “Term Loans” and together with the Revolving Loan Facility, the “Credit Facility”).

 

On December 4, 2015, the Borrowers entered into an Amendment No. 2 and Waiver to the Credit Agreement (“Amendment No. 2”) to amend the Credit Facility. Amendment No. 2 amends the existing Credit Facility to extend the maturity date of the Tranche B Term Loan, increase the interest rate margin on the Tranche B term loan by 25 basis points, and modify the leverage ratio covenant for fiscal quarters ending prior to March 31, 2017. It also waived certain events of default. There was $56.8 million outstanding under the Credit Facility at December 31, 2015.

 

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 (“Tranche A”) in the amount of $15.0 million is payable in quarterly installments with the first payment due on March 31, 2015 and matures on December 5, 2017. Repayment of the second tranche of Term Loans (“Tranche B”) in the amount of $22.5 million is due on January 5, 2017. 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.

 

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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. Amendment No. 2 then modified the leverage ratio covenant for fiscal quarters ending December 31, 2015 and March 31, 2016 by waiving the ratio requirement entirely. 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.

 

Amended Election, Exchange and Loan Agreements

 

In addition, pursuant to the Amended Election, Exchange and Loan Agreements dated November 2, 2012, we repaid the outstanding principal to a holder of its $9.0 million of existing promissory notes (“Consolidated Notes”) in the amount of $500,000. The term of the remaining $8.5 million in Consolidated Notes was extended using two different maturity dates. $4,605,300 of the Consolidated Notes was extended to March 1, 2014 and $3,894,700 was extended to October 31, 2015. All of the holders of the Consolidated 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 Consolidated 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 its 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 Consolidated 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 Consolidated 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 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 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 Consolidated 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.

 

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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 Consolidated 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.

 

The WFS Facility bore interest at a rate per annum equal to nine percent (9.0%) and 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 $43.0 million paid in cash 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 $10.0 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 $10.0 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 sheets as of December 31, 2015 and 2014.

 

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In connection with the indemnification, each of 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 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.

 

On October 13, 2015, DPTS commenced a Minnesota state court lawsuit against World Fuel Services, Inc., asserting claims for breach of contract and unjust enrichment relating to unpaid fees and costs for crude oil transloading services (see Item 3, Legal Proceedings). As a result, we have suspended payment of the Operational Override. In order to not violate terms of the Credit Agreement, SunTrust waived certain events of default that could be triggered in connection with our pursuit of remedies against subsidiaries of World Fuel Services Corporation for railcar sublease agreements and unpaid fees and costs for crude oil transloading services.

 

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 9.0%. In 2015, we adjusted our estimate due to lower expected volumes. The Operational Override was equal to $34.3 million at December 31, 2015.

 

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.

 

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Contractual Obligations

 

The following table summarizes our contractual obligations at December 31, 2015:

                
   Payments Due by Period
   Total    Less Than One
Year
    One to Three
Years
    Three to Five
Years
    More Than Five
Years
Total Debt  $56,750,000   $3,225,000   $53,525,000   $-   $- 
Interest Expense   5,474,417    2,810,248    2,664,169    -    - 
Office Lease   226,400    91,800    134,600    -    - 
Railcar Lease   17,440,843    6,294,805    6,082,002    4,222,548    841,488 
Operational Override   7,914,210    -    -    -    7,914,210 
Notes Payable - Vehicles   225,893    57,623    105,340    62,930    - 
Total  $88,031,762   $12,479,476   $62,511,111   $4,285,478   $8,755,698 

 

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 $56.75 million outstanding under the Credit Facility at December 31, 2015.

 

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 (“Tranche A”) in the amount of $15.0 million is payable in quarterly installments and matures on December 5, 2017. Repayment of the second tranche of Term Loans (“Tranche B”) in the amount of $22.5 million is due on January 5, 2017. 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.

 

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 $10.0 million, then the Company is obligated to pay PTS the difference on or before January 31, 2027. As previsouly mentioned, payment of the Operational Override has been suspended. In order to not violate terms of the Credit Agreement, SunTrust waived certain events of default that could be triggered in connection with our pursuit of remedies against subsidiaries of World Fuel Services Corporation for railcar sublease agreements and unpaid fees and costs for crude oil transloading services.

 

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.

 

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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.

 

We are exposed to interest rate risk on the outstanding borrowings on our revolving credit facility. As of December 31, 2015, we had $56.75 million outstanding under the Credit Facility. A 10% increase in the floating portion of our interest rates for 2015, would have increased interest expense by approximately $0.02 million for the fiscal year ended December 31, 2015.

 

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, 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, 2015.

 

35
 

 

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 internal controls over financial reporting as of December 31, 2015. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control – Integrated Framework (2013). Based on that assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2015.

 

March 11, 2016

  /s/ Craig M. McKenzie  
  Chief Executive Officer  
     
  /s/ Timothy R. Brady  
  Chief Financial Officer and Treasurer  

 

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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 Stockholders (the “Proxy Statement”), which we intend to file with the SEC pursuant to Regulation 14A within 120 days after December 31, 2015. 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   52   Chief Executive Officer and Director
  Gabriel G. Claypool   40   President and Chief Operating Officer
  Timothy R. Brady   54   Chief Financial Officer and Treasurer
  James L. Thornton   40   Executive Vice President, Strategy & General Counsel

 

Craig M. McKenzie has served as a member of our board of directors and Chief Executive Officer of our Company since February 2013. He served as Chairman of our board of directors from February 2013 to February 2015. 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 2009 until the combination. From 2007 to 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 has served as our President and Chief Operating Officer since February 2013.  He served as a member of our board of directors from February 2011 to May 2015 and as Chairman of our board of directors through February 2013.  Mr. Claypool was the Chief Executive Officer and Secretary of our Company from February 2011 to February 2013.  Over the last five years, Mr. Claypool has led the Company through several on time/on budget projects representing $85M in CAPEX, four consecutive years of double digit volume growth in crude operations and the forming of three separate midstream joint ventures. With numerous years’ experience with midstream logistics and commodity marketing, Mr. Claypool’s focus is on safe operations and growth of their railroad based logistics businesses.  Mr. Claypool brings a strong business development and management track record from two Fortune 10 companies, handling senior level relationships with Fortune 500 firms for over 10 years.  Mr. Claypool holds a Bachelor of Business Administration degree from the University of Iowa.

 

Timothy R. Brady has served as Chief Financial Officer and Treasurer since March 2012. He previously served as Chief Financial Officer and Treasurer of Dakota Plains from September 2011 to March 2012. Mr. Brady was instrumental in taking our Company public in 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.

 

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James L. Thornton has served as Executive Vice President, Strategy & General Counsel since March 2013. In his role as General Counsel, he is responsible for managing our legal and regulatory affairs. As Corporate Secretary, he is also responsible for a variety of our corporate governance matters. Mr. Thornton previously served as the senior legal counsel of Toreador Resources Corporation in Paris, France before its combination with ZaZa Energy Corporation in February 2012. From 2007 to 2011, Mr. Thornton was an attorney with McKenna, Long & Aldridge LLP, an AmLaw 100 firm, where he represented clients in a broad range of corporate finance, merger and acquisition matters as well as advising public company clients on SEC reporting and disclosure requirements, corporate governance issues, and other corporate and securities matters. Before joining McKenna, Long & Aldridge LLP, Mr. Thornton practiced in the corporate departments of Balch & Bingham LLP and Locke Lord LLP. Mr. Thornton holds a J.D. from Washington and Lee University School of Law and a B.S. in Finance from the University of Tennessee.

 

Executive officers are elected annually by the board of directors and serve for 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 Stockholders 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, 2015, 2014 and 2013.

 

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.

 

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(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
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   Composite Second Amended and Restated Bylaws of Dakota Plains Holdings, Inc., as amended through June 11, 2015 (incorporated by reference to Exhibit 3.1 to current report on Form 8-K filed June 17, 2015)
     
3.3   Certificate of Designation of Series A Junior Participating Preferred Stock of Dakota Plains Holdings, Inc. (incorporated by reference to Exhibit 3.1 to current report on Form 8-K filed January 25, 2016)
     
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   Amendment No. 1 to Revolving Credit and Term Loan Agreement, dated August 6, 2015, by and among Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the lenders party thereto and SunTrust Bank, as administrative agent (incorporated by reference to Exhibit 10.1 to current report on Form 8-K filed August 11, 2015)
     
4.3   Amendment No. 2 and Waiver to Revolving Credit and Term Loan Agreement, dated December 4, 2015, Dakota Plains Transloading, LLC, Dakota Plains Sand, LLC, Dakota Plains Marketing, LLC, Dakota Plains Holdings, Inc., the subsidiary loan parties party thereto, the lenders time to time party thereto and SunTrust Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to current report on Form 8-K filed December 4, 2015)
     
4.4   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 Form 8-K filed December 8, 2014)
     
4.5   Rights Agreement dated as of January 24, 2016 between Dakota Plains Holdings, Inc. and Interwest Transfer Company, Inc., as Rights Agent (incorporated by reference to Exhibit 4.1 to current report on Form 8-K filed January 25, 2016)
     
10.1*   Dakota Plains Holdings, Inc. 2011 Equity Incentive Plan, as amended through June 18, 2015 (incorporated by reference to Exhibit 99.1 to registration statement on Form S-8 filed July 8, 2015; file no. 333-205557)
     
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)

 

39
 

 

Exhibit No.   Description
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 stockholders, 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*   Amended and Restated Employment Agreement with James L. Thornton, dated March 12, 2014
     
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 Form 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 Form 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 Form 8-K filed December 8, 2014)
     
21.1   List of Subsidiaries
     
23.1   Consent of Mantyla McReynolds LLC
     
23.2   Consent of BDO, USA, LLP
     
24.1   Powers of Attorney (incorporated by reference to signature page)

 

40
 

 

Exhibit No.   Description
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.

 

41
 

 

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 11, 2016.

 

    DAKOTA PLAINS HOLDINGS, INC.
     
  By  /s/ Craig M. McKenzie
   

Craig M. McKenzie,

Chief Executive Officer 

 

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   Chief Executive Officer (Principal Executive Officer) and Director   March 11, 2016
Craig M. McKenzie    
         
/s/ Timothy R. Brady    Chief Financial Officer and Treasurer
(Principal Financial Officer and Principal Accounting Officer)
  March 11, 2016
Timothy R. Brady  

 
         
/s/ K. Adam Kroloff   Chairman of the Board of Directors and Director   March 11, 2016
K. Adam Kroloff    
         
 /s/ Steven A. Blank   Director   March 11, 2016
Steven A. Blank    
         
/s/ Gary L. Alvord   Director   March 11, 2016
Gary L. Alvord    
         
 /s/ David H. Fellon   Director   March 11, 2016
David H. Fellon    

 

42
 

 

Dakota Plains Holdings, Inc.    
     
Consolidated Financial Statements as of December 31, 2015 and 2014 and for each of the three years in the Period Ended December 31, 2015
     
Report of Mantyla McReynolds LLC, Independent Registered Public Accounting Firm   F-2
     
Report of BDO USA, LLP, Independent Registered Public Accounting Firm   F-3
     
Financial Statements    
     
Consolidated Balance Sheets   F-4
     
Consolidated Statements of Operations   F-5
     
Consolidated Statements of Cash Flows   F-6
     
Consolidated Statements of Stockholders’ Equity (Deficit)   F-7
     
Notes to the Consolidated Financial Statements   F-8 – F-32

 

F-1
 

 

Report of Mantyla McReynolds LLC, Independent Registered Public Accounting Firm

 

Board of Directors and Stockholders

Dakota Plains Holdings, Inc.

Wayzata, Minnesota

 

We have audited the accompanying consolidated balance sheet of Dakota Plains Holdings, Inc. as of December 31, 2015 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the year ended December 31, 2015. 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 audit.

 

We conducted our audit 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 audit 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 audit provides 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, 2015, and the results of its operations and its cash flows for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ Mantyla McReynolds LLC 

Salt Lake City, Utah 

March 11, 2016

 

F-2
 

 

Report of BDO USA, LLP, Independent Registered Public Accounting Firm

 

Board of Directors and Stockholders 

Dakota Plains Holdings, Inc. 

Wayzata, Minnesota

 

We have audited the accompanying consolidated balance sheet of Dakota Plains Holdings, Inc. as of December 31, 2014 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the two 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 the results of its operations and its cash flows for each of the two 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 23, 2015

 

F-3
 

 

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES 

CONSOLIDATED BALANCE SHEETS 

DECEMBER 31, 2015 AND 2014

 

ASSETS

         
   December 31, 
   2015   2014 
CURRENT ASSETS          
Cash and Cash Equivalents  $1,821,482   $4,690,706 
Trade Receivables, Net   8,936,062    3,268,386 
Income Tax Receivable   9,648    14,803 
Other Current Assets   439,309    99,776 
Other Receivables   42,038    781,135 
Deferred Tax Asset   110,000    2,266,000 
Total Current Assets   11,358,539    11,120,806 
           
PROPERTY AND EQUIPMENT          
Land   3,191,521    3,191,521 
Site Development   5,829,639    5,829,640 
Terminal   21,437,077    21,383,972 
Machinery   18,218,163    18,133,754 
Storage Tanks   15,299,541    9,307,570 
Construction in Progress   -    1,886,470 
Other Property and Equipment   3,123,163    2,603,417 
Total Property and Equipment   67,099,104    62,336,344 
Less – Accumulated Depreciation   10,908,003    6,143,159 
Total Property and Equipment, Net   56,191,101    56,193,185 
           
FINANCE COSTS, NET   2,271,201    1,537,795 
           
RESTRICTED CASH   3,000,593    3,000,000 
           
DEFERRED TAX ASSET   -    26,762,000 
           
OTHER ASSETS   512,901    512,901 
           
Total Assets  $73,334,335   $99,126,687 
           
LIABILITIES AND STOCKHOLDERS’ DEFICIT          
CURRENT LIABILITIES          
Accounts Payable  $4,791,157   $7,387,612 
Accrued Expenses   4,149,601    1,696,358 
Promissory Notes, SunTrust   3,225,000    23,250,000 
Operational Override Liability   1,879,607    715,497 
Notes Payable – Vehicles   57,623    - 
Total Current Liabilities   14,102,988    33,049,467 
           
LONG-TERM LIABILITIES          
Promissory Notes, SunTrust   53,525,000    25,250,000 
Operational Override Liability   32,426,367    44,595,370 
Notes Payable – Vehicles   168,270    - 
Deferred Tax Liability   110,000    - 
Other Non-Current Liabilities   2,917    9,917 
Total Long-Term Liabilities   86,232,554    69,855,287 
           
Total Liabilities   100,335,542    102,904,754 
           
COMMITMENTS AND CONTINGENCIES (NOTE 14)          
           
STOCKHOLDERS’ DEFICIT          
Preferred Stock – Par Value $.001; 10,000,000 Shares Authorized; None Issued or Outstanding   -    - 
Common Stock – Par Value $.001; 100,000,000 Shares Authorized; 55,175,363 and 55,044,829 Issued and Outstanding, Respectively   55,175    55,044 
Additional Paid-In Capital   8,012,268    6,267,788 
Accumulated Deficit   (35,068,650)   (10,100,899)
Total Stockholders’ Deficit   (27,001,207)   (3,778,067)
           
Total Liabilities and Stockholders’ Deficit  $73,334,335   $99,126,687 

 

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

 

F-4
 

 

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013

             
   Year Ended December 31, 
   2015   2014   2013 
REVENUES               
Transloading Revenue  $23,161,752   $26,781,637   $- 
Sand Revenue   4,532,393    1,379,520    - 
Rental Income   120,000    120,000    - 
Rental Income – Related Party   -    -    349,372 
Other   1,398,950    -    - 
Total Revenues   29,213,095    28,281,157    349,372 
                
COST OF REVENUES   6,796,772    8,040,016    - 
(exclusive of items shown separately below)               
                
OPERATING EXPENSES               
Transloading Operating Expenses   4,176,658    2,799,268    - 
General and Administrative Expenses   10,343,262    9,131,788    8,449,125 
Depreciation and Amortization   4,764,844    4,332,900    179,546 
Total Operating Expenses   19,284,764    16,263,956    8,628,671 
                
INCOME (LOSS) FROM OPERATIONS   3,131,559    3,977,185    (8,279,299)
                
OTHER INCOME (EXPENSE)               
Income from Investment in Dakota Petroleum Transport Solutions, LLC   -    -    4,312,394 
Income (Loss) from Investment in DPTS Marketing LLC   -    (355,265)   2,961,671 
Income from Investment in Dakota Plains Services, LLC   -    606,977    130,305 
Interest Expense (Net of Interest Income)   (8,071,283)   (2,793,190)   (3,630,950)
Gain on Extinguishment of Debt   -    -    1,726,515 
Change in Operational Override   10,958,375    -    - 
Other Income (Expense)   (1,704,618)   (34,022)   - 
Total Other Income (Expense)   1,182,474    (2,575,500)   5,499,935 
                
INCOME (LOSS) BEFORE  TAXES   4,314,033    1,401,685    (2,779,364)
                
INCOME TAX PROVISION (BENEFIT)   29,281,784    (854,993)   (1,054,000)
                
NET INCOME (LOSS)   (24,967,751)   2,256,678    (1,725,364)
                
NET INCOME ATTRIBUTABLE TO NON-CONTROLLING INTERESTS   -    5,520,752    - 
                
NET LOSS ATTRIBUTABLE TO SHAREHOLDERS OF DAKOTA PLAINS HOLDINGS, INC.  $(24,967,751)  $(3,264,074)  $(1,725,364)
                
Net Loss Per Common Share – Basic and Diluted  $(0.46)  $(0.06)  $(0.04)
                
Weighted Average Shares Outstanding – Basic and Diluted   54,228,266    53,971,183    42,338,999 

 

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

 

F-5
 

 

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013

             
   Year Ended December 31, 
   2015   2014   2013 
CASH FLOWS FROM OPERATING ACTIVITIES               
Net Income (Loss)  $(24,967,751)  $2,256,678   $(1,725,364)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by (Used in) Operating Activities               
Depreciation and Amortization   4,764,844    4,332,900    179,546 
Amortization of Debt Discount   -    640,985    349,632 
Amortization of Finance Costs   1,017,844    203,394    70,728 
Gain on Extinguishment of Debt   -    -    (1,726,515)
Gain on Sale of Dakota Plains Services, LLC   -    (472,624)   - 
Deferred Income Taxes   29,280,000    (1,033,000)   (26,000)
Share-Based Consulting Fees   -    -    299,288 
Decrease in Deferred Rental Income   -    -    (24,793)
Income from Investment in Dakota Petroleum Transport Solutions, LLC   -    -    (4,312,394)
Loss (Income) from Investment in DPTS Marketing LLC   -    355,265    (2,961,671)
Income for Investment in Dakota Plains Services, LLC   -    (606,977)   (130,305)
Decrease in Operational Override Liability   (10,958,375)   -    - 
Non-Cash Rental (Income) Expense   -    17,941    (12,169)
Amortization of Deferred Rent   (7,000)   (7,000)   (4,083)
Share-Based Compensation   2,513,258    2,330,651    2,753,817 
Changes in Working Capital and Other Items, Net of Purchase of Membership Interest and Consolidation of VIE:               
Increase in Trade Receivables   (5,667,676)   (3,245,923)   - 
Decrease (Increase) in Other Receivables   739,097    (712,239)   - 
Decrease (Increase) in Income Taxes Receivable   5,155    1,105,254    (1,120,057)
Decrease (Increase) in Other Current Assets   (339,533)   460,724    (55,986)
Decrease in Due from Related Party   -    1,676,006    46,018 
Increase (Decrease) in Accounts Payable   (2,886,173)   2,251,463    69,318 
Decrease in Income Taxes Payable   -    -    (1,028,000)
Increase in Accrued Expenses   1,314,493    129,769    1,307,740 
Decrease in Deferred Rental Income   -    -    (8,062)
Increase in Due from Related Party   -    (24,484)   - 
Increase in Restricted Cash   (593)   -    - 
Increase in Other Assets   -    (496,999)   (15,500)
Net Cash Provided By (Used In) Operating Activities   (5,192,410)   9,161,784    (8,074,812)
                
CASH FLOWS FROM INVESTING ACTIVITIES               
Purchases of Property and Equipment   (5,136,844)   (12,285,389)   (159,621)
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 
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   (5,136,844)   (40,579,405)   5,055,198 
                
CASH FLOWS FROM FINANCING ACTIVITIES               
Finance Costs Paid   (612,500)   (1,430,459)   (9,783)
Common Shares Surrendered   (356,845)   (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)
Increase in Restricted Cash   -    (3,000,000)   - 
Repayment of Promissory Notes   -    (7,717,317)   (6,922,684)
Proceeds from Promissory Note, Pioneer Project   -    -    7,500,000 
Principal Payments on Promissory Note, Pioneer Project   -    (7,500,000)   - 
Advances on Promissory Notes, SunTrust   9,000,000    48,500,000    - 
Payments on Promissory Notes, SunTrust   (750,000)   -    - 
Proceeds from Notes Payable – Vehicles   270,165    -    - 
Payments on Notes Payable – Vehicles   (44,272)   -    - 
Payments on Operational Override Liability   (46,518)   -    - 
Net Cash Provided By Financing Activities   7,460,030    23,096,719    13,691,139 
                
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS   (2,869,224)   (8,320,902)   10,671,525 
                
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD   4,690,706    13,011,608    2,340,083 
                
CASH AND CASH EQUIVALENTS – END OF PERIOD  $1,821,482   $4,690,706   $13,011,608 
                
Supplemental Disclosure of Cash Flow Information               
Cash Paid During the Period for Interest  $5,204,872   $1,536,450   $3,085,750 
Cash Paid During the Period for Income Taxes  $1,784   $11,852   $1,073,308 
                
Non-Cash Financing and Investing Activities:               
Property and Equipment Included in Accounts Payable  $380,549   $754,815   $10,215 
Finance Costs Included in Accrued Expenses  $1,138,750   $-   $- 
Purchase of Property and Equipment Paid Subsequent to Period End Related to Consolidation of VIE  $-   $-   $6,173,638 
Preferred Dividend Receivable  $-   $457,532   $498,632 
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  $411,802   $39,439,828   $- 
Increase in Deferred Tax Asset  $-   $24,114,000   $- 
Increase in Contingent Liability  $-   $45,310,867   $- 

 

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

 

F-6
 

 

DAKOTA PLAINS HOLDINGS, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT) 

FOR THE YEARS ENDED DECEMBER 31, 2015, 2014 AND 2013

                        
           Additional       Non-Controlling   Total
Stockholders’
 
   Common Stock   Paid-In   Accumulated   Interest In   Equity 
   Shares   Amount   Capital   Deficit   Subsidiary   (Deficit) 
                               
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 Common 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   144,477    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 Method 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   55,044,828    55,044    6,267,788    (10,100,899)   -    (3,778,067)
Share-Based Compensation   -    -    2,155,258    -    -    2,155,258 
Issuance of Restricted Common Shares   66,667    67    (67)   -    -    - 
Common Shares Surrendered   (237,399)   (237)   (356,608)   -    -    (356,845)
Issuance of Common Shares to Board Directors   267,934    268    349,732    -    -    350,000 
Issuance of Common Shares to Employee   33,333    33    7,967    -    -    8,000 
Increase in Joint Venture Ownership Pursuant to Equity Method Transaction   -    -    (411,802)   -    -    (411,802)
Net Loss   -    -    -    (24,967,751)   -    (24,967,751)
Balance – December 31, 2015   55,175,363   $55,175   $8,012,268   $(35,068,650)  $-   $(27,001,207)

 

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

 

F-7
 

 

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

 

December 31, 2015

   
1. Organization and Nature of Business

 

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

 

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

 

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

 

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

 

F-8
 

 

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 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.

 

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

 

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

 

In February 2016, the FASB issued ASU 2016-02, “Leases”, effective for annual periods and interim periods within those periods beginning after December 15, 2018. The new guidance requires recognition of leased assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. This new guidance will be effective beginning January 1, 2019. The Company is evaluating the impact of this standard on its consolidated financial statements.

 

Liquidity

 

As of December 31, 2015, the Company had cash and cash equivalents and trade receivables of approximately $10.7 million and accounts payable and accrued expenses of approximately $8.9 million. In addition, it has $3.2 million aggregate principal amount of promissory notes due prior to December 31, 2016.

 

The Company is focused on increasing the crude oil and frac sand throughput at its transloading facility and reducing its overall expenses. As evidenced by the positive cash flow depicted in its 2016 cash flow forecast, the Company believes that the cash flows from operations will allow it to meet its current obligations in the ordinary course of business. In order to achieve positive cash flows in 2016, the Company is committed to its plan to reduce its general and administrative expenses when compared to 2015. In addition, the Company reduced the headcount at its transloading facility by approximately 24% in February 2016. 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.

 

Joint Venture Equity Investment

 

The Company used the equity method to account for investments in joint ventures where it 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 DPTS, DPTS Marketing LLC (“DPTSM”) and DPTS Sand, LLC from its joint venture partner (See Note 13, Member Interest Purchase Agreement). Prior to the aforementioned transactions, the Company accounted for its investments in DPS and DPTSM using the equity method. 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 was adjusted for its share of intercompany transactions. Any significant unrealized intercompany profits or losses were eliminated in applying the equity method of accounting.

 

F-9
 

 

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. Accordingly, the accompanying 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, 2015 and 2014, the Company had no investments in joint ventures where it had significant influence, representing equity ownership of not more than 50%, and was not accounting for any investments using the equity method.

 

Cash and Cash Equivalents

 

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

 

Segments

 

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

 

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

 

Accounts Receivable

 

Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. At December 31, 2015 and 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  
Tanks   13 years  
Other Property and Equipment   3-5 years  
Land    

 

Expenditures for leasehold improvements, replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Depreciation expense was $4,764,844, $4,332,900 and $179,546 for the years ended December 31, 2015, 2014 and 2013, respectively. The Company had fixed assets related to in-progress construction of $0 and $1,886,470 at December 31, 2015 and 2014, respectively.

 

F-10
 

 

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 during the years ended December 31, 2015, 2014 and 2013.

 

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, 2015 and 2014.

 

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.

 

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

 

The tax effects from an uncertain tax position can be recognized in the consolidated financial statements only if the position is more likely than not 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, restricted stock and restricted stock unit 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.

 

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.

 

F-11
 

 

Revenue Recognition

 

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

 

Concentration of Risk

 

For the years ended December 31, 2015 and 2014, the three largest customers of DPTS accounted for approximately 90% and 86% of the total revenues from crude oil transloading. For the year ended December 31, 2013, DPTS Marketing LLC, a related party through common ownership, accounted for 100% of total revenues from crude oil transloading.

 

For the years ended December 31, 2015 and 2014, UNIMIN was the sole customer of DPTS Sand, LLC and accounted for 100% of total revenues from frac sand transloading.

 

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, 2015, 2014, and 2013, the potentially dilutive shares are anti-dilutive and thus not added into the diluted EPS calculation.

 

The following stock options, warrants, restricted stock and restricted stock units represent potentially dilutive shares as of December 31, 2015, 2014 and 2013:

 

    December 31,  
    2015   2014   2013  
Restricted Stock     822,816     1,031,150     769,063  
Restricted Stock Units     1,624,121     -     -  
Stock Options     -     -     415,625  
Stock Warrants     2,771,000     2,771,000     2,771,000  
                     
Total Potentially Dilutive Shares     5,217,937     3,802,150     3,955,688  

 

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.

 

F-12
 

 

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

 

FASB 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 balance sheets as of December 31, 2015 and 2014 and the accompanying consolidated statement of operations for the year ended December 31, 2015 include the accounts of the Company and its wholly owned subsidiaries. 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”).

 

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.

 

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 statement of operations for the year ended December 31, 2013.

 

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.

 

F-13
 

 

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 for the year ended December 31, 2013. The rental income for the years ended December 31, 2015 and 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.

 

Rental income related to the Supplemental Agreement was $11,310 for the year ended December 31, 2013. The rental income for the year ended December 31, 2015 and 2014 was eliminated upon consolidation.

 

On 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 
       
Sales   $ 17,475,294
Net Earnings     7,926,044
Company’s Share of Equity in Net Earnings     3,963,022

 

The statements of operations information for the years ended December 31, 2015 and 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 statement of operations for the year ended December 31, 2013. The following audited pro forma results of operations assumes that the change in control of day-to-day management of the operations had been effective for the aforementioned period. 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   
         
Revenues   $ 17,475,294  
Net Income     735,658  
Net Income Attributable to Non-Controlling Interest     2,461,022  
Net Income Attributable to Stockholders of Dakota Plains Holdings, Inc.     (1,725,364 )

 

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.

 

F-14
 

 

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 member 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. 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 its 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.

 

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 was included in other income on the consolidated statements of operations for the years ended December 31, 2014 and 2013.

 

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

 

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

 

The statement of operations information for the year ended December 31, 2015 has been excluded as it is included in the consolidated financial statements of the Company.

 

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.

 

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 for the years ended December 31, 2014 and 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  
Revenues   $ 70,619,811     $ 56,079,342  
Net Income     1,901,413       1,236,307  
Net Income Attributable to Non-Controlling Interest     5,165,487       2,961,671  
Net Loss Attributable to Stockholders of Dakota Plains Holdings, Inc.     (3,264,074 )     (1,725,364 )

 

F-15
 

 

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.

 

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.

 

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 was included in other income on the consolidated statements of operations for the years ended December 31, 2014 and 2013. As required by GAAP, the Company recognized its pro rata share of the net income from DPS for the years ended December 31, 2014 and 2013, less the unrecognized losses from the period ended December 31, 2012.

 

The unaudited financial statements of DPS are summarized as follows:

 

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

 

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 for the year ended December 31, 2014.

 

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 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 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.

 

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 $60,470 for the period from January 1, 2013 through June 30, 2013. 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.

 

F-16
 

 

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. The rental income for the years ended December 31, 2015 and 2014 was eliminated upon consolidation.

 

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, 2015 and 2014.

 

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 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 expensed as general and administrative expenses.

 

F-17
 

 

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 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 common 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.

 

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.

 

In May 2015, the Company issued an aggregate of 33,558 shares of common stock to its former non-employee directors pursuant to its 2011 Equity Incentive Plan, as amended for service to the Company. These shares were valued at $50,000 or $1.49 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 2015, the Company issued an aggregate of 234,376 shares of common stock to its non-employee directors pursuant to its 2011 Equity Incentive Plan, as amended for service to the Company. These shares were valued at $300,000 or $1.28 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 2015, the Company issued 33,333 shares of common stock to an employee pursuant to its 2011 Equity Incentive Plan, as amended for service to the Company. These shares were valued at $8,000 or $0.24 per share, the market value of the shares of common stock on the date of issuance and expensed as general and administrative expenses.

  

During the year ended December 31, 2015, 237,399 shares of common stock were surrendered by certain executives, employees, and directors of the Company to satisfy tax obligations in connection with the stock grants and vesting of restricted stock awards. The total value of these shares was $356,845, which was based on the closing market price on the date of surrender.

 

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 were recognized as compensation or interest expense over the vesting term.

  

Warrants

 

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.

 

F-18
 

 

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, 2015, 2014, and 2013:

                     
    Year Ended
December 31,
 
    2015   2014   2013  
General and Administrative Expenses   $ -   $ -   $ 223,100  
Interest Expense     -     640,985     349,632  

 

A summary of the warrant activity for the years ended December 31, 2015, 2014 and 2013 is as follows: 

                           
    Number
of
Warrants
  Weighted
Average
Exercise
Price
  Remaining
Contractual
Term
(in Years)
  Intrinsic
Value
 
Outstanding at January 1, 2013     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  
Granted     -     -     -     -  
Exercised     -     -     -     -  
Outstanding at December 31, 2015     2,771,000   $ 2.24     2.95   $ -  

 

For the years ended December 31, 2015, 2014 and 2013, other information pertaining to warrants is as follows: 

                     
    2015   2014   2013  
Weighted-average grant-date fair value of warrants granted   $ -   $ -   $ 1.46  
Total intrinsic value of warrants exercised   $ -   $ -   $ -  
Total grant-date fair value of warrants vested during the year   $ -   $ -   $ 280,223  

 

The following assumptions were used for the Black-Scholes option valuation model to value the warrants granted during the years ended December 31, 2015, 2014 and 2013. 

                     
    2015   2014   2013  
Risk free rates     -     -     0.72 %
Dividend yield     -     -     0.00 %
Expected Volatility     -     -     51.97 %
Weighted average expected life     -     -     5 yrs.  

 

The table below reflects the status of warrants outstanding at December 31, 2015: 

                     
    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, 2015 and 2014.

 

F-19
 

 

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.

 

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, 2015, 2014, and 2013: 

                     
    Year Ended
December 31,
 
    2015   2014   2013  
General and Administrative Expenses   $ -   $ -   $ 169,939  

 

A summary of options for the years ended December 31, 2015, 2014 and 2013 is as follows: 

                           
    Number
of Options
  Weighted
Average
Exercise
Price
  Remaining
Contractual
Term
(in Years)
  Intrinsic
Value
 
Outstanding at January 1, 2013     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      -     -     -     -  
Granted     -     -     -     -  
Exercised     -     -     -     -  
Forfeited or Expired      -     -     -     -  
Outstanding at December 31, 2015     -   $ -     -   $ -  
                           
Stock Options Exercisable at December 31, 2013     215,625   $ 2.90     2.9   $ -  
Stock Options Exercisable at December 31, 2014     -   $ -     -   $ -  
Stock Options Exercisable at December 31, 2015     -   $ -     -   $ -  

 

For the years ended December 31, 2015, 2014, and 2013, other information pertaining to stock options was as follows: 

                     
    2015   2014   2013  
Weighted-average per share grant-date fair value of stock options granted   $ -   $ -   $ 1.63  
Total grant-date fair value of stock options vested during the year   $ -   $ -   $ -  

 

The following assumptions were used for the Black-Scholes option valuation model to value the options granted during the years ended December 31, 2015, 2014, and 2013: 

                     
    2015   2014   2013  
Risk free rates     -     -     0.84 %
Dividend yield     -     -     0.00 %
Expected volatility     -     -     39.14-52.43 %
Weighted average expected life     -     -     4-5 yrs.  

 

F-20
 

 

Restricted Stock Awards

 

During the years ended December 31, 2015, 2014, and 2013 the Company issued an aggregate of 1,690,788, 589,483 and 794,063 shares of restricted stock and restricted stock units, respectively, as compensation to officers, employees and consultants of the Company. The shares of restricted stock and restricted stock units vest over various terms with all shares of restricted stock and restricted stock units vesting no later than March 2018. As of December 31, 2015, there was $2.4 million of total unrecognized compensation expense related to unvested shares of restricted stock and restricted stock units. The Company has assumed a zero percent forfeiture rate on all grants. The Company recorded general and administrative expense, related to shares of restricted stock and restricted stock units of $2,155,528, $1,364,816 and $1,285,066 for the years ended December 31, 2015, 2014 and 2013, respectively.

 

The following table reflects the outstanding restricted stock awards and activity related thereto for the years ended December 31, 2015, 2014 and 2013: 

                                       
    For the Year Ended:  
    December 31, 2015   December 31, 2014   December 31, 2013  
    Number
of
Shares
  Weighted
Average
Price
  Number
of
Shares
  Weighted
Average
Price
  Number
of
Shares
  Weighted
Average
Price
 
Restricted Shares Outstanding                                      
Beginning of Year     1,031,150   $ 2.89     769,063   $ 3.82     568,437   $ 1.36  
Shares Granted     1,690,788     1.59     589,483     2.22     794,063     3.81  
Lapse of Restrictions     (275,001 )   3.44     (327,396 )   3.88     (593,437 )   1.46  
Restricted Shares Outstanding     2,446,937   $ 1.93     1,031,150   $ 2.89     769,063   $ 3.82  

  

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”).

 

On December 4, 2015, the Borrowers entered into an Amendment No. 2 and Waiver to the Credit Agreement (the “Amendment”) to amend the Credit Facility. The Amendment amends the existing Credit Facility to extend the maturity date of the Tranche B Term Loan, increase the interest rate margin on the Tranche B term loan by 25 basis points and modify the leverage ratio covenant for fiscal quarters ending prior to March 31, 2017. The Amendment also waived certain events of default. There was $56.8 million outstanding under the Credit Facility at December 31, 2015.

 

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 (“Tranche A”) in the amount of $15.0 million is payable in quarterly installments and matures on December 5, 2017. Repayment of the second tranche of Term Loans (“Tranche B”) in the amount of $22.5 million is due on January 5, 2017. 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 interest expense, income taxes, depreciation expense and amortization), or leverage ratio. Amendment No. 2 then modified the leverage ratio covenant for fiscal quarters ending December 31, 2015 and March 31, 2016 by waiving the ratio requirement entirely. The method of calculating all of the components used in the covenants is included in the Credit Agreement.

 

F-21
 

 

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). Amendment No. 2 then waives certain events of default that could be triggered in connection with the Company’s pursuit of remedies against subsidiaries of World Fuel Services Corporation for railcar sublease agreements and unpaid fees and costs for crude oil transloading services. As a result, the Company has suspended payment of the Operational Override.

 

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

 

The 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 DPTS Sand, LLC.

 

The Company incurred finance costs of $1,617,909 in the year ended December 31, 2014 related to the Credit Agreement and $1,751,250 in the year ended December 31, 2015 related to the Amendment. These costs were capitalized and are being amortized over the term of the Credit Agreement using the straight-line method, which approximates the effective interest method. For the years ended December 31, 2015 and 2014, the Company recognized interest expense of $1,017,844 and $80,144 related to these finance costs, respectively.

 

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 its 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. 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 and 2013, the Company recognized interest expense of $640,985 and $349,632, 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 and 2013 was $119,202 and $65,021, 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 its $9.0 million of existing promissory notes (“Consolidated Notes”) in the amount of $500,000. The term of the remaining $8.5 million in Consolidated Notes was extended using two different maturity dates. $4,605,300 of the Consolidated Notes was extended to March 1, 2014 and $3,894,700 was extended to October 31, 2015. All of the holders of the Consolidated 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 Consolidated Notes.

 

 F-22

 

 

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.

 

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 Consolidated 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 Consolidated 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 Consolidated 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 Consolidated 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%) and 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.

 

 F-23

 

 

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.

 

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:  Amount 
December 31, 2016  $3,225,000 
December 31, 2017   53,525,000 
Total   56,750,000 
Less: Current Portion   3,225,000 
Total Long-Term Portion  $53,525,000 

 

Vehicle Loans

 

DPTS has entered into six loan agreements related to vehicles used at the Pioneer Terminal. The loan agreements have interest rates ranging from 4.02% to 5.90% and the loans mature between November 2017 and May 2020.

 

The annual maturities related to the vehicle loans are as follows: 

    
Year Ending:  Amount 
December 31, 2016  $57,623 
December 31, 2017   58,980 
December 31, 2018   46,360 
December 31, 2019   48,538 
December 31, 2020   14,392 
Total   225,893 
Less: Current Portion   57,623 
Total Long-Term Portion  $168,270 

  

   
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. At December 31, 2015, a valuation allowance of $27.4 million was applied to the net deferred tax assets based on the uncertainty regarding whether or not the assets will be realized.

 

The income tax provision (benefit) for the years ended December 31, 2015, 2014, and 2013 consists of the following: 

             
   2015   2014   2013 
Current Income Taxes               
Federal  $-   $-   $(879,000)
State   1,784    12,007    (149,000)
                
Deferred Income Taxes               
Federal   1,710,000    (1,148,000)   (8,000)
State   146,000    (25,000)   (18,000)
Valuation Allowance   27,424,000    306,000    - 
                
Total Provision (Benefit)  $29,281,784   $(854,993)  $(1,054,000)

 

 F-24

 

 

The following is a reconciliation of the reported amount of income tax provision (benefit) for the years ended December 31, 2015, 2014 and 2013 to the amount of income tax provision (benefit) that would result from applying the statutory rate to the pretax income (loss).

 

Reconciliation of reported amount of income tax benefit: 

          
   Year Ended
December 31,
 
   2015   2014   2013 
Net Income (Loss) Before Taxes and NOL  $4,314,033   $1,401,685   $(2,779,364)
Federal statutory rate   35%   35%   35%
Tax Provision (Benefit) Computed at Federal Statutory Rates   1,510,000    490,000    (973,000)
State Taxes, Net of Federal Taxes   127,000    (121,000)   (106,000)
Non-Deductible Compensation   -    169,000    - 
Other   220,784    178,007    25,000 
Net Income Attributable to Non-Controlling Interest   -    (1,877,000)     
Change in Valuation Allowance   27,424,000    306,000    - 
Reported Provision (Benefit)  $29,281,784   $(854,993)  $(1,054,000)

 

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

       
   December 31, 
   2015   2014 
Deferred Tax Assets          
Current:          
Prepaid Expenses  $(167,000)  $(30,000)
Net Operating Loss   -    1,897,000 
Accrued Interest   785,000    - 
Goodwill   398,000    399,000 
Other   91,000    - 
Valuation Allowance   (997,000)   - 
Total Current   110,000    2,266,000 
           
Non-Current:          
Fixed Assets   (7,309,000)   (3,864,000)
Share-Based Compensation   1,323,000    695,000 
Net Operating Loss   13,899,000    7,500,000 
Goodwill   5,388,000    5,791,000 
Operational Override Liability   13,016,000    16,946,000 
Valuation Allowance   (26,427,000)   (306,000)
Total Non-Current   (110,000)   26,762,000 
           
Total Deferred Tax Assets  $-   $29,028,000 

 

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 provision (benefit). For the years ended December 31, 2015, 2014 and 2013, 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, 2015 and 2014 relating to unrecognized benefits.

 

The Company reported a net operating loss (“NOL”) carry forward for federal tax purposes of approximately $36.9 million and $24.3 million at December 31, 2015 and 2014, respectively.

 

 F-25

 

 

The Company recorded a deferred tax asset for the tax Goodwill in the amount of $5.8 million at December 31, 2015. This deferred tax asset will be reduced as the Company amortizes the Goodwill. In addition, the Company recorded a deferred tax asset of $13.0 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.

 

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.  In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2015.  Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future crude oil prices.  The markets for crude oil continue to be volatile.  Changes in crude oil prices have a significant impact on the Company’s cash flows.  Prices for crude oil may fluctuate widely in response to relatively minor changes in the supply of and demand for crude oil and a variety of additional factors that are beyond the Company’s control.  Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance.

 

In determining whether to establish a valuation allowance on the Company’s deferred tax assets, management concluded that the objectively verifiable evidence of cumulative negative earnings for the three-year period ended December 31, 2015, is difficult to overcome with any forms of positive evidence that may exist.  Accordingly, the valuation allowance against the Company’s deferred tax asset at December 31, 2015 was $27.4 million.  No valuation allowance was recorded at December 31, 2014.

 

The 2014, 2013, and 2012 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 (“Original Office Lease”). 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 Original Office Lease expires on May 31, 2017. The Company is also responsible for a pro rata share of real estate taxes and general operating expenses.

 

Effective July 1, 2015, the Company terminated the Original Office Lease and entered into a revised operating lease agreement on the same office space (“Revised Office Lease”). The provisions of the Revised Office Lease are substantially similar to Original Office Lease, but the expiration date was extended to June 30, 2018.

 

Also effective July 1, 2015, the Company entered into a new operating lease agreement on 1,696 square feet of office space (“New Office Lease”). The lease requires initial base monthly lease payments of $6,360. The base annual lease payments increase by $1 per square foot on June 1 of 2016, 2017 and 2018. The New Office Lease expires on June 30, 2018. The Company is also responsible for a pro rata share of real estate taxes and general operating expenses. The New Office Lease was terminated in January 2016, and the Company has no further obligations related to this lease agreement.

 

Total rent expense under the agreements was approximately $202,000 and $138,000 for the years ended December 31, 2015 and 2014, respectively.

 

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

             
Year Ending:     Amount  
   December 31, 2016     $ 91,800  
   December 31, 2017       89,200  
   December 31, 2018       45,400  
Total     $ 226,400  

 

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

 

F-26
 

 

   
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.

 

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, 2015 and 2014:

 

    Quoted Prices In Active
Markets for Identical

Assets
(Level 1)
    Significant Other
Observable Inputs
(Level 2)
    Significant
Unobservable
Inputs
(Level 3)
 
December 31, 2015:                        
Operational Override Liability – Current Liability   $     $     $ (1,879,607 )
Operational Override Liability – Non-Current Liability                 (32,426,367 )
Total Operational Override Liability   $     $     $ (34,305,974 )
                         
December 31, 2014:                        
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 liability related to the Operational Override (See Note 13, Membership Interest Purchase Agreement). There were no transfers between fair value levels during the years ended December 31, 2015 and 2014. Level 2 liabilities consist of promissory notes (see Note 8, Promissory Notes).

 

The following table presents changes for the liability measured at fair value using significant unobservable inputs (Level 3) during the years ended December 31, 2015 and 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 )
Decrease for Lower than Estimated Volumes     10,958,375  
Principal Payments on Operational Override     46,518  
Balance at December 31, 2015   $ (34,305,974 )

 

   
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

 

F-27
 

 

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 World Fuel Services Corporation (“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 recorded as restricted cash on the consolidated balance sheets as of December 31, 2015 and 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.

 

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.

 

F-28
 

 

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.

 

In December 2014, 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%. In 2015, the Company recalculated the fair value of the Operational Override due to lower expected volumes. The Operational Override at December 31, 2015 is $34.3 million.

 

Annual maturities of the Operational Override are as follows:

             
Year Ending:     Amount  
December 31, 2016   $ 1,879,607  
December 31, 2017     2,093,108  
December 31, 2018     2,289,456  
December 31, 2019     2,504,223  
December 31, 2020     2,753,684  
Thereafter     22,785,896  
Total     34,305,974  
Less: Current Portion     1,879,607  
Total Long-Term Portion   $ 32,426,367  

 

Railcar Sublease Agreements

 

Concurrent with the Membership Interest Purchase Agreement, the Company, through DPTSM, entered into five Amended and Restated Railcar Sublease Agreements with Western Petroleum Company (“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 net lease expense under the Amended Sublease Agreements recorded to Other Expense on the statement of operations was approximately $1.7 million and $0.3 million for the years ended December 31, 2015 and 2014, respectively.  In the third quarter of 2015, DPTSM commenced a Minnesota state court lawsuit against Western Petroleum Company and is disputing the validity of the Amended Sublease Agreements under DPTS Marketing LLC v. Western Petroleum Company.

 

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

 

F-29
 

 

             
Year Ending:     Amount  
  December 31, 2016   $ 6,295,000  
  December 31, 2017     3,246,000  
  December 31, 2018     2,836,000  
  December 31, 2019     2,350,000  
  December 31, 2020-2021     2,714,000  
Total   $ 17,441,000  

 

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  

 

During the year ended December 31, 2015, the Company trued-up the transaction with PTS. As part of the true-up, the Company assumed additional net liabilities and recorded an adjustment to Additional Paid-In Capital of $411,802 during the year ended December 31, 2015 related to these net liabilities.

 

14.Commitments and Contingencies

 

Lac-Mégantic

 

We and certain of our subsidiaries, including DPTS and DPTSM, were 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. 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”). 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.

 

Between 2013 and 2015, we, certain of our subsidiaries, DPTS and DPTSM, along with a number of third parties, were sued in various actions in both the United States and Canada, by multiple third parties seeking economic, compensatory and punitive damages allegedly caused by the Derailment.

 

F-30
 

 

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.

 

On June 8, 2015, we entered into a settlement agreement (the “Settlement Agreement”) with the Trustee, Montreal, Maine and Atlantic Canada Co. (“MMAC”), and the monitor (the “Monitor”) in MMAC’s Canadian bankruptcy (collectively, the “MMA Parties”) resolving all claims arising out of the Derailment.  On December 22, 2015, the effective date of the bankruptcy plans filed by the Trustee in the U.S. and by MMAC in Canada (the “U.S. Bankruptcy Plan” and the “CCAA Plan” respectively, each a “Plan” and collectively the “Plans”), the Settlement Agreement became final and effective.  Under the terms of the Settlement Agreement, WFS contributed $110 million (the “Settlement Payment”) to a compensation fund established to compensate parties who suffered losses as a result of the derailment. As part of the settlement, we also assigned to the Trustee and MMAC certain claims we have against third parties arising out of the Derailment.

 

In consideration of the Settlement Payment and the assignment of claims to the Trustee and MMAC, we and certain of our subsidiaries, including DPTS and DPTSM (collectively, the “DAKP Parties”), received, and will continue to receive, the benefit of the global releases and injunctions set forth in the Plans. These global releases and injunctions bar all claims which may exist now or in the future against the DAKP Parties arising out of the Derailment, other than criminal claims which by law may not be released.

 

Dakota Petroleum Transport Solutions, LLC

 

TJMD, LLP v. Dakota Petroleum Transport Solutions, LLC

 

Since October 2012, DPTS had 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 alleged 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 sought payment for work performed prior to the final, September termination, as well as, monetary damages for future losses, and other relief. On October 9, 2015, we entered into a settlement agreement with TJMD resolving all claims between the parties.

 

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

 

On December 29, 2015, World Fuel Services, Inc. brought suit against DPTS and Gabriel Claypool in the United States District Court of North Dakota.  World Fuel Services, Inc. sought emergency relief for conversion and replevin of crude oil held by DPTS at the Pioneer Terminal pending the ongoing litigation for failure to pay for crude oil transloading services.  DPTS filed a motion to dismiss and, in the alternative, to stay the case in deference to the Transloading Case.  On January 20, 2016, the court approved the motion to stay pending the proceedings in the Transloading Case.

 

   
16. Subsequent Events

 

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

 

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

 

F-31
 

 

   
17. Quarterly Results of Operations (Unaudited)

 

Quarterly data for the years ended December 31, 2015, 2014, and 2013 is as follows:

                           
    Quarter Ended  
    March 31,   June 30,   September 30,   December 31,  
2015                          
Total Revenues   $ 9,387,634   $ 8,711,027   $ 6,151,139   $ 4,963,295  
Operating Expenses     6,365,737     7,121,992     6,024,997     6,568,810  
Income (Loss) From Operations     3,021,897     1,589,035     126,142     (1,605,515 )
Other Income (Expense)     (2,711,404 )   (2,469,985 )   7,919,306     (1,555,443 )
Income Tax Provision (Benefit)     127,500     (331,000 )   29,233,284     252,000  
Net Income (Loss)     182,993     (549,950 )   (21,187,836 )   (3,412,958 )
                           
Net Income (Loss) Per Common Share – Basic     0.00     (0.01 )   (0.39 )   (0.06 )
Net Income (Loss) Per Common Share – Diluted     0.00     (0.01 )   (0.39 )   (0.06 )

 

                           
    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 Stockholders 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  
Operating 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  

 

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