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As filed with the Securities and Exchange Commission on October 14, 2014

Registration No. 333-198894

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

AMENDMENT NO. 1

TO

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Mammoth Energy Partners LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		1389		47-1902732
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

 

 

4727 Gaillardia Parkway, Suite 200

Oklahoma City, OK 73142

(405) 265-4600

(Address, including zip code and telephone number, including area code, of registrant’s principal executive offices)

 

 

Mark Layton

Chief Financial Officer

Mammoth Energy Partners LP

4727 Gaillardia Parkway, Suite 200

Oklahoma City, OK 73142

(405) 265-4600

(Name, address, including zip code and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Seth R. Molay, P.C. John Goodgame Patrick J. Hurley Akin Gump Strauss Hauer & Feld LLP 1700 Pacific Avenue, Suite 4100 Dallas, TX 75201 (214) 969-4780		J. Michael Chambers Brett E. Braden Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, TX 77002 (713) 546-7416

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement is declared effective.

If any securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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

 

Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		x  (Do not check if a smaller reporting company)		Smaller reporting company		¨

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to be Registered		Proposed Maximum Aggregate Offering Price(2)		Amount of Registration Fee
Common units representing limited partner interests(1)		$100,000,000		$12,880

(1)	Includes common units that may be sold to cover the exercise of an over-allotment option granted to the underwriters.

(2)	Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(o) under the Securities Act and previously paid.

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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The information in this prospectus is not complete and may be changed. We and the selling unitholders may not sell the securities described herein until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell such securities and it is not soliciting an offer to buy such securities in any state where such offer or sale is not permitted.

 

Subject to Completion, Dated October 14, 2014.

Mammoth Energy Partners LP

                 Common Units Representing Limited Partner Interests

 

 

This is the initial public offering of our common units representing limited partner interests. Prior to this offering, there has been no public market for our common units. We are offering                  common units in this offering. The selling unitholders identified in this prospectus are offering an additional                  common units in this offering. We will not receive any of the proceeds from the sale of common units by the selling unitholders.

We anticipate that the initial public offering price will be between $             and $             per common unit. We have applied for listing of our common units on The NASDAQ Global Market under the symbol “TUSK.”

The underwriters have an option to purchase an additional                      common units, of which                  common units would be sold by us and                  common units would be sold by the selling unitholders, to cover any over-allotments.

 

 

We are an “emerging growth company” under applicable Securities and Exchange Commission rules and will be subject to reduced public company reporting requirements. Investing in our common units involves risks. See “Risk Factors” beginning on page 22.

These risks include the following:

 

•

We may not have sufficient cash available for distribution to pay any quarterly distribution on our common units.

 

•

Our partnership agreement does not require us to pay distributions. The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter.

 

•

For each of the year ended December 31, 2013 and the twelve months ended June 30, 2014, on a pro forma basis, we would not have generated sufficient cash available for distribution to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015.

 

•

Our business is difficult to evaluate because of our limited operating history.

 

•

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

 

•

Wexford owns our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates (including Wexford and Gulfport) will have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

 

•

Wexford, Gulfport and other affiliates of our general partner may compete with us.

 

•

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

•

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

 

•

We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

 

•

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

 

•

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

 

 

 

Price to Public

Underwriting Discounts and Commissions(1)

Proceeds to Mammoth Energy

Proceeds to Selling Unitholders

Per Common Unit

$

$

$

$

Total

$

$

$

$

 

(1)	See “Underwriting” for additional information regarding underwriter compensation.

Delivery of the common units is expected to be made on or about                     , 2014 through the book-entry facilities of The Depository Trust Company.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved the securities described herein or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse

The date of this prospectus is                     , 2014.

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TABLE OF CONTENTS

 

		Page
PROSPECTUS SUMMARY			1
RISK FACTORS			22
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			57
USE OF PROCEEDS			58
CAPITALIZATION			59
DILUTION			60
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			61
HOW WE WILL MAKE DISTRIBUTIONS			72
SELECTED HISTORICAL COMBINED FINANCIAL DATA			73
PRO FORMA FINANCIAL INFORMATION			76
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			81
BUSINESS			100
MANAGEMENT			124
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			132
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			140
PRINCIPAL AND SELLING UNITHOLDERS			147
DESCRIPTION OF OUR COMMON UNITS			149
THE PARTNERSHIP AGREEMENT			151
UNITS ELIGIBLE FOR FUTURE SALE			164
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			166
INVESTMENT IN MAMMOTH ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS			179
UNDERWRITING			181
LEGAL MATTERS			186
EXPERTS			186
WHERE YOU CAN FIND MORE INFORMATION			186
FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF MAMMOTH ENERGY PARTNERS LP			A-1
GLOSSARY OF OIL AND NATURAL GAS TERMS			B-1
INDEX TO FINANCIAL STATEMENTS			F-1

 

 

 

 

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ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We have not, and the selling unitholders and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We, the selling unitholders and the underwriters are only offering to sell, and only seeking offers to buy, our common units in jurisdictions where offers and sales are permitted.

The information contained in this prospectus is accurate and complete only as of the date of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

This prospectus includes industry data and forecasts that we obtained from internal company surveys, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable.

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, ^™ or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

Unless the context otherwise requires, the information in this prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their over-allotment option.

 

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RISK FACTORS

An investment in our common units involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common units. Our business, financial condition and results of operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

Risks Related to Our Business

We may not have sufficient cash available for distribution to pay any quarterly distribution on our common units.

We may not have sufficient cash available for distribution each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. Our expected aggregate annual distribution amount for the twelve months ending September 30, 2015 is based on the assumptions set forth in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015—Assumptions and Considerations.” If our assumptions prove to be inaccurate, our actual distributions for the twelve months ending September 30, 2015 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all. The amount of cash we have to distribute each quarter principally depends upon the amount of revenues we generate from oilfield services, which are dependent upon the oil and gas industry and particularly on the level of exploration and production activity within the United States and Canada. In addition, the actual amount of cash we will have to distribute each quarter under the cash distribution policy that the board of directors of our general partner will adopt will be reduced by maintenance capital expenditures, payments in respect of debt service and other contractual obligations and fixed charges and increases in reserves for future operating or capital needs that the board of directors may determine is appropriate.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please see “Cash Distribution Policy and Restrictions on Distributions.”

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our future business performance may be volatile, and our cash flows may be unstable. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero.

 

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The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of cash available for distribution we generate. Our partnership agreement does not require us to make any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute all of the cash available for distribution we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters regardless of the amount of cash available for distribution we generate. Our partnership agreement does not require us to make any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.

For each of the year ended December 31, 2013 and the twelve months ended June 30, 2014, on a pro forma basis, we would not have generated sufficient cash available for distribution to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015. In addition, as of December 31, 2013 and June 30, 2014, on a historical basis, we did not have sufficient cash on hand to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015.

During the twelve months ending September 30, 2015, we estimate that we will be able to pay aggregate quarterly distributions of $         per common unit on an annualized basis ($ per common unit if the underwriters’ over-allotment option is exercised in full). In order to pay these estimated distributions, we must generate approximately $         million of cash available for distribution during the twelve months ending September 30, 2015. We have a limited operating history upon which to rely in evaluating whether we will have sufficient cash to allow us to pay quarterly distributions on our common units. In addition, as of December 31, 2013 and June 30, 2014, on a historical basis, we did not have sufficient cash on hand to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015. For a description of the material assumptions underlying our estimate of these per common unit quarterly distributions during the twelve months ending September 30, 2015, please see “Cash Distribution Policy and Restrictions on Distributions— Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015—Assumptions and Considerations.”

The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties, which could cause actual results to differ materially from our forecasted results.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending September 30, 2015. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual distribution, which may cause the market price of our common units to decline materially.

Our business is difficult to evaluate because we have a limited operating history.

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. All of our historical assets and operations described in this prospectus are currently those of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling and Sand Tiger, which are entities controlled by our sponsor, Wexford, and the Stingray entities, which are entities currently beneficially owned

 

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50% by each of Wexford and Gulfport. Immediately prior to the closing of this offering, we will effect the Contribution Transactions. Although Sand Tiger began operations in 2007, the other operating entities involved in the Contribution Transactions began operations between September 2011 and September 2014. Further, these companies have not previously been operated as one business. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

Our customer base is concentrated and the loss of, or nonperformance by, one or more of our significant customers could cause our revenue to decline substantially.

Our top five customers accounted for approximately 54.3% and 58.8% of our revenue, on a pro forma basis, for the six months ended June 30, 2014 and the year ended December 31, 2013, respectively. Gulfport was our largest customer accounting for approximately 36.8% and 46.1% of our revenue for such periods, respectively, on a pro forma basis, with no other customer accounting for more than 10% of our revenue during those periods. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer decided not to continue to use our services, our revenue would decline and our operating results and financial condition could be harmed. In addition, we are subject to credit risk due to the concentration of our customer base. Any increase in the nonpayment of and nonperformance by our counterparties, either as a result of changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and cash available for distribution and could adversely affect our liquidity.

Our business depends on the oil and natural gas industry and particularly on the level of exploration and production activity within the United States and Canada, which may be adversely impacted by industry conditions that are beyond our control.

Substantially all of our revenue is derived from sales to companies in the oil and gas industry. We depend largely on our customers’ willingness and ability to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States and Canada. If these expenditures decline, our business will suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:

 

•

the domestic and foreign supply of and demand for oil and natural gas;

 

•

the level of prices, and expectations about future prices, of oil and natural gas;

 

•

the level of global oil and natural gas exploration and production;

 

•

the cost of exploring for, developing, producing and delivering oil and natural gas;

 

•

the expected decline rates of current production;

 

•

the price of foreign imports;

 

•

political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

 

•

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

•

speculative trading in crude oil and natural gas derivative contracts;

 

•

the level of consumer product demand;

 

•

the discovery rates of new oil and natural gas reserves;

 

•

contractions in the credit market;

 

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available pipeline and other transportation capacity;

 

•

weather conditions and other natural disasters;

 

•

political instability in oil and natural gas producing countries;

 

•

domestic and foreign governmental approvals and regulatory requirements and conditions;

 

•

the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;

 

•

technical advances affecting energy consumption;

 

•

the proximity and capacity of oil and natural gas pipelines and other transportation facilities;

 

•

the price and availability of alternative fuels;

 

•

the ability of oil and natural gas producers to raise equity capital and debt financing;

 

•

merger and divestiture activity among oil and natural gas producers; and

 

•

overall domestic and global economic conditions.

Any of the above factors could impact the level of oil and natural gas exploration and production activity and could ultimately have a material adverse effect on our business, financial condition, results of operations and cash flows.

The cyclicality of the oil and natural gas industry may cause our operating results to fluctuate.

We derive our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We may experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, in 2009, declines in prices for oil and natural gas, combined with adverse changes in the capital and credit markets, caused many exploration and production companies to reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (e.g., an hour, a day, a week) for the actual period of time the service is provided to our customers. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market prices and utilization, with resulting volatility in our revenues.

If oil and natural gas prices remain volatile, or if oil prices decline or natural gas prices remain low or decline further, the demand for our services could be adversely affected.

The demand for our services is primarily determined by current and anticipated oil and natural gas prices and the related general production spending and level of drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and may cause lower rates and lower utilization of our well service equipment. If oil prices decline or natural gas prices continue to remain low or decline further, or if there is a reduction in drilling activities, the demand for our services and our results of operations could be materially and adversely affected.

Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate, or WTI, has ranged from a high of $145.31 per barrel, or Bbl,

 

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in July 2008 to a low of $30.28 per Bbl in December 2008. The Henry Hub spot market price of natural gas has ranged from a high of $13.31 per million British thermal units, or MMBtu, in July 2008 to a low of $1.82 per MMBtu in April 2012. During 2013, West Texas Intermediate prices ranged from $85.61 to $112.24 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.05 to $4.53 per MMBtu. On June 30, 2014, the West Texas Intermediate posted price for crude oil was $106.07 per Bbl and the Henry Hub spot market price of natural gas was $4.39 per MMBtu.

Competition within the oilfield services industry may adversely affect our ability to market our services.

The oilfield services industry is highly competitive and fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. The amount of equipment available may exceed demand, which could result in active price competition. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. In addition, adverse market conditions lower demand for well servicing equipment, which results in excess equipment and lower utilization rates. If market conditions in our oil-oriented operating areas were to deteriorate or if adverse market conditions in our natural gas-oriented operating areas persist, utilization rates may decline.

Shortages, delays in delivery and interruptions in supply of drill pipe, replacement parts, other equipment, supplies and materials may adversely affect our contract land and directional drilling business.

During periods of increased demand for drilling services, the industry has experienced shortages of drill pipe, replacement parts, other equipment, supplies and materials, including, in the case of our pressure pumping operations, proppants, acid, gel and water. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply could result in significant delays in delivery of equipment and materials or prevent operations. Interruptions may be caused by, among other reasons:

 

•

weather issues, whether short-term such as a hurricane, or long-term such as a drought, and

 

•

shortage in the number of vendors able or willing to provide the necessary equipment, supplies and materials, including as a result of commitments of vendors to other customers or third parties.

These price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating costs. Severe shortages, delays in delivery and interruptions in supply could limit our ability to construct and operate our drilling rigs and could have a material adverse effect on our business, financial condition, cash flows, results of operations and cash available for distribution.

Advancements in drilling and well service technologies could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

As new horizontal and directional drilling, pressure pumping, pressure control and other well service technologies develop, we may be placed at a competitive disadvantage, and competitive pressure may force us to implement new technologies at a substantial cost. We may not be able to successfully acquire or use new technologies.

Further, our customers are increasingly demanding the services of newer, higher specification drilling rigs.

There can be no assurance that we will:

 

•

have sufficient capital resources to build new, technologically advanced drilling rigs;

 

•

successfully integrate additional drilling rigs;

 

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effectively manage the growth and increased size of our organization and drilling fleet;

 

•

successfully deploy idle, stacked or additional drilling rigs;

 

•

maintain crews necessary to operate additional drilling rigs; or

 

•

successfully improve our financial condition, results of operations, business or prospects as a result of building new drilling rigs.

If we are not successful in building new rigs and equipment or upgrading our existing rigs and equipment in a timely and cost-effective manner, we could lose market share. New technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could have a material adverse impact on our business, financial condition, results of operation and cash available for distribution.

Our business depends upon our ability to obtain specialized equipment and parts from third-party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

We purchase specialized equipment and parts from third party suppliers and affiliates, including companies controlled by Wexford. At times during the business cycle, there is a high demand for hydraulic fracturing, coiled tubing and other oil field services and extended lead times to obtain equipment needed to provide these services. Further, there are a limited number of suppliers that manufacture the equipment we use. Should our current suppliers be unable or unwilling to provide the necessary equipment and parts or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution. In addition, future price increases for this type of equipment and parts could negatively impact our ability to purchase new equipment to update or expand our existing fleet or to timely repair equipment in our existing fleet.

As part of our proppant production and sales business, we rely on third parties for raw materials and transportation, and the termination of our relationship with one or more of these third parties could adversely affect our operations.

As part of our proppant production and sales business, we buy raw sand, process it into premium monocrystalline sand, a specialized mineral that is used as a proppant (also known as frac sand), at our indoor sand processing plant located in Pierce County, Wisconsin and sell it to our customers for use in their hydraulic fracturing operations to enhance the recovery rates of hydrocarbons from oil and natural gas wells. We contract with third party providers to transport raw sand from a sand mine to our sand processing plant. We also provide logistics solutions to deliver our frac sand products to our customers. Because our customers generally find it impractical to store frac sand in large quantities near their job sites, they seek to arrange for product to be delivered where and as needed, which requires predictable and efficient loading and shipping of product. To facilitate our logistics capabilities, we contract with third party providers to transport our frac sand products to railroad facilities for delivery to our customers. We also lease a railcar fleet from various third parties to deliver our frac sand products to our customers and lease or otherwise utilize origin and destination transloading facilities. The termination or nonrenewal of our relationship with any one or more of these third parties involved in the sourcing, transportation and delivery of our frac sand products could result in material operational delays, increase our operating costs, limit our ability to service our customers’ wells or otherwise materially and adversely affect our business, operating results and cash available for distribution.

Future performance of our proppant processing and sales business will depend on our ability to succeed in competitive markets, and on our ability to appropriately react to potential fluctuations in the demand for and supply of frac sand.

In our proppant production and sales business, we operate in a highly competitive market that is characterized by a small number of large, national producers and a larger number of small, regional or local producers.

 

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Competition in the industry is based on price, consistency and quality of product, site location, distribution and logistics capabilities, customer service, reliability of supply and breadth of product offering. The large, national producers with whom we compete include Badger Mining Corporation, Fairmount Minerals, Ltd., Hi-Crush Partners LP, Preferred Proppants LLC, Unimin Corporation and U.S. Silica Holdings Inc. Our larger competitors may have greater financial and other resources than we do, may develop technology superior to ours, may have production facilities that are located closer to sand mines from which raw sand is mined or to their key customers than our processing facility or have a more cost effective access to raw sand and transportation facilities that we do. Should the demand for hydraulic fracturing services decrease, prices in the frac sand market could materially decrease as producers may seek to preserve market share or exit the market and sell frac sand at below market prices. In addition, oil and natural gas exploration and production companies and other providers of hydraulic fracturing services could acquire their own frac sand reserves, develop or expand frac sand production capacity or otherwise fulfill their own proppant requirements and existing or new frac sand producers could add to or expand their frac sand production capacity, which may negatively impact pricing and demand for our frac sand. We may not be able to compete successfully against either our larger or smaller competitors in the future, and competition could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

An increase in the supply of raw frac sand having similar characteristics as the raw frac sand we produce could make it more difficult for us to market our sand on favorable terms or at all.

We have entered into a long-term, take-or-pay contract with our principal frac sand supplier. If significant new reserves of raw frac sand continue to be discovered and developed, and those frac sands have similar characteristics to the frac sand we produce, the market price for our frac sand may decline. If the market price for our frac sand falls below an amount equal to the contracted purchase price in our take-or-pay contract plus our processing and related transportation costs, this could have an adverse effect on our results of operations, cash flows and cash available for distribution over the remaining term of this contract.

Diminished access to water and inability to secure or maintain necessary permits may adversely affect our operations in our proppant production and sales business.

As part of our proppant production and sales business, we own and operate an indoor sand processing plant located in Pierce County, Wisconsin. We also lease and operate two sand transloading facilities, one in Chippewa Falls, Wisconsin and the other in St. Paul, Minnesota. The processing of raw sand and production of natural sand proppant require significant amounts of water. As a result, securing water rights and water access is necessary for the operation of our processing facilities. If the area where our facilities are located experiences water shortages, restrictions or any other constraints due to drought, contamination or otherwise, there may be additional costs associated with securing water access. We have obtained water rights that we currently use to service our activities. However, the amount of water that we are entitled to use pursuant to our water rights must be determined by the appropriate regulatory authorities. Such regulatory authorities may amend the regulations regarding such water rights, increase the cost of maintaining such water rights or eliminate our current water rights, and we may be unable to retain all or a portion of such water rights. If implemented, these new regulations could also affect local municipalities and other industrial operations and could have a material adverse effect on costs involved in operating our proppant production and sales business. Such changes in laws, regulations or government policy and related interpretations pertaining to water rights may alter the environment in which we do business, which may have an adverse effect on our financial condition and results of operations. Additionally, a water discharge permit may be required to properly dispose of water at our processing site. Certain of our facilities are also required to obtain storm water permits. The water discharge, storm water or any other permits we may be required to have in order to conduct our operations is subject to regulatory discretion, and any inability to obtain or maintain the necessary permits could have an adverse effect on our financial condition, results of operations and cash available for distribution.

 

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Demand for our frac sand products could be reduced by changes in well stimulation processes and technologies, as well as changes in governmental regulations and other applicable law.

As part of our proppant production and sales business, we sell custom frac sand products to our customers for use in their hydraulic fracturing operations to enhance the recovery rates of hydrocarbons from oil and natural gas wells. A significant shift in demand from frac sand to other proppants, or the development of new processes to replace hydraulic fracturing altogether, could cause a decline in the demand for the frac sand we produce and result in a material adverse effect on our financial condition and results of operations. Further, federal and state governments and agencies have adopted various laws and regulations or are evaluating proposed legislation and regulations that are focused on the extraction of shale gas or oil using hydraulic fracturing, a process which utilizes proppants such as those that we produce. Future hydraulic fracturing-related legislation or regulations could restrict the ability of our customers to utilize, or increase the cost associated with, hydraulic fracturing, which could reduce demand for our proppants and adversely affect our financial condition, results of operations, cash flows and cash available for distribution. For additional information regarding the regulation of hydraulic fracturing, see “—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

We provide the majority of our remote accommodations services to a limited number of customers, and the termination of one or more of these relationships could adversely affect our operations.

We provide turnkey remote accommodations services for oilfield related labor located in remote areas, which services include site identification, permitting and development, facility design, construction, installation and full site maintenance. The majority of our revenue from this business is derived from a limited number of customers pursuant to long-term agreements with these customers. The termination of our relationships or nonrenewal of our agreements with one or more of these customers could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The customized nature, and remote location, of the modular camps that we provide and service present unique challenges that could adversely affect our ability to successfully operate our remote accommodations business.

We rely on a third-party subcontractor to manufacture and install the customized modular units used in our remote accommodations business. These customized units often take a considerable amount of time to manufacture and, once manufactured, often need to be delivered to remote areas that are frequently difficult to access by traditional means of transportation. In the event we are unable to provide these modular units in a timely fashion, we may not be entitled to full, or any, payment therefor under the terms of our contracts with customers. In addition, the remote location of the modular camps often makes it difficult to install and maintain the units, and our failure, on a timely basis, to have such units installed and provide maintenance services could result in our breach of, and non-payment by our customers under, the terms of our customer contracts. Any of these factors could have a material adverse effect on our remote accommodation business and our overall financial condition, results of operations and cash available for distribution.

Health and food safety issues and food-borne illness concerns could adversely affect our remote accommodations business.

We provide food services to our customers as part of our remote accommodations business and, as a result, face health and food safety issues that are common in the food and hospitality industries. Food-borne illnesses, such as E. coli, hepatitis A, trichinosis or salmonella, and food safety issues have occurred in the food industry in the past and could occur in the future. Our reliance on third-party food suppliers and distributors increases the risk that food-borne illness incidents could be caused by factors outside of our control. New illnesses resistant to any precautions may develop in the future, or diseases with long incubation periods could arise. Further, the remote nature of our accommodation facilities and related food services may increase the risk of contamination of our food supply and create additional health and hygiene concerns due to the limited access to modern amenities and conveniences that

 

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may not be faced by other food service providers or hospitality businesses operating in urban environment. If our customers become ill from food-borne illness, we could be forced to close some or all of our remote accommodation facilities on a temporary basis or otherwise. Any such incidents and/or any report of publicity linking us to incidents of food-borne illness or other food safety issues, including food tampering or contamination, could adversely affect our remote accommodations business as well as our overall financial condition, results of operations and cash available for distribution.

Development of permanent infrastructure in the Canadian oil sands region or other locations where we locate our remote accommodations could negatively impact our remote accommodations business.

Our remote accommodations business specializes in providing modular housing and related services for work forces in remote areas which lack the infrastructure typically available in towns and cities. If permanent towns, cities and municipal infrastructure develop in the oil sands region of northern Alberta, Canada or other regions where we locate our modular camps, then demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.

Revenue generated and expenses incurred by our remote accommodation business are denominated in the Canadian dollar and could be negatively impacted by currency fluctuations.

Our remote accommodation business generates revenue and incurs expenses that are denominated in the Canadian dollar. These transactions could be materially affected by currency fluctuations. Changes in currency exchange rates could adversely affect our combined results of operations or financial position. We also maintain cash balances denominated in the Canadian dollar. At December 31, 2013, we had $4.0 million of cash in Canadian accounts. A 10% increase in the strength of the Canadian dollar versus the U.S. dollar would have resulted in an increase in pre-tax income of approximately $1.0 million as of December 31, 2013. Conversely, a corresponding decrease in the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

Certain of our completion and production services, particularly our hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations, cash flows and cash available for distribution.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. During the last two years, certain of the areas have experienced extreme drought conditions and competition for water in such shales is growing. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Our inability to obtain water to use in our operations from local sources or to effectively utilize flowback water could have an adverse effect on our financial condition, results of operations, cash flows and cash available for distribution.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chairman, President and Chief Financial Officer, could disrupt our operations. We do not have an employment agreement with these executives at this time. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

 

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If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.

The delivery of our products and services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited. As a result, competition for experienced oilfield service personnel is intense, and we face significant challenges in competing for crews and management with large and well-established competitors. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Unionization efforts could increase our costs or limit our flexibility.

Presently, none of our employees work under collective bargaining agreements. Unionization efforts have been made from time to time within our industry, to varying degrees of success. Any such unionization could increase our costs or limit our flexibility.

Our operations may be limited or disrupted in certain parts of the continental U.S. and Canada during severe weather conditions, which could have a material adverse effect on our financial condition, results of operations and cash available for distribution.

We provide contract land and directional drilling services completion and production services in the Utica, Permian Basin, Marcellus, Granite Wash, Cana Woodford and Cleveland Sand resource plays located in the continental U.S. We also provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers located in Ohio, Oklahoma, Texas, Wisconsin, Minnesota and Alberta, Canada. For the six months ended June 30, 2014 and the year ended December 31, 2013, we generated approximately 57.1% and 52.4%, respectively, of our pro forma revenue, on a pro forma basis, from our operations in Ohio, Wisconsin, Minnesota and Canada where weather conditions may be severe, particularly during winter and spring months. Repercussions of severe weather conditions may include:

 

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curtailment of services;

 

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weather-related damage to equipment resulting in suspension of operations;

 

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weather-related damage to our facilities;

 

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inability to deliver equipment and materials to jobsites in accordance with contract schedules; and

 

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loss of productivity.

Many municipalities, including those in Ohio and Wisconsin, impose bans or other restrictions on the use of roads and highways, which include weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This can limit our access to these jobsites and our ability to service wells in these areas. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs in those regions. Weather conditions may also affect the price of crude oil and natural gas, and related demand for our services. Any of these factors could have a material adverse effect on our financial condition, results of operations and cash available for distribution.

 

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Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and ultimately adversely impact our results of operations, liquidity, financial condition and cash available for distribution.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could limit our ability to grow.

The oilfield services industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures were approximately $64.0 million and $71.6 million for the year ended December 31, 2013 and the year ended December 31, 2012, respectively. Currently, our capital expenditures budget for 2014 is approximately $139.0 million. To date, we have financed capital expenditures primarily with funding from our equity investors, cash generated by operations and borrowings under our revolving credit facilities and term loans from our lenders. Following the completion of this offering and the application of the net proceeds to repay our outstanding indebtedness, we intend to finance our capital expenditures primarily with cash on hand, cash flow from operations and borrowings under revolving credit facilities. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment or properly maintaining our existing equipment. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures for 2014 or future years could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability and cash available for distribution.

The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

As a component of our business strategy, we have pursued and intend to continue to pursue selected, accretive acquisitions of complementary assets, businesses and technologies. Acquisitions involve numerous risks, including:

 

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unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including but not limited to environmental liabilities;

 

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difficulties in integrating the operations and assets of the acquired business and the acquired personnel;

 

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limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business, in order to comply with public reporting requirements;

 

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potential losses of key employees and customers of the acquired businesses;

 

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inability to commercially develop acquired technologies;

 

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risks of entering markets in which we have limited prior experience; and

 

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increases in our expenses and working capital requirements.

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have financed capital expenditures primarily with funding from our equity investors, cash generated by operations and borrowings under our revolving credit facilities and term loans. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing unitholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.

Our ability to grow through acquisitions and manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position, results of operations and cash available for distribution may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

We may have difficulty managing growth in our business, which could adversely affect our financial condition, results of operations and cash available for distribution.

As a recently formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand the scope of our activities and our geographic coverage through both organic growth and acquisitions, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, engineers and other professionals in the oilfield services industry, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution and our ability to successfully or timely execute our business plan.

 

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If our intended expansion of our business is not successful, our financial condition, profitability and results of operations could be adversely affected, and we may not achieve the distributions and increases in revenue and profitability that we hope to realize.

A key element of our business strategy involves the expansion of our services, geographic presence and customer base. These aspects of our strategy are subject to numerous risks and uncertainties, including:

 

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an inability to retain or hire experienced crews and other personnel;

 

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a lack of customer demand for the services we intend to provide;

 

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an inability to secure necessary equipment, raw materials (particularly sand and other proppants) or technology to successfully execute our expansion plans;

 

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shortages of water used in our hydraulic fracturing operations;

 

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unanticipated delays that could limit or defer the provision of services by us and jeopardize our relationships with existing customers and adversely affect our ability to obtain new customers for such services; and

 

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competition from new and existing services providers.

Encountering any of these or any unforeseen problems in implementing our planned expansion could have a material adverse impact on our business, financial condition, results of operations and cash flows, and could prevent us from achieving the distributions and increases in revenues and profitability that we hope to realize.

Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.

Our existing and future indebtedness, whether incurred in connection with acquisitions, operations or otherwise, may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:

 

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increasing our vulnerability to general adverse economic and industry conditions;

 

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the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;

 

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our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

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any failure to comply with the financial or other covenants of our debt, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;

 

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our level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and

 

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our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.

Our new and any future revolving credit facilities will impose restrictions on us that may affect our ability to successfully operate our business.

Our new and any future revolving credit facilities and any future term debt will limit our ability to take various actions, such as:

 

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incurring additional indebtedness;

 

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paying distributions;

 

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creating certain additional liens on our assets;

 

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entering into sale and leaseback transactions;

 

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making investments;

 

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entering into transactions with affiliates;

 

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making material changes to the type of business we conduct or our business structure;

 

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making guarantees;

 

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disposing of assets in excess of certain permitted amounts;

 

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merging or consolidating with other entities; and

 

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selling all or substantially all of our assets.

In addition, our new and any future revolving credit facilities and any future term debt will require us to maintain certain financial ratios and to satisfy certain financial conditions, which may require us to reduce our debt or take some other action in order to comply with each of them. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under these credit facilities and debt agreements. Further, from time to time certain of our subsidiaries have not been in compliance with one or more of the financial covenants contained in their respective credit agreements. In each instance, the lender waived such noncompliance. If we fail to comply with the covenants in our new or any future credit facilities and such failure is not waived by the lender, a default may be declared by the lenders, which could have a material adverse effect on us.

Our new and any future credit facilities are expected to provide for variable interest rates, which may increase or decrease our interest expense.

On a pro forma basis, we would have had an aggregate of $107.1 million outstanding under various credit facilities at June 30, 2014, which bore interest at variable rates generally based on prime plus various factors. Based on this pro forma debt structure, a 1% increase or decrease in the interest rates would increase or decrease interest expense, respectively, by approximately $1.1 million per year. We do not currently hedge our interest rate exposure.

We may not be able to provide services that meet the specific needs of oil and natural gas exploration and production companies at competitive prices.

The markets in which we operate are generally highly competitive and have relatively few barriers to entry. The principal competitive factors in our markets are price, product and service quality and availability, responsiveness, experience, technology, equipment quality and reputation for safety. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

 

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In addition, some exploration and production companies have begun performing hydraulic fracturing and directional drilling on their wells using their own equipment and personnel. Any increase in the development and utilization of in-house fracturing and directional drilling capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.

Our operations are subject to hazards inherent in the oil and natural gas industry, which could expose us to substantial liability and cause us to lose customers and substantial revenue.

Risks inherent to our industry, such as equipment defects, vehicle accidents, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards such as oil spills and releases of, and exposure to, hazardous substances. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues. In addition, these risks may be greater for us than some of our competitors because we sometimes acquire companies that may not have allocated significant resources and management focus to safety and environmental matters and may have a poor environmental and safety record and associated possible exposure.

Our insurance may not be adequate to cover all losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations, cash flows and cash available for distribution. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, cash flows and cash available for distribution.

We are subject to extensive environmental, health and safety laws and regulations that may subject us to substantial liability or require us to take actions that will adversely affect our results of operations.

Our business is significantly affected by stringent and complex federal, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection and health and safety matters. As part of our business, we handle, transport and dispose of a variety of fluids and substances, including hydraulic fracturing fluids which can contain hydrochloric acid and certain petrochemicals.

 

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This activity poses some risks of environmental liability, including leakage of hazardous substances from the wells to surface and subsurface soils, surface water or groundwater. We also handle, transport and store these substances. The handling, transportation, storage and disposal of these fluids are regulated by a number of laws, including: the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; and other federal and state laws and regulations promulgated thereunder. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. We could be exposed to liability for cleanup costs, natural resource damages and other damages under these and other environmental laws. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations have changed in the past, and they are likely to change in the future and become more stringent. If existing environmental requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for oil and natural gas.

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases (collectively, GHGs) present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010.

In addition, the EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set New Performance Standards for new coal-fired and natural-gas fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility, which could reduce the demand for our products and services. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

 

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Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The Environmental Protection Agency, or EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed

 

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amendment extending compliance dates for certain storage vessels. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected later in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas and Ohio, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act, or OSHA, to state regulators and on a public internet website. In January 2012, the Ohio Department of Natural Resources, or ODNR, issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area and the ODNR continues to monitor earthquake activity in proximity to wells undergoing hydraulic fracturing. We use, and intend to continue using, hydraulic fracturing extensively in our operations, and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the demand for these services and materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

 

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Penalties, fines or sanctions that may be imposed by the U.S. Mine Safety and Heath Administration could have a material adverse effect on our proppant production and sales business and our overall financial condition, results of operations and cash flows.

The U.S. Mine Safety and Health Administration, or MSHA, has primary regulatory jurisdiction over commercial silica operations, including quarries, surface mines, underground mines, and industrial mineral process facilities. While we do not directly conduct any mining operations, we are dependent on several regulated mines for the supply of natural sand used in our proppant production. In addition, MSHA representatives perform at least two annual inspections of our production facilities to ensure employee and general site safety. As a result of these and future inspections and alleged violations and potential violations, we and our suppliers could be subject to material fines, penalties or sanctions. Any of our production facilities or our suppliers’ mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our proppant production and sales business and our overall financial condition, results of operations, cash flows and cash available for distribution.

Increasing trucking regulations may increase our costs and negatively impact our results of operations.

In connection with our business operations, including the transportation and relocation of our oilfield service equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials (HAZMAT). Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the United States Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures, which could reduce demand for our services.

 

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Conservation measures and technological advances could reduce demand for oil and natural gas and our services.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

The operational insurance coverage we maintain for our business may not fully insure us against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, any insurance obtained by us may not be adequate to cover any losses or liabilities and this insurance may not continue to be available at all or on terms which are acceptable to us. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. See “Business—Operating Risks and Insurance” for additional information on our insurance policies. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our business activities, financial condition, results of operations and cash available for distribution.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, results of operations and cash available for distribution.

We operate with most of our customers under master service agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an

 

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unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition, results of operation and cash available for distribution.

We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, common unit price, results of operations, financial condition and cash available for distribution could be materially adversely affected.

We will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as early as December 31, 2015. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming an accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify for an exemption from the requirement to provide auditors’ attestation on internal controls afforded to emerging growth companies under the Jumpstart Our Business Startups Act enacted by the U.S. Congress in April 2012. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations and cash available for distribution could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common units. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

 

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Risks Inherent in an Investment in Us

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

Following the offering, Wexford will own our general partner and will appoint all of the directors of our general partner, except for those members of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement described under “Certain Relationships and Related Party Transactions.” Certain of the directors of our general partner are also officers and/or directors of Wexford or Gulfport. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. Therefore, conflicts of interest may arise between our general partner and its affiliates, including Wexford and Gulfport, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

 

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Our general partner is allowed to take into account the interests of parties other than us, such as Wexford and Gulfport, in exercising certain rights under our partnership agreement.

 

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Neither our partnership agreement nor any other agreement requires Wexford or Gulfport to pursue a business strategy that favors us.

 

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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

 

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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

 

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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.

 

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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

 

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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.

 

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Our general partner intends to limit its liability regarding our contractual and other obligations.

 

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Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

 

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Our general partner controls the enforcement of obligations that it and its affiliates owe to us.

 

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, Wexford and Gulfport and their affiliates may compete with us. Please see “—Wexford, Gulfport and other affiliates of our general partner may compete with us.” and “Conflicts of Interest and Fiduciary Duties.”

 

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The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

In connection with the closing of this offering, the board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute an amount equal to the cash available for distribution we generate each quarter to our unitholders. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please see “Cash Distribution Policy and Restrictions on Distributions.”

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of its owners to the detriment of our common unitholders.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the cash available for distribution we generate each quarter, which could limit our ability to grow and make acquisitions.

As a result of our cash distribution policy, we will have limited cash available to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per common unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the cash available for distribution that we have to distribute to our unitholders. Please see “Cash Distribution Policy and Restrictions on Distributions.”

Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces them with contractual standards of conduct. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

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how to allocate business opportunities among us and its affiliates;

 

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whether to exercise its call right;

 

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how to exercise its voting rights with respect to the units it owns;

 

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whether to exercise its registration rights; and

 

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whether or not to consent to any merger or consolidation of the Partnership or any amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please see “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

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whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

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our general partner and its executive officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its executive officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

 

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our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction, even a transaction with an affiliate or the resolution of a conflict of interest, is:

(1) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

(2) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please see “Conflicts of Interest and Fiduciary Duties.”

Wexford, Gulfport and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Wexford and Gulfport, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Wexford or Gulfport may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Wexford, Gulfport and their affiliates, may acquire, develop or dispose of other assets or businesses in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets or businesses.

 

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, Wexford and Gulfport. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please see “Conflicts of Interest and Fiduciary Duties.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Wexford and Gulfport, as a result of Wexford’s ownership of our general partner and the investor rights agreement we expect to enter into with Gulfport prior to the closing of this offering, and not by our unitholders. Please see “Management” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner. Following the closing of this offering, Wexford and Gulfport will beneficially own     % and     % of our common units, respectively (or     % and     % of our common units, respectively, if the underwriters exercise their option to purchase additional common units in full).

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

 

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Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. Please see “Cash Distribution Policy and Restrictions on Distributions.”

At the closing of this offering, we and our general partner will also enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement. This fee will reduce the amount of cash available for distribution to our unitholders. Please see “Certain Relationships and Related Party Transactions—Advisory Services Agreement.”

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the Partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the Partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. Please see “The Partnership Agreement—Limited Liability.”

 

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Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates (including Wexford) beneficially own more than         % of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-common unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. If our general partner and its affiliates (including Wexford) reduce their ownership to below 75% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). Upon consummation of this offering, and assuming no exercise of the underwriters’ over-allotment option, affiliates of our general partner (including Wexford) will collectively own     % of our common units. For additional information about the limited call right, please see “The Partnership Agreement—Limited Call Right.”

We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

 

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the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;

 

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the amount of cash distributions on each common unit may decrease;

 

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the ratio of our taxable income to distributions may increase;

 

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the relative voting strength of each previously outstanding common unit may be diminished; and

 

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the market price of the common units may decline.

Please see “The Partnership Agreement—Issuance of Additional Partnership Interests.”

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

 

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NASDAQ does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We have applied for listing of our common units on the NASDAQ Global Market. Because we will be a publicly traded partnership, NASDAQ does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of NASDAQ’s corporate governance requirements. Please see “Management.”

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions and limitations regarding claims, suits, actions or proceedings. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees and limitations regarding claims, suits, actions or proceedings. Please see “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.” By purchasing a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.

If you bring a claim, suit, action or proceeding against us and do not obtain a judgment on the merits that substantially achieves the full remedy sought, then you may be obligated to reimburse the litigation costs of us and our affiliates.

If any person brings any claims, suits, actions or proceedings described in “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction” (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain unitholders.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per common unit for the 20 consecutive trading days immediately prior to the date set for redemption. Please see “The Partnership Agreement—Non-Taxpaying Holders; Redemption” and “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

 

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We will incur increased costs as a result of being a publicly traded partnership, which may significantly affect our financial condition.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and NASDAQ, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership.

Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase certain of our legal and financial compliance costs and make compliance activities more time-consuming and costly, particularly after we are no longer an “emerging growth company.” For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting.

However, for as long as we remain an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We intend to take advantage of these reporting exemptions until we are no longer an “emerging growth company.”

We could be an “emerging growth company” for up to five years following the completion of our initial public offering, although, if we have more than $1.0 billion in annual revenue, if the market value of our common units that is held by non-affiliates exceeds $700 million as of June 30 of any year, or we issue more than $1.0 billion of non-convertible debt over a three-year period before the end of that five-year period, we would cease to be an “emerging growth company” as of the following December 31.

We estimate that we will incur approximately $3.5 million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate. After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not “emerging growth companies,” including Section 404 of the Sarbanes-Oxley Act. See “—Risks Related to Our Business—We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, common unit price, results of operations, financial condition and cash available for distribution could be materially adversely affected” on page 42 of this prospectus.

For so long as we are an “emerging growth company” we will not be required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investors.

We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other

 

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public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We cannot predict if investors will find our common units less attractive because we will rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our common unit price may be more volatile.

Under the Jumpstart Our Business Startups Act of 2012, “emerging growth companies” can delay adopting new or revised accounting standards until such time as those standards apply to private companies. Prior to the completion of this offering, we intend to irrevocably elect not to avail ourselves to this exemption from new or revised accounting standards and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not “emerging growth companies.”

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our common unitholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. As described in “Certain Relationships and Related Party Transactions” these include, among others, agreements to provide our services and frac sand products to our affiliates and agreements pursuant to which our affiliates provide or will provide us with certain services, including administrative and advisory services and office space. Each of these entities is either controlled by or affiliated with Wexford or Gulfport, as the case may be, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our unitholders’ best interests because Wexford and/or Gulfport may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, see “Conflicts of Interest and Fiduciary Duties.”

There has been no public market for our common units and if the price of our common units fluctuates significantly, your investment could lose value.

Prior to this offering, there has been no public market for our common units. Although we have applied for a listing of our common units on The NASDAQ Global Select Market, we cannot assure you that an active public market will develop for our common units or that our common units will trade in the public market subsequent to this offering at or above the initial public offering price. If an active public market for our common units does not develop, the trading price and liquidity of our common units will be materially and adversely affected. If there is a thin trading market or “float” for our common units, the market price for our common units may fluctuate significantly more than the stock market as a whole. Without a large float, our common units are less liquid than the securities of companies with broader public ownership and, as a result, the trading prices of our common units may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The initial offering price, which will be negotiated between us and the underwriters, may not be indicative of the trading price for our common units after this offering. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common units could fluctuate widely in response to several factors, including:

 

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our quarterly or annual operating results;

 

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changes in our earnings estimates;

 

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investment recommendations by securities analysts following our business or our industry;

 

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additions or departures of key personnel;

 

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changes in the business, earnings estimates or market perceptions of our competitors;

 

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our failure to achieve operating results consistent with securities analysts’ projections;

 

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•

changes in industry, general market or economic conditions; and

 

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announcements of legislative or regulatory change.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common units could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce the price for our common units.

Upon completion of this offering, Wexford and Gulfport will beneficially own a substantial number of our common units and may sell such common units in the public or private markets. Future sales of these common units or substantial amounts of our common units, or the perception that such sales may occur, could adversely affect the prevailing market price of our common units.

Upon completion of this offering, Wexford and Gulfport will beneficially own              and              common units, respectively, or              and              common units, respectively, if the underwriters’ over-allotment option is exercised in full. Future sales of these common units or substantial amounts of our common units, or the perception that such sales may occur, could adversely affect the prevailing market price of our common units.

We cannot predict the effect, if any, that future sales of common units, or the availability of common units for future sales, will have on the market price of our common units prevailing from time to time. In addition, the sale of common units could impair our ability to raise capital through the sale of additional common units. All of the common units sold in this offering, except for any common units purchased by our affiliates, will be freely tradable. See “Units Eligible for Future Sale.”

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common units or if our operating results do not meet their expectations, our common unit price could decline.

The trading market for our common units will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our common unit price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common units or if our operating results do not meet their expectations, our common unit price could decline.

Purchasers in this offering will experience immediate dilution and will experience further dilution with the future exercise of unit options granted to certain of our executive officers under their respective employment agreements.

The initial public offering price is substantially higher than the pro forma net tangible book value per common unit of our outstanding common units. As a result, you will experience immediate and substantial dilution of approximately $         per common unit, representing the difference between our net tangible book value per common unit as of June 30, 2014 after giving effect to this offering and an assumed initial public offering price of $         (which is the midpoint of the range set forth on the cover of the prospectus). A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover page of this prospectus) would increase (decrease) our net tangible book value per common unit after giving effect to this offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and

 

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estimated offered expenses payable by us. If the options granted to certain of our executive officers under their respective employment agreements are exercised in full, the investors in this offering will experience further dilution. See “Dilution” for a description of dilution.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income purposes, please see “Material U.S. Federal Income Tax Consequences—Partnership Status” for a further discussion.

 

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If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please see “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file United States federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Please see “Material U.S. Federal Income Tax Consequences—Tax Exempt Organizations and Other Investors.”

 

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We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of our common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please see “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please see “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following

 

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this offering, Gulfport and affiliates of Wexford will directly and indirectly own approximately     % and     %, respectively, of the total interests in our capital and profits. Therefore, a transfer by Gulfport and affiliates of Wexford of all or a portion of their interests in us could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please see “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in Ohio, Oklahoma, Wisconsin, Minnesota, Pennsylvania and Texas. Many of these states impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

We will have a subsidiary that is taxable as a corporation for federal income tax purposes and it will be subject to corporate-level income taxes.

Our subsidiary that will own the remote accommodations services business will be treated as a corporation for federal income tax purposes, which will subject it to corporate-level income taxes and may reduce the cash available for distribution to us and, in turn, to unitholders. In the future, we may conduct additional operations through this subsidiary or other subsidiaries that are subject to corporate-level income taxes.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

•

business strategy;

 

•

planned acquisitions and future capital expenditures;

 

•

ability to obtain permits and governmental approvals;

 

•

technology;

 

•

financial strategy, including with respect to distributions;

 

•

future operating results; and

 

•

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Cash Distribution Policy and Restrictions on Distributions,” “How We Will Make Distributions,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “budget,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective” or “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the many factors including those described in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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USE OF PROCEEDS

Our net proceeds from the sale of                  common units in this offering, assuming a public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus), are estimated to be $         million, after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds we receive are estimated to be $         million if the underwriters’ over-allotment option is exercised in full. We intend to use the net proceeds from this offering to repay our outstanding borrowings in the aggregate amount of $         million under the following credit facilities:

 

Facility		Amount
April 2013 Redback facility
June 2013 Redback facility
October 2013 Redback facility
July 2014 Redback facility
October 2013 Coil Tubing facility
January 2013 Muskie facility
May 2013 Bison facility
July 2013 Stingray Pressure Pumping facility
September 2014 Panther Drilling facility

For additional information regarding our outstanding borrowings under each credit facility that will be repaid with the net proceeds from this offering, including the applicable interest rate, the maturity date and the use of proceeds from any borrowings incurred within one year under such facilities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Existing Credit Facilities.”

Any remaining net proceeds will be used for other general partnership purposes, which may include the acquisition of additional equipment and complementary businesses.

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds that we will receive in this offering to increase or decrease by approximately $         million.

We will not receive any proceeds from the sale of common units by the selling unitholders, including any sale the selling unitholders may make upon exercise of the underwriters’ over-allotment option.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2014:

 

•

on an actual basis;

 

•

on a pro forma basis to give effect to the issuance of                 common units to Gulfport and affiliates of Wexford in exchange for the Stingray Contribution; and

 

•

on a pro forma basis described above, as adjusted to give effect to the sale of                 common units in this offering at an assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus), our receipt of an estimated $         million of net proceeds from this offering after deducting underwriting discounts and commissions and estimated offering expenses and the use of a portion of those proceeds to repay outstanding borrowings as described under the caption “Use of Proceeds.”

This table does not reflect the issuance of up to                  common units that may be sold to the underwriters upon exercise of their over-allotment option, or the use of the resulting proceeds. You should read the following table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Pro Forma Financial Information” and our combined financial statements and related notes appearing elsewhere in this prospectus.

 

		As of June 30, 2014
		Actual(1)				Pro Forma				Pro Forma As Adjusted(2)
		(in thousands)
Cash and cash equivalents		$	7,358			$				$
Long-term debt (including current maturities)(3)		$	70,430			$				$
Members’ equity/Partners’ capital:
Member’s equity			167,522				—				—
Common unitholders			—
Public			—
Gulfport and Wexford affiliates			—
Total members’ equity/unitholders’ capital			167,522
Total capitalization		$	237,952			$				$

 

(1)

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the completion of the offering. The data in the “Actual” column of this table has been derived from the historical combined financial statements and other financial information included in this prospectus that pertain to the assets, liabilities, revenues and expenses of the common control entities.

(2)

A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus) would increase (decrease) each of cash and cash equivalents, partners’ capital and total capitalization by $         million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(3)	Represents borrowings outstanding under our credit agreements, which borrowings will be repaid in full and which agreements will be terminated at the closing of this offering.

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of our common units sold in this offering will exceed the pro forma net tangible book value per common unit after the offering. Our reported net tangible book value as of June 30, 2014 was $         million, or $         per common unit, based upon common units outstanding as of that date after giving pro forma effect to the Contribution Transactions. Net tangible book value per common unit before the offering is determined by dividing the net tangible book value (total tangible assets less total liabilities) of the capital stock and membership interests received in the Contribution Transactions by the number of common units (                 common units) to be issued to Wexford’s affiliate Mammoth Holdings, Rhino and to Gulfport in connection with this offering and the Contribution Transactions. Assuming the sale by us of          common units offered in this offering at an estimated initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus) and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, our net tangible book value as of June 30, 2014 would have been approximately $         million, or $         per common unit, after giving pro forma effect to the Contribution Transactions. This represents an immediate increase in net tangible book value of $         per common unit to our existing unitholders and an immediate dilution of $         per common unit to new investors purchasing common units at the initial public offering price.

The following table illustrates the per common unit dilution:

 

Assumed initial public offering price per common unit						$
Net tangible book value per common unit as of June 30, 2014		$
Increase per common unit attributable to new investors		$
As adjusted net tangible book value per common unit after the offering						$
Dilution per common unit to new investors						$

A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth in the cover of this prospectus) would increase (decrease) our net tangible book value after the offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table sets forth, as of June 30, 2014, after giving pro forma effect to the Stingray Contribution, the number of common units to be issued by us in the contribution, the holders of which will be our existing unitholders immediately prior to the closing of this offering, and by the new investors at the assumed initial public offering price of $         per common unit, together with the total consideration paid and average price per common unit paid by each of these groups, before deducting underwriting discounts and commissions and estimated offering expenses.

 

		Common Units Purchased						Total Consideration								Average Price
		Number		Percent				Amount				Percent				Per Common Unit
Existing unitholders						%		$						%		$
New investors						%								%
Total					100.0	%		$					100.0	%		$

If the underwriters’ over-allotment option is exercised in full, the number of common units held by new investors will be increased to             , or approximately     % of the total number of common units.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. Please see “—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical and pro forma results of operations, you should refer to our historical combined financial statements and pro forma financial data, and the notes thereto, included elsewhere in this prospectus.

General

Cash Distribution Policy

In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will distribute all of the cash available for distribution we generate each quarter, beginning with the quarter ending                     , 2014. Our first distribution, however, is expected to include cash available for distribution for the period from the closing of this offering through                     , 2014. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that cash available for distribution for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Further, it is our intent, subject to market conditions, to finance expansion capital expenditures externally. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. Please see “Risk Factors—Risks Inherent in an Investment in Us—The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.”

Because our policy will be to distribute all cash available for distribution we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low revenue, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in the performance of our operations and earnings caused by, among other things, fluctuations in demands for our services resulting from changes in the prices of oil and natural gas. Such variations in the amount of our quarterly cash distributions may be significant and could result in no distribution for any quarter.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

 

•

Our unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. The board of directors of our general partner will adopt a policy pursuant to which we will distribute to our unitholders each quarter all of the cash available for distribution we generate each quarter, as determined quarterly by the board of directors, but it may change this policy at any time.

 

•

We anticipate that the new revolving credit facility we intend to enter into in connection with the consummation of this offering will contain certain financial tests and covenants that we must satisfy. If we are unable to satisfy the restrictions under this new revolving credit facility or any future debt agreements, we could be prohibited from making a distribution to you notwithstanding our stated distribution policy.

 

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•

Our business performance may be volatile, and our cash flows may be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually.

 

•

We will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly distributions over time. Furthermore, none of our limited partner interests, including those beneficially held by Wexford and Gulfport, will be subordinate in right of distribution payment to the common units sold in this offering.

 

•

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.

 

•

Prior to making any distributions on our units, we will reimburse our general partner and certain of its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash to pay distributions to our unitholders.

 

•

Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

•

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. To fund growth, we will eventually need capital in excess of the amounts we may retain in our business. As a result, our growth will depend on our ability in the future, to raise debt and equity capital from third parties in sufficient amounts and on favorable terms when needed. To the extent efforts to access capital externally are unsuccessful, our ability to grow will be significantly impaired.

We do not have any operating history as an independent company upon which to rely in evaluating whether we will have sufficient cash to allow us to pay distributions on our common units. While we believe, based on our financial forecast and related assumptions, that we should have sufficient cash to enable us to pay the forecasted aggregate distribution on all of our common units for the twelve months ending June 30, 2015, we may be unable to pay the forecasted distribution or any amount on our common units.

We expect to pay our distributions within 60 days of the end of each quarter. Our first distribution is expected to include cash available for distribution for the period from the closing of this offering through                     , 2014.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and for the Twelve Months Ended June 30, 2014

If we had been formed and completed the transactions contemplated in this prospectus on January 1, 2013, our unaudited pro forma cash available for distribution for the year ended December 31, 2013 would have been approximately $27.4 million, or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full). If we had been formed and completed the transactions contemplated in this prospectus on July 1, 2013, our unaudited pro forma cash available for

 

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distribution for the twelve months ended June 30, 2014 would have been approximately $41.8 million, or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full).

The unaudited pro forma condensed combined financial statements upon which the unaudited pro forma cash available for distribution is based do not purport to present the financial results that would have been attained had we been formed and the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our unaudited pro forma condensed combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution shown above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods and not as presenting our financial results. Please see our unaudited pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus. We have not calculated cash available for distribution on a pro forma quarter-by-quarter basis for the year ended December 31, 2013 or the twelve months ended June 30, 2014 to determine if we would have generated cash available for distribution sufficient to pay with respect to any particular quarter the pro forma average quarterly distribution for such period or any distribution at all.

The following table illustrates, on a pro forma basis, the amount of cash available for distribution for the year ended December 31, 2013 and for the twelve months ended June 30, 2014 that would have been available for distribution to our unitholders had we been formed and completed the transactions contemplated by this prospectus on January 1, 2013 and July 1, 2013, respectively. The assumptions and adjustments that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes.

Unaudited Pro Forma Cash Available for Distribution

 

		Year Ended December 31, 2013				Twelve Months Ended June 30, 2014
		(in thousands, except per unit data)
Revenue		$	238,867			$	299,692
Expenses:
Cost of revenue, excluding depreciation, amortization and impairment		$	189,549			$	243,834
Selling, general and administrative expenses(1)			18,675				20,145
Depreciation and amortization			33,822				42,538
Impairment of long-lived assets			938				938
Interest expense, net			4,238				5,320
Other (income) expense, net			215				676
Provision for income taxes			2,715				2,357
Net income (loss)		$	(11,285	)		$	(16,116	)
Adjustments to reconcile net income (loss) to Adjusted EBITDA(2):
Add:
Depreciation and amortization		$	33,822			$	42,538
Impairment of long-lived assets			938				938
Equity based compensation			518				531
Interest expense, net			4,238				5,320
Other (income) expense, net			215				676
Provision for income taxes			2,715				2,357
Adjusted EBITDA		$	31,161			$	36,244

 

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		Year Ended December 31, 2013				Twelve Months Ended June 30, 2014
		(in thousands, except per unit data)
Less:
Cash interest expense		$	4,238			$	5,320
Provision for income taxes			2,715				2,357
Expansion and maintenance capital expenditures(3)			112,571				175,176
Net working capital(4)			(3,472	)			(13,735	)
Other (income) expense, net			295				486
Add:
Funding for expansion and maintenance capital expenditures(5)			112,571				175,176
Unaudited pro forma cash available for distribution		$	27,385			$	41,816
Unaudited pro forma cash distributions per common unit:
Assuming no exercise of the underwriters’ over-allotment option		$				$
Assuming full exercise of the underwriters’ over-allotment option		$				$
Unaudited pro forma aggregate distribution (assuming no exercise of the underwriters’ over-allotment option) to:
Common units held by the public		$				$
Common units held by Gulfport and Wexford affiliates
Total Distributions (assuming no exercise of the underwriters’ over-allotment option)		$	27,385			$	41,816
Unaudited pro forma aggregate distribution (assuming full exercise of the underwriters’ over-allotment option) to:
Common units held by the public		$				$
Common units held by Gulfport and Wexford affiliates
Total Distributions (assuming full exercise of the underwriters’ over-allotment option)		$	27,385			$	41,816

 

(1)

Includes $3.5 million of estimated incremental annual cash expense associated with being a publicly traded partnership, including $3.0 million of incremental selling, general and administrative expenses and an annual fee of $500,000 pursuant to an advisory services agreement that we expect to enter into with Wexford at the closing of this offering.

(2)	For a definition and description of Adjusted EBITDA, please see footnote 2 to the table in “Selected Historical Combined Financial Data.”

(3)	Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity. We did not differentiate between expansion capital expenditures and maintenance capital expenditures during the periods presented.

(4)	Net working capital reflects the period-over-period change in operating cash flow.

(5)	Funding for expansion and maintenance capital expenditures came primarily from borrowings under our revolving credit facilities and term loans, capital contributions and cash generated by operations.

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015

During the twelve months ending September 30, 2015, we estimate that we will be able to generate approximately $87.8 million of cash available for distribution or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full). In “—Assumptions and Considerations” below, we discuss the material assumptions underlying this estimate. The cash available for distribution discussed in this estimate will likely differ from the actual cash available for distribution that we will generate during the twelve months ending September 30, 2015. We can give you no

 

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assurance that our assumptions will be realized or that we will generate any cash available for distribution during this period, in which event we will not be able to pay quarterly cash distributions on our common units.

When considering our ability to generate cash available for distribution and how we calculate forecasted cash available for distribution, please keep in mind all the risk factors and other cautionary statements under the headings “Risk Factors” and “Forward-Looking Statements,” which discuss factors that could cause our results of operations and cash available for distribution to vary significantly from our estimates.

Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate approximately $87.8 million of cash available for distribution for the twelve months ending September 30, 2015. The accompanying prospective financial information was not prepared with a view toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.

The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by the management team of our general partner as of the date of its preparation, are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending September 30, 2015 should not be regarded as a representation by us or the underwriters or any other person that we will be able to, or that we will, make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated cash available for distribution for the twelve months ending September 30, 2015. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”

Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.

The following table illustrates the amount of cash available for distribution that we estimate that we will generate for the twelve months ending September 30, 2015 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending September 30, 2015 in the table below are estimates and all historical figures in this section are pro forma based on our unaudited pro forma condensed combined financial statements.

 

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Estimated Cash Available for Distribution

 

		Three Months Ending																Twelve Months Ending
		December 31, 2014				March 31, 2015				June 30, 2015				September 30, 2015				September 30, 2015
		(in thousands, except per unit data)
Revenue		$	114,240			$	128,459			$	145,619			$	155,471			$	543,789
Expenses:
Cost of revenue, excluding depreciation, amortization and impairment		$	82,421			$	93,096			$	106,319			$	112,468			$	394,305
Selling, general and administrative expenses(1)			5,188				5,011				5,093				5,158				20,450
Depreciation and amortization			14,513				16,138				17,635				17,908				66,194
Impairment of long-lived assets			—				—				—				—				—
Interest expense, net(2)			906				371				688				826				2,791
Other (income) expense, net			—				—				—				—				—
Provision for income taxes			594				1,097				810				751				3,252
Net income (loss)		$	10,618			$	12,746			$	15,074			$	18,360			$	56,798
Adjustments to reconcile net income (loss) to Adjusted EBITDA(3):
Add:
Depreciation and amortization		$	14,513			$	16,138			$	17,635			$	17,908			$	66,194
Impairment of long-lived assets			—				—				—				—				—
Equity based compensation			—				—				—				—				—
Interest expense, net			906				371				688				826				2,791
Other (income) expense, net			—				—				—				—				—
Provision for income taxes			594				1,097				810				751				3,252
Adjusted EBITDA		$	26,631			$	30,352			$	34,207			$	37,845			$	129,035
Less:
Cash interest expense		$	906			$	371			$	688			$	826			$	2,791
Provision for income taxes			594				1,097				810				751				3,252
Maintenance capital expenditures(4)			7,035				7,998				8,445				8,535				32,013
Expansion capital expenditures			34,167				47,315				23,465				2,275				107,222
Net working capital(5)			5,647				(3,348	)			1,251				668				4,218
Other (income) expense, net (6)			(252	)			(247	)			(249	)			(252	)			(1,000	)
Add:
Funding for expansion capital expenditures(7)			34,167				47,315				23,465				2,275				107,222
Estimated cash available for distribution		$	12,701			$	24,481			$	23,262			$	27,317			$	87,761
Estimated cash distributions per common unit:
Assuming no exercise of the underwriters’ over-allotment option		$				$				$				$				$
Assuming full exercise of the underwriters’ over-allotment option		$				$				$				$				$
Estimated aggregate distribution (assuming no exercise of the underwriters’ over-allotment option) to:
Common units held by the public		$				$				$				$				$
Common units held by Gulfport and Wexford affiliates
Total Distributions (assuming no exercise of the underwriters’ over-allotment option)		$	12,701			$	24,481			$	23,262			$	27,317			$	87,761
Estimated aggregate distribution (assuming full exercise of the underwriters’ over-allotment option) to:
Common units held by the public		$				$				$				$				$
Common units held by Gulfport and Wexford affiliates
Total Distributions (assuming full exercise of the underwriters’ over-allotment option)		$	12,701			$	24,481			$	23,262			$	27,317			$	87,761

 

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(1)

Includes $3.5 million of estimated incremental annual cash expense associated with being a publicly traded partnership, including $3.0 million of incremental selling, general and administrative expenses and an annual fee of $500,000 pursuant to an advisory services agreement that we expect to enter into with Wexford at the closing of this offering.

(2)	Assumes average borrowings of $59.5 million at an interest rate of LIBOR plus 2.75% under a new revolving credit facility we intend to enter into before the closing of this offering.

(3)	For a definition and description of Adjusted EBITDA, please see footnote 2 to the table in “Selected Historical Combined Financial Data.”

(4)	Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity.

(5)	Net working capital reflects the period-over-period change in operating cash flow.

(6)	Includes additional assumed contributions from investment and asset sales.

(7)	We expect to fund these expansion capital expenditures primarily with funds generated from our operations and borrowings under our new revolving credit facility.

Assumptions and General Considerations

Based upon the specific assumptions outlined below, following completion of this offering, we expect to generate cash available for distribution in an amount sufficient to allow us to pay an aggregate of $             per common unit ($             per common unit if the underwriters’ over-allotment option is exercised in full) on all of our outstanding units for each quarter in respect of the twelve months ending September 30, 2015.

While we believe that our assumptions are reasonable in light of our management’s current expectations concerning future events, such assumptions are not all-inclusive and the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. Such forward-looking statements are based on assumptions and beliefs that our management believes to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances.

Further, we can give no assurance that our forecasted results will be achieved. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the forecasted cash distribution, or any amount, on our outstanding common units in respect of the twelve months ending September 30, 2015 or thereafter, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” and our accounting policies discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies and Estimates.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenues. We estimate that our total revenues for the twelve months ending September 30, 2015 will be approximately $543.8 million as compared to our pro forma total revenues of approximately $299.7 million for the twelve months ended June 30, 2014 and $238.9 million for the year ended December 31, 2013. Our forecast of total revenues is based on the following assumptions by operating division:

Completion and Production Services. Our completion and production services division includes our pressure control and well services, pressure pumping services, flow back services and our proppant production and sales business. We estimate that our total completion and production services division revenue for the twelve months ending September 30, 2015 will be approximately $362.0 million as compared to approximately $179.5 million for the twelve months ended June 30, 2014 and approximately $120.9 million for the year ended December 31, 2013, on a pro forma basis. In general, we believe that this

 

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increase will be attributable to increased utilization of equipment purchased in 2013 and 2014, contributions from additional equipment intended to be purchased in 2014 and 2015 and our contracted income associated with our pressure pumping and sand contracts with Gulfport that were effective October 1, 2014.

Pressure Control and Well Services. In our pressure control services business, we anticipate generating revenue of approximately $48.6 million for the twelve months ending September 30, 2015 as compared to revenue of approximately $25.8 million for the twelve months ended June 30, 2014 and approximately $18.3 million for the year ended December 31, 2013, on a pro forma basis. We experienced lower utilization rates in 2013 and the first half of 2014 while additional coil tubing units and other equipment purchased during those periods were being placed into service. As of September 1, 2014, we had five coiled tubing units, with an average age of less than three years, capable of running over 21,000 feet of two inch coil rated at 10,000 psi in service, which we believe are well suited for the performance requirements of the unconventional resource markets we serve in the Permian Basin and Midcontinent region. Since this additional equipment was placed into service, the utilization rates of our pressure control equipment have steadily increased and are expected to remain at the current more elevated levels given the increasing demand for coil tubing services. We intend to acquire and place into service three additional coil tubing units and other coil tubing equipment during the twelve months ending September 30, 2015 at a cost of approximately $15.7 million supporting our expansion into West Texas. We expect rising utilization as new equipment suited to the Permian Basin is delivered given the strong drilling demand in that market.

We made significant investments during 2013 and the first half of 2014 in our fluid pumping equipment, adding nine additional pump down spreads in total. As of September 1, 2014, we had nine fluid pumping units with an average age of less than two years. We intend to acquire and place into service seven additional pump down spreads during the twelve months ending September 30, 2015 at an estimated cost of approximately $10.6 million, which are expected to be placed into service in the first and second quarters of 2015.

Pressure Pumping Services. In our pressure pumping services business, we anticipate generating revenue of approximately $224.1 million for the twelve months ending September 30, 2015 as compared to approximately $117.0 million for the twelve months ended June 30, 2014 and approximately $82.5 million for the year ended December 31, 2013, on a pro forma basis. As of September 1, 2014, we owned a total of 52 high-pressure fracturing (pumping) units, grouped into three fleets or “spreads,” capable of delivering a total of 117,000 horsepower. We have contracted to purchase eight additional high-pressure fracturing units with expected delivery by October 31, 2014, which will bring our fleet to 20 units per spread. For our existing three fracturing fleets, we anticipate higher utilization levels and day rates supported by a multi-year take or pay contract for two of the three fracturing spreads as well as increased utilization from our third spread, which was brought online in early 2014. Our multi-year take or pay contract includes a monthly service fee paid for each of the two spreads. Additionally, we intend to add an additional fracturing spread fleet comprised of 20 high-pressure fracturing units in 2015 with expected delivery in April 2015 at a cost of approximately $33.0 million.

Flowback Services. In our flowback services business, we anticipate generating revenue of approximately $27.2 million for the twelve months ending September 30, 2015 as compared to approximately $13.9 million for the twelve months ended June 30, 2014 and approximately $11.6 million for the year ended December 31, 2013, on a pro forma basis. As of September 1, 2014, we had five production testing packages, 12 solids control packages, two hydrostatic testing packages and five torque services packages as well as other flowback equipment to form up to a total of seven well-testing spreads. In anticipation of increased activity in the basins we serve, we intend to add additional production testing, solids control and rental equipment during the second and third quarters of 2015 at a cost of approximately $8.2 million.

Proppant Production and Sales. In our proppant production and sales business, we anticipate generating revenue of approximately $62.1 million for the twelve months ending September 30, 2015 as compared to approximately $22.8 million for the twelve months ended June 30, 2014 and approximately $8.5 million for the year ended December 31, 2013, on a pro forma basis. In our proppant production and

 

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sales business, we anticipate selling approximately 535,000 tons of proppant at an average price per ton of approximately $116 as compared to approximately 337,000 tons at an average price per ton of $102 for the twelve months ended June 30, 2014 and approximately 166,000 tons at an average price per ton of $119 for the year ended December 31, 2013. We currently have three long-term sales contracts (one-year and multi-year in nature) that that we expect will account for approximately 67% of our forecasted proppant sales revenue for the twelve months ending September 30, 2015. Additionally, the upward pricing trends in the spot market and our intention to sell excess non-contracted sand in the spot market contribute to our revenue forecast. Underpinning our higher forecasted revenues are certain equipment upgrades and additions that we made in September 2014, enabling us to increase our production of sand in excess of 600,000 tons per year on an annualized basis.

Contract Land and Directional Drilling Services. We estimate that our total contract land and directional drilling services division revenue for the twelve months ending September 30, 2015 will be approximately $150.3 million as compared to approximately $98.5 million for the twelve months ended June 30, 2014 and approximately $92.9 million for the year ended December 31, 2013, on a pro forma basis. To provide our land drilling services, we expanded our land drilling rig fleet from eight to 14 rigs in 2014 and currently anticipate adding one additional rig to our fleet in mid-2015 at a cost of approximate $17.5 million. Of the six new land drilling rigs in 2014, five were placed in service in February 2014 after having been acquired in January 2014 from Lantern Drilling. The sixth rig was acquired in June 2014 and is now contracted and to be placed in service in October 2014. As of September 1, 2014, we had 13 drilling rigs operating under term contracts with a term of more than one well and an average duration of approximately seven months. To provide our directional drilling services, we own seven MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 56 mud motors and an inventory of related parts and equipment. Overall, in our contract land and directional drilling services division, we expect utilization levels to continue to rise due to strong demand in the Permian Basin. Based on the current rig market in the Permian Basin, we believe current day rates are in excess of our current contracts, supporting an increase pricing as contracts are renewed. As a result, in our land drilling services, we anticipate extending the terms of our existing contracts at the then current market prices.

Remote Accommodation Services. We estimate that our remote accommodation services division revenue for the twelve months ending September 30, 2015 will be approximately $31.5 million as compared to approximately $21.7 million for the twelve months ended June 30, 2014 and approximately $25.0 million for the year ended December 31, 2013, on a pro forma basis. We believe that this increase will be attributable to increased utilization of available room nights and additional available rooms, approximately 68% of which are contracted during the twelve months ending September 30, 2015. As of September 1, 2014, we had 700 rooms and we plan to have a total of 890 rooms by the end of 2014, 762 of which are expected to be at Sand Tiger Lodge, our camp in northern Alberta, Canada, and 128 of which are expected to be leased as rental equipment to a third party. The new rooms have been ordered and are expected to be in service in December 2014.

Cost of Revenues (Excluding Depreciation, Amortization and Impairment). We estimate that our total cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $394.3 million as compared to approximately $243.8 million for the twelve months ended June 30, 2014 and approximately $189.5 million for the year ended December 31, 2013, on a pro forma basis. Our forecast of cost of revenues (excluding depreciation, amortization and impairment) is based on the following assumptions by operating division:

Completion and Production Services. We estimate that our completion and production services division cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $276.1 million as compared to approximately $149.1 million for the twelve months ended June 30, 2014 and approximately $101.9 million for the year ended December 31, 2013, on a pro forma basis. Our completion and production services cost of revenues consists of labor expenses, utility and fuel costs, repairs and maintenance expenses, and health, safety and environmental related costs, among others. The majority of the increase is attributable to the increase in

 

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forecasted revenue as our variable costs scale in line with forecasted revenue. A small portion of the cost increase is expected to result from contractual price increases in our vendor contracts and our assumption that non-contracted costs will rise in line with historical inflation averages.

Contract Land and Directional Drilling Services. We estimate that our contract land and directional drilling services division cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $104.3 million as compared to approximately $85.2 million for the twelve months ended June 30, 2014 and approximately $76.2 million for the year ended December 31, 2013, on a pro forma basis. Our contract land and directional drilling services cost of revenues consists of labor expenses, utility and fuel costs, repairs and maintenance expenses, and health, safety and environmental related costs, among others. The majority of the increase is attributable to the increase in forecasted revenue as our variable costs scale in line with forecasted revenue with some of the costs being passed through to customers. A small portion of the cost increase is expected to result from contractual price increases in our vendor contracts and our assumption that non-contracted costs will rise in line with historical inflation averages.

Remote Accommodation Services. We estimate that our remote accommodation services division cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $13.9 million as compared to approximately $9.5 million for the twelve months ended June 30, 2014 and approximately $11.4 million for the year ended December 31, 2013, on a pro forma basis. Our remote accommodation services cost of revenues consists of labor expenses, utility and fuel costs, repairs and maintenance expenses, and health, safety and environmental related costs, among others. The majority of the increase is attributable to the increase in forecasted revenue as our variable costs scale in line with forecasted revenue. A small portion of the cost increase is expected to result from contractual price increases in our vendor contracts and our assumption that non-contracted costs will rise in line with historical inflation averages.

Selling, General and Administrative Expenses. We estimate that our total selling, general and administrative expenses for the twelve months ending September 30, 2015 will be approximately $20.5 million as compared to approximately $20.1 million for the twelve months ended June 30, 2014 and approximately $18.7 million for the year ended December 31, 2013, on a pro forma basis. Each period includes $3.0 million of incremental selling, general and administrative expenses that we expect to incur annually as the result of being a publicly traded partnership and an annual fee of $500,000 pursuant to an advisory services agreement that we expect to enter into with Wexford at the closing of this offering. Please see “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.” In connection with this offering, we have added, and expect to continue to add, additional personnel to bolster our corporate functions to support our growing operations and public company obligations. Our estimate of selling, general and administrative expenses for the forecast period does not include any compensation expense that may be incurred in connection with the grant of awards pursuant to the equity incentive plan in connection with this offering. Any charge associated with the grant of such awards will be a non-cash expense. Please see “Management—Executive Compensation.”

Depreciation and Amortization. We estimate that our total depreciation and amortization for the twelve months ending September 30, 2015 will be approximately $66.2 million as compared to approximately $42.5 million for the twelve months ended June 30, 2014 and approximately $33.8 million for the year ended December 31, 2013, on a pro forma basis. We estimate the increase will be primarily attributable to higher depreciation expenses related to additional equipment and fixed assets to be placed into service in each of our operating divisions as described above under “—Operations and Revenues.”

Interest Expense. We estimate that our total interest expense for the twelve months ending September 30, 2015 will be approximately $2.9 million as compared to approximately $5.3 million for the twelve months ended June 30, 2014 and approximately $4.2 million for the year ended December 31, 2013, on a pro forma basis. We plan to fully repay all borrowings outstanding under our existing credit facilities with net proceeds from this offering and put in place a new credit facility that will be used for various purposes, including to fund our

 

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equipment purchases and other organic growth projects. Accordingly, future changes in interest expense will be attributable to changes in borrowings during the forecast period to support our operations. Our new credit facility to be entered into in connection with this offering is expected to offer more competitive terms than our prior combination of divisional loans which are all being repaid and terminated upon the closing of this offering. We have assumed average borrowings of $59.5 million at an interest rate of LIBOR plus 2.75% under this new credit facility. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Revolving Credit Facility.”

Capital Expenditures. We estimate that our total capital expenditures will be $139.2 million for the twelve months ending September 30, 2015 as compared to approximately $175.2 million for the twelve months ended June 30, 2014 and approximately $112.6 million for the year ended December 31, 2013, on a pro forma basis. We estimate that our expansion capital expenditures and maintenance capital expenditures will be approximately $107.2 million and $32.0 million, respectively, for the twelve months ending September 30, 2015, compared to an aggregate expansion and maintenance capital expenditures of approximately $175.2 million for the twelve months ended June 30, 2014 and approximately $112.6 million for the year ended December 31, 2013, on a pro forma basis. We did not differentiate between expansion capital expenditures and maintenance capital expenditures during the twelve months ended June 30, 2014 or the year ended December 31, 2013. Substantially all of our growth capital expenditures during the forecast period are expected to be attributable to the additional equipment anticipated to be purchased as described above under “—Operations and Revenues.” We anticipate that approximately 79.0% of our total expansion capital expenditures during the forecast period will be attributable to our completion and production services division and that approximately 21% and 0% will be attributable to our contract land and directional drilling services division and our remote accommodations services division, respectively. After the closing of this offering, we expect to fund expansion capital expenditures with funds generated from our operations, borrowings under our anticipated new revolving credit facility and term loans and issuances of additional equity and debt securities. For purposes of this forecast, we have assumed that we will fund all of the forecasted expansion capital expenditures with borrowings under our anticipated new revolving credit facility. We anticipate that the majority of our maintenance capital expenditures will be spent on the replacement and refurbishment of equipment that becomes damaged due to the nature of operating in challenging environments and will be funded with cash from operations or borrowings under our new revolving credit facility. We anticipate that approximately 62% of our total maintenance capital expenditures during the forecast period will be attributable to our completion and production services division and that approximately 35% and 3% will be attributable to our contract land and directional drilling services division and our remote accommodations services division, respectively.

Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending September 30, 2015 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

•

There will not be any new federal, state or local regulation of the portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

 

•

There will not be any major adverse change in commodity prices, our business or the energy industry in general;

 

•

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend;

 

•

Although we may undertake projects where opportunities arise, for the purposes of this forecast no acquisitions or other significant expansion capital expenditures are reflected (other than as described above);

 

•

Market, insurance and overall economic conditions will not change substantially;

 

•

Our customers subject to take-or-pay and fixed-volume commitments will fully perform under their contractual arrangements with us; and

 

•

We will not undertake any extraordinary transactions that would materially affect our cash flow.

 

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HOW WE WILL MAKE DISTRIBUTIONS

General

Within 60 days after the end of each quarter, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date. Our first distribution is expected to include cash available for distribution for the period from the closing of this offering through                     , 2014. We do not have a legal obligation to pay distributions, and the amount of distributions, if any, declared and paid under our distribution policy is determined by the board of directors of our general partner. See “Cash Distribution Policy and Restrictions on Distributions.”

Method of Distributions

We intend to distribute cash available for distribution to our unitholders, pro rata. Our partnership agreement permits us to borrow to make distributions, but we are not required to, and do not intend to, borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

Common Units

At the closing of this offering, we will have         common units outstanding. Each common unit will be entitled to receive cash distributions to the extent we distribute cash available for distribution. Common units will not accrue arrearages. Our partnership agreement allows us to issue an unlimited number of additional common units or other equity interests of equal or senior rank.

General Partner Interest

Upon the closing of this offering, our general partner will own a non-economic general partner interest and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other equity interests in the future and will be entitled to receive pro rata distributions in respect of those equity interests.

 

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SELECTED HISTORICAL COMBINED FINANCIAL DATA

The following table sets forth our selected historical combined financial data as of and for each of the periods indicated. The selected historical combined financial data as of December 31, 2013 and 2012 and for the years ended December 31, 2013 and 2012 are derived from the historical audited combined financial statements of the common control entities included elsewhere in this prospectus. The selected combined historical financial data as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 are derived from the historical unaudited combined financial statements of the common control entities included elsewhere in this prospectus. The selected combined historical balance sheet data as of June 30, 2013 are derived from the unaudited combined balance sheet of the common control entities as of such date, which is not included in this prospectus. Operating results for the years ended December 31, 2013 and 2012 and the six months ended June 30, 2014 and 2013 do not reflect the Drilling Transaction for periods prior to January 29, 2014 or the Stingray Contribution and are not necessarily indicative of results that may be expected for any future periods or as of any future date. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Pro Forma Financial Information” and the historical combined financial statements and related notes of the common control entities included elsewhere in this prospectus.

 

		Six Months Ended(1) June 30,								Year Ended(1) December 31,
		2014				2013				2013				2012
		(in thousands)
Statement of Operations Data:
Revenue:
Completion and production services		$	44,481			$	18,455			$	47,731			$	16,892
Contract land and directional drilling services			51,823				31,936				59,790				26,842
Remote accommodation services			9,586				12,895				25,027				14,169
Total			105,890				63,286				132,548				57,903
Cost of revenue, excluding depreciation, amortization and impairment:
Completion and production services			36,033				16,987				42,627				13,764
Contract land and directional drilling services			42,157				25,209				53,987				20,501
Remote accommodation services			4,165				6,115				11,416				7,333
Selling, general and administrative expenses			6,082				5,162				13,614				6,443
Depreciation and amortization			15,034				8,486				18,995				8,149
Impairment of long-lived assets			—				—				938				2,435
Total			103,471				61,959				141,577				58,625
Operating income (loss)			2,419				1,327				(9,029	)			(722	)
Interest expense			(1,864	)			(801	)			(2,012	)			(274	)
Other income (expense), net			(43	)			153				(215	)			(49	)
Income (loss) before income taxes			512				679				(11,256	)			(1,045	)
Provision for income taxes			1,059				1,417				2,715				1,013
Net loss		$	(547	)		$	(738	)		$	(13,971	)		$	(2,058	)

 

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		Six Months Ended(1) June 30,								Year Ended(1) December 31,
		2014				2013				2013				2012
		(in thousands)
Other Financial Data:
Adjusted EBITDA(2) (unaudited)		$	17,647			$	9,995			$	11,422			$	10,225
Cash flows (used in) provided by operating activities		$	(1,741	)		$	(4,879	)		$	4,162			$	4,791
Purchases of property and equipment		$	(75,128	)		$	(18,445	)		$	(63,956	)		$	(71,584	)
Other investing activities, net			575				1,953				634				—
Cash flows used in investing activities		$	(74,553	)		$	(16,492	)		$	(63,322	)		$	(71,584	)
Capital contributions		$	47,024			$	17,313			$	26,979			$	59,114
Proceeds from financing arrangements, net of repayments			27,901				9,002				31,966				13,959
Other financing activities, net			(278	)			(437	)			(361	)			(115	)
Cash flows provided by financing activities:		$	74,647			$	25,878			$	58,584			$	72,958

 

		As of June 30,								As of December 31,
		2014				2013				2013				2012
		(in thousands)
Balance sheet data:
Cash and cash equivalents		$	7,358			$	10,946			$	8,284			$	9,075
Other current assets			53,784				34,222				35,643				18,375
Property and equipment, net			214,507				125,390				155,244				117,656
Other assets			4,479				3,683				3,472				3,396
Total assets			280,128			$	174,241			$	202,643			$	148,502
Current liabilities		$	71,708			$	37,528			$	57,147			$	31,067
Long-term debt, net of current maturities			38,819				9,533				22,905				7,213
Other long-term liabilities			2,079				1,932				1,877				1,425
Shareholders’ and members’ equity			167,522				125,248				120,714				108,797
Total liabilities and shareholders’ and members’ equity		$	280,128			$	174,241			$	202,643			$	148,502

 

(1)

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the contribution of the common control entities and the Stingray entities to us prior to the completion of this offering other than certain activities related to the preparation of the registration statement for this offering. The historical combined financial statements and other financial information of Mammoth Energy Partners LP included in this prospectus pertain to assets, liabilities, revenues and expenses of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling, Bison Trucking and Sand Tiger, which are entities under the common control of our sponsor, Wexford. Except for Sand Tiger, each of the common control entities was treated as a partnership for federal income tax purposes. As a result, essentially all of their taxable earnings and losses were passed through to Wexford, and they did not pay federal income taxes at the entity level. Prior to the completion of this offering, each of these entities will become our wholly owned subsidiary.

(2)

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as earnings before interest expense, provision for income taxes, depreciation and amortization expense, impairment of long-lived assets, equity based compensation and other non-operating income or expense, net. We exclude the items listed above from net income in arriving at Adjusted EBITDA

 

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because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net loss.

 

		Six Months Ended June 30,								Year Ended December 31,
		2014				2013				2013				2012
		(in thousands)
Reconciliation of Adjusted EBITDA to net loss:
Net loss		$	(547	)		$	(738	)		$	(13,971	)		$	(2,058	)
Depreciation and amortization expense			15,034				8,486				18,995				8,149
Impairment of long-lived assets			—				—				938				2,435
Equity based compensation			194				182				518				363
Interest expense			1,864				801				2,012				274
Other (income) expense, net			43				(153	)			215				49
Provision for income taxes			1,059				1,417				2,715				1,013
Adjusted EBITDA		$	17,647			$	9,995			$	11,422			$	10,225

 

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PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma condensed combined financial statements and related notes of the Partnership have been prepared to show the effect of the Stingray Contribution and the Drilling Transaction on the combined historical financial statements of Redback Energy Services (the common control entities) for periods and as of the dates indicated. The unaudited pro forma condensed combined financial statements should be read together with the historical combined financial statements of Redback Energy Services, the historical combined financial statements of Stingray Pressure Pumping LLC and Stingray Logistics LLC (the Stingray entities), and the Statements of Revenues and Direct Operating Expenses of Certain Drilling Rigs of Lantern Drilling Company (relating to the assets acquired in the Drilling Transaction) included elsewhere in this prospectus. The following unaudited pro forma condensed combined financial statements are based on certain assumptions and adjustments as explained in the accompanying notes.

The Stingray Contribution and the Drilling Transaction will be treated as business combinations accounted for under the acquisition method of accounting with the identifiable assets acquired and liabilities assumed recognized at full fair value on the date of the Stingray Contribution and the date of the Drilling Transaction.

The pro forma data presented reflect events directly attributable to the Stingray Contribution and the Drilling Transaction and certain assumptions we believe are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the Stingray Contribution or the Drilling Transaction actually occurred on the dates indicated below.

The Stingray Contribution will be completed immediately prior to the closing of this offering.

The unaudited pro forma condensed combined balance sheet assumes that the Stingray Contribution occurred on June 30, 2014. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2013 and for the six months ended June 30, 2014 assumes the Stingray Contribution and the Drilling Transaction occurred on January 1, 2013.

 

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Mammoth Energy Partners LP

Unaudited Pro Forma Condensed Combined Balance Sheet

June 30, 2014

(dollar amounts in thousands)

 

		Common Control Entities Historical				Stingray Entities Historical				Pro Forma Adjustments				Pro Forma
Assets
Cash and cash equivalents		$	7,358			$	12,654			$	—			$
Other current assets			50,227				20,219				(4,371	)(a)
Total current assets			57,585				32,873				(4,371	)
Property and equipment, net			214,507				76,686					(b)
Other assets			8,036				639					(b)
Total assets		$	280,128			$	110,198			$				$
Liabilities and Unitholders’, Shareholders’ and Members’ Equity
Current liabilities		$	71,708			$	49,935				(4,371	)(a)
Long-term debt, net of current maturities			38,819				19,573				—
Other long-term liabilities			2,079				—				—
Unitholders’, shareholders’ and members’ equity			167,522				40,690					(c)
Total liabilities and unitholders’, shareholders’ and members’ equity		$	280,128			$	110,198			$				$

 

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Mammoth Energy Partners LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2013

(dollar amounts in thousands)

 

		Common Control Entities Historical				Stingray Entities Historical				Drilling Transaction				Pro Forma Adjustments				Pro Forma
Revenue:
Completion and production services		$	47,731			$	82,483			$	—			$	(9,266	)(d)		$
Contract land and directional drilling services			59,790				—				33,102
Remote accommodation services			25,027				—				—				—
Total		$	132,548			$	82,483				33,102			$	(9,266	)		$
Cost of revenue, excluding depreciation, amortization and impairment:
Completion and production services			42,627				68,556				—				(9,266	)(d)
Contract land and directional drilling services			53,987				—				35,831				(13,602	)(e)
Remote accommodation services			11,416				—				—				—
Selling, general and administrative expenses			13,614				1,561				497				(497	)(e)
Depreciation and amortization			18,995				7,938				—				6,889	(e)
Impairment of long-lived assets			938				—
Total		$	141,577			$	78,055			$	36,328			$	(16,476	)		$
Operating income (loss)			(9,029	)			4,428				(3,226	)			7,210
Interest expense			(2,012	)			(1,090	)			—				(1,135	)(e)
Other income (expense), net			(215	)			—				—				—
Income (loss) before income taxes			(11,256	)			3,338				(3,226	)			6,075
Provision for income taxes			2,715				—				—				—
Net income (loss)		$	(13,971	)		$	3,338			$	(3,226	)		$	6,075			$
Pro forma income (loss) before income taxes																		$
Pro forma provision for income taxes (d)
Pro forma net loss																		$
Pro forma Adjusted EBITDA																		$
Reconciliation of Adjusted EBITDA to net loss:
Net loss																		$
Depreciation and amortization expense
Impairment of long-lived assets
Equity based compensation
Interest expense
Other (income) expense, net
Provision for income taxes
Adjusted EBITDA																		$

 

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Mammoth Energy Partners LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Six Months Ended June 30, 2014

(dollar amounts in thousands)

 

		Common Control Entities Historical				Stingray Entities Historical				Drilling Transaction				Pro Forma Adjustments				Pro Forma
Revenue:
Completion and production services		$	44,481			$	64,847			$	—			$	(4,916	)(f)		$
Contract land and directional drilling services			51,823				—				2,696				—
Remote accommodation services			9,586				—				—				—
Total		$	105,890			$	64,847				2,696				(4,916	)		$
Cost of revenue, excluding depreciation, amortization and impairment:
Completion and production services			36,033				54,915				—				(4,916	)(f)
Contract land and directional drilling services			42,157				—				2,929				(244	)(g)
Remote accommodation services			4,165				—				—				—
Selling, general and administrative expenses			6,082				1,215				115				(115	)(g)
Depreciation and amortization			15,034				8,030				—				574	(g)
Impairment of long-lived assets			—				—				—				—
Total		$	103,471			$	64,160			$	3,044			$	(4,701	)		$
Operating income (loss)			2,419				687				(348	)			215
Interest expense			(1,864	)			(855	)			—				(94	)(g)
Other income (expense), net			(43	)			44				—				—
Income (loss) before income taxes			512				(124	)			(348	)			121
Provision for income taxes			1,059				—				—					(c)
Net income (loss)		$	(547	)		$	(124	)		$	(348	)		$	121			$
Pro forma income (loss) before income taxes																		$
Pro forma provision for income taxes (d)
Pro forma net loss																		$
Pro forma Adjusted EBITDA																		$
Reconciliation of Adjusted EBITDA to net loss:
Net loss																		$
Depreciation and amortization expense
Impairment of long-lived assets
Equity based compensation
Interest expense
Other (income) expense, net
Provision for income taxes
Adjusted EBITDA																		$

 

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Mammoth Energy Partners LP

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

(dollar amounts in thousands)

 

1.	Basis of Presentation

The historical financial information is derived from the combined historical financial statements of Redback Energy Services (the common control entities) and the combined historical financial statements of Stingray Pressure Pumping LLC and its affiliate (the Stingray entities) included elsewhere in this prospectus. The Drilling Transaction statement of operations information was derived from the Statements of Revenue and Direct Operating Expenses for Certain Drilling Rigs of Lantern Drilling Company included elsewhere in this prospectus. The unaudited pro forma condensed combined balance sheet as of June 30, 2014 has been prepared as if the Stingray Contribution occurred on June 30, 2014. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2013 assumes that the Stingray Contribution and the Drilling Transaction occurred on January 1, 2013.

 

2.	Pro Forma Assumptions and Adjustments

We made the following adjustments in the preparation of the unaudited pro forma condensed consolidated financial statements.

 

(a)	To eliminate $4,371 of intercompany receivable and payables primarily related to the purchase of sand used for hydraulic fracturing.

 

(b)

To record the Stingray Contribution at fair value for approximately $         for              common units value at the assumed initial public offering price of $         per share (the midpoint of the range set forth in the prospectus), which will represent     % of our outstanding common units immediately prior to the closing of this offering. The allocation of the purchase price to the assets acquired and liabilities assumed are preliminary and, therefore, subject to change.

 

(c)	To record the effect of income taxes to reflect the domestication of Sand Tiger Holdings Inc. as a Delaware Corporation.

 

(d)	To eliminate $9,266 of intercompany sales and purchases of sand used for hydraulic fracturing.

 

(e)

To record adjustments in connection with the Drilling Transaction: (i) to reduce cost of revenue by $13,602 for operating lease rental expense under sublease agreements that were not assumed by Bison; (ii) to reduce selling, general and administrative expenses by $497 for operational management fees charged by the former parent company of the acquired drilling rigs that will not be incurred by Bison; (iii) to record $6,889 of depreciation expense in connection with the drilling rigs acquired; and (iv) to record $1,125 of interest expense for the $25,000 of additional long-term debt issued to partially fund the drilling rig acquisition.

 

(f)	To eliminate $4,916 of intercompany receivable and payables primarily related to the purchase of sand for hydraulic fracturing.

 

(g)

To record adjustments in connection with the Drilling Transaction to: (i) reduce cost of revenue by $244 for operating lease rental expense under sublease agreements that were not assumed by Bison Drilling; (ii) reduce selling, general and administrative expenses by $115 for operational management fees charged by the former parent company of the acquired drilling rigs that will not be incurred by Bison Drilling; (iii) record $574 of depreciation expense in connection with the drilling rigs acquired; and (iv) record $94 of interest expense for the $25,000 of additional long-term debt issued to partially fund the Drilling Transaction.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Summary Combined Historical and Pro Forma Financial Data,” “Selected Historical Combined Financial Data,” “Pro Forma Financial Information” and the historical combined financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this prospectus.

Overview

We are a growth-oriented Delaware limited partnership providing completion and production, contract land and directional drilling and remote accommodation services primarily to companies engaged in the exploration and development of North American onshore unconventional sands and shale oil and natural gas reserves. As part of our completion and production services division, we also produce and sell custom natural sand proppant, which is primarily used in hydraulic fracturing operations.

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the transactions described below other than certain activities related to the preparation of the registration statement for this offering. Except as expressly noted otherwise, the historical financial information of Mammoth Energy Partners LP included in this prospectus is derived from the combined financial results for the following companies: Redback Energy Services; Redback Coil Tubing; Muskie Proppant; Panther Drilling; Bison Drilling; Bison Trucking; and Sand Tiger, all of which have been controlled and managed by our equity sponsor, Wexford and which we refer to in this prospectus as the common control entities. Prior to the closing of this offering, these entities together with White Wing, Sand Tiger Holdings Inc. and Dunvegan North Oilfield Services, ULC will be contributed to us by Mammoth Holdings, Gulfport and Rhino in return for common units and, as a result, will become our wholly owned subsidiaries. Sand Tiger Holdings Inc. and Dunvegan North Oilfield Services, ULC are holding companies for Sand Tiger. As such, all of the operations have been in Sand Tiger and the historical results of operations of both Sand Tiger Holdings Inc. and Dunvegan North Oilfield Services, ULC are minimal and immaterial, so they are excluded from the financial information presented in this prospectus. White Wing was formed in August 2014 and began operations in September 2014 and, as a result, is not included in the financial information in the prospectus. Also prior to the closing of this offering, two other entities, Stingray Pressure Pumping and Stingray Logistics, which we collectively refer to in this prospectus as the Stingray entities and in which Wexford and its affiliates currently own, in the aggregate, a non-controlling 50% equity interest, will be contributed to us by the holders of all of the equity interests in these entities in return for common units, at which time these entities will also become our wholly owned subsidiaries. The remaining 50% equity interests in the Stingray entities are currently owned, and will be contributed to us, by Gulfport. Because the Stingray entities are not under common control with the common control entities the historical financial information of the Stingray entities is not reflected in the historical combined financial statements of Mammoth Energy Partners LP, but instead is presented in this prospectus on a standalone basis and on a pro forma basis for Mammoth Energy Partners LP. As a result, the historical combined financial information of Mammoth Energy Partners LP as of and for the periods ended December 31, 2013 and 2012 and the six months ended June 30, 2014 and 2013 will not be indicative of the results that would have been achieved on a historical basis or that may be expected for any future periods. For more information, please see “Summary Combined Historical and Pro Forma Financial Data,” “Pro Forma Financial Information” and related notes thereto included elsewhere in this prospectus.

 

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Since the dates presented below, we have conducted our operations through the following entities, which comprise our three operating divisions: completion and production services, contract land and directional drilling services and remote accommodation services. These entities commenced operations on the dates indicated below.

 

•

Completion and Production Services Division

 

•

Muskie Proppant—September 2011

 

•

Redback Energy Services—October 2011

 

•

Redback Coil Tubing—May 2012

 

•

Contract Land and Directional Drilling Services Division

 

•

Bison Drilling—November 2010

 

•

Panther Drilling—December 2012

 

•

Bison Trucking—August 2013

 

•

White Wing—September 2014

 

•

Remote Accommodation Services Division

 

•

Sand Tiger—October 2007

Our completion and production division provides equipment rental, flowback and pressure control services and also produces custom natural sand proppant that is primarily used in hydraulic fracturing operations. Our contract land and directional drilling services division provides drilling rigs and crews for operators as well as rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. Our remote accommodations division provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging.

Our customers are predominantly independent oil and natural gas exploration and production companies, and oilfield service companies that use natural sand proppant for hydraulic fracturing. We have facilities and service centers that are strategically located to primarily serve resource plays in the Utica Shale in Eastern Ohio, the Permian Basin in West Texas, the Marcellus Shale in West Virginia and Pennsylvania, the Granite Wash in Okahoma and Texas, the Cana Woodford Shale and the Cleveland Sand in Oklahoma, and the oil sands in Alberta, Canada.

Our primary business objective is to provide an attractive total return to unitholders by optimizing business results through organic growth opportunities and accretive acquisitions. To achieve this objective, we plan to:

 

•

continue to capitalize on the increased activity in the high growth unconventional resource plays in the Permian Basin and Utica Shale, using our equipment which is designed to provide services for unconventional wells;

 

•

continue to grow our existing customer relationships by cross selling our services and expanding to other geographic regions in which our customers operate;

 

•

continue to monitor demand and expand our service offerings by investing in new equipment and facilities to add services and extend our presence in areas that we currently serve and other geographic locations; and

 

•

grow our business, relationships and service offerings by acquiring select companies and assets that are accretive and enhance our existing service offerings, broaden our service offerings or expand our customer relationships.

 

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Results of Operations

The following table sets forth selected operating data for the periods indicated. As described more fully above, three of the seven businesses within our operating divisions commenced operations in 2012 or 2013. Therefore, our results of operations for these periods do not include full year results for certain businesses. Consideration should be given to this timing and the related impact on the comparability of our results.

 

		Six Months Ended June 31,								Year Ended December 31,
		2014				2013				2013				2012
		(in thousands)
Revenue:
Completion and production services		$	44,481			$	18,455			$	47,731			$	16,892
Contract land and directional drilling services			51,823				31,936				59,790				26,842
Remote accommodation services			9,586				12,895				25,027				14,169
Total revenue			105,890				63,286				132,548				57,903
Gross Profit(1):
Completion and production services			8,448				1,468				5,104				3,128
Contract land and directional drilling services			9,666				6,727				5,803				6,341
Remote accommodation services			5,421				6,780				13,611				6,836
Total gross profit(1)			23,535				14,975				24,518				16,305
Selling, general and administrative expenses			6,082				5,162				13,614				6,443
Depreciation and amortization			15,034				8,486				18,995				8,149
Impairment of long-lived assets			—				—				938				2,435
Operating (loss) income			2,419				1,327				(9,029	)			(722	)
Interest expense			(1,864	)			(801	)			(2,012	)			(274	)
Other (expense) income, net			(43	)			153				(215	)			(49	)
(Loss) income before income taxes			512				679				(11,256	)			(1,045	)
Provision for income taxes			1,059				1,417				2,715				1,013
Net loss		$	(547	)		$	(738	)		$	(13,971	)		$	(2,058	)

 

(1)	Excludes depreciation and amortization.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Revenue. Revenue for the six months ended June 30, 2014 increased $42.6 million, or 67.3%, to $105.9 million from $63.3 million for the six months ended June 30, 2013. The increase in revenue by operating division was as follows:

Completion and Production Services. Completion and production services division revenue increased $26.1 million, or 141.0%, to $44.5 million for the six months ended June 30, 2014 from $18.4 million for the same period in 2013. The increase was primarily attributable to our sand production operation, which began selling product in February 2013 and accounted for $16.3 million, or 62.5%, of the total division revenue increase for the six month period ended June 30, 2014 compared to the six month period ended June 30, 2013. Our coil tubing services business accounted for $5.4 million, or 20.7%, of the total division revenue increase. Our coiled tubing services revenue growth was primarily attributable to our investment of $7.7 million in additional equipment to complete another coil spread that was placed in service in February 2014. Our pump down services business did not have any revenue during the first six months of 2013 and accounted for $2.9 million, or 11.1%, of the total division revenue increase. Our investment in new equipment to provide pump down services was $6.0 million. Revenue from our remaining completion and

 

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production services business increased $1.5 million, or 5.7%, of the total division revenue increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to a $2.3 million, or 39.0%, increase in revenue at our flow back services business as a result of our investment of $7.7 million in additional flow back equipment since January 1, 2013. This increase was partially offset by a decrease of $0.8 million, or 32.8%, in revenue at our field services business as result of more competition and less rig moves compared to the six month period ended June 30, 2013.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $19.9 million, or 62.3%, to $51.8 million for the six months ended June 30, 2014 from $31.9 million for the same period in 2013. The increase was primarily attributable to our land drilling services, which accounted for $19.6 million, or 99.0%, of the total division revenue increase. In 2013, we invested an additional $14.2 million to increase our rig fleet from seven rigs to eight rigs. The additional rig was placed in service in November 2013. In January 2014, we invested $47.0 million to acquire five additional horizontal drilling rigs. Revenue from our remaining land and directional drilling services business increased $0.3 million, or 1.0% of total division revenue increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to an increase of $2.8 million, or 14.1% of the total division revenue increase, for our rig moving business, which was not operating during the six months ended June 30, 2013. The increase attributable to the rig moving business was substantially offset by a decrease of $2.5 million, or 13.1%, for our directional drilling services business during the six months ended June 30, 2014 compared to the same period in 2013.

Remote Accommodation Services. Remote accommodation services division revenue decreased $3.3 million, or 25.7%, to $9.6 million for the six months ended June 30, 2014 from $12.9 for the same period in 2013. The decrease was a result of a decrease in room nights from 62,426 for the six months ended June 30, 2013 compared to 42,288 for the six months ended June 30, 2014. The decrease in room nights was due to a reduction in room nights for one of our primary customers related to scaling back a project combined with a slow ramp up on another customers’ project.

Gross Profit. Gross profit for the six months ended June 30, 2014 was $23.5 million, or 22.2% of total revenue, compared to $15.0 million, or 23.7% of total revenue for the six months ended June 30, 2013. Gross profit by operating division was as follows:

Completion and Production Services. Completion and production services gross profit was $8.4 million, or 19.0% of division revenue, for the six months ended June 30, 2014, compared to $1.5 million, or 8.0%, of division revenue for the same period in 2013. The increase was primarily attributable to our sand production operation, which began selling product in 2013 and accounted for $3.1 million, or 44.9%, of the total division gross profit increase for the six month period ended June 30, 2014 compared to the six month period ended June 30, 2013. During the six month period ended June 30, 2013, the market for sand was more competitive, resulting in downward pricing pressure compared to the same period in 2014. Gross profit from our coil tubing services division increased $2.7 million, or 39.1% of the total division gross profit increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase in the coil tubing gross profit was primarily attributable to achieving economies of scale in our operation as a result of the 126.8% revenue growth in the coil tubing services division compared to the six months ending June 30, 2013. Gross profit from our remaining completion and production services business increased $1.1 million, or 15.9% of total division gross profit increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to a 39.0% increase in revenue at our flow back services business as well as an increase at our pump down services business, which was not operating during the six months ended June 30, 2013. The increases at our flow back services and pump down services businesses were partially offset by a 32.8% decline in revenues at our field services business.

Contract Land and Directional Drilling Services. Contract land and directional drilling services gross profit was $9.7 million, or 18.7% of division revenue, for the six months ended June 30, 2014 compared to $6.7 million, or 21.1%, of division revenue for the same period in 2013. Gross profit from our

 

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land drilling services business accounted for $3.9 million, or 130.0% of the total division gross profit increase for the six months ending June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to our investment of $61.2 million to increase our rig fleet from seven to thirteen rigs. Gross profit from our rig moving business, which was not operating during the six months ended June 30, 2013 accounted for $1.4 million, or 46.7% of the total division gross profit increase during the six months ended June 30, 2014. The increases in our land drilling and rig moving businesses were partially offset by a $2.3 million decrease at our directional drilling services business for the six month period ended June 30, 2014 compared to the six month period ended June 30, 2013. This specific decrease was primarily due to a customer that changed drilling technology and discontinued use of some of our services.

Remote Accommodation Services. Remote accommodation services division gross profit was $5.4 million, or 56.6% of division revenue, for the six months ended June 30, 2014, compared to $6.8 million, or 52.6% of division revenue, for the same period in 2013. The gross profit was adversely impacted by lower utilization as compared to 2013 due to a reduction in room nights for one of our primary customers related to scaling back a project combined with a slow ramp up on another customers project.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $0.9 million, or 17.8%, to $6.1 million for the six months ended June 30, 2014, from $5.2 million for the six months ended June 30, 2013. The increase in expenses was primarily attributable to increased administrative personnel to support the growth of our operations. As a percentage of revenue, these expenses decreased to 5.7% in 2014, from 8.2% in 2013 due to the increase in our revenues.

Depreciation and Amortization. Depreciation and amortization increased $6.5 million, or 77.2%, to $15.0 million for the six months ended June 30, 2014 from $8.5 million for the six months ended June 30, 2013. The increase was primarily attributable to the acquisition of additional equipment for our contract land drilling operations and our directional drilling business operations.

Interest Expense. Interest expense increased $1.1 million, or 132.7%, to $1.9 million for the six months ended June 30, 2014 from $0.8 million for the six months ended June 30, 2013. The increase in interest expense was attributable to increased borrowings during 2014 and 2013 to support the continued expansion of our operations.

Income Taxes. Each of Redback Energy Services, Redback Coil Tubing, Bison Drilling, Bison Trucking, Panther Drilling and Muskie Proppant is a limited liability company and, as a pass-through entity, does not pay federal income tax and, generally, state income tax. The income tax expense recognized was attributable to Sand Tiger which, through its holding companies will be treated as a corporation for U.S. federal income tax purposes and is subject to Canadian income taxes. For the six months ended June 30, 2014, we recognized $1.1 million of income tax expense compared to $1.4 million for the six months ended June 30, 2013, a decrease of $0.3 million, or 25.3%. The decrease was primarily attributable to Sand Tiger’s decreased profitability.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenue. Revenue for the year ended December 31, 2013 increased $74.6 million, or 128.9%, to $132.5 million from $57.9 million for the year ended December 31, 2012. The increase in revenue by operating division was as follows:

Completion and Production Services. Completion and production services division revenue increased $30.8 million, or 182.6%, to $47.7 million for the year ended December 31, 2013 from $16.9 million for the year ended December 31, 2012. The increase was primarily attributable to our sand production operation which did not have any revenue during 2012, and accounted for $17.8 million, or 57.6%, of the total division revenue increase for 2013. Our coiled tubing services business operated for the full year in 2013, compared to four months in 2012, and accounted for $10.5 million, or 34.2%, of the total division revenue increase. Our coiled tubing services revenue growth was attributable to our investment of $3.3 million in

 

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additional equipment that completed another coil spread that was placed in service in February 2013. We also expanded our service offerings during 2013 with an investment of $5.4 million in new equipment to provide pump down services. The first of our four pump down spreads was placed in service in July 2013, and our other three spreads were placed in service in August 2013. Pump down services accounted for $1.7 million, or 5.5%, of the total division revenue increase during 2013. Substantially all of the remaining increase in revenue for this division was attributable to an increase in the workover rig business due to additional drilling activity in the Permian Basin during 2013.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $33.0 million, or 122.7%, to $59.8 million for the year ended December 31, 2013, from $26.8 million for the year ended December 31, 2012. The increase was primarily attributable to our directional drilling services business that commenced operations in late December of 2012, compared to a full year of operations in 2013, and accounted for $19.4 million, or 58.4%, of the total division revenue increase. The land drilling services accounted for $13.1 million, or 39.5%, of the total division revenue increase. In 2012, we invested $28.9 million to increase our rig fleet from four rigs to seven rigs. Of the three new rigs, two were placed in service in August 2012 and one was placed in service in October 2012. In 2013, we invested an additional $14.2 million to increase our rig fleet from seven rigs to eight rigs. The additional rig was placed in service in November 2013.

Remote Accommodation Services. Remote accommodation services division revenue increased $10.8 million, or 76.6%, to $25.0 million for 2013 from $14.2 million for 2012. The increase was a result of our $5.5 million investment in additional housing units to expand our business and increase our capacity to an average of 626 available room nights during 2013 from an average of 422 available room nights during 2012.

Gross Profit. Gross profit for 2013 was $24.5 million, or 18.5% of total revenue, compared to $16.3 million, or 28.2% of total revenue, for 2012. Gross profit by operating division was as follows:

Completion and Production Services. Completion and production services division gross profit was $5.1 million, or 10.7% of division revenue, for 2013, compared to $3.1 million, or 18.5% of revenue, for 2012. The decrease in gross profit as a percentage of revenue was primarily attributable to the direct costs of our sand production business exceeding revenue by $0.8 million during 2013. Our sand operations did not begin selling product until February 2013 at which point the market for sand had become increasingly competitive, resulting in downward pricing pressure. Gross profit for our remaining completion and production services business during 2013 was $5.9 million, or 19.6% of division revenue, compared to $3.1 million, or 18.5% of revenue for 2012. The increase in gross margin as a percentage of revenue was primarily attributable to achieving economies of scale in our coiled tubing business which operated for a full year in 2013 compared to four months in 2012.

Contract Land and Directional Drilling Services. Contract land and directional drilling services gross profit was $5.8 million, or 9.7% of division revenue, in 2013, compared to $6.3 million, or 23.6% of division revenue, in 2012. The decrease in gross profit as a percentage of revenue was primarily attributable to our spudder rigs operating at a loss in 2013 due to increased competition and lower pricing, the trend toward increased horizontal drilling resulting in downward pricing pressure and lower utilization of our vertical drilling rigs and a higher mix of revenue from footage contracts in 2013, which resulted in lower gross margins when compared to gross margins from our daywork contracts. Two of our rigs were also down for a longer than expected period of time for maintenance work during 2013. In December 2013, we discontinued offering spudder rig services and are actively marketing the spudder rigs and related equipment for sale.

Remote Accommodation Services. Remote accommodation services division gross profit was $13.6 million, or 54.4% of division revenue, in 2013, compared to $6.8 million, or 48.2% of division revenue, in 2012. The increase in gross profit as a percentage of revenue was primarily attributable to achieving economies of scale in our operation as a result of the 76.6% growth in revenue.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $7.2 million, or

 

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111.3%, to $13.6 million for 2013, from $6.4 million for 2012. The increase in expenses was primarily attributable to the commencement of our coiled tubing operations in May 2012, our sand production operations in May 2012 and our directional drilling operation in December 2012. As a percentage of revenue, these expenses decreased to 10.3% in 2013, from 11.1% in 2012 due to the increase in our revenues. While construction of our sand production operations and administrative support for these operations began in May 2012, the plant was not complete and our first sales did not occur until February 2013.

Depreciation and Amortization. Depreciation and amortization increased $10.9 million, or 133.1%, to $19.0 million for 2013 from $8.1 million for 2012. The increase was primarily attributable to the expansion of our contract land drilling operations and the timing of the commencement of our coiled tubing, sand production, and directional drilling business operations.

Impairment of Long-lived Assets. Impairment of long-lived assets in 2013 represented a $0.9 million loss to write down the spudder rigs and related equipment to fair value, including estimated costs to sell. Impairment of long-lived assets in 2012 represented a $2.4 million loss on certain properties that resulted from a moratorium on mining for sand.

Interest Expense. Interest expense increased $1.7 million, or 634.7%, during 2013, compared to 2012. The increase in interest expense was attributable to increased borrowings during 2013 to support the continued expansion in our operations. During 2012, substantially all of our operating expansion was funded by our equity holders.

Income Taxes. Each of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling and Bison Trucking is a limited liability company that is treated as a pass-through entity for federal income tax and most state income tax purposes. The income tax expense recognized was primarily attributable to Sand Tiger. For 2013, we recognized $2.7 million of income tax expense compared to $1.0 million for 2012, an increase of $1.7 million, or 168.0%. The increase was primarily attributable to Sand Tiger’s increased profitability.

Liquidity and Capital Resources

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity to date have been capital contributions from our equity holders, borrowings under our credit facilities and cash flows from operations. Following the completion of this offering, we anticipate that our primary sources of liquidity will be cash flows from operations and borrowings under our revolving credit facility. Our primary use of capital has been for investing in property and equipment used to provide our services. Following the completion of this offering, our primary uses of cash will be for paying distributions to our unitholders and for replacement and expansion capital expenditures, including acquisitions and investments in property and equipment. We regularly monitor potential capital sources, including equity and debt financings, in an effort to meet our planned capital expenditures and liquidity requirements. Our future success will be highly dependent on our ability to access outside sources of capital.

Our partnership agreement does not require us to distribute any of the cash we generate from operations. We believe, however, that it will be in the best interests of our unitholders if we distribute a substantial portion of the cash we generate from operations. The board of directors of our general partner will adopt a policy to distribute an amount equal to the cash available for distribution we generate each quarter to our unitholders. Our first distribution, however, will include cash available for distribution for the period from the closing of this offering through                     , 2014.

As of June 30, 2014, we had an aggregate of $70.4 million in borrowings outstanding under our credit facilities, leaving an aggregate of $10.1 million of available borrowing capacity under these credit facilities.

 

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Liquidity and cash flow

The following table sets forth our cash flows for the periods indicated:

 

		Six Months Ended June 30,								Year Ended December 31,
		2014				2013				2013				2012
Net cash (used in) provided by operating activities		$	(1,062	)		$	(7,362	)		$	4,162			$	4,791
Net cash used in investing activities			(74,553	)			(16,492	)			(63,322	)			(71,584	)
Net cash provided by financing activities			74,647				25,878				58,584				72,958
Effect of foreign exchange rate on cash			41				(153	)			(215	)			40
Net change in cash		$	(927	)		$	1,871			$	(791	)		$	6,205

Operating Activities

Net cash used in operating activities was $1.1 million for the six months ended June 30, 2014, compared to $7.4 million for the six months ended June 30, 2013. The decrease in operating cash flows was primarily attributable to timing differences in the collection of trade receivables and payments of related party payables.

Net cash provided by operating activities was $4.2 million for the year ended December 31, 2013, compared to $4.8 million for the year ended December 31, 2012. The decrease in operating cash flows was primarily attributable to timing differences in the collection of trade receivables and payments of trade payables, and an increase in our sand inventories.

Our operating cash flow is sensitive to many variables, the most significant of which are the timing of billing and customer collections and the purchase of sand inventories, and which may affect our cash available for distributions.

Investing Activities

Net cash used in investing activities was $74.6 million for the six months ended June 30, 2014, compared to $16.5 million for the six months ended June 30, 2013. Substantially all cash used in investing activities was used to purchase property and equipment that is utilized to provide our services.

Net cash used in investing activities was $63.3 million for the year ended December 31, 2013, compared to $71.6 million for 2012. Substantially all cash used in investing activities was used to purchase property and equipment that is utilized to provide our services. The following table summarizes our capital expenditures by operating division for the periods indicated:

 

		Six Months Ended June 30,								Year Ended December 31,
		2014				2013				2013				2012
Completion and production		$	8,202			$	8,464			$	21,920			$	37,182
Contract and directional drilling services			64,313				9,320				36,487				28,954
Remote accommodations			2,613				661				5,549				5,448
		$	75,128			$	18,445			$	63,956			$	71,584

Financing Activities

Net cash provided by financing activities was $74.6 million for the six months ended June 30, 2014, compared to $25.9 million for the six months ended June 30, 2013. We received $47.0 million and $17.3 million from our equity holders during the six months ended June 30, 2014 and 2013, respectively. The remaining financing cash flow was from net borrowings under our credit facilities and issuance of long-term debt.

 

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Net cash provided by financing activities was $58.6 million for the year ended December 31, 2013, compared to $73.0 million for 2012. We received $27.0 million and $59.1 million from our equity holders during the years ended December 31, 2013 and 2012, respectively. The remaining financing cash flow was primarily from net borrowings under our credit facilities.

Working Capital

Our working capital totaled $(10.6) million, $(13.2) million and $(3.6) million at June 30, 2014, December 31, 2013 and December 31, 2012, respectively. Our cash balances totaled $7.4 million, $8.3 million and $9.1 million at June 30, 2014, December 31, 2013 and December 31, 2012, respectively.

Existing Credit Facilities

Redback Energy Services LLC

On April 1, 2013, Redback Energy Services, as borrower, entered into a business loan agreement with Legacy Bank, as lender, providing for a $2.0 million revolving line of credit, subject to a borrowing base limitation, which we sometimes refer to as the April 2013 Redback facility. This facility amended Redback Energy Services’ prior revolving line of credit with Legacy Bank, entered into on April 25, 2012, increasing the amount available for borrowings from $1.5 million to $2.0 million and extending the maturity date from March 31, 2013 to April 1, 2014. On April 1, 2014, the April 2013 facility was once again amended, and the maturity date was extended to April 1, 2015. The borrowing base under the March 2013 facility is currently set as the lesser of $2.0 million and 75% of the aggregate amount of certain eligible accounts of Redback Energy Services specified in the business loan agreement. Interest is payable monthly at the greater of (i) the minimum prime lending rate for large U.S. Money Center Commercial banks as published in the Money Rate Section of The Wall Street Journal (or any substitute index as may be designated by the Legacy Bank), which we refer to as the Legacy Bank prime rate, plus 1.00% and (ii) 5.65% per annum. In the event of default, the interest rate will be increased by adding an additional 5.00% per annum to the applicable interest rate, subject to interest rate limitations under applicable law. As of June 30, 2014, $1.1 million was outstanding under the April 2013 Redback facility with an interest rate of 6.00% per annum.

The April 2013 Redback facility is secured by specified assets of Redback Energy Services and contains certain customary covenants, including covenants that (i) limit the incurrence of additional debt by the borrower in excess of $100,000 without the lender’s prior written approval, (ii) restrict the use of the loan proceeds solely to working capital purposes, (iii) require maintenance of a minimum combined debt service coverage ratio of 1.25 to 1 and a minimum $8.5 million tangible net worth and (iv) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013 and June 30, 2014, Redback Energy Services was in compliance with all of its covenants under this facility. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

On June 21, 2013, in connection with a formation of its pump-down business, Redback Energy Services, as borrower, entered into another business loan agreement with Legacy Bank, as lender, providing for a $1.5 million revolving line of credit, subject to a borrowing base limitation, which we sometimes refer to as the June 2013 Redback facility. The borrowing base under this facility is set as the lesser of $1.5 million and 75% of the aggregate amount of certain eligible accounts of Redback Energy Services specified in the business loan agreement. Interest is payable monthly at the greater of (i) the Legacy Bank prime rate plus 1.00% and (ii) 5.25% per annum. In the event of default, interest rate will be increased by adding an additional 5.00% per annum to the applicable interest rate, subject to interest rate limitations under applicable law. The June 2013 Redback facility matures on May 30, 2015. As of June 30, 2014, $0.3 million was outstanding under this facility, with an interest rate of 5.25% per annum.

The June 2013 Redback facility is secured by specified assets of Redback Energy Services and provides for the cross pledge and cross collateralization of the indebtedness secured under this facility with all other indebtedness of the borrower incurred with the lender. The June 2013 Redback facility contains certain customary covenants,

 

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including covenants that (i) limit the incurrence of additional debt by the borrower in excess of $100,000 without the lender’s prior written approval, (ii) restrict the use of the loan proceeds solely to working capital purposes of Redback Energy Services’ pump down business, (iii) prohibit the borrower’s ability to change its business activities, cease operations, liquidate, merge, acquire or consolidate with any other entity without the lender’s prior written consent, (iv) prohibit the borrower’s ability to transfer collateral not in the ordinary course of business without the lender’s prior written consent, (v) restrict distributions with respect to any capital account, (vi) require maintenance of a minimum combined debt service coverage ratio of 1.25 to 1 and a minimum $8.5 million equity position during the term of the loan plus 50% of net income and (vii) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013 and June 30, 2014, Redback Energy Services was in compliance with all of its covenants under this facility. We intend to repay in full and terminate the June 2013 Redback facility with a portion of the net proceeds from this offering.

On October 7, 2013, Redback Energy Services, as borrower, entered into an additional business loan agreement with Legacy Bank, as lender, providing for an approximately $8.5 million revolving line of credit, subject to a borrowing base limitation, which we sometimes refer to as the October 2013 Redback facility. The borrowing base under this facility is set as the lesser of $8.5 million or 60% of the aggregate amount of certain eligible equipment of Redback Energy Services and 35% of all pump-down equipment specified in the business loan agreement. Interest is payable monthly at the greater of (i) the Legacy Bank prime rate plus 1.00% and (ii) 5.25% per annum. In the event of default, interest rate will be increased by adding an additional 5.00% per annum to the above-referenced interest rate, subject to interest rate limitations under applicable law. The facility had an original maturity of October 9, 2014. In September 2014, the facility was extended and now has a maturity date of April 1, 2015. Redback Energy Services used borrowings under this facility to repay and terminate two prior term loans it had entered into with Legacy Bank (one originally entered into in April 2013 and the other entered into in June 2013 in connection with the formation of its pump down business) in the aggregate principal amount of $8.5 million. As of June 30, 2014, $5.3 million was outstanding under the October 2013 Redback facility, with an interest rate of 5.25% per annum.

The October 2013 Redback facility is secured by specified assets of Redback Energy Services and also provides for the cross pledge and cross collateralization of the indebtedness secured under this facility with all other indebtedness of the borrower incurred with the lender. The October 2013 Redback facility contains certain customary covenants, including covenants that (i) limit the incurrence of additional debt by the borrower in excess of $100,000 without the lender’s prior written approval, (ii) restrict the use of the loan proceeds solely to purchases of equipment, (iii) prohibit the borrower’s ability to change its business activities, cease operations, liquidate, merge, acquire or consolidate with any other entity without the lender’s prior written consent, (iv) prohibit the borrower’s ability to transfer collateral not in the ordinary course of business without the lender’s prior written consent, (v) restrict distributions with respect to any capital account, (vi) require maintenance of a minimum combined debt service coverage ratio of 1.25 to 1 and a loan to value ratio that does not exceed 60% of combined equipment collateral pool and (vii) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013, Redback Energy Services was in compliance with all of its covenants under this facility. As of June 30, 2014, Redback Energy Services was not in compliance with the minimum combined debt service coverage ratio. Redback Energy Services received a waiver on the minimum combined debt service coverage ratio for the first and second quarter of 2014 and expects to be in compliance with the minimum combined debt service coverage ratio in the third quarter of 2014. We intend to repay in full and terminate the October 2013 Redback facility with a portion of the net proceeds from this offering.

On July 22, 2014, Redback Energy Services, as borrower, entered into a promissory note with UMB Bank, n.a., as lender, for $2.0 million which we sometimes refer to as the July 2014 Redback Facility. The loan bears interest at an interest rate of 3.25% per annum and is amortizing in 60 monthly installments of $36,024, with a final maturity date of July 22, 2019. The loan is secured by a security interest in a double fluid pumper trailer and contains certain customary covenants, including covenants that require the borrower to maintain (i) a debt service coverage ratio of no less than 1.25 to 1, (ii) a tangible net worth of no less than $13,236,992, (iii) a debt to

 

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tangible net worth ratio of 0.8 to 1 or less and (iv) a current ratio of no less than 0.97 to 1. We intend to repay in full and terminate the July 2014 Redback facility with a portion of the net proceeds from this offering.

Redback Coil Tubing LLC

On October 14, 2013, Redback Coil Tubing, as borrower, entered into a loan and security agreement with Stillwater National Bank and Trust Company, or Stillwater, as lender, which we sometimes refer to as the October 2013 Coil Tubing facility, providing for (i) a term loan in the principal amount of up to $8.0 million and (ii) a $3.0 million revolving credit facility, subject to a borrowing base limitation. In September 2014, the term loan was amended to include another $2.5 million of principal. The borrowing base under the revolving credit facility is set at an amount equal to 80% of the aggregate amount of certain eligible accounts (specified in the loan and security agreement) as of the date of determination.

Outstanding indebtedness under the term loan and the revolving credit facility bears interest at the prime rate, as published in the “Bonds, Rates & Yields” section of The Wall Street Journal, plus an additional 0.50% if the ratio of funded debt to EBITDA (as defined in the loan and security agreement) is between 3 to 1 and 4 to 1, or 1% if the ratio of funded debt to EBITDA exceeds 4 to 1. Depending on these ratios, the minimum interest rate will range from 4.45% to 5.45%. In the event of default, interest on outstanding indebtedness under the term loan and the revolving credit facility will be payable at the rate of 15% per annum. The term loan matures on October 14, 2017, while the revolving credit facility matures on September 25, 2015. Redback Coil Tubing used $2.4 million in borrowings under the revolving credit facility to repay and terminate its prior term loan and revolving credit facility with Coppermark Bank entered into on October 5, 2012, as subsequently amended. Other borrowings under the revolving credit facility may be used only for general working capital purposes. Borrowings under the term loan may be used only for purchases of equipment. As of June 30, 2014, Redback Coil Tubing had outstanding borrowings of $6.3 million under the term loan and $1.6 million under the revolving credit facility, in each case with an interest rate of 4.45%.

The term loan and the revolving credit facility are secured by specified assets of Redback Coil Tubing. Additionally, the loan and the security agreement contain certain customary covenants, including covenants that (i) restrict the encumbrance of the borrower’s assets, (ii) limit the incurrence of additional debt, (iii) restrict the sale or transfer of the borrower’s assets, (iv) prohibit the borrower’s ability to merge or consolidate with any person or entity, sell all or substantially all assets, materially change its business, amend organizational documents, issue any indebtedness or other rights convertible into any equity interest (or enter into an agreement relating to any of the forgoing), (v) prohibit payment of dividends or making other distributions, (vi) prohibit making loans, except for certain ordinary course advances or extensions of credit, (vii) require maintenance of tangible net worth of at least $15.0 million and a ratio of funded debt to EBITDA that does not exceed 4 to 1 and (viii) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013 and June 30, 2014, Redback Coil Tubing was in compliance with all of its covenants under the October 2013 Coil Tubing facility. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

Muskie Proppant LLC

On January 31, 2013, Muskie Proppant, as borrower, entered into a loan agreement with Citizens State Bank of La Crosse, as lender, providing for a $3.0 million loan. As amended to date, the loan matures on February 1, 2015 and accrues interest at the highest U.S. Prime Rate as published in The Wall Street Journal “Money Table” plus 2.0%, payable monthly. The facility is secured by a real estate mortgage. As of June 30, 2014, $1.9 million was outstanding under this facility, with an interest rate of 5.25%.

In June and July of 2013, Muskie Proppant received an aggregate of approximately $3.5 million in loans from its members to fund the expansion of its processing plant and logistics facilities. Muskie Proppant’s obligations under these loans are secured by substantially all of Muskie Proppant’s assets. These loans mature on July 31, 2015, unless they are accelerated or extended in accordance with their terms. Interest on these loans

 

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accrue at a rate equal to the lesser of (i) the prime rate of interest announced from time to time by Citibank, N.A. plus 2.5% per annum and (ii) the maximum rate of interest permitted by applicable law, and is payable monthly. In the event of default, interest will accrue at the lesser of 16% per annum and the maximum amount allowed by law. The notes evidencing these loans contain certain customary covenants, including covenants that prevent Muskie Proppant, without the prior written consent of the respective noteholder, from (i) incurring or guaranteeing certain debts, (ii) allowing certain liens to encumber its property, (iii) making certain distributions to members, (iv) assigning or transferring certain assets, (v) transacting with affiliates and (vi) acquiring securities in other entities. As of June 30, 2014, Muskie Proppant had outstanding borrowings of $3.7 million under these loans, which bore interest at a weighted average rate of 5.75%, and was in compliance with all of its covenants under these loans. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

Bison Drilling and Field Services LLC

On May 31, 2013, Bison Drilling, as borrower, entered into a loan and security agreement with International Bank of Commerce, as lender, which, as amended, provided for a $5.0 million revolving loan, with a maturity date of June 1, 2015, and a $30.0 million term loan, with a maturity date of April 1, 2017. Effective May 30, 2014, the revolving loan was amended to increase the revolving loan by $2.0 million to $7.0 million. Effective January 31, 2014, the term loan was amended to increase the face amount to $51.9 million and extend the maturity date to April 30, 2017. Initially, the borrowings under the term loan were to be used for purchasing and making improvements to certain business related equipment and business activities, refinancing a current term loan with Amegy Bank and paying certain loan fees. The additional funds were to be used for funding, in part, Bison’s acquisition of five additional electric horizontal drilling rigs. The borrowings under the revolving loan may be used for short-term working capital requirements and refinancing a previous revolving loan with Amegy Bank.

The revolving loan and the term loan each bear interest at the New York Prime Rate, plus an additional percentage of 0.75%, adjusted on the date of change, with a floor of 4.25% per annum for the revolving loan and 4.5% for the term loan. The interest is calculated on the daily outstanding principal balance computed on the basis of a 360 day year for 12 months of 30 days each. As amended, the term loan required Bison Drilling to make only interest payments on a monthly basis through the last day of April 2014. Beginning on May 31, 2014, the term loan requires Bison Drilling to pay monthly payments of principal and interest based upon a 36 month amortization of the remaining principal balance. For the revolving loan, Bison Drilling pays interest-only monthly payments through the maturity date of May 31, 2015, at which time all accrued interest and unpaid principal will be due and payable in full. As of June 30, 2014, Bison Drilling had outstanding borrowings of $49.2 million under the term loan, with an interest rate of 4.5% and $4.8 million under the revolving loan, with an interest rate of 4.25%.

Both loans are secured by Bison Drilling’s personal property, now owned or hereafter acquired, and the loans contain customary covenants, including covenants that (i) require quarterly financial statements and annual audited financial statements, (ii) require annual projection reports, (iii) require a monthly borrowing base certificate, (iv) restrict distributions to its members, (v) restrict the incurrence of additional debt, (vi) require a leverage ratio not greater than 3 to 1 and a fixed charge ratio not less than 1.35 to 1, (vii) restrict the issuance of loans and guarantees, (viii) restrict transactions with affiliates and (ix) require a minimum tangible net worth of (a) at least $30.0 million as of December 31, 2013 and (b) at least $50.0 million as of January 31, 2014. As of December 31, 2013, Bison Drilling’s actual tangible net worth was $28.9 million and Bison Drilling received a waiver from the lender for such non-compliance. At June 30, 2014, Bison Drilling was in violation of the minimum fixed coverage ratio with a ratio of 1.20 to 1 and received a waiver from the lender. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

Stingray Pressure Pumping LLC

On July 3, 2013, Stingray Pressure Pumping entered into a loan and security agreement with International Bank of Commerce which, as amended, provides for a term credit loan in the amount of $50.0 million for the

 

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purpose of purchasing additional equipment. Outstanding borrowings bear interest at the prime rate as quoted by JP Morgan Bank & Co., New York, New York, plus 0.75%, with a floor of 4.50% per annum. Interest is calculated on the daily outstanding principal balance computed on the basis of a 365 day year for 12 months of 30 days each.

The loan is secured by, among other things, all of Stingray Pressure Pumping’s accounts, goods, equipment, fixtures, inventory, now owned or hereafter acquired, and the loan contains certain customary covenants, including covenants that (i) require quarterly financial statements and annual audited financial statements, (ii) require annual projection reports, (iii) require an annual receivable report in conjunction with the quarterly statements, (iv) restrict distributions to members, (v) restrict the incurrence of additional debt, (vi) require a debt to tangible net worth ratio that does not exceed 1.75 to 1; (vii) restrict the issuance of loans and guarantees, (viii) restrict transactions with affiliates and (ix) require, initially, a minimum tangible net worth of $30.0 million, which increases each year by one-third of the prior year’s net income (but may not be reduced as a result of the prior year’s net income loss, if any).

As of June 30, 2014, Stingray Pressure Pumping had an outstanding balance of $35.4 million, with an interest of 4.50%, and was in compliance with the covenants of the loan, including the debt to tangible net worth ratio. We intend to repay in full and terminate this loan with a portion of the net proceeds from this offering.

In September 2014, Stingray Pressure Pumping amended the term loan agreement to receive funds for the purchase of additional equipment and bring the balance up to the original agreement capacity of $50.0 million.

Stingray Logistics LLC

On November 26, 2012, Stingray Logistics, as borrower, entered into a master loan and security agreement with Mack Financial Services, a division of VFS US LLC, as lender, for the purpose of acquiring construction, motor vehicles, trailers and other personal property or related equipment. Pursuant to the agreement, Stingray Logistics LLC granted a purchase money security interest in any of the equipment acquired with the proceeds of the loan. Each acquisition is made pursuant to a separate schedule, which is deemed a separate loan agreement with respect to the acquired equipment, and incorporates the terms of the master loan agreement.

The master loan and security agreement contains customary covenants, including covenants that (i) require the purchased equipment to be free from all claims and liens, (ii) require the equipment to remain in good operating condition and in conformity with all governmental regulations, (iii) restrict the transfer of the equipment, (iv) require borrower to maintain certain types of insurance coverage and (v) require borrower to provide lender with financial information upon request by lender.

On November 26, 2012, Stingray Logistics entered into a schedule under this master loan and security agreement pursuant to which Stingray Logistics borrowed approximately $0.9 million at an interest rate of 5.99% to purchase thirteen vehicles. The term for the loan is 48 months, with monthly interest and principal payments of approximately $21,635.

On September 25, 2013, Stingray Logistics entered into a credit sales contract for the purchase of six vehicles. Pursuant to this agreement, Stingray Logistics granted a purchase money security interest in the purchased equipment and is required to make 48 monthly payments which started on October 25, 2013, for a total of $0.5 million. The credit sales contract contains customary covenants, including covenants that (i) require the equipment to remain free from all liens and security interests, (ii) require the equipment to remain in good operating condition and in conformity with all governmental regulations, (iii) require quarterly and annual financial statements and (iv) require borrower to maintain certain types of insurance coverage. The aggregate balance as of June 30, 2014 of these arrangements was $1.3 million.

 

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Panther Drilling Systems LLC

In September 2014, Panther Drilling, as borrower, entered into a loan and security agreements with Bank7, as lender, providing for a term loan in the principal amount of $4.0 million. The loan requires three months of interest only payments beginning October 2014. Principal and interest payments will then begin January 2015 for 35 months until the maturity date of December 8, 2017. The loan has an interest rate of 5.75%. The loan is secured by specified assets and contains customary covenants. Among these are (i) restrictions on the encumbrance of the borrower’s assets, (ii) requirements to provide certain financial statements to the lender on a regular basis, (iii) the requirement of a minimum quarterly EBITDA of $730,000 starting with the first quarter of 2015 and (iv) a minimum net worth requirement of $7.5 million.

New Revolving Credit Facility

In connection with this offering, we and our subsidiaries intend to enter into a $150.0 million senior secured revolving credit facility, which we refer to as the new credit facility, with PNC Capital Markets LLC, as lead arranger, PNC Bank, National Association, as the administrative and collateral agent, and the lenders from time-to-time party thereto, to, among other things, provide for ongoing working capital needs, including capital expenditures and fund general capital needs. Borrowings under the new credit facility will be secured by a first priority perfected security interest in all of our assets, and our direct and indirect domestic subsidiaries will guarantee our obligations under the facility.

The new credit facility will be available on a revolving basis during a five-year period commencing on the new credit facility’s closing date. Outstanding borrowings will bear interest, at our option, at a rate based on LIBOR plus 250, 275 or 300 basis points (depending on the percentage of maximum available credit then-available) or the base rate plus 150, 175 or 200 (depending on the percentage of maximum available credit then-available).

The new credit facility will contain customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make certain investments, divest assets, effect fundamental changes (including mergers, consolidations and certain joint ventures), change the nature of our business, make restricted payments (including dividends), enter into swap contracts and forward sales contracts and enter into affiliate transactions. The negative covenants will be subject to certain exceptions, conditions and limitations as specified in the new credit facility.

The new credit facility also will contain certain affirmative covenants, including, but not limited to, affirmative covenants regarding periodic reports, payment of fees, conduct of business, maintenance of existence, payment of indebtedness, standards of financial statements, tax shelter regulations and federal securities laws. In addition, under the new credit facility, we will be subject to certain financial covenants, including, but not limited to, (i) a minimum interest coverage ratio, requiring us to maintain an interest coverage ratio of not less than 3.00:1.00 and (ii) a maximum leverage covenant prohibiting us (other than in certain limited circumstances) from having a ratio of funded debt to EBITDA of greater than 4.00:1.00 (increasing to 4.25:1.00 during a specified permitted acquisition period). The affirmative covenants and financial covenants will be subject to certain exceptions, conditions and limitations as specified in the new credit facility. The new credit facility also will contain customary indemnification obligations.

The lenders will be able to accelerate all of the indebtedness under the new credit facility upon the occurrence (and during the continuance of) any event of default. The new credit facility will contain customary events of default, including bankruptcy, non-payment, breach of covenants, change of control, materially incorrect representations and cross-default to other indebtedness. Generally, with the consent of lenders holding a majority of the outstanding loans or commitments to lend, we will be able to amend the terms and provisions of the new credit facility.

Capital Requirements and Sources of Liquidity

During the year ended December 31, 2013, our capital expenditures for the common control entities, excluding acquisitions, were approximately $21.9 million, $36.5 million and $5.6 million in our completion and production

 

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services division, contract land and directional drilling services division and remote accommodation services division, respectively, for aggregate capital expenditures of approximately $64.0 million. During the six months ended June 30, 2014, our capital expenditures for the common control entities, excluding acquisitions, were approximately $8.2 million, $16.6 million and $2.6 million in our completion and production services division, contract land and directional drilling services division and remote accommodation services division, respectively, for aggregate capital expenditures of approximately $27.4 million. During 2014, we currently estimate that our aggregate capital expenditures will be approximately $139.0 million, of which approximately $77.1 million has been allocated to our contract land and directional drilling division primarily for the recent Drilling Transaction and maintenance capital expenditures, approximately $9.8 million has been allocated to our remote accommodations service division primarily for expansion of facilities and approximately $13.6 million has been allocated to our completion and production services division primarily for additional pumping and coil tubing units.

We believe that our operating cash flow and available borrowings under our revolving credit facilities will be sufficient to fund our operations and make expected distributions for at least the next twelve months. However, future cash flows are subject to a number of variables, and significant additional capital expenditures will be required to conduct our operations. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures and make expected distributions. Further, we do not have a specific acquisition budget for 2014 since the timing and size of acquisitions cannot be accurately forecasted. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures or distributions and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our new revolving credit facility, joint venture partnerships, asset sales, offerings of debt and equity securities or other means. We cannot assure you that this additional capital will be available on acceptable terms or at all. If we are unable to obtain funds we need, we may not be able to complete acquisitions that may be favorable to us, finance the capital expenditures necessary to conduct our operations or make expected distributions.

Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2013 (in thousands):

 

		Total				Less than 1 Year				1-3 Years				3-5 Years				More than 5 Years
Contractual obligations:
Long-term debt, including current portion(1)		$	31,616			$	8,712			$	19,927			$	2,977			$	—
Operating lease obligations(2)			11,225				2,539				4,152				2,022				2,512
Purchase commitment to sand supplier(3)			3,329				1,000				2,329				—				—
		$	46,170			$	12,251			$	26,408			$	4,999			$	2,512

(1)	The long-term debt excludes interest payments on each obligation.

(2)	Operating lease obligations relate to real estate, rail cars and other equipment.

(3)	The purchase commitment to a sand supplier represents our monthly obligation to purchase a minimum amount of sand. If the minimum purchase requirement is not met, the shortfall is settled each month in cash.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our combined financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2 of our combined financial statements appearing elsewhere in this prospectus for a discussion of additional accounting policies and estimates made by management.

 

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Use of Estimates. In preparing the financial statements, our management makes informed judgments and estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the allowance for doubtful accounts, depreciation and amortization of property and equipment, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets.

Revenue Recognition. We generate revenue from multiple sources within our three operating divisions. In all cases, revenue is recognized when services are performed, collection of the receivables is probable, persuasive evidence of an arrangement exists and the price is fixed and determinable. Services are sold without warranty or the right to return. The specific revenue sources are outlined as follows:

Completion and Production Services Revenue. Completion and production services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted or hourly basis, and revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and the personnel involved in such services or mobilization. Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. The labor charges and the use of consumable supplies are reflected on completed field tickets.

Contract Land and Directional Drilling Services Revenue. Contract drilling services are provided under daywork or footage contracts, and revenue is recognized as the work progresses based on the days completed or the feet drilled, as applicable. Mobilization revenue and costs for daywork and footage contracts are recognized over the days of actual drilling. Directional drilling services are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Proceeds from customers for the cost of oilfield downhole rental equipment that is involuntarily damaged or lost in-hole are reflected as revenues.

Remote Accommodation Services. Revenue from remote accommodation services is recognized when rooms are occupied and services have been rendered. Advanced deposits on rooms and special events are deferred until services are provided to the customer.

Revenues arising from claims for amounts billed in excess of the contract price or for amounts not included in the original contract are recognized when billed less any allowance for uncollectibility. Revenue from such claims is only recognized if it is probable that the claim will result in additional revenue, the costs for the additional services have been incurred, management believes there is a legal basis for the claim and the amount can be reliably estimated. Revenues from such claims are recorded only to the extent that contract costs relating to the claims have been incurred. Historically, we have not billed any customer for amounts not included in the original contract.

The timing of revenue recognition may differ from contract billing or payment schedules, resulting in revenues that have been earned but not billed (“unbilled revenue”) or amounts that have been billed, but not earned (“deferred revenue”).

Allowance for Doubtful Accounts. We regularly review receivables and provide for estimated losses through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding our customers’ ability to make required payments, economic events and other factors. As the financial condition of customers change, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event we were to determine that a customer may not be able to make required payments, we would increase the allowance through a charge to income in the period in which that determination is made. Uncollectable accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made of their uncollectibility.

 

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Depreciation and Amortization. In order to depreciate and amortize our property and equipment, we estimate useful lives, attrition factors and salvage values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances in industry or changes in regulations governing the industry.

Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of such assets is evaluated by measuring the carrying amount of the assets against the estimated undiscounted future cash flows associated with the assets. If such evaluations indicate that the future undiscounted cash flow from the assets is not sufficient to recover the carrying value of such assets, the assets are adjusted to their estimated fair values.

Income Taxes. The Partnership and each of our subsidiaries, except Sand Tiger, is treated as a pass-through entity for federal income tax and most state income tax purposes. Accordingly, income taxes on net earnings are payable by the stockholders, members or partners and are not reflected in the historical financial statements. Sand Tiger is subject to corporate income taxes and they are provided in the financial statements based upon Financial Accounting Standards Board, or FASB, Accounting Standard Codification, or ASC, 740 Income Taxes. As such, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities as a result of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

Emerging Growth Company

The Jumpstart Our Business Startups Act of 2012 permits an “emerging growth company” like us to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We are choosing to “opt out” of this provision and, as a result, we will comply with new or revised accounting standards as required when they are adopted. This decision to opt out of the extended transition period is irrevocable.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the Jumpstart Our Business Startups Act of 2012 or as long as we are a non-accelerated filer. See “Summary—Emerging Growth Company.” Please also see “Risk Factors—Risks Inherent in an Investment in Us—For so long as we are an ‘emerging growth company’ we will not be required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investors.”

 

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Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended 2013 and 2012 or the six month period ended June 30, 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Quantitative and Qualitative Disclosure about Market Risks

The demand, pricing and terms for oil and gas services provided by us are largely dependent upon the level of activity for the U.S. oil and natural gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available pipeline and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and natural gas producers.

The level of activity in the U.S. oil and natural gas exploration and production industry is volatile. Expected trends in oil and natural gas production activities may not continue and demand for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. Recently, demand for our services has been strong and we are continuing our past practice of committing our equipment on a short-term or day-to-day basis.

Interest Rate Risk

We had a cash and cash equivalents balance of $7.4 million at June 30, 2014. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure to changes in the fair value of these investments as a result of changes in interest rates. Declines in interest rates, however, will reduce future income.

We had $70.4 million outstanding under various credit facilities at June 30, 2014, which bore interest at variable rates generally based on prime plus various factors. Based on the current debt structure, a 1% increase or decrease in the interest rates would increase or decrease interest expense by approximately $0.7 million per year. We do not currently hedge our interest rate exposure.

Foreign Currency Risk

Our remote accommodation businesses generate revenue and incur expenses that are denominated in the Canadian dollar. These transactions could be materially affected by currency fluctuations. Changes in currency exchange rates could adversely affect our consolidated results of operations or financial position. We also maintain cash balances denominated in the Canadian dollar. At June 30, 2014, we had $3.5 million of cash in Canadian accounts. A 10% increase in the strength of the Canadian dollar versus the U.S. dollar would have resulted in an increase in pre-tax income of approximately $0.3 million as of June 30, 2014. Conversely, a corresponding decrease in the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

 

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Seasonality

We provide completion and production services primarily in the Utica, Permian Basin, Eagle Ford, Marcellus, Granite Wash, Cana Woodford and Cleveland sand resource plays located in the continental U.S. We also provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers that are strategically located to serve resource plays in Ohio, Oklahoma, Wisconsin, Minnesota and Alberta, Canada. For the year ended December 31, 2013 and the six months ended June 30, 2014, we generated approximately 52.4% and 57.1%, respectively, of our pro forma revenue from our operations in Ohio, Wisconsin, Minnesota and Canada where weather conditions may be severe. As a result, our operations may be limited or disrupted, particularly during winter and spring months, in these geographic regions, which would have a material adverse effect on our financial condition and results of operations. Our operations in Oklahoma and Texas are generally not affected by seasonal weather conditions.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

 

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BUSINESS

General

Overview

We are a growth-oriented Delaware limited partnership providing completion and production services, contract and directional drilling services and remote accommodation services primarily to companies engaged in the exploration and development of North American onshore unconventional sands and shale oil and natural gas reserves, commonly referred to as “unconventional resources.” Our primary business objective is to provide an attractive total return to unitholders by optimizing business results and maximizing distributions through organic growth opportunities and accretive acquisitions.

“Unconventional resources” references the different manner by which they are exploited as compared to the extraction of conventional resources. In unconventional drilling, the wellbore is generally drilled to specific objectives within narrow parameters, often across long, lateral intervals within narrow horizontal formations offering greater contact area with the producing formation. Typically, the well is then hydraulically fractured at multiple stages to optimize production. Our completion and production services division provides pressure pumping services, pressure control services, flowback services and equipment rental, and also produces and sells proppant for hydraulic fracturing. Our contract land and directional drilling services division provides drilling rigs and crews for operators as well as rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. Our remote accommodation division provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We believe that these services play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources. Our complementary suite of drilling and completion and production related services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

Our facilities and service centers are strategically located in Ohio, Oklahoma, Wisconsin, Minnesota, Pennsylvania, Texas and Alberta, Canada primarily to serve the following resource plays:

 

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The Utica Shale in Eastern Ohio;

 

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The Permian Basin in West Texas;

 

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The Appalachian Basin in the Northeast;

 

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The Arkoma Basin in Arkansas and Oklahoma;

 

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The Anadarko Basin in Oklahoma;

 

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The Marcellus Shale in West Virginia and Pennsylvania;

 

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The Granite Wash and Mississippi Shale in Oklahoma and Texas;

 

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The Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma;

 

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The Gulf Coast of Louisiana; and

 

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The oil sands in Alberta, Canada.

Our operational division heads have an average of over 26 years of oilfield service experience and bring valuable basin-level expertise and long-term customer relationships to our business. We provide our completion and production and contract and directional drilling services to a diversified range of both public and private independent producers. Our top five customers for the year ended December 31, 2013, representing 58.8% of our revenue, on a pro forma basis, were Gulfport, Diamondback Energy, Inc., Grizzly Oil Sands ULC, Apache Corporation and JAMEX, Inc. Our top five customers for the six months ended June 30, 2014, representing 54.3% of our revenue on a pro forma basis, were Gulfport, Breitburn Operating LP, J. Cleo Thompson, RSP Permian LLC and Apache Corporation.

 

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We commenced our operations in October 2007 with the acquisition of the assets of Sand Tiger. We have since grown organically and through acquisitions by focusing on the increasing needs of producers in unconventional resource plays. Further information regarding our growth is provided below under “—Our Services.” After giving pro forma effect to the Stingray Contribution and Drilling Transaction, we had $238.9 million of revenue, a $7.8 million net loss and $34.7 million of Adjusted EBITDA for the year ended December 31, 2013 and $168.5 million of revenue, a $1.0 million net loss and $25.8 million of Adjusted EBITDA for the six months ended June 30, 2014. For a definition of Adjusted EBITDA, a reconciliation of Adjusted EBITDA to net income (loss), the most closely comparable financial measure calculated in accordance with GAAP, and a discussion of Adjusted EBITDA as a performance measure, please see “Selected Historical Combined Financial Data” and “Pro Forma Financial Information.”

Our Services

We manage our business through three operating divisions: completion and production services, contract and directional drilling services and remote accommodation services.

Completion and Production Services

Our completion and production business provides pressure pumping, pressure control services, flowback services and equipment rental, as well as production and sales of proppant for hydraulic fracturing.

Pressure Pumping. Our pressure pumping services consist of hydraulic fracturing and well cementing services. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. Currently, we provide pressure pumping services in the Appalachian Basin in the Northeast. Our pressure pumping services include the following:

 

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Hydraulic Fracturing. We provide high-pressure hydraulic fracturing services. Fracturing services are performed to enhance the production of oil and natural gas from formations having low permeability such that the flow of hydrocarbons is restricted. We have significant expertise in multi-stage fracturing of horizontal oil- and natural gas-producing wells in shale and other unconventional geological formations.

The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, in our case primarily sand or ceramic beads, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return for the operator.

We own and operate fleets of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of a high pressure hydraulic pump, a diesel engine, a transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted to a flat-bed trailer. As of September 1, 2014, we owned a total of 52 high-pressure fracturing units capable of delivering a total of 117,000 horsepower. We have contracted to purchase eight additional high-pressure fracturing units, which are expected to be delivered by October 31, 2014 and will increase the total number of high-pressure fracturing units we own to 60. We refer to the group of fracturing units, other equipment and vehicles necessary to perform a typical fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” In areas in which we operate on a 24-hour-per-day basis, we typically staff three crews per fleet. All of our fracturing units and high pressure pumps are manufactured to our specifications to enhance the performance and durability of our equipment and meet our customers’ needs.

Each hydraulic fracturing fleet includes a mobile, on-site control center that monitors pressures, rates and volumes, as applicable. From there, our field-level managers supervise the job-site by radio. Each control center is equipped with high bandwidth satellite hardware that provides continuous upload and download of job telemetry data. The data is delivered on a real-time basis to on-site job personnel, the operator and an assigned coordinator at our headquarters for display in both digital and graphical form.

 

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An important element of fracturing services is determining the proper fracturing fluid, proppants and injection program to maximize results. In virtually all of our hydraulic fracturing jobs, our customers specify the composition of the fracturing fluid to be used. The fracturing fluid may contain hazardous substances, such as hydrochloric acid and certain petrochemicals. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water. The customers remove the water from the well using a controlled flow-back process, and we are not involved in that process or in the disposal of the fluid.

Pressure Control. Our pressure control services consist of coiled tubing, nitrogen and fluid pumping services. Our pressure control services equipment is designed to support drilling activities in unconventional resource plays with the ability to operate under high pressures without having to delay or cease production during completion operations. Ceasing or suppressing production during the completion phase of an unconventional well could result in formation damage impacting the overall recovery of reserves. Our pressure control services help operators minimize the risk of such damage during completion activities. Currently, we provide pressure control services in Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma, the Granite Wash and Mississippi Shale in Oklahoma and Texas, the Utica Shale in Ohio and the Permian Basin in West Texas. Our pressure control services include the following:

 

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Coiled Tubing Services. Coiled tubing services involve injecting coiled tubing into wells to perform various well-servicing and workover operations. Coiled tubing is a flexible steel pipe with a diameter of typically less than three inches and manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck-mounted reel for onshore applications. Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services to enhance the flow of oil or natural gas without using a larger, more costly workover rig. The principal advantages of using coiled tubing in a workover include the ability to (i) continue production from the well without interruption, thus reducing the risk of formation damage, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe in the case of a workover rig, which must be jointed and unjointed, (iii) direct fluids into a wellbore with more precision, allowing for improved stimulation fluid placement, (iv) provide a source of energy to power a downhole mud motor or manipulate down-hole tools and (v) enhance access to remote fields due to the smaller size and mobility of a coiled tubing unit. As of September 1, 2014, we had five coiled tubing units capable of running over 21,000 feet of two inch coil rated at 10,000 pounds per square inch, or psi, in service, which we believe are well suited for the performance requirements of the unconventional resource markets we serve. The average age of these units was less than three years at September 1, 2014 with the deep service unit being a 2009 model.

 

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Nitrogen Services. Nitrogen services involve the use of nitrogen, an inert gas, in various pressure pumping operations. When provided as a stand-alone service, nitrogen is used in displacing fluids in various oilfield applications. As of September 1, 2014, we had a total of four nitrogen pumping units capable of pumping at a rate of up to 3,000 standard cubic feet per minute with pressures up to 15,000 psi. Pumping at these rates and pressures is typically required for the unconventional oil and natural gas resource plays we serve. The average age of these units was less than three years at September 1, 2014.

 

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Fluid Pumping Services. Fluid pumping services consist of maintaining well pressure, pumping down wireline tools, assisting coiled tubing units and the removal of fluids and solids from the wellbore for clean-out operations. As of September 1, 2014, we had nine fluid pumping units with an average age of less than two years. Of these, four were coiled tubing double pump units capable of output of up to 13 barrels per minute, and are rated to a maximum of 15,000 psi service and four were quintuplex wireline pump down units capable of output of up to 20 barrels per minute, and are rated to a maximum of 15,000 psi service.

Flowback. Our flowback services consist of production testing, solids control, hydrostatic testing and torque services. Flowback involves the process of allowing fluids to flow from the well following a treatment, either in

 

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preparation for an impending phase of treatment or to return the well to production. Our flowback equipment consists of manifolds, accumulators, valves, flare stacks and other associated equipment that combine to form up to a total of seven well-testing spreads. We provide flowback services in the Appalachian Basin, the Permian Basin and mid-continent markets.

 

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Production Testing. Production testing focuses on testing production potential. Key measurements are recorded to determine activity both above and below ground. Production testing and the knowledge it provides help our customers determine where they can more efficiently deploy capital. As of September 1, 2014, we had five production testing packages.

 

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Solids Control. Solids control services provide prepared drilling fluids for drilling rigs with equipment such as sand separators and plug catchers. These services reduce costs throughout the entire drilling process. As of September 1, 2014, we had 12 solids control packages.

 

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Hydrostatic Testing. Hydrostatic testing is a procedure in which pressure vessels, such as pipelines, are tested for damage or leaks. This method of testing helps maintain safety standards and increases the durability of the pipeline. We employ hydrostatic testing at industry standards and to a customer’s desired specifications and configuration. As of September 1, 2014, we had two hydrostatic testing packages.

 

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Torque Services. Torque refers to the force applied to a rotary device to make it rotate. We offer a comprehensive range of torque services, offering a customer the dual benefit of reducing costs on the rig as well as reducing hazards for both personnel and equipment. We had five torque service packages as of September 1, 2014.

Equipment Rentals. Our equipment rental services provide a wide range of rental equipment used in flowback and hydraulic fracturing services. Our equipment rentals consist of light plants and other oilfield related equipment. We provide equipment rental services in the Appalachian Basin, Permian Basin and mid-continent markets.

Proppant Production and Sales. In our proppant production and sales business, we process raw sand into premium monocrystalline natural sand proppant, also known as frac sand, which is the most widely used type of proppant due to its broad applicability in unconventional oil and natural gas wells and its cost advantage relative to other proppants. Natural frac sand may be used as proppant in all but the highest pressure and temperature drilling environments and is being employed in nearly all major U.S. unconventional oil and natural gas producing basins, including those in which we operate. Industry estimates that the total domestic proppant market is projected to grow 11% annually through 2017. We buy raw sand from third party suppliers under fixed-price contracts, process it into premium monocrystalline sand at our indoor sand processing plant located in Pierce County, Wisconsin. We collaborate with our customers to develop products to help them optimize production from unconventional wells. We start by producing a majority of the standard proppant sizes as defined by the ISO/API 13503-2 specifications. These grain sizes can be customized to meet the demands of a specific well. Our supply of superior Jordan substrate exhibits the physical properties necessary to withstand the environments of completion and production of the wells in North American shale basins. Our indoor processing plant (which we own and operate) is designed for year-round continuous wet and dry plant operation capable of producing a wide variety of frac sand products based on the needs of our customers.

We also provide logistics solutions to facilitate delivery of our frac sand products to our customers. Our logistics capabilities in this regard are important to our customers, who focus on both the reliability and flexibility of product delivery. Because our customers generally find it impractical to store frac sand in large quantities near their job sites, they typically prefer product to be delivered where and as needed, which requires predictable and efficient loading and shipping capabilities. We contract with third party providers to transport our frac sand products to railroad facilities for delivery to our customers. We currently lease or have access to origin transloading facilities on the Canadian National Railway Company (CN), Union Pacific (UP), Burlington Northern Santa Fe (BNSF) and the Canadian Pacific (CP) rail systems and use an in-house railcar fleet that we lease from various third parties to deliver our frac sand products to our customers. Origin transloading facilities

 

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on multiple railways allow us to provide predictable and efficient loading and shipping of our frac sand products. We also utilize a destination transloading facility in Cadiz, Ohio, which is operated by one of our affiliates, to serve the Utica Shale, and utilize destination transloading facilities located in some of North America’s other prolific resource plays, including the Permian Basin and Bakken Shale, to meet our customers’ delivery needs.

Master Services Agreements. We contract with most of our completion and production customers under master service agreements, or MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. However, our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts which cause such events. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation of risk, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

Contract and Directional Drilling Services

Our contract and directional drilling business provides contract drilling and directional drilling services.

Contract Drilling. As part of our contract drilling services, we provide both vertical and horizontal drilling services to our customers. Currently, we perform our contract drilling services in the Permian Basin of West Texas. Our top five customers for the contract drilling services for the year ended December 31, 2013 were Diamondback Energy E&P, LLC, JAMEX, Inc., EXL Petroleum, LP, Red Willow Production, LLC and Cambrian Management, LTD. For the six months ended June 30, 2014, the top five customers for the contract drilling services were Breitburn Operating LP, J. Cleo Thompson, RSP Permian LLC, Capitan Energy and Hibernia Resources LLC.

A majority of the wells we drill for our customers are drilled in unconventional basins or resource plays. These plays are generally characterized by complex geologic formations that often require higher horsepower, premium rigs and experienced crews to reach targeted depths. As of September 1, 2014, we owned and operated 14 land drilling rigs, ranging from 800 to 1,600 horsepower, 11 of which are specifically designed for drilling horizontal and directional wells, which are increasing as a percentage of total wells drilled in North America and are frequently utilized in unconventional resource plays. As of September 1, 2014, 13 of our 14 drilling rigs were operating under term contracts with a term of more than one well or a stated period of time. To facilitate the provision of our contract drilling services, as of September 1, 2014, we also owned 32 trucks specifically tailored to move rigs and two cranes to assist us in moving rigs in the Permian Basin. As part of our contract drilling services we also provide pipe inspection services.

A land drilling rig generally consists of engines, a hoisting system, a rotating system, a drawworks, a mast, pumps and related equipment to circulate the drilling fluid under various pressures, blowout preventers, drill string and related equipment. The engines power the different pieces of equipment, including a rotary table or top drive that turns the drill pipe, or drill string, causing the drill bit to bore through the subsurface rock layers.

 

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Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a drilling line, a traveling block and hook assembly and ancillary equipment that attaches to the rotating system, a mechanism known as the drawworks. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydromatic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.

The rotating equipment from top to bottom consists of a swivel, the kelly bushing, the kelly, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the swivel and the drill bit as the drill stem. The swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drill bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.

Drilling fluid, often called drilling mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.

There are numerous factors that differentiate drilling rigs, including their power generation systems, horsepower, maximum drilling depth and horizontal drilling capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well.

Our drilling rigs, including the five electric horizontal drilling rigs acquired in January 2014, have rated maximum depth capabilities ranging from 12,500 feet to 20,000 feet. Of these drilling rigs, seven are electric rigs and seven are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the

 

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power from its generators (which in the case of mechanical rigs, power the rig directly) into electricity to power the rig. Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job. Power requirements for drilling jobs may vary considerably, but most of our mechanical drilling rigs employ six engines to generate between 400 and 1,700 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations drill to measured depths greater than 10,000 to 18,000 feet. Generally, land rigs operate with four crews of five people and two tool pushers, or rig managers, rotating on a weekly or bi-weekly schedule.

We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs.

We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. We typically enter into drilling contracts that provide for compensation on a daywork basis. Occasionally, we enter into drilling contracts that provide for compensation on a footage basis, however, a majority of such footage drilling contracts also provide for daywork rates for work outside core drilling activities contemplated by such footage contracts and under certain other circumstances. We have not historically entered into turnkey contracts; however, we may decide to enter into such contracts in the future. It is also possible that we may acquire such contracts in connection with future acquisitions of drilling assets. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, the anticipated duration of the work to be performed and market conditions. As of September 1, 2014, ten of our 14 drilling rigs were operating under term contracts that provide for a take-or-pay model where customers cannot terminate contracts without paying the full amount remaining, three were operating under contracts that allow the customer to terminate on 30 days’ notice, upon payment of an agreed upon fee, and the rig we acquired on September 1, 2014 was not yet in service.

Daywork Contracts. Under daywork drilling contracts, we provide equipment and labor and perform services under the direction, supervision and control of our customers. We are paid a specified operating daywork rate from the time the drilling unit is rigged up at the drilling location and is ready to commence operations. Additionally, the daywork drilling contracts typically provide for fees and/or a daywork rates for mobilization, demobilization, moving, standby time and for any continuous period that normal operations are suspended or cannot be carried on because of force majeure conditions. The daywork drilling contracts also generally provide that the customer has the right to designate the points at which casing will be set and the manner of setting, cementing and testing. Such specifications include hole size, casing size, weight, grade and approximate setting depth. Furthermore, the daywork drilling contracts specify the equipment, materials and services to be separately furnished by us and our customer. Under these contracts, liability is typically allocated so that our customer is solely responsible for the following: (i) damage to our surface equipment as a result of certain corrosive elements; (ii) damage to customer’s equipment; (iii) damage to our in-hole equipment; (iv) damage or loss to the hole; (v) damage to the underground; and (vi) costs and damages associated with a wild well. We remain responsible for any damage to our surface equipment (except for damage resulting from the presence of certain corrosive elements) and for pollution or contamination from spills of materials that originate above the surface, are wholly in our control and are directly associated with our equipment. Daywork drilling contracts generally allow the customer to terminate the contract prior to drilling to a specified depth. This right, however, is generally subject to early termination compensation, the amount of which depends on when the termination occurs.

Footage Contracts. Under footage contracts, the contractor is typically paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. A majority of these types of drilling contracts, however, contain both footage and daywork basis provisions, the applicability of which typically depends on the depth of drilling and/or the type of services being performed. For instance, when drilling occurs below a specified drilling depth or when work is considered outside the scope of the footage basis, which we refer to as core drilling, then daywork contract terms apply similar to those described above. Otherwise, the footage contract terms apply. These include a footage rate price that is a specific dollar amount per linear foot of

 

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hole drilled within the contract footage depth. Also, under the footage contract terms, we assume more responsibility for base drilling activities compared to daywork drilling. For instance, in addition to assuming responsibility for damage to our surface equipment and damage caused by certain pollution and contamination, we are responsible for the following: (i) damage to our in-hole equipment; (ii) damage to the hole that is attributable to our performance; and (iii) any costs or expenditures associated with drilling a new hole after such damage. Our customers remain responsible for any loss to their equipment, for any damage to a hole caused by them and for any underground damage. As with contracts for daywork drilling, footage drilling contracts generally allow the customer to terminate the contract before drilling to a specified depth. This right, however, is generally subject to early termination compensation, the amount of which depends on when the termination occurs.

Because we assume higher risk in a footage drilling contract, we typically pay more of the out-of-pocket costs associated with such contracts as compared to daywork contracts. We endeavor to manage these additional risks through the use of our engineering expertise and bid the footage contracts accordingly. We typically maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a negative impact on our profitability. While we have historically entered into few footage contracts, we may enter into more such arrangements in the future to the extent warranted by market conditions.

Turnkey Contracts. Turnkey contracts typically provide for a drilling company to drill a well for a customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. The drilling company would provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. The drilling company may subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, a drilling company would not receive progress payments and would be paid by its customer only after it had performed the terms of the drilling contract in full.

The risks to the drilling company under a turnkey contract are substantially greater than those under a daywork basis. This is primarily because under a turnkey contract, the drilling company assumes most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel.

Directional Drilling. Our directional drilling services provide for the efficient drilling and production of oil and natural gas from unconventional resource plays. Our directional drilling equipment includes mud motors used to propel drill bits and kits for measurement while drilling, or MWD, and electromagnetic, or EM, technology. MWD kits are down-hole tools that provide real-time measurements of the location and orientation of the bottom-hole assembly, which is necessary to adjust the drilling process and guide the wellbore to a specific target. This technology, coupled with our services, allows our customers to drill wellbores to specific objectives within narrow location parameters within target horizons. The evolution of unconventional resource reserve recovery has increased the need for the precise placement of a wellbore. Wellbores often travel across long-lateral intervals within narrow formations as thin as ten feet. Our personnel are involved in all aspects of a well from the initial planning of a customer’s drilling program to the management and execution of the horizontal or directional drilling operation. Currently, we perform our directional drilling services in the Appalachian Basin, Anadarko Basin, Arkoma Basin, Permian Basin and the Gulf Coast of Louisiana. For the year ended December 31, 2013, our top five customers for the directional drilling services were Gulfport, Fairway Resources, LLC, Le Norman Operating LLC, Charter Oak Production Co., LLC and Spring Operating Co. For the six months ended June 30, 2014, our top five customers for the directional drilling services were Gulfport, Le Norman Operating LLC, Fairway Resources, LLC, El Toro Resources LLC, and Ranken Energy Corporation.

 

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As of September 1, 2014, we owned seven MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 42 mud motors and an inventory of related parts and equipment. Subsequent to September 1, 2014, we acquired 14 additional mud motors. As of September 1, 2014, we employed 18 directional drillers with significant industry experience to implement our services.

Remote Accommodations Services

Our remote accommodations services provide housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We provide a turnkey solution for our customers’ accommodation needs. These modular camps, when assembled together, form large dormitories, with kitchen/dining facilities and recreation areas. These camps are operated as “all inclusive,” where meals are prepared and provided for the guests. The primary revenue source for these camps is lodging fees. In 2013, we expanded our remote accommodation services business after being awarded a long-term contract by an unrelated third party. We also have an agreement with an affiliate pursuant to which we provide remote accommodation services on an on-going basis. See “Certain Relationships and Related Party Transactions.” As of September 1, 2014, we had 700 remote accommodation rooms and by the end of 2014, we expect to own facilities supporting oil sands activities in northern Alberta, Canada with an aggregate of 890 rooms, 762 of which are expected to be at Sand Tiger Lodge, our camp in northern Alberta, and 128 of which are expected to be leased as rental equipment to a third party.

Our Industry

We operate principally in the oilfield services industry, but also compete with producers and sellers of natural sand proppant used in hydraulic fracturing operations and remote accommodations providers primarily supporting oil and natural gas operations. We believe that the following trends in our industry will benefit our operations:

 

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Increased U.S. Crude Oil Production. According to the EIA, U.S. average crude oil production reached approximately 11.9 million barrels per day during July 2014, an increase of approximately 34% over 2012. U.S. average crude oil production has grown at a compound annual growth rate of 6.5% over the period from 2007 through 2013 due to production gains from unconventional reservoirs. We expect that this continued growth will result in increased demand for our services.

 

 

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Increased use of horizontal drilling to develop unconventional resource plays. According to Baker Hughes, the horizontal rig count on September 12, 2014 was 1,342, or approximately 70% of the total U.S. onshore rig count. This compares to 382 horizontal rigs, or approximately 22% of the total U.S. onshore rig count, at year-end 2006. As a result of improvements in drilling and production-enhancement

 

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technologies, oil and natural gas companies are increasingly developing unconventional resources such as tight sands and shales. Successful and economic production of these unconventional resource plays frequently requires horizontal drilling, fracturing and stimulation services. Drilling related activity for unconventional resources is typically done on tighter acre-spacing and thus requires that more wells be drilled relative to conventional resources. We believe that all of these characteristics will drive the demand for our services.

 

 

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Tight oil production growth is expected to continue to be the primary driver of U.S. oil production growth. According to the EIA, U.S. tight oil production has grown from 0.38 million barrels per day in 2007 to almost 3.5 million barrels per day in 2013, representing 35% of total U.S. crude oil production in 2013. A majority of this increase has come from the Eagle Ford play in South Texas, the Bakken Shale in the Williston Basin of North Dakota and Montana, and the Permian Basin in West Texas. We believe the Utica Shale and the Permian Basin, our primary target business locations, will be key drivers of U.S. tight oil production as these plays are developed in the coming years due to anticipated increases in horizontal drilling activity.

 

 

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Horizontal wells are heavily dependent on oil field services. The continued increase in footage drilled per year since 2009 has resulted in increased demand for oil field services. Also, according to Baker Hughes, as of September 12, 2014, oil and liquids focused rigs accounted for approximately 82% of all rigs drilling in the United States, up from 16% at year-end 2005. The scope of services for a horizontal well are greater than for a conventional well. It has been reported in the industry that the average

 

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horsepower, length of the lateral and number of fracture stages has continued to increase since 2008. We believe our commitment to provide services in oil and liquids-focused plays, such as the Utica Shale and the Permian Basin, provide us the opportunity to compete in those regional markets where the majority of total footage is drilled each year in the United States.

 

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New and emerging unconventional resource plays. In addition to the growth and development of existing unconventional resource plays such as the Bakken, Eagle Ford, Barnett, Fayetteville, Cotton Valley, Haynesville, Marcellus and Woodford Shales, exploration and production companies continue to find new unconventional resources. These include oil and liquids-based shales in the Permian, Utica, Cana Woodford, Granite Wash, Niobrara and Woodford resource plays. In certain cases, exploration and production companies have acquired vast acreage positions in these plays that require them to drill and produce hydrocarbons to hold the leased acreage. We believe these emerging resource plays will continue to drive demand for our services as they typically require the use of extended reach horizontal drilling, multiple stage fracture stimulation and high pressure completion capabilities. We also believe we are well-positioned to expand our services in two major developing unconventional plays, the Utica Shale in Ohio and the Permian Basin in West Texas.

 

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Increased focus on onshore unconventional plays by large independent oil companies, major integrated oil and natural gas companies and national oil companies. Major integrated exploration and production companies have increasingly been allocating capital and other resources to the U.S. onshore unconventional oil and natural gas tight sand and shale resource plays. Over the past two years, exploration and production companies such as ExxonMobil Corporation, BP p.l.c. and Chevron Corporation have made strategic acquisitions and/or formed joint ventures in these domestic unconventional resource plays. Also, international demand for access to U.S. unconventional development has been increasing as national oil companies look to benefit from the technologies developed in the U.S. shale exploration. The following table represents some of the largest publicly announced joint ventures and acquisitions completed in domestic onshore unconventional oil and natural gas shale plays since the beginning of 2008.

 

Acquirer		Seller		Play		Date		Deal Value ($mm)
Devon Energy Corporation		GeoSouthern		Eagle Ford		11/20/2013		$6,000.0
Whiting Petroleum Corp.		Kodiak Oil and Gas Corp.		Bakken		7/13/2014		6,000.0
Royal Dutch Shell Plc		East Resources Inc.; KKR		Marcellus		5/28/2010		4,700.0
Apache Corporation		Mariner Energy Inc.		Permian		4/15/2010		3,900.0
Denbury Resources Inc.		Encore Acquisition Company		Permian		11/1/2009		4,464.9
Statoil ASA		Brigham Exploration Company		Bakken		10/17/2011		4,400.0
Chevron Corporation		Atlas Energy Inc.		Marcellus		11/9/2010		4,307.6
Marathon Oil Corporation		Hilcorp Resources		Eagle Ford		6/1/2011		3,500.0
CONSOL Energy Inc.		Dominion Resources Inc.		Marcellus		3/15/2010		3,475.0
Statoil Hydro		Chesapeake Energy Corporation		Marcellus		11/11/2008		3,375.0
Chevron Corporation; EnerVest Ltd., Royal Dutch Shell Plc		Chesapeake Energy Corporation		Permian		9/12/2012		3,300.0
Plains Exploration & Production Co		Chesapeake Energy Corporation		Haynesville		7/1/2008		3,300.0
Noble Energy Inc.		CONSOL Energy Inc.		Marcellus		8/18/2011		3,200.0
Encana Corporation		Freeport-McMoRan Inc. Assets		Eagle Ford		5/7/2014		3,100.0
Apache Corporation		BP Plc		Permian		7/20/2010		3,100.0
Baytex Energy Corp.		Aurora Oil and Gas		Eagle Ford		2/6/2014		2,588.0
American Energy Partners		Enduring Resources		Permian		6/9/2014		2,500.0
Total SA		Chesapeake Energy Corporation; EnerVest Ltd.		Utica		12/30/2011		2,320.0
CNOOC Limited		Chesapeake Energy Corporation		Eagle Ford		10/10/2010		2,160.0
Exxon Mobile Corp.		Denbury Resources, Inc.		Bakken		9/20/2012		2,000.0

 

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Need for additional drilling activity to maintain production levels. With the increased maturity of the onshore conventional and, in many cases, unconventional resource plays, oil and natural gas production may be characterized as having steeper initial decline curves. As a result, we believe that an increasing number of wells will need to be drilled to offset production declines. Given average decline rates and demand forecasts, we believe that the number of wells drilled is likely to continue to increase in coming years. Once a well has been drilled, it requires recurring production and completion services, which we believe will drive demand for our services.

 

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Continued development of the Canadian oil sands. Our remote accommodations business is significantly influenced by the level of development of oil sands deposits in Alberta, Canada and activity levels in support of oil and natural gas development in Canada generally. Despite the general economic downturn in 2009 and early 2010 resulting from the global financial crisis, activity in the Canadian oil sands has grown significantly in the last six years. Demand for oil sands accommodations is influenced to a great extent by the longer-term outlook for crude oil prices rather than current energy prices, given the multi-year time frame to complete oil sands projects and the costs associated with development of such large scale projects. Utilization of our existing Canadian accommodations capacity and our future expansions will largely depend on continued oil sands development spending.

Our Business Strategy

Our primary business objective is to provide an attractive total return to unitholders by optimizing business results and maximizing distributions through organic growth opportunities and accretive acquisitions. We intend to achieve this by the successful execution of our business plan to strategically deploy our equipment and personnel to provide drilling, completion and production services and remote accommodation services in unconventional resource plays. We believe these services optimize our customers’ ultimate resource recovery and present value of hydrocarbon reserves. We also believe that our services create cost efficiencies for our customers by providing a suite of complementary oilfield services designed to address a wide range of our customers’ needs. Specifically, we intend to:

 

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Capitalize on the increased activity in the unconventional resource plays. Our equipment is designed to provide horizontal drilling and completion and production services for unconventional wells, and our operations are strategically located in major unconventional resource plays. We intend to continue capitalizing on the growth in these markets and diversifying our operations across the different unconventional resource basins. Our core operations are focused primarily in the Utica Shale in Ohio and the Permian Basin in West Texas. We intend to continue to strategically deploy assets to these and other unconventional resource basins and will look to capitalize on further growth in emerging unconventional resource plays as they develop. We also plan to continue to grow our accommodations business in the Canadian oil sands as capital projects are announced and contracts awarded to service companies in need of accommodations.

 

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Expand our services as determined by demand. During the first eight months of 2014, in response to increased customer demand, we expanded our drilling business by acquiring six electric horizontal drilling rigs, expanded our completion and production business to 117,000 horsepower and expanded our remote accommodations business by purchasing additional rooms. We intend to continue to expand our business lines as demand increases in resource plays in which we currently operate, as well as in new resource plays. If we perceive unmet demand in our principal geographic locations for different service lines, we will seek to expand our current service offerings to meet that demand.

 

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Leverage our broad range of services for unconventional wells. We offer a complementary suite of services relating to the drilling of unconventional wells and completion and production services related thereto. Our drilling and completion and production services division provides pressure pumping services, pressure control services and flowback services for unconventional wells and includes processing and sales of proppant. Our drilling services division adds drilling capabilities to our other well-related services. We intend to leverage our existing customer relationships, operational track record and our industry reputation to cross sell our services and to increase our exposure and product offerings to our

 

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existing customers, broaden our customer base and expand opportunistically to other geographic regions in which our customers have operations, as well as to create operational efficiencies for our customers.

 

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Expand through selected, accretive acquisitions. To complement our organic growth, we intend to actively pursue selected, accretive acquisitions of related businesses and assets that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence. For instance, we believe demand for horizontal drilling rigs will continue to increase, and in January 2014, we acquired five electric horizontal drilling rigs, and on September 1, 2014 we acquired an additional electric horizontal drillings rig, which increased our fleet of drilling rigs to a total of 14, 11 of which are specifically designed for horizontal drilling. We believe this strategy will facilitate the continued expansion of our customer base, geographic presence and service offerings and permit us to increase cash available for distribution.

 

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Leverage our experienced operational management team and basin-level expertise. We seek to manage our business as close as possible to the needs of our customer base. Our operational division heads have longstanding relationships with our largest customers. We intend to leverage these relationships and our operational management team’s basin-level expertise to deliver innovative, client focused and basin-specific services to our customers.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

 

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Quality equipment designed for horizontal drilling. Our service fleet is predominantly comprised of equipment that has been designed to optimize recovery from unconventional wells. As of June 1, 2014, approximately 65% of our pressure pumping equipment had been purpose built within the last twelve months to that end. Most of our pressure control equipment has been designed and built by us and is less than two years old. Our accommodation units have an average age of approximately three years and are built on a customer-by-customer basis to meet their specific needs. We believe that our equipment will allow us to provide a high level of service to our customers and capitalize on future growth in the unconventional resource plays that we serve.

 

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Experienced management and operating team. Our operational division heads have an extensive track record in the oilfield services business with an average of over 26 years of oilfield services experience. In addition, our field managers have expertise in the geological basins in which they operate and understand the regional challenges that our customers face. We believe their knowledge of our industry and business lines enhances our ability to provide innovative, client-focused and basin-specific customer service, which we also believe strengthens our relationships with our customers.

 

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Strategic geographic positioning. We currently operate facilities and service centers to support our operations in major unconventional resource plays in the United States, including the Utica Shale in Ohio, the Permian Basin in West Texas, the Appalachian Basin in the Northeast, the Arkoma Basin in Arkansas and Oklahoma, the Anadarko Basin in Oklahoma, the Cana Woodford and Woodford Shales in Oklahoma, the Granite Wash and Mississippi Shale in Oklahoma and Texas, the Gulf Coast of Louisiana and the oil sands in Canada. We believe our geographic positioning within growing oil and natural gas resource plays allows us to strategically capitalize on the increased activity in these unconventional resource plays.

 

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Long-term, basin-level relationships with a stable customer base. Our operational division heads and field managers have formed long-term relationships with our customer base. We believe these relationships help provide us a more stable and growth-oriented client base in the unconventional shale markets that we currently serve. Our customers include large independent oil and natural gas exploration and production companies. Our top five customers for the year ended December 31, 2013, representing 58.8% of our revenue, on a pro forma basis, were Gulfport, Diamondback Energy, Inc., Grizzly Oil Sands ULC, Apache Corporation and JAMEX, Inc. Our top five customers for the three

 

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months ended March 31, 2014, representing 55.7% of our revenue on a pro forma basis, were Gulfport, Breitburn Operating LP, J. Cleo Thompson, Apache Corporation and Hibernia Resources LLC.

Our Relationship with Wexford and Gulfport

We are managed and operated by the board of directors and executive officers of our general partner, Mammoth Energy Partners GP LLC, which is owned by Mammoth Energy, an entity controlled by our founder and sponsor Wexford. As a result of owning our general partner, Mammoth Energy will have the right to appoint all members of the board of directors of our general partner, except for the member of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement.

In addition to Wexford’s beneficial ownership of our general partner and Gulfport’s right to appoint one director, upon completion of this offering, assuming Wexford, Gulfport and their respective affiliates make no additional purchases of our common units, Wexford and Gulfport will beneficially own approximately         % and         %, respectively, of our common units (approximately         % and         %, respectively, if the underwriters’ over-allotment option is exercised in full).

Given our relationship with Wexford and Gulfport and their significant ownership interests in us, we believe they have a strong incentive to support and promote the successful execution of our business plans and objections, but they will continue to be free to act in a manner that is beneficial to their own interests without regard to ours.

For further information regarding our relationship with Wexford and Gulfport, including the investor rights agreement, please see “Management” and “Certain Relationships and Related Party Transactions.”

Properties

Our corporate headquarters are located at 4727 Gaillardia Parkway, Suite 200, Oklahoma City, Oklahoma 73142. We currently own ten properties, six located in Ohio, one located in Wisconsin, one located in Texas and two located in Canada, which are used for field offices, yards, production plants or housing. In addition to our headquarters, we also lease thirteen properties that are used for field offices, yards or transloading facilities for frac sand. We lease all of these properties from third parties.

We believe that our facilities are adequate for our current operations.

Marketing and Customers

Our customers consist primarily of independent oil and natural gas producers and land-based drilling contractors in North America. For the six months ended June 30, 2014 and the year ended December 31, 2013, on a pro forma basis, we had approximately 112 and 146 customers, respectively, including Gulfport, Diamondback Energy, Inc., Grizzly Oil Sands ULC, Apache Corporation, JAMEX, Inc., Chesapeake Energy Corporation and Marathon Oil. Our top five customers accounted for approximately 54.3% and 58.8% of our revenue, on a pro forma basis, for the six months ended June 30, 2014 and the year ended December 31, 2013, respectively. For the six months ended June 30, 2014 and the year ended December 31, 2013, Gulfport was our largest customer accounting for approximately 36.8% and 46.1% of our revenue, respectively, on a pro forma basis, with no other customer accounting for more than 10% of our revenue during those periods. For the year ended December 31, 2012, Gulfport, Grizzly Oil Sands ULC and Marathon Oil were our largest customers accounting for approximately 26%, 20% and 14%, respectively, of our revenue, on a pro forma basis, with no other customer accounting for more than 10% of our revenue for that year. Although we believe we have a broad customer base and wide geographic coverage of operations, it is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer decided not to continue to use our services, revenue could decline and our operating results and financial condition could be harmed.

 

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Operating Risks and Insurance

Our operations are subject to hazards inherent in the oilfield services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause:

 

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personal injury or loss of life;

 

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damage or destruction of property, equipment, natural resources and the environment; and

 

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suspension of operations.

In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.

Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

Despite our efforts to maintain safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

We maintain commercial general liability, workers’ compensation, business auto, commercial property, motor truck cargo, umbrella liability, in certain instances, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. The limits for our general liability policies for our business entities fall within the following ranges (as may be applicable):

 

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Commercial General Liability Limit (primary policy): $1,000,000 to $2,000,000 per occurrence and $2,000,000 per project aggregate.

 

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Commercial Umbrella Limit: $1,000,000 to $10,000,000.

 

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Excess Liability Limit (in excess of Commercial Umbrella): $10,000,000 to $25,000,000.

In some cases, the above policies require a deductible, ranging from $5,000 to $25,000 per occurrence. We also maintain workers’ compensation insurance policies with limits of $1,000,000, with deductibles ranging from $1,000 to $2,500. Further, we have pollution legal liability coverage for our business entities with limits ranging from $1,000,000 to $5,000,000, which coverage is subject, in certain cases, to 30-day discovery and 90-day reporting requirements and deductibles ranging from $10,000 to $25,000. Our pollution liability policy would cover, among other things, third party liability and costs of clean-up relating to environmental contamination on our premises while our equipment and chemicals are in transit and while on our customers’ job site. With respect to our hydraulic fracturing operations, coverage would be available under our pollution legal liability policy for any surface or subsurface environmental clean-up and liability to third parties arising from any surface or subsurface contamination.

We also have certain specific coverages for some of our businesses. For our remote accommodation services business, we maintain an insurance policy to cover our back-up generator, water treatment plant and other property, which has a limit of $22,256,500 and an insurance policy of up to $7,500,000 to cover business interruptions and loss of profits (subject to waiting periods ranging from 48 hours and 96 hours). For our pressure pumping services business, we maintain an equipment floater that covers losses up to $20,000,000 per occurrence and $20,000,000 per well site. The deductible is $10,000 for equipment valued at least $100,000 and $5,000 for equipment valued under $100,000.

 

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For our proppant production and sales business, we maintain insurance to cover the loss of certain equipment, buildings and other property, including loss of income for certain specified events. We maintain a main property policy, providing coverage for up to $10,000,000 for certain major equipment breakdowns and catastrophic events, provided, however, that damages from flooding and earthquakes are limited to up to $5,000,000, with a $50,000 deductible per occurrence. The deductibles for other types of coverages under the main property policy range from $2,500 to $25,000. We also maintain three excess property insurance policies for the proppant production and sales business to insure various buildings, business and personal property, equipment and expenses related to business interruption, providing coverage ranging from $15,000,000 to approximately $39,200,000 per occurrence, once damages exceed certain specified thresholds and subject to deductibles ranging from $10,000 per occurrence to $50,000 per occurrence in the case of earthquake and flood damage.

For our contract land and directional drilling business, we maintain inland marine insurance to cover physical loss or damage to our drilling rigs and other mobile equipment. For Bison, this insurance provides coverage up to a limit of $55,997,542, in the case of our drilling rigs, and $14,316,690, in the case of our mobile equipment. The deductible for Bison’s operating rigs is $150,000 per occurrence while the deductible for its stacked rigs is $100,000 per occurrence. In the case of mobile equipment, the deductible for each occurrence is 5% of the scheduled value of the equipment, subject to a $5,000 minimum. In the event of a total loss or constructive total loss, no deductible will apply. For Panther, the inland marine insurance provides coverage for mobile equipment up to a limit of $4,978,694. For equipment that Panther leases from others, the insurance provides coverage of up to $500,000 per item and up to $3,000,000 for all equipment items combined. For equipment that Panther may lease to others, the insurance provides coverage of up to $250,000 per item and up to $1,000,000 for all equipment items combined. The deductible Panther is required to pay is $5,000 for items up to $150,000 and $10,000 for items greater than $150,000. Panther’s inland marine insurance excludes coverage equipment damage that occurs while the equipment is located underground.

Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See “Risk Factors” on page 22 of this prospectus for a description of certain risks associated with our insurance policies.

Safety and Remediation Program

In the oilfield services industry, an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced and skilled workforce. Recently, many of our large customers have placed an emphasis not only on pricing, but also on safety records and quality management systems of contractors. We believe these factors will gain further importance in the future. We have committed resources toward employee safety and quality management training programs. Our field employees are required to complete both technical and safety training programs. Further, as part of our safety program and remediation procedures, we check fluid lines for any defects on a periodic basis to avoid line failure during hydraulic fracturing operations, marking such fluid lines to reflect the most recent testing date. We also regularly monitor pressure levels in the fluid lines used for fracturing and the surface casing to verify that the pressure and flow rates are consistent with the job specific model in an effort to avoid failure. As part of our safety procedures, we also have the capability to shut down our pressure pumping and fracturing operations both at the lines and in our data van. In addition, we maintain spill kits on location for containment of pollutants that may be spilled in the process of providing our hydraulic fracturing services. The spill kits are generally comprised of pads and booms for absorption and containment of spills, as well as soda ash for neutralizing acid. Fire extinguishers are also in place on job sites at each pump.

Historically, we have used a third-party contractor to provide remediation and spill response services when necessary to address spills that were beyond our containment capabilities. None of these prior spills were significant,

 

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and we have not experienced any incidents, citations or legal proceeding relating to our hydraulic fracturing services for environmental concerns. To the extent our hydraulic fracturing or other oilfield services operations result in a future spill, leak or other environmental impact that is beyond our ability to contain, we intend to engage the services of such remediation company or an alternative company to assist us with clean-up and remediation.

Competition

The markets in which we operate are highly competitive. To be successful, a company must provide services and products that meet the specific needs of oil and natural gas exploration and production companies and drilling services contractors at competitive prices.

We provide our services and products across the United States and in Alberta, Canada and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies.

Our major competitors for our pressure control services include Schlumberger Limited, Halliburton Company, Baker Hughes Incorporated, Weatherford International Ltd., Key Energy Services Inc., Nabors Industries Ltd., Complete Energy Services, Inc. and RPC Incorporated and a significant number of locally oriented businesses. Our major competitors in pressure pumping services include Halliburton Company, Baker Hughes Incorporated, Schlumberger Limited, Weatherford International Ltd, Nabors Industries Ltd., RPC Incorporated, Complete Energy Services, Inc. and FracTech Services, Inc. In our contract and directional drilling services segment, our primary competitors include Helmerich & Payne, Inc., Precision Drilling Corporation, Patterson-UTI Energy, Inc., Cactus Drilling, Sidewinder Drilling, Inc., Baker Hughes Incorporated, Weatherford International Ltd. and various regional and local service providers. Our major competitors in our proppant production and sales business are Badger Mining Corporation, Fairmount Minerals, Ltd., Hi-Crush Partners LP, Preferred Proppants LLC, Unimin Corporation and U.S. Silica Holdings Inc. Our major competitors for our remote accommodation business include Oil States International, Inc., Black Diamond Limited and a significant number of local businesses.

We believe that the principal competitive factors in the market areas that we serve are quality of service and products, reputation for safety and technical proficiency, availability and price. While we must be competitive in our pricing, we believe our customers select our services and products based on the local leadership and basin-expertise that our field management and operating personnel use to deliver quality services and products.

Regulation

We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the handling of hazardous materials, the transportation of explosives, the protection of human health and the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance which is incorporated into our daily operating procedures. The oil and natural gas industry is subject to environmental regulation pursuant to local, state and federal legislation.

Transportation Matters

In connection with our transportation and relocation of our oilfield service equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing and insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials (HAZMAT). Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.

 

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Interstate motor carrier operations are subject to safety requirements prescribed by the United States Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria which could result in a suspension of operations. The rating scale consists of “satisfactory,” “conditional” and “unsatisfactory” ratings. As of September 1, 2014, all of our trucking operations have “satisfactory” ratings with the Department of Transportation. We have undertaken comprehensive efforts that we believe are adequate to comply with the regulations. Further information regarding our safety performance is available at the Department of Transportation Federal Motor Carrier Safety Administration website at www.fmcsa.dot.gov.

Environmental Matters and Regulation

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. We handle, transport, store and dispose of wastes that are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

 

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Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials associated with oil and gas deposits and, accordingly may result in the generation of wastes and other materials containing naturally occurring radioactive materials, or NORM. NORM exhibiting levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because certain of the properties presently or previously owned, operated or occupied by us may have been used for oil and gas production operations, it is possible that we may incur costs or liabilities associated with NORM.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. Noncompliance with these requirements may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, our sand proppant production operations are subject to air permits issued by the Wisconsin Department

 

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of Natural Resources regulating our emission of fugitive dust and other constituents. In addition, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” These and other laws and regulations may increase the costs of compliance for some facilities where we operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases (collectively, GHGs) present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set New Source Performance Standards for new coal-fired and natural-gas fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility, which could reduce the demand for our products and services.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

 

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Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration—wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would update existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected later in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any

 

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possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas and Ohio, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that well operators disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. In January 2012, the Ohio Department of Natural Resources, or ODNR, issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area and the ODNR continues to monitor earthquake activity in proximity to wells undergoing hydraulic fracturing. Many other states have adopted similar legislation, including several where we provide services.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Regulation of Sand Proppant Production

The U.S. Mine Safety and Health Administration, or MSHA, has primary regulatory jurisdiction over commercial silica operations, including quarries, surface mines, underground mines and industrial mineral processing facilities. While we do not directly conduct any mining operations, we are dependent on several regulated mines for the supply of natural sand used in our proppant production. In addition, MSHA representatives perform at least two annual inspections of our production facilities to ensure employee and general site safety. To date, these inspections have not resulted in any citations for material violations of MSHA standards, and we believe we are in material compliance with MSHA requirements.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are

 

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authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although changes to the regulatory burden on the oil and natural gas industry could affect the demand for our services, we would not expect to be affected any differently or to any greater or lesser extent than other companies in the industry with similar operations.

Drilling. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

•

the location of wells;

 

•

the method of drilling and casing wells;

 

•

the timing of construction or drilling activities, including seasonal wildlife closures;

 

•

the surface use and restoration of properties upon which wells are drilled;

 

•

the plugging and abandoning of wells; and

 

•

notice to, and consultation with, surface owners and other third parties.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

State Regulation. States regulate the drilling for oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

OSHA Matters

We are also subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Employees

As of September 1, 2014, we had approximately 914 full time employees, including 262 salaried administrative or supervisory employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full time employees.

 

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Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

 

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MANAGEMENT

Management of Mammoth Energy Partners LP

We are managed and operated by the board of directors and executive officers of our general partner.

Mammoth Holdings owns all the membership interests in our general partner. As a result of owning our general partner, Mammoth Holdings, an entity controlled by Wexford, will have the right to appoint all members of the board of directors of our general partner, including the independent directors, except for those members of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement. Pursuant to the investor rights agreement we will enter into with Gulfport prior to the closing of this offering, as long as Gulfport and its affiliates own 10% or more of our common units, Gulfport shall be entitled to appoint one director.

Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owner.

Upon the closing of this offering, we expect that our general partner will have five directors, one of whom will be independent as defined under the independence standards established by NASDAQ and the Exchange Act. Spencer D. Armour, III will serve as the initial independent member of the board of directors of our general partner. In accordance with the rules of NASDAQ, Mammoth Holdings will appoint one additional independent member within 90 days of the effective date of the registration statement of which this prospectus forms a part and one additional independent member within one year of such effective date, bringing the total number of directors on the board of directors of our general partner to seven. NASDAQ does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by NASDAQ and the Exchange Act, subject to the transitional relief during the one-year period following completion of this offering.

The executive officers of our general partner will manage the day-to-day affairs of our business and intend to devote as much time as is necessary for the proper conduct of our business.

Our partnership agreement requires us to reimburse our general partner and certain of its affiliates, including Wexford, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, in connection with the closing of this offering, we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement. Please see “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

 

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Executive Officers and Directors of Our General Partner

The following table shows information for the executive officers and directors of our general partner upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers. Ages are as of June 30, 2014.

 

Name		Age				Position
Marc McCarthy			43			Executive Chairman and Director
Phil Lancaster			56			President
Mark Layton			39			Chief Financial Officer
Spencer D. Armour, III			60			Director Nominee
Aaron Gaydosik			38			Director Nominee
Joseph M. Jacobs			61			Director Nominee
Kenneth A. Rubin			59			Director Nominee

Marc McCarthy has served as Executive Chairman of the Board of Directors of our general partner since September 17, 2014. Mr. McCarthy is currently a Senior Managing Director at Wexford, having joined Wexford in June 2008. Upon completion of this offering, Mr. McCarthy will become a consultant to Wexford. Mr. McCarthy also serves as a director of Coronado Midstream LLC, a private gas gathering and processing operation in Midland, TX. From September 2009 until June 2013, Mr. McCarthy served as Chairman of the Board and a director of EPL Oil & Gas, Inc., an independent oil and natural gas exploration and production company. He also served on the Nominating and Governance Committee of EPL Oil & Gas, Inc. Before joining Wexford, Mr. McCarthy was a Senior Managing Director at Bear Stearns & Co., Inc. within its Global Equity Research Department having been responsible for coverage of the international oil and gas sector. Mr. McCarthy joined Bear Stearns & Co. in 1997 and held various positions of increasing responsibility until his departure in June 2008. Prior to 1997, he worked in equity research at Prudential Securities, also following the oil and gas sector. Mr. McCarthy is a Chartered Financial Analyst and received a B.A. in Economics from Tufts University. We believe Mr. McCarthy’s experience as a director of both publicly-traded and private oil and gas companies, as well as his experience in evaluating financial, strategic and operational aspects of companies in our industry at Wexford, qualifies him for service as a Director of our general partner.

Phil Lancaster became President of our general partner in August 2014 and served as its initial director from August 2014 to September 2014. Mr. Lancaster has served as Chief Executive Officer of Redback Energy Services LLC since September 2011. From June 2006 to November 2010, Mr. Lancaster served as Chief Executive Officer of Great White Energy Services, and from November 2010 to September 2011, Mr. Lancaster was a consultant to Wexford in connection with energy-related investments. Mr. Lancaster served on the board of directors of Bronco Drilling Company, Inc., a Nasdaq-listed drilling company, from August 2005 until July 2006 and Gulfport, a Nasdaq Global Select listed exploration and production company, from February 2006 until August 2006. Mr. Lancaster received a Bachelor of Science degree from the David Lipscomb College.

Mark Layton became Chief Financial Officer of our general partner in August 2014. Mr. Layton served as Chief Financial Officer of Stingray Pressure Pumping LLC from January 2014 to August 2014. Mr. Layton was employed from August 2011 through January 2014 by Archer Well Company Inc. where his last position was Director of Finance for North America. From September 2009 through August 2011, Mr. Layton was employed by Great White Energy Services, Inc. where his last position was Corporate Controller and Director of Financial Reporting. Mr. Layton served as Vice President of Finance of Crossroads Wireless, Inc., a wireless telecommunications service company, from May 2007 through September 2009. In February 2009, an involuntary petition petition under Chapter 7 of the United States Bankruptcy Code was filed against Crossroads Wireless, Inc. in the Western District of Oklahoma. From April 2004 through May 2007, Mr. Layton served as the Director of Financial Reporting for Chickasaw Holding Company, a telecommunications service company.

 

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He began his career in public accounting with Finley & Cook PLLC. Mr. Layton has a Bachelor of Science degree in Accounting from the University of Central Oklahoma. Mr. Layton is a Certified Public Accountant.

Spencer D. Armour, III has agreed to serve as a director of our general partner and is expected to join the Board of Directors of our general partner prior to the closing of this offering. Mr. Armour has served as chairman of ProPetro Services, Inc. since January 2013 and has been a partner at PT Petroleum, LLC since March 2013. He has also served as Managing Partner of Armada Gas & Oil Company in Midland, Texas, a company that invests in oil and gas production, minerals and the oilfield service sector, since 2009. Mr. Armour has over thirty years of experience in the oilfield service business. From April 2007 to December 2008, Mr. Armour served as Vice President of Corporate Development at Basic Energy Services, Inc. From March 2006 until March 2007, Mr. Armour served as Chief Executive Officer of Sledge Drilling Corp. From January 2002 until February 2006, he served as Executive Vice President of Contracts/Drilling Fluids for Patterson-UTI Energy, Inc. Mr. Armour served as a director of Patterson-UTI Energy, Inc. from July 1999 to May 2002. He founded Lone Star Mud, Inc. in 1986 and served as its President until January 1998. He was appointed for a six year term to the University of Houston System Board of Regents in September 2011 and currently serves as Chairman of the Finance Committee. Mr. Armour received a Bachelor of Science in Economics from the University of Houston in 1977. We believe Mr. Armour’s knowledge of the oilfield services industry and his experience as a director of a public company qualifies him for service as a Director of our general partner.

Aaron Gaydosik has agreed to serve as a Director of our general partner and is expected to join the board of directors of our general partner prior to the closing of this offering. Mr. Gaydosik has served as Chief Financial Officer of Gulfport since August 2014. From July 2013 until joining Gulfport, Mr. Gaydosik served as Vice President of Finance at Kodiak Oil & Gas Corp., an independent energy company with operations focused primarily in the Williston Basin of North Dakota. From May 2007 through July 2013, Mr. Gaydosik held various positions of increasing levels of responsibility at Credit Suisse, most recently as a Director in its Oil and Gas Group, focused on capital markets and advisory transactions primarily for exploration and production companies. His prior investment banking experience also includes two years in the energy group at Wachovia Securities. Mr. Gaydosik holds a Bachelor of Business Administration in Finance from Southern Methodist University and a Masters of Business Administration from the University of Chicago Booth School of Business. We believe Mr. Gaydosik’s experience with financial matters in the oil and gas industry qualifies him for service as a Director of our general partner.

Joseph M. Jacobs has agreed to serve as a Director of our general partner and is expected to join the board of directors of our general partner prior to the closing of this offering. Mr. Jacobs is the President of Wexford, which he co-founded in 1994. From 1982 to 1994, Mr. Jacobs was employed by Bear Stearns & Co., Inc., where he attained the position of Senior Managing Director. From 1979 to 1982, he was employed as a commercial lending officer at Citibank, N.A. Mr. Jacobs served as a director for ICx Technologies, Inc. from December 2002 to August 2010, Republic Airways Holding Inc. from March 1998 to June 2008 and Azul S.A. from March 2008 to January 2010, and has served on the boards and creditors’ committees of a number of public and private companies in which Wexford has held investments. Mr. Jacobs has served as a director of the general partner of Rhino Resources LP since July 2010. Mr. Jacobs holds an M.B.A. from Harvard Business School and a B.S. in Economics from the Wharton School of the University of Pennsylvania. Mr. Jacobs was selected to serve as a director due to his significant service on the boards of other public and private companies, which provides a thorough understanding of board roles and responsibilities and widespread knowledge of various industries, businesses, operations, opportunities and risks. We believe Mr. Jacobs’ current position as President of Wexford also provides a comprehensive knowledge of management strategy and policy that qualifies him for service as a Director of our general partner.

Kenneth A. Rubin has agreed to serve as a Director of our general partner and is expected to join the board of directors of our general partner prior to the closing of this offering. Mr. Rubin joined Wexford in 1996 and became a partner in 2001. Mr. Rubin focuses on investment grade and government fixed income investments. Mr. Rubin has served on the board of directors of the general partner of Rhino Resources LP since January 2014

 

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and has served on the boards of private companies. Mr. Rubin holds a Juris Doctor degree from Stanford Law School, Order of the Coif, and a Bachelor of Arts degree in economics and mathematics from Yale University. We believe Mr. Rubin’s long-term experience in the capital and investment markets. Mr. Rubin and his understanding of our business, history and organization qualifies him for service as a Director of our general partner.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will have authority over compensation matters.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by NASDAQ and Rule 10A-3 promulgated under the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. Spencer D. Armour, III will serve as the initial member of the audit committee. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

Conflicts Committee

We expect that at least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Wexford and Gulfport, and must meet the independence standards established by NASDAQ and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Director Compensation

To date, none of the directors have received compensation for services rendered as a board member. Members of the board of directors of our general partner who are also officers or employees of our general partner will not receive compensation for their services as directors. It is anticipated that after the completion of this offering, non-employee directors will be paid a monthly retainer of $         and a per meeting attendance fee of $         and reimbursed for all ordinary and necessary expenses incurred in the conduct of our business.

In connection with this offering, we intend to implement an equity incentive plan. Under the plan, certain non-employee directors will be granted              restricted units, which will vest in three equal annual installments beginning on the date of grant.

 

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Compensation Committee Interlocks and Insider Participation

The board of directors of our general partner does not currently have a compensation committee and although it is not required and does not currently intend to establish a compensation committee, it may do so in the future. None of our executive officers serve, or have served during the past year, as a member of the board of directors or compensation committee of any other company that has one or more executive officers serving as a member of the board of directors of our general partner.

Executive Compensation

Summary of Compensation for Our Named Executive Officers

The following table shows the compensation of all individuals serving as our principal executive officer during 2013 and of our two other most highly compensated executive officers serving as of December 31, 2013, whose total compensation exceeded $100,000 for the fiscal year ended December 31, 2013.

 

		Year				Salary				Bonus(1)				All Other Compensation(2)				Total
Marc McCarthy, Chairman(3)			2013			$	—			$	—			$	—			$	—
Phil Lancaster, President(4)			2013			$	298,148			$	100,000			$	36,948			$	435,096
Mark Layton, Chief Financial Officer(5)			2013			$	—			$	—			$	—			$	—

 

(1)	Consists of a discretionary bonus.

(2)

Consists of $7,393 attributable to our matching contributions to Mr. Lancaster’s 401(k) account, $20,223 attributable to reimbursement of medical premiums and expenses, $332 attributable to life insurance premiums paid by us on behalf of Mr. Lancaster and $9,000 attributable to an automobile allowance provided by us to Mr. Lancaster.

(3)	Mr. McCarthy became our Executive Chairman on September 17, 2014, and did not receive any compensation from us in 2013.

(4)	Represents compensation Mr. Lancaster received during 2013 as the Chief Executive Officer of Redback Energy Services LLC.

(5)	Mr. Layton joined us in January 2014 and did not receive any compensation from us in 2013.

Employment Agreements

In September 2014, we entered into an oral employment agreement with Mark Layton, our Chief Financial Officer. Mr. Layton’s annual base salary is $225,000, which can be increased from time to time by the board of directors or compensation committee of our general partner. Subject to Mr. Layton’s achievement of certain performance goals to be determined by the board of directors or the compensation committee, Mr. Layton will be eligible to receive a target annual bonus of 75% of his annual base salary. Upon the completion of this offering, Mr. Layton will receive a one-time cash bonus of $300,000 and will be entitled to receive annual equity incentive awards equal to 100% of his annual base salary, which will vest equally over a four year period. Mr. Layton is entitled to participate in any life and medical insurance plans and other similar plans that we establish from time to time for our executive employees. Mr. Layton’s employment with us is terminable by either party.

2014 Equity Incentive Plan

Prior to the completion of this offering, we did not have any option or other equity incentive plan and there are no options, restricted units or other equity awards outstanding for any of our named executive officers. Prior to this offering, we intend to implement our equity incentive plan as described below. The equity incentive plan is intended to provide an additional incentive to our management and directors following the completion of this offering to continue to grow our business and enhance the value for our unitholders.

Eligible award recipients are employees, consultants and directors of our company and its affiliates. The equity interests that may be issued pursuant to awards consist of our authorized but unissued common units, and

 

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the maximum aggregate amount of such common units which may be issued upon exercise of all awards under the plan may not exceed              common units, subject to adjustment to reflect certain transactions or changes in our capital structure.

We anticipate granting unit options and restricted phantom units to employees and certain non-employee directors under the plan upon completion of this offering in an amount to be determined by the plan administrator.

Securities to be Offered. The aggregate number of common units initially authorized for issuance of awards under the plan is              common units. However, (i) common units covered by an award that expires or otherwise terminates without having been exercised in full and (ii) common units that are forfeited to, or repurchased by, us pursuant to a forfeiture or repurchase provision under the plan may return to the plan and be available for issuance in connection with a future award.

Administration. The board of directors of our general partner (or the compensation committee or any other committee of the board of directors as may be appointed by the board of directors of our general partner from time to time) will administer the plan. Among other responsibilities, the plan administrator selects participants from among the eligible individuals, determines the number of common units that will be subject to each award and determines the terms and conditions of each award, including methods of payment, vesting schedules and limitations and restrictions on awards. The plan administrator may amend, suspend or terminate the plan at any time. Amendments will not be effective without unitholder approval if unitholder approval is required by applicable law or stock exchange requirements. Unless terminated earlier, our equity incentive plan will terminate in August 2024.

Unit Options. Unit options will be treated as nonstatutory options and may be granted pursuant to option agreements to employees, directors and consultants. The plan administrator will determine the exercise price of a unit option, provided that the exercise price of a unit option cannot be less than 100% of the fair market value of a common unit on the date of grant, except when assuming or substituting options in limited situations such as an acquisition. Unit options granted under the plan will vest over a period of time specified by the plan administrator in the individual option agreements, and will generally have a term of ten years, unless specified otherwise by the plan administrator in the option agreement.

Acceptable consideration for the purchase of common units issued upon the exercise of a unit option will be determined by the plan administrator and may include (i) cash or check, (ii) a broker-assisted cashless exercise, (iii) the tender of common units previously owned by the option holder, (iv) unit withholding and (v) other legal consideration approved by the plan administrator, such as exercise with a full recourse promissory note (not applicable for directors and executive officers).

Unless the plan administrator provides otherwise (solely with respect to intervivos transfers to certain family members and estate planning vehicles), unit options generally are not transferable except by will or the laws of descent and distribution. An optionee may designate a beneficiary, however, who may exercise the unit option following the option holder’s death.

Restricted Awards. Restricted awards are awards of either actual common units (e.g., restricted unit awards), or of hypothetical units (restricted phantom units) having a value equal to the fair market value of an identical number of common units, that will be settled in the form of common units or cash upon vesting or other specified payment date, and which may provide that such restricted awards may not be sold, transferred or otherwise disposed of for such period as the plan administrator determines. The purchase price and vesting schedule, if applicable, of restricted awards are determined by the plan administrator. A restricted phantom unit is similar to a restricted unit award except that participants holding restricted phantom units do not have any unitholder rights until the restricted phantom unit is settled with common units. Restricted phantom units

 

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represent an unfunded and unsecured obligation and prior to settlement in the form of common units a holder of a restricted phantom unit has no rights other than those of a general unsecured creditor.

To the extent provided by the plan administrator, in its discretion, distributions made by the Partnership with respect to restricted units will be subject to the same forfeiture and other restrictions as the restricted unit in which case such distributions will be held without interest until the restricted unit vests or is forfeited. In addition, the plan administrator may provide that such distributions be used to acquire additional restricted units for the Participant, which may be subject to such vesting and other terms as the plan administrator may prescribe. Absent such restrictions, distributions will be paid to the holder of restricted unit without restriction at the same time as cash distributions are paid by the Partnership to its unitholders.

Performance Awards. Performance awards entitle the recipient to vest in or acquire common units, or restricted phantom units that will be settled in the form of common units or cash upon the attainment of specified performance goals. The plan administrator may condition the right to exercise or receive an award under the equity incentive plan, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more specified performance goals. Performance awards may be granted independent of or in connection with the granting of any other award under the plan. Performance goals will be established by the plan administrator based on one or more business criteria that apply to the plan participant, a business unit or our company and our affiliates. Performance goals will be objective and generally will be determined prior to the time that 25% of the service period has elapsed but not later than 90 days after the beginning of the service period. No payout will be made on a performance award granted to a named executive officer unless all applicable performance goals and service requirements are achieved. Performance awards may not be sold, assigned, transferred, pledged or otherwise encumbered and terminate upon the termination of the participant’s service to us or our affiliates.

Unit Appreciation Rights. Unit appreciation rights may be granted independent of or in tandem with the granting of any unit option under the plan. Unit appreciation rights are granted pursuant to unit appreciation rights agreements. The exercise price of a unit appreciation right granted independent of an option is determined by the plan administrator, but as a general rule will be no less than 100% of the fair market value of a common unit on the date of grant. The exercise price of a unit appreciation right granted in tandem with a unit option is the same as the exercise price of the related unit option. Upon the exercise of a unit appreciation right, we will pay the participant an amount equal to the product of (i) the excess of the per unit fair market value of a common unit on the date of exercise over the strike price, multiplied by (ii) the number of common units with respect to which the unit appreciation right is exercised. Payment will be made in cash, delivery of units, or a combination of cash and units as deemed appropriate by the plan administrator.

Anti-Dilution Adjustments. In the event that there is an equity restructuring change in our common units without the receipt of consideration by us, such as pursuant to a merger, consolidation, reorganization, recapitalization, reincorporation, distribution in property other than cash, unit split, liquidating distribution, combination of units, exchange of units, change in entity structure or other transaction, appropriate adjustments will be made to the various limits under, and the unit terms of, the plan including (i) the number and class of units reserved under the plan, (ii) the maximum number of unit options and unit appreciation rights that can be granted to any one person in a calendar year and (iii) the number and class of units and exercise price, strike price, or purchase price, if applicable, of all outstanding unit awards.

Transactions. In the event of a change in control transaction (other than a transaction resulting in Wexford, Gulfport or an entity controlled by, or under common control with Wexford or Gulfport maintaining direct or indirect control over the Partnership), or a transaction such as a dissolution or liquidation of our company, or any separation or division, including, but not limited to, a split-up, a split-off or a spin-off, or a sale in one or a series of related transactions, of all or substantially all of the assets of our company or a merger, consolidation, or reverse merger in which we are not the surviving entity, then all outstanding unit awards under the plan may be assumed, continued or substituted for by any surviving or acquiring entity (or its parent company), or may be

 

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cancelled either with or without consideration for the vested portion of the awards, all as determined by the plan administrator. In the event an award would be cancelled without consideration paid to the extent vested, the award recipient may exercise the award in full or in part for a period specified by the plan administrator, which also may accelerate the vesting of such awards in its discretion.

Tax Withholding. At our discretion, and subject to conditions that the plan administrator may impose, a participant’s minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

Termination of Employment or Service. The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

401(k) Plan

Each of our entities has a 401(k) Plan. Under these plans, our employees may elect to defer a portion of their compensation up to the statutorily prescribed limit, and each pay period our entities make matching contributions to participating employees’ deferrals, with various matching percentages and vesting. These 401(k) Plans are intended to qualify under Section 401(a) of the Internal Revenue Code. As such, contributions to the 401(k) Plans and earnings on those contributions generally are not taxable to the employee until distributed from the 401(k) Plans, and all contributions are deductible by our entities when made.

Limitations on Liability and Indemnification of Officers and Directors

Limited Partnership Agreement

Our limited partnership agreement provides that we will, to the fullest extent permitted by Delaware law, indemnify our directors and officers against losses that they may incur in investigations and legal proceedings resulting from their service. See “Conflicts of Interest and Fiduciary Duties” and “The Partnership Agreement— Indemnification” for further discussion.

Indemnification Agreements

We will enter into indemnification agreements with each of our current directors and executive officers effective upon the closing of this offering. These agreements require us to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and executive officers.

Liability Insurance

We intend to provide liability insurance for our directors and officers, including coverage for public securities matters. There is no pending litigation or proceeding involving any of our directors, officers or employees for which indemnification from us is sought. We are not aware of any threatened litigation that may result in claims for indemnification from us.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Upon completion of this offering, assuming Wexford, Gulfport and their respective affiliates make no additional purchases of our common units, Wexford and Gulfport will beneficially own approximately         % and         %, respectively, of our common units (approximately         % and         %, respectively, if the underwriters’ over-allotment option is exercised in full) and Wexford will own a non-economic general partner interest in us that does not entitle it to receive distributions.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliates (including Wexford and Gulfport) in connection with the formation, ongoing operation and any liquidation of the Partnership.

Formation Stage

 

The consideration received by our general partner and its affiliates prior to or in connection with this offering

•

With respect to Wexford,              common units and $         million of the net proceeds of this offering as a selling unitholder of              common units ($         million for              common units if the underwriters exercise their over-allotment option in full);

 

•

With respect to Gulfport,              common units and $         million of the net proceeds of this offering as a selling unitholder of              common units ($         million for              common units if the underwriters exercise their over-allotment option in full); and

 

•

With respect to our general partner, a non-economic general partner interest.

Operational Stage

 

Payments to our general partner and its affiliates

We will reimburse our general partner and certain of its affiliates (including Wexford) for all expenses incurred on our behalf. At the closing of this offering, we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement.

 

Cash distributions to our general partner and its affiliates

We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner, pro rata.

 

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of the interest. Please see “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

 

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Liquidation Stage

 

Liquidation

Upon our liquidation, our unitholders will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements and Transactions with Affiliates in Connection with this Offering

In connection with this offering, we will enter into certain agreements and transactions with our general partner, Wexford, Gulfport and Rhino as described in more detail below.

Contribution Agreements

In connection with the closing of this offering, we will enter into contribution agreements with Gulfport, Rhino and Mammoth Holdings that will effect the Contribution Transactions. For more information regarding the Contribution Transactions see “Prospectus Summary - Our History and Contribution Transactions.”

Registration Rights and Investor Rights Agreements

Under our partnership agreement and the registration rights agreement that we will enter into with Mammoth Holdings prior to the closing of this offering, our general partner and its affiliates (including Wexford and Mammoth Holdings) will have certain demand and “piggyback” registration rights. Further, prior to the closing of this offering, we will enter into an investor rights agreement with Gulfport in which Gulfport will be granted (i) certain demand and “piggyback” registration rights, (ii) the right to designate one director of our general partner for so long as Gulfport owns 10% or more of our outstanding common units and (iii) certain information rights. Our registration rights agreement with Rhino will provide for “piggyback” registration rights. For more information regarding these rights, see “Management” and “Units Eligible for Future Sale—Registration Rights.”

Advisory Services Agreement

Prior to the closing of this offering we will enter into an advisory services agreement with Wexford under which Wexford will provide us with general financial and strategic advisory services related to our business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. This agreement has a term of two years commencing on the completion of this offering. The agreement will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. The agreement may be terminated at any time by either party upon 30 days’ prior written notice. In the event we terminate the agreement, we are obligated to pay all amounts due through the remaining term of the agreement. In addition, in this agreement we have agreed to pay Wexford to-be-negotiated market-based fees approved by our independent directors for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the advisory services agreement will not extend to our day-to-day business or operations. In this agreement, we have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. In the event we are dissatisfied with the services provided by Wexford, our only remedy against Wexford is to terminate the agreement.

Other Agreements with Affiliates

Effective September 9, 2013, Panther Drilling entered into a master service agreement with Diamondback E&P, whereby Panther provides directional drilling and other services to Diamondback E&P. This master service agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from work performed prior to the termination of the master service agreement.

 

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Furthermore, the master service agreement does not obligate Diamondback E&P to issue any order or accept any offers from Panther Drilling for its directional drilling or other services. In the third quarter 2013, Diamondback E&P began using Panther Drilling’s directional drilling services. For the six months ended June 30, 2014, Panther Drilling recognized $0.2 million from Diamondback E&P. Diamondback E&P owed Panther Drilling $0.01 million at June 30, 2014. For the year ended December 31, 2013, Diamondback E&P incurred $0.4 million for services performed by Panther Drilling. Diamondback E&P owed Panther Drilling $0.3 million as of December 31, 2013. Diamondback E&P is a wholly-owned subsidiary of Diamondback Energy, Inc., or Diamondback, in which Gulfport and affiliates of Wexford beneficially owned approximately 1.7% and 12.0%, respectively, of its outstanding common stock as of September 22, 2014.

On October 17, 2013, Bison Trucking entered into a master service contract with Diamondback E&P, pursuant to which Bison Trucking may, from time to time, provide services or sell or lease goods, equipment or facilities to Diamondback E&P in connection with its business activities. This agreement, which may be terminated at the option of either party on 30 days’ notice, does not obligate Diamondback E&P to issue any order or accept any offers from Bison Trucking for its services. Bison Trucking recognized $0.3 million from Diamondback E&P for services during the six months ended June 30, 2014. As of June 30, 2014, Diamondback E&P owed Bison Trucking $0.1 million. For the year ended December 31, 2013, Diamondback E&P incurred $0.05 million for services performed by Bison Trucking and, as of December 31, 2013, owed Bison Trucking $0.05 million for work performed under the master service contract.

On January 1, 2013, Bison Drilling entered into a master field services agreement with Diamondback E&P, pursuant to which Bison Drilling may, from time to time, provide services or sell or lease specified goods to Diamondback E&P in connection with its business activities. This agreement, which may be terminated at the option of either party upon 30 days’ notice, does not obligate Diamondback E&P to issue any order or accept any offers from Bison Drilling for its services. On February 21, 2013, this master field services agreement was amended to provide a revised rate schedule for services. Diamondback E&P incurred $0.6 million for services for the six months ended June 30, 2014 and as of June 30, 2014 owed Bison Drilling $0.1 million. For the year ended December 31, 2013 and 2012, Diamondback E&P incurred $4.1 million and $3.8 million, respectively, for services performed by Bison Drilling and, as of December 31, 2013 and 2012, owed Bison Drilling $0.2 million and $0.3 million, respectively, for work performed under the master field services contract.

On January 1, 2013, Bison Drilling entered into a master drilling agreement with Diamondback E&P, pursuant to which Bison Drilling may provide rigs to Diamondback E&P to be used in connection with Diamondback E&P’s exploration and development of its oil and natural gas properties. The master drilling agreement may be terminated at the option of either party on 30 days’ notice. If Diamondback E&P requires drilling services within the Permian Basin, then Diamondback E&P must order such services from Bison Drilling and Bison Drilling must provide such services. However, the master drilling agreement does not obligate Diamondback E&P to issue any order to Bison Drilling for drilling services and it does not obligate Bison Drilling to accept an order from Diamondback E&P for a rig if two of its rigs are then obligated to perform other drilling services and such drilling services have not been completed. For the six months ended June 30, 2014, Diamondback E&P incurred $2.3 million for services and, as of June 30, 2014, owed Bison Drilling $0.8 million. For the year ended December 31, 2013 and 2012, Diamondback E&P incurred $9.9 million and $13.1 million, respectively, for services performed by Bison Drilling and, as of December 31, 2013 and 2012, owed Bison Drilling $0.5 million and $2.0 million, respectively, for work performed under the master drilling agreement.

Pursuant to two separate limited loan guaranty agreements, each effective January 31, 2014, certain affiliates of Wexford agreed to guarantee up to $25.0 million of principal and interest under Bison Drilling’s loan and security agreement with International Bank of Commerce, dated May 31, 2013, as subsequently amended. Each of these guaranty agreements will automatically terminate and the obligations of each guarantor will be released at such time as the principal amount outstanding under Bison Drilling’s term loan, as amended, is $30.0 million or less.

We have provided remote accommodation and food services to Grizzly Oil Sands ULC, or Grizzly, an entity owned approximately 75% by affiliates of Wexford and approximately 25% by Gulfport, since 2008. Since

 

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June 25, 2012, these services have been provided to Grizzly pursuant to a written agreement with an initial term of one year. The agreement automatically renews for successive one-year terms unless terminated by either party by giving written notice of such termination to the other party at least 30 days prior to the expiration of the then-current term. We recognized $2.1 million for the six months ended June 30, 2014. As of June 30, 2014, Grizzly owed us approximately $1.2 million. For the years ended December 31, 2013 and 2012, we recognized revenue from Grizzly of approximately $12.8 million and $6.5 million, respectively, and as of December 31, 2013 and December 31, 2012, Grizzly owed us additional amounts of approximately $3.6 million and $1.0 million, respectively, for such services. Prior to June 2012, we provided these services to Grizzly without a written agreement.

On May 16, 2013, Muskie entered into a master services agreement with Diamondback E&P LLC, or Diamondback E&P, whereby Muskie Proppant sells custom natural sand proppant to Diamondback E&P. This agreement, which may be terminated at the option of either party on 30 days’ notice, does not obligate Diamondback E&P to issue any order or accept any offers from Muskie Proppant for sand proppant. Muskie Proppant did not recognize any revenue from Diamondback E&P for the six months ended June 30, 2014. Muskie Proppant recognized $0.7 million of revenue from sales of sand proppant to Diamondback E&P in 2013, and did not recognize any revenue from Diamondback E&P in 2012. Diamondback E&P did not owe Muskie Proppant any amounts as of December 31, 2013 or 2012.

In September 2014, effective October 1, 2014, Gulfport entered into a sand supply agreement with Muskie Proppant. Pursuant to this agreement, Muskie Proppant has agreed to sell and deliver, and Gulfport has agreed to purchase, specified annual and monthly amounts of proppant sand, subject to certain exceptions specified in the agreement, at a fixed price per ton, subject to certain adjustments, plus agreed costs and expenses. Failure by either Muskie Proppant or Gulfport to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. In addition, failure to pick up the sand on a timely basis from the designated facility will lead to demurrage charges payable by Gulfport. If Gulfport fails to make payments when due, or Muskie Proppant fails to deliver the required amounts of sand over three consecutive months, the other party can terminate the sand supply agreement. The sand supply agreement has a term ending on September 30, 2018 and includes, among others, confidentiality and non-solicitation provisions.

Panther Drilling performs directional drilling services for Gulfport pursuant to a master service agreement, dated February 22, 2013. The master service agreement may be terminated by Panther Drilling at any time prior to the receipt of notification by Gulfport to perform work pursuant to the agreement. Gulfport, however, may terminate the master service agreement at any time by giving written notice to Panther Drilling. The master service agreement does not obligate Gulfport to call upon Panther Drilling to perform any work under the master service agreement, and Panther Drilling is not obligated to accept any work requests from Gulfport. Furthermore, the designation of any work to be performed by Panther Drilling and the cessation of such work shall be at the sole discretion of Gulfport. For the six months ended June 30, 2014, Gulfport incurred $3.5 million for services performed by Panther Drilling and, as of June 30, 2014, owed Panther Drilling $1.6 million. For the year ended December 31, 2013 and 2012, Gulfport incurred $12.9 million and $0.1 million, respectively, for services performed by Panther Drilling and, as of December 31, 2013 and 2012, owed Panther Drilling $1.8 million and $0.1 million, respectively, for work performed under the master service contract.

Panther Drilling provides directional drilling services to an entity under common ownership. For the six months ended June 30, 2014, the Panther Drilling recognized $0.7 million of revenue from this entity. Receivables from related parties included $0.7 million at June 30, 2014. No revenue was earned from this entity in the prior year and there was no amount owed as of December 31, 2013.

Redback Energy Services performs completion and production services for Gulfport pursuant to a master service agreement dated June 11, 2012. The master service agreement may be terminated by Redback Energy Services at any time prior to the receipt of notification by Gulfport to perform work pursuant to the agreement.

 

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Gulfport, however, may terminate the master service agreement at any time by giving written notice to Redback Energy Services. The master service agreement does not obligate Gulfport to call upon Redback Energy Services to perform any work under the master service agreement, and Redback Energy Services is not obligated to accept any work requests from Gulfport. For the six months ended June 30, 2014 and the year ended December 31, 2013, Gulfport incurred $0.4 million and $0 million, respectively, for services performed by Redback Energy Services and, as of June 30, 2014 and December 31, 2013, owed Redback Energy Services $0.4 million and $0 million, respectively, for work performed under the master service agreement.

From time to time, we provide goods and services and pay for goods and services on behalf of certain affiliates of Wexford. As of June 30, 2014 these affiliates owed us $0.04 million. During the years ended December 31, 2013 and 2012, these affiliates incurred $0.02 million and $0.02 million, respective, for services performed. At December 31, 2013 and 2012, these Wexford affiliates owed us an aggregate of $0.07 million and $0.06 million, respectively.

On May 7, 2013, Muskie Proppant entered into a transloading agreement with Hopedale Mining LLC, or Hopedale, pursuant to which Hopedale will operate and maintain our Nelms No. 1 rail transloading facility located in Cadiz, Ohio and transload sand on a requirement basis. The agreement provides for a term of two years, subject to the option to terminate as described below. Under the agreement, Muskie Proppant is obligated to pay Hopedale a transloading fee in the amount of $4.00 per ton of sand. If Muskie Proppant fails to transload at least 7,500 tons of sand per month on average for a three-month period or pay an average of $30,000 for each month during such period (or such lesser amount as may be due in accordance with the agreement), Hopedale has the right to terminate the agreement. Muskie Proppant incurred $0.2 million in costs for the six months ended June 30, 2014 and, as of June 30, 2014, owed Hopedale $0.03 million. For the year ended December 31, 2013, Muskie Proppant incurred $0.3 million in costs to Hopedale and, as of December 31, 2013, owed Hopedale $0.03 million under this agreement. Hopedale is a wholly-owned subsidiary of Rhino Resource Partners LP, which is an affiliate of Wexford.

Redback Coil Tubing purchases coil tubing equipment from Serva Group, Ltd. and Serva Group LLC, which prior to their sale to an unrelated third party in May 2014 were affiliates of Wexford and are collectively referred to as Serva Group. Redback Coil Tubing also contracts for repairs and maintenance services from Serva Group. For the six months ended June 30, 2014, Redback Coil Tubing purchased $0.09 million of equipment from and incurred $0.2 million of repairs and maintenance cost payable to Serva Group. As of May 2014, this entity was sold and is no longer a related party to Serva Group. During the year ended December 31, 2013, Redback Coil Tubing purchased $1.7 million of equipment and incurred $0.2 million of repairs and maintenance cost from the Serva Group. During the year ended December 31, 2012, Redback Coil Tubing purchased $8.0 million of equipment. At December 31, 2013 and December 31, 2012, Redback Coil Tubing owed $1.3 million and $1.4 million, respectively to the Serva Group.

Panther Drilling rents rotary steerable equipment in connection with its directional drilling services from Double Barrel Downhole Technologies, an affiliate of Wexford. Costs incurred for the six months ended June 30, 2014 were $0.2 million. Costs incurred for the year ended December 31, 2013 were $1.4 million.

In July 2013, Muskie Proppant received loans in the aggregate principal amount of approximately $3.5 million from its members, which consisted of Gulfport and entities controlled by Wexford. Muskie Proppant makes monthly interest payments on these loans at the prime rate plus 2.5% (5.75% at December 31, 2013). The loans mature on July 31, 2015. The aggregate balances of these loans and accrued interest as of June 30, 2014 and December 31, 2013 were $3.7 million and $3.6 million, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Existing Credit Facilities” for additional information regarding these loans.

Pursuant to a limited loan guaranty agreement, dated July 3, 2013, certain affiliates of Wexford guaranteed the full and prompt payment of up to $15.0 million borrowed by Stingray Pressure Pumping under the Loan and

 

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Security Agreement, dated July 3, 2013, by and between Stingray Pressure Pumping and International Bank of Commerce. In September 2014, the amount guaranteed was reduced to $9.5 million as a result of Stingray Pressure Pumping reaching certain financial milestones.

Everest Operations Management LLC, or Everest, an affiliate of Wexford, has historically provided office space and certain technical, administrative and payroll services to us, and we have reimbursed Everest in amounts determined by it based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for us. The reimbursement amounts were determined based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by Everest, or specifically identified invoices processed, depending on the nature of the cost. For the six months ended June 30, 2014, we incurred $2.5 million in expenses and, as of June 30, 2014, owed $0.5 million under these arrangements. For the years ended December 31, 2013 and 2012, we incurred total costs under these arrangements of $25.3 million and $15.6 million, respectively, and, as of December 31, 2013 and December 31, 2012, owed $0.7 million and $0.7 million, respectively, under these arrangements. To the extent these services continue after the completion of this offering, we intend to enter into written services agreements on substantially the same terms as those described above.

SG Holdings I, LLC, or SG Holding, an affiliate of Wexford, has historically provided office space and certain technical, administrative and payroll services to us, and we have reimbursed SG Holding in amounts determined by it based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for us. The reimbursement amounts were determined based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by SG Holding, or specifically identified invoices processed depending on the nature of the cost. For the six months ended June 30, 2014, we incurred $0.3 million in expenses and, as of June 30, 2014, we owed $0.4 million under these arrangements. For the years ended December 31, 2013 and 2012, we incurred total costs under these arrangements of $0.7 million and $0.4 million, respectively, and, as of December 31, 2013 and December 31, 2012, owed $0.3 million and $0.3 million, respectively, under these arrangements. To the extent these services continue after the completion of this offering, we intend to enter into written services agreements on substantially the same terms as described above.

From time to time, we pay for goods and services on behalf of certain affiliates of Wexford, and certain of these affiliates pay for goods and services on our behalf. For the six months ended June 30, 2014, we incurred $0.03 million in costs related to these transactions. For years ended December 31, 2013 and 2012, we incurred $0.6 million and $0.4 million, respectively. As of June 30, 2014, these affiliates did not owe us any amounts and we owed them an aggregate of $0.5 million. At December 31, 2013 and 2012, these Wexford affiliates owed us an aggregate of $0.0 and $0.2 million, respectively, and we owed them an aggregate of $1.2 million and $1.1 million, respectively, under these arrangements.

Wexford provides certain administrative and analytical services to companies under common control. For the years ended December 31, 2013 and 2012, we incurred $0.3 million and $0.07 million, respectively. As of December 31, 2013 and 2012, we owed Wexford $0.03 million and $0.2 million, respectively.

The Stingray entities were formed in March 2012 and November 2012, respectively. Since their formation, the Stingray entities have provided Gulfport with hydraulic fracturing services and equipment rentals in the Utica Shale in Ohio. In December 2013, the Stingray entities entered into a master services agreement with Gulfport. Gulfport agreed to use Stingray Pressure Pumping’s services (or pay liquidated damages if it fails to do so), and Stingray was obligated to provide such services, for a specified number of well fracing stages each year in certain Ohio counties if Gulfport drills and/or completes wells in these counties. The agreement provided for a primary term expiring on November 15, 2015 in the case of hydraulic fracturing services and January 1, 2016 in the case of each service other than our hydraulic fracturing. The master services agreement could be terminated by Gulfport at any time by giving the applicable Stingray entity written notice. Additionally, Gulfport could, without liability, countermand any work order given to the applicable Stingray entity at any time before it begin such

 

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work. If the work had already begun such work, then Gulfport could still cancel the service at any time, being liable only for the value of the work performed prior to the cancellation. The applicable Stingray entity could terminate the master service agreement by giving Gulfport written notice prior to receiving a notification from Gulfport to perform a specific service. For the six months ended June 30, 2014, the Stingray entities recognized revenue of approximately $60.8 million and had receivables of $13.6 million as of June 30, 2014. For the year ended December 31, 2013 and the period from March 20, 2012 through December 31, 2012, all of the Stingray entities revenue recognized was provided to Gulfport. As of December 31, 2013 and December 31, 2012, Gulfport owed the Stingray entities $8.2 million and $5.3 million, respectively, for these services.

In September 2014, effective October 1, 2014, Gulfport entered into an amended and restated master services agreement for pressure pumping services with Stingray Pressure Pumping. Pursuant to this agreement, Stingray Pressure Pumping has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to Gulfport, dedicating two frac spreads and related equipment for the performance of these services. Gulfport has agreed to pay Stingray Pressure Pumping a monthly service fee plus the associated costs of the services provided. Gulfport and Stingray Pressure Pumping have each agreed to maintain insurance at certain minimum thresholds. This agreement has a term ending on September 30, 2018 and includes, among others, confidentiality and non-solicitation provisions. This agreement may be terminated in the event of a covenant breach by either party on 45 days written notice and a failure to cure. Stingray Pressure Pumping may also terminate in the event of payment default by Gulfport.

Since the formation of the Stingray entities, Gulfport has provided the Stingray entities with certain office space and IT, accounting, administrative and payroll services and employees and the Stingray entities have reimbursed Gulfport in an amount determined by Gulfport based on estimates of the amount of office space provided and the amount of its employees’ time spent performing services for the Stingray entities. The reimbursement amounts were determined based upon underlying salary costs of Gulfport employees performing Stingray entities related functions, payroll, revenue or headcount, or specific invoices processed, depending on the nature of the cost. For the six months ended June 30, 2014, the Stingray entities incurred total costs of approximately $0.0 million, and did not have a payable amount. For the year ended December 31, 2013 and the period from March 20, 2012 through December 31, 2012, the Stingray entities incurred total costs of $0.4 million and $1.8 million, respectively, under this arrangement. As of December 31, 2013 and December 31, 2012, the Stingray entities owed Gulfport $0.0 and $0.9 million, respectively, for these services.

The Company also rented certain equipment used in its hydraulic fracturing operations from Stingray Energy Services LLC. These amounts totaled $0.05 million for the six months ended June 30, 2014. As of June 30, 2014 and December 31, 2013, related party accounts payable included $0.1 million to this affiliate. The Company also pays certain other costs on behalf of the affiliate. At June 30, 2014 and December 31, 2013, related party accounts receivable included $2.4 million and $1.8 million, respectively.

The Company also provides certain management, administrative, and treasury functions to Stingray Cementing, LLC. The Company also pays certain other costs on behalf of the affiliate which are passed through to the affiliate. At June 30, 2014 and December 31, 2013, accounts receivable due from the affiliate were $0.8 million and $1.0 million, respectively. In November of 2012, certain equipment was purchased for the Company and paid for by this affiliate resulting in a $0.09 million payable to the affiliate at June 30, 2014 and December 31, 2013.

The Stingray entities also are parties to an agreement to purchase equipment from an affiliate of Wexford. For the year ended December 31, 2013 and the year ended December 31, 2012, the Stingray entities purchased equipment and/or made deposits for equipment not yet delivered in the aggregate amounts of $10.3 million and $0.0 million, respectively. The Stingray entities also contracted for repairs and maintenance services with an affiliate of Wexford and, for the year ended December 31, 2013 and for the period from March 20, 2012 (inception) through December 31, 2012, the cost of such services were $1.7 million and $0.2 million, respectively. As December 31, 2013 and 2012, the Stingray entities owed this affiliate $2.0 million and $0.2 million, respectively. For the six months ended June 30, 2014, purchases totaled $2.1 million and costs incurred for repairs and maintenance were $0.3 million.

 

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Procedures for Review, Approval and Ratification of Transactions with Related Persons

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Historically, the review and approval of related party transactions have been the responsibility of our management, and all of the transactions and agreements disclosed in this section have been approved by our management, subject to a conflicts of interest policy set forth in our employee handbook, pursuant to which all of our employees must avoid any situations where their personal outside interest could conflict, or even appear to conflict, with the interests of the Partnership. Although our management believes that the terms of the related party transactions described above are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties.

Please see “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace them with contractual standards. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning it must not act in a manner that it believes is adverse to our interests. This duty to act in good faith is the default standard set forth under our partnership agreement and our general partner will not be subject to any higher standard.

Our partnership agreement specifies decisions that our general partner may make in its individual capacity, and permits our general partner to make these decisions free of any contractual or other duty to us or our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

When the directors and officers of our general partner cause our general partner to manage and operate our business, the directors and officers must cause our general partner to act in a manner consistent with our general partner’s applicable duties. However, the directors and officers of our general partner have fiduciary duties to manage our general partner, including when it is acting in its capacity as our general partner, in a manner beneficial to Wexford or Gulfport.

Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. Where the directors and officers of our general partner are causing our general partner to act in its capacity as our general partner, the directors and officers must cause the general partner to act in good faith, meaning they cannot cause the general partner to take an action that they believe is adverse to our interests. However, where a decision by our general partner in its capacity as our general partner is not clearly not adverse to our interest, the directors of our general partner may determine to submit the determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, executive officers and owners (including Wexford) and other affiliates (including Gulfport), on the one hand, and us and our limited partners, on the other hand.

Whenever a conflict arises between our general partner or its owners, on the one hand, and us or our limited partners, on the other hand, the resolution, course of action or transaction in respect of such conflict of interest shall be conclusively deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action or transaction in respect of such conflict of interest is:

 

•

approved by the conflicts committee of our general partner; or

 

•

approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

 

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Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, all determinations, other actions or failures to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be presumed to be “in good faith,” and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Please see “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

•

amount and timing of asset purchases and sales;

 

•

cash expenditures;

 

•

borrowings;

 

•

entry into and repayment of current and future indebtedness;

 

•

issuance of additional units; and

 

•

the creation, reduction or increase of reserves.

Our partnership agreement permits us to borrow funds to make a distribution, and further provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.

The directors of our general partner who are also officers or directors of Wexford or Gulfport have a fiduciary duty to make decisions in the best interests of the owners of Wexford or Gulfport, which may be contrary to our interests.

Certain directors of our general partner are also officers or directors of Wexford or Gulfport. These officers and directors have fiduciary duties to Wexford or Gulfport that may cause them to pursue business strategies that disproportionately benefit Wexford or Gulfport or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as Wexford and Gulfport, in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general

 

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partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the Partnership or amendment of the partnership agreement.

Our partnership agreement restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that have the effect of restricting the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

 

•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it did not believe that the decision was adverse to our interests;

 

•

our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners for any losses sustained or liabilities incurred as a result of the general partner’s, officer’s or director’s determinations, acts or omissions in their capacities as general partner, officers or directors, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged by it in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

 

•

in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

Furthermore, if any person brings any claims, suits, actions or proceedings described in “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction” (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please see “—Fiduciary Duties” and “The Partnership Agreement.”

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

 

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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

 

•

expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

 

•

preparing and transmitting tax, regulatory and other filings, periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

•

acquiring, disposing, mortgaging, pledging, encumbering, hypothecating, or exchanging our assets or merging or otherwise combining us with or into another person;

 

•

negotiating, executing and performing contracts, conveyance or other instruments;

 

•

distributing cash;

 

•

selecting or dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

 

•

maintaining insurance for our benefit;

 

•

forming, acquiring an interest in, and contributing property and loaning money to, any further limited partnerships, joint ventures, corporations, limited liability companies or other entities;

 

•

controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

 

•

indemnifying any person against liabilities and contingencies to the extent permitted by law;

 

•

purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing additional options, rights, warrants, appreciation rights, phantom or tracking interests relating to our partnership interests; and

 

•

entering into agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please see “The Partnership Agreement” for information regarding the voting rights of unitholders.

Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.

We will reimburse our general partner and certain of its affiliates (including Wexford) for the costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine such other expenses that are allocable to us, and neither the partnership agreement nor the advisory services agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. Please see “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

Common units are subject to our general partner’s call right.

If at any time our general partner and its affiliates (including Wexford) beneficially own more than         % of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at the

 

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market price calculated in accordance with the terms of our partnership agreement. If our general partner and its affiliates (including Wexford) reduce their ownership to below 75% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please see “The Partnership Agreement—Limited Call Right.”

We may choose to not retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Wexford and Gulfport, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Wexford and Gulfport may compete with us for investment opportunities and may own an interest in entities that compete with us. Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Wexford and Gulfport. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us.

Duties of the General Partner

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate the fiduciary duties that might otherwise be owed by our general partner and replaces them with various contractual standards governing the duties of our general partner and any contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in

 

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addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The provisions enable our general partner to take into consideration all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests. The following is a summary of:

 

•

the default fiduciary duties imposed on general partners of limited partnerships by the Delaware Act in the absence of partnership agreement provisions to the contrary;

 

•

the contractual standards contained in our partnership agreement that replace the default fiduciary duties; and

 

•

certain rights and remedies of limited partners with respect to these contractual duties.

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

 

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it believed its actions or omissions were not adverse to our interests, and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held.

If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general partner or its affiliates, and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, its board, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of

 

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overcoming such presumption and proving that such decision was not in good faith. These standards replace the obligations to which our general partner would otherwise be held.

 

Rights and remedies of limited partners

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

Partnership agreement modified standards

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its reliance on the provisions of our partnership agreement.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct of our general partner or such officer or director engaged by it in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please see “The Partnership Agreement—Indemnification.”

 

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PRINCIPAL AND SELLING UNITHOLDERS

The following table sets forth certain information with respect to the beneficial ownership of our common units by:

 

•

the selling unitholders;

 

•

each unitholder known by us to be the beneficial owner of more than five percent of the outstanding common units;

 

•

each of our directors;

 

•

each of our named executive officers; and

 

•

all of our directors and executive officers as a group.

Except as otherwise indicated, we believe that each of the unitholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned.

 

Common Units Beneficially Owned Prior to Offering(1)

Common Units Beneficially Owned After Offering(1)

Common Units Beneficially Owned After Offering if the Underwriters’ Over- allotment Option Is Exercised in Full(1)

Name of Beneficial Owner

Number

Percentage

Number

Percentage

Number

Percentage

Selling Unitholders and other 5% Unitholders:

Mammoth Energy Holdings LLC(2)

Gulfport Energy Corporation

Rhino Resource Partners LP

Executive Officers and Directors:

Marc McCarthy

Phil Lancaster

Mark Layton

Spencer D. Armour, III*

Aaron Gaydosik*

Joseph M. Jacobs*

Kenneth A. Robin*

All executive officers and directors as a group (     persons)

 

*	Director nominee.

(1)

Percentage of beneficial ownership is based upon common units outstanding as of                     , 2014, and common units outstanding after the offering. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any common units which such person has the right to acquire within 60 days. For purposes of computing the percentage of outstanding common units held by each person or group of persons named above, any security that such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our unitholders may differ.

(2)

Wexford is the manager of Mammoth Energy Holdings LLC, which is one of the selling unitholders in this offering. The number of common units to be sold in the offering by Mammoth Energy Holdings LLC includes up to              common units that will be sold if the underwriters exercise their over-allotment option in full. As manager of Mammoth Energy Holdings LLC, Wexford has the exclusive authority to, among other things, purchase, hold and dispose of its assets, including the common units that will be owned by Mammoth Energy Holdings LLC. Wexford may, by reason of its status as manager of Mammoth Energy Holdings LLC, be deemed to beneficially own the interest in the common units owned by Mammoth Energy Holdings LLC. Each of Charles E. Davidson and Joseph M. Jacobs may, by reason of his status as a controlling person of Wexford, be deemed to beneficially own the interests in the common units owned by

 

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Mammoth Energy Holdings LLC. Each of Charles E. Davidson, Joseph M. Jacobs and Wexford share the power to vote and to dispose of the interests in the common units owned by Mammoth Energy Holdings LLC. Each of Messrs. Davidson and Jacobs disclaims beneficial ownership of the common units owned by Mammoth Energy Holdings LLC and Wexford. Wexford’s address is Wexford Plaza, 411 West Putnam Avenue, Greenwich, Connecticut 06830.

Each of the selling unitholders in this offering is deemed to be an underwriter within the meaning of Section 2(a)(11) of the Securities Act.

 

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DESCRIPTION OF OUR COMMON UNITS

Our Common Units

The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the relative rights and privileges of holders of our common units to partnership distributions, please see “How We Will Make Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please see “The Partnership Agreement.”

Transfer Agent and Registrar

                     will serve as registrar and transfer agent for our common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

 

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

•

special charges for services requested by a holder of a common unit; and

 

•

other similar fees or charges.

There is no charge to our unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 

•

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

•

gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

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Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Listing

We have applied for listing of our common units on The NASDAQ Global Market under the symbol “TUSK.”

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

•

with regard to the duties of our general partner, please see “Conflicts of Interest and Fiduciary Duties”;

 

•

with regard to the transfer of common units, please see “Description of Our Common Units—Transfer of Common Units”; and

 

•

with regard to allocations of taxable income and taxable loss, please see “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

We were originally formed in February 2014 in Delaware as a corporation and converted to a Delaware limited partnership in August 2014. We will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of providing oil field services, our general partner may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will generally allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders prior to such issuance on a pro rata basis, so that after such issuance, the capital account balances attributable to all common units are equal.

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the common units.

At the closing of this offering, Wexford and Gulfport will have the ability to ensure passage of, as well as the ability to ensure the defeat of, any amendment which requires a unit majority by virtue of their combined     % beneficial ownership of our common units.

 

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In voting their common units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. The holders of a majority of the common units (including common units deemed owned by our general partner) represented in person or by proxy shall constitute a quorum at a meeting of such common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.

The following is a summary of the vote requirements specified for certain matters under our partnership agreement.

 

Issuance of additional units

No approval right.

 

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please see “—Amendment of the Partnership Agreement.”

 

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. Please see “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. Please see “—Dissolution.”

 

Continuation of our business upon dissolution

Unit majority. Please see “—Dissolution.”

 

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2024 in a manner that would cause a dissolution of our partnership. Please see “—Withdrawal or Removal of Our General Partner.”

 

Removal of our general partner

Not less than 66 2/3 % of the outstanding common units, including common units held by our general partner and its affiliates. Please see “—Withdrawal or Removal of Our General Partner.”

 

Transfer of our general partner interest

No approval right. Please see “—Transfer of General Partner Interest.”

 

Transfer of ownership interests in our general partner

No approval right. Please see “—Transfer of Ownership Interests in the General Partner.”

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

 

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Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

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brought in a derivative manner on our behalf;

 

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asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

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asserting a claim arising pursuant to any provision of the Delaware Act; or

 

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asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims and irrevocably waives the right to trial by jury.

If any person brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

 

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to remove or replace our general partner;

 

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to approve some amendments to our partnership agreement; or

 

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to take other action under our partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

 

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Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is likely that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

 

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Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in a manner not adverse to us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

 

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enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

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enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, affiliates of our general partner will own approximately     % of our outstanding common units (approximately     % if the underwriters exercise their over-allotment option in full).

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

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a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

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a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

 

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

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an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

 

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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

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an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

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any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

 

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a change in our fiscal year or taxable year and related changes;

 

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conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

 

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do not adversely affect the limited partners (including any particular class of partnership interests as compared to other classes of partnership interests) in any material respect;

 

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

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are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

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are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

 

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Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

 

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the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

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the entry of a decree of judicial dissolution of our partnership; or

 

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

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the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

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neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as set forth in our partnership agreement. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2024 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2024, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please see “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please see “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3 % of the outstanding units, voting together as a single class, including common units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. The ownership of more than 33 1/3 % of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, affiliates of our general partner will own     % of our outstanding common units.

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

 

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If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in the General Partner

At any time, the owner of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Mammoth Energy Partners GP LLC as our general partner or from otherwise changing our management. Please see “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please see “—Meetings; Voting.”

Limited Call Right

If at any time our general partner and its affiliates (including Wexford) beneficially own more than         % of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. If our general partner and its affiliates (including Wexford) reduce their ownership to below 75% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. The purchase price in the event of this purchase is the greater of:

 

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the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

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the average of the daily closing prices of the Partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the

 

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market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please see “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Non-Taxpaying Holders; Redemption

To avoid any adverse effect on our ability to operate our assets or generate revenues from our assets, our partnership agreement provides our general partner the power to amend our partnership agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners (or their owners, to the extent relevant), has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

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obtain proof of the federal income tax status of our limited partners (and their owners, to the extent relevant); and

 

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permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of such person’s federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per common unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

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obtain proof of the nationality, citizenship or other related status of our limited partners (or their owners, to the extent relevant); and

 

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permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by the general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per common unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which

 

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a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please see “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

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our general partner;

 

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any departing general partner;

 

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any person who is or was an affiliate of our general partner or any departing general partner;

 

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any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

 

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any person who is or was serving as a manager, managing member, general partners, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or our subsidiaries;

 

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any person who controls our general partner or any departing general partner; and

 

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any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets

 

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to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner and certain of its affiliates for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

In connection with the closing of this offering, we and our general partner will enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement. Please see “Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions.”

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on its Electronic Data Gathering, Analysis and Retrieval system, or EDGAR, or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

 

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information regarding the status of our business and our financial condition (provided that this obligation shall be satisfied to the extent the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC pursuant to Section 13 of the Exchange Act;

 

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a current list of the name and last known address of each record holder;

 

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copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed; and

 

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such other information regarding our affairs as our general partner determines is just and reasonable.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units proposed to be sold by our general partner or its affiliates (including Wexford and Mammoth Holdings) or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

In addition, in connection with this offering, we will enter into a registration rights agreement with each of Mammoth Holdings and Rhino and an investor rights agreement with Gulfport. Pursuant to the agreements with Mammoth Holdings and Gulfport, we will be required to file registration statements to register the common units issued to affiliates of Wexford and Gulfport, as applicable, upon their demand and, if requested, to include their common units in registration statements that we file for ourself or others, which we refer to as “piggyback” registration rights. Our registration rights agreement with Rhino will provide for piggyback registration rights. These agreements also include provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of Wexford, Gulfport and Rhino and, in certain circumstances, to third parties. Please see “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common units. Upon completion of this offering, Wexford and Gulfport will beneficially own                  and                  common units, respectively, and                  and                  common units, respectively, if the underwriters exercise their over-allotment option in full. Future sales of these common units or substantial amounts of our common units in the public market, or the perception that such sales may occur, could adversely affect the prevailing market price of our common units. We cannot predict the effect, if any, that future sales of common units, or the availability of common units for future sales, will have on the market price of our common units prevailing from time to time.

Sale of Restricted Units

Upon completion of this offering, we will have              common units outstanding. Of these common units, the              common units being sold in this offering, plus any common units sold upon exercise of the underwriters’ over-allotment option, will be freely tradable without restriction under the Securities Act, except for any such common units held or acquired by an “affiliate” of ours, as that term is defined in Rule 144 promulgated under the Securities Act, which common units will be subject to the volume limitations and other restrictions of Rule 144 described below. The remaining              common units held by our existing unitholders upon completion of this offering, or              common units if the underwriters exercise their over-allotment option in full, will be “restricted securities,” as that phrase is defined in Rule 144, and may be resold only after registration under the Securities Act or pursuant to an exemption from such registration, including, among others, the exemptions provided by Rule 144 and 701 under the Securities Act, which rules are summarized below. These remaining common units held by our existing unitholders upon completion of this offering will be available for sale in the public market after the expiration of the lock-up agreements described in “Underwriting,” taking into account the provisions of Rules 144 and 701 under the Securities Act.

Rule 144

In general, under Rule 144 as currently in effect, persons who became the beneficial owner of common units prior to the completion of this offering may sell their common units upon the earlier of (1) the expiration of a six-month holding period, if we have been subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for at least 90 days prior to the date of the sale and have filed all reports required thereunder, or (2) the expiration of a one-year holding period.

At the expiration of the six-month holding period, assuming we have been subject to the Exchange Act reporting requirements for at least 90 days and have filed all reports required thereunder, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of common units, and a person who was one of our affiliates at any time during the three months preceding a sale would be entitled to sell, within any three-month period, a number of common units that does not exceed the greater of either of the following:

 

•

1% of the number of common units then outstanding, which will equal approximately              common units immediately after this offering; or

 

•

the average weekly trading volume of our common units on The NASDAQ Global Market during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

At the expiration of the one-year holding period, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of common units without restriction. A person who was one of our affiliates at any time during the three months preceding a sale would remain subject to the volume restrictions described above.

Sales under Rule 144 by our affiliates are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us.

 

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Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchased common units from us in connection with a compensatory or option plan or other written agreement before the effective date of this offering, or who purchased common units from us after that date upon the exercise of options granted before that date, are eligible to resell such common units in reliance upon Rule 144 beginning 90 days after the date of this prospectus. If such person is not an affiliate, the sale may be made subject only to the manner-of-sale restrictions of Rule 144. If such a person is an affiliate, the sale may be made under Rule 144 without compliance with its one-year minimum holding period, but subject to the other Rule 144 restrictions.

Issuance of Additional Partnership Interests

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type and at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Partnership Interests.”

Registration Rights

Under our partnership agreement and the registration rights agreement that we will enter into with Mammoth Holdings prior to the closing of this offering, our general partner and its affiliates (including Wexford and Mammoth Holdings) will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold, subject to certain exceptions. In addition, under the investor rights agreement that we will to enter into prior to the closing of this offering, Gulfport will have similar registration rights with respect to the units that it holds. Our registration rights agreement with Rhino will provide for piggyback registration rights.

Subject to the terms and conditions of the applicable agreements, these registration rights allow the beneficiaries or their assignees holding any units to require registration of any of these units and/or to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates (including Wexford and Mammoth Holdings), Gulfport and Rhino may sell their units in private transactions at any time, subject to compliance with applicable laws.

Equity Incentive Plan

We intend to file one or more registration statements on Form S-8 under the Securities Act to register common units issued or reserved for issuance under our equity incentive plan. The first such registration statement is expected to be filed soon after the date of this prospectus and will automatically become effective upon filing with the SEC. Accordingly, common units registered under such registration statement will be available for sale in the open market following the effective date, unless such common units are subject to vesting restrictions with us Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described below.

Lock-Up Agreements

We, each of our directors and executive officers, Mammoth Holdings, Gulfport and Rhino have agreed that, without the prior written consent of Credit Suisse Securities (USA) LLC, we and they will not, directly or indirectly, for a period of 180 days after the date of the offering, offer, pledge, sell, contract to sell or otherwise transfer or dispose of any common units (other than the common units subject to this offering) or any other securities convertible into or exercisable or exchangeable for common units (subject to certain exceptions). For additional information, see “Underwriting.”

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we” or “us” are references to Mammoth Energy Partners LP and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Akin Gump Strauss Hauer & Feld LLP and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Akin Gump Strauss Hauer & Feld LLP with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion with respect to the following federal income tax issues:

(1) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please see “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”);

(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please see “—Disposition of Units—Allocations Between Transferors and Transferees”); and

(3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please see “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder.

 

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Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the Partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the exploration, production and marketing of certain natural resources, including crude oil, natural gas and products thereof, as well as other types of income such as interest (other than from a financial business) and dividends. We estimate that less than       % of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Akin Gump Strauss Hauer & Feld LLP is of the opinion that we will be treated as a partnership and our partnership and limited liability company subsidiary will be disregarded as separate from us for federal income tax purposes.

The representations made by us and our general partner upon which Akin Gump Strauss Hauer & Feld LLP has relied in rendering its opinion include, without limitation:

(a) Neither we nor any of our partnership or limited liability company subsidiaries has elected to be treated as a corporation for federal income tax purposes; and

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Akin Gump Strauss Hauer & Feld LLP has opined is “qualifying income” within the meaning of Section 7704(d) of the Code.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Akin Gump Strauss Hauer & Feld LLP that we will be treated as a partnership for federal income tax purposes.

 

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Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the Partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please see “—Tax Consequences of Unit Ownership—Treatment of Securities Loans.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under their particular circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units increased by the unitholder’s initial allocable share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, and any decreases in the unitholder’s share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2017, will be allocated, on a cumulative basis, an amount of federal taxable income that will be approximately         % of the cash expected to be distributed on those units with respect to that period. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the anticipated quarterly distributions on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

•

we distribute less cash than we have assumed in making this projection;

 

•

we make a future offering of units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes during such period or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

 

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Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “liabilities” will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss) generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please see “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation and depletion recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased.

Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income

 

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generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

•

interest on indebtedness allocable to property held for investment;

 

•

interest expense allocated against portfolio income; and

 

•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction

Our items of income, gain, loss and deduction generally will be allocated amongst our unitholders in accordance with their percentage interests in us.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic

 

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effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Akin Gump Strauss Hauer & Feld LLP is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please see “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax (“NIIT”) applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

 

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Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Akin Gump Strauss Hauer & Feld LLP has not opined on the validity of this approach. Please see “—Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please see “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please see “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions, if any, and, ultimately, gain or loss on the disposition of those assets. If we dispose of depreciable or depletable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please see “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

 

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The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses. Please see “Disposition of Units—Recognition of Gain or Loss.”

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our liabilities with respect to the units sold. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale. Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation or depletion recapture and our “inventory items,” regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the Partnership as the value of the interest sold bears to the value of the partner’s entire interest in the Partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of the units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for

 

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all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

 

•

a short sale;

 

•

an offsetting notional principal contract; or

 

•

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined quarterly, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. The Department of the Treasury has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Akin Gump Strauss Hauer & Feld LLP is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and

 

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to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please see “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Akin Gump Strauss Hauer & Feld LLP is unable to opine as to the validity of such filing positions.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please see “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S.

 

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person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the Partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, less than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future.

Recent changes in law may affect certain foreign unitholders. Please read “—Administrative Matters—FATCA Withholding Requirements.”

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

 

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The IRS may audit our federal income tax information returns. Neither we nor Akin Gump Strauss Hauer & Feld LLP can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns.

The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(c) a tax-exempt entity;

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

 

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Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy related penalties will be assessed against us.

FATCA Withholding Requirements

Under the Foreign Account Tax Compliance Act (“FATCA”), a withholding agent may be required to withhold 30% of any interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”) or gross proceeds from the sale of any property of a type which can produce interest or dividends from sources within the United States paid to (i) a foreign financial institution (which includes foreign broker-dealers, clearing organizations, investment companies, hedge funds and certain other investment entities) unless such foreign financial institution agrees to verify, report and disclose its U.S. account holders and meets certain other specified requirements or (ii) a non-financial foreign entity that is a beneficial owner of the payment unless such entity certifies that it does not have any substantial U.S. owners or provides the name, address and taxpayer identification number of each substantial U.S. owner and such entity meets certain other specified requirements or otherwise qualifies for an exemption from this withholding.

The withholding provisions described above are scheduled to apply to payments of FDAP Income made on or after July 1, 2014 and to payments of relevant gross proceeds made on or after January 1, 2017. Each prospective unitholder should consult its own tax advisor regarding these withholding provisions.

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in those jurisdictions. We will initially own assets and conduct business in Ohio, Oklahoma, Wisconsin, Minnesota, Pennsylvania and Texas. Many of these states impose a personal income tax. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

 

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INVESTMENT IN MAMMOTH ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because these plans, and persons with discretionary control over their assets, are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), restrictions imposed by Section 4975 of the Internal Revenue Code, or provisions under other federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) and entities whose underlying assets are considered to include “plan assets” of such plans, accounts or arrangements. Among other things, consideration should be given to:

 

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whether the investment is prudent under Section 404(a)(1)(B) of ERISA or any other applicable Similar Laws;

 

•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA or any other applicable Similar Laws; and

 

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please see “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a “fiduciary,” should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans from engaging in certain specified transactions involving plan assets with parties that are “parties in interest” under ERISA or “disqualified persons” under Section 4975 of the Internal Revenue Code with respect to the plan, unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. The fiduciary of the plan that engaged in the prohibited transaction also may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

The acquisition or holding of our securities by a plan with respect to which either we, our general partner, selling unitholders or any of their respective affiliates is considered a party in interest or a disqualified person may be or result in a direct or indirect prohibited transaction under Section 406 of ERISA or Section 4975 of the Internal Revenue Code unless the investment is acquired and is held under an applicable statutory, class or individual prohibited transaction exemption. In this regard, the U.S. Department of Labor has issued prohibited transaction class exemptions, or “PTCEs,” that may apply to the acquisition and holding of our securities. These class exemptions include, without limitation, PTCE 84-14 respecting transactions determined by independent qualified professional asset managers, PTCE 90-1 respecting insurance company pooled separate accounts, PTCE 91-38 respecting bank collective investment funds, PTCE 95-60 respecting life insurance company general accounts and PTCE 96-23 respecting transactions determined by in-house asset managers. However, there can be no assurance that all of the conditions of any of these exemptions will be satisfied.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code and any other applicable Similar Laws.

 

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Department of Labor regulations, as modified by Section 3(42) of ERISA (commonly referred to as the “plan asset regulations”), provide guidance with respect to whether the assets of an entity, including the Partnership, in which employee benefit plans or other entities whose underlying assets include plan assets by reason of employee benefit plan investments in that entity (each, a “benefit plan investor”) acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

•

the equity interests acquired by benefit plan investors are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under certain provisions of federal securities laws;

 

•

the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

 

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there is no “significant investment” by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the benefit plan investors.

It is not anticipated that our assets will be considered plan assets because we are primarily engaged in business activities that we believe qualify us as an “operating company” under the plan asset regulations (although no assurance can be given in this regard). In addition, our common units are “publicly-offered securities” for purposes of the plan asset regulations, so that even significant investment by benefit plan investors in our common units would not result in our assets being treated as plan assets under ERISA. Finally, investment in each class of our securities by benefit plan investors might not be “significant” for purposes of the plan assets regulations, although it is unlikely that we will be in a position to monitor the level of investment in any class of our securities by benefit plan investors.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and any other applicable Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations. Each person investing in our common units will be deemed to represent that its acquisition, holding and disposition of the common units will not constitute a non-exempt prohibited transaction under ERISA or Section 4975 of the Internal Revenue Code.

 

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement with respect to the common units being offered, we and the selling unitholders have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC is acting as representative, the following respective numbers of common units:

 

Underwriter		Number of Common Units
Credit Suisse Securities (USA) LLC
Total

The underwriting agreement provides that the underwriters are obligated to purchase all of the common units in the offering if any are purchased, other than those common units covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated. Each of the selling unitholders in this offering is deemed to be an underwriter within the meaning of Section 2(a)(11) of the Securities Act.

We and the selling unitholders have granted to the underwriters a 30-day option to purchase up to an aggregate of                  additional common units at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common units. To the extent that the underwriters exercise this over-allotment option, each underwriter will purchase additional common units from us and the selling unitholders in approximately the same proportion as they purchased the common units shown in the table above.

The underwriters propose to offer the common units initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $             per common unit. The underwriters and selling group members may allow a discount of $             per common unit on sales to other broker/dealers. After the initial public offering the representatives may change the public offering price and concession and discount to broker/dealers. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The following table summarizes the compensation and estimated expenses we will pay:

 

Per Common Unit

Total

Without Over- allotment

With Over- allotment

Without Over- allotment

With Over- allotment

Public offering price for common units sold by us

$

$

$

$

Underwriting Discounts and Commissions paid by us

$

$

$

$

Expenses payable by us

$

$

$

$

Public offering price for common units sold by the selling unitholders

$

$

$

$

Underwriting Discounts and Commissions paid by the selling unitholders

$

$

$

$

Expenses payable by the selling unitholders

$

$

$

$

We estimate that our out-of-pocket expenses for this offering, excluding underwriting discounts and commissions, will be approximately $             million. The selling unitholders will not bear any portion of these expenses.

The representative has informed us that it does not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the common units being offered.

 

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We have agreed that, subject to certain exceptions, we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act relating to any of our common units or securities convertible into or exchangeable or exercisable for any of our common units, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus.

Mammoth Holdings, Gulfport and Rhino, which are the selling unitholders in this offering, as well as the executive officers and directors of our general partner, have each agreed that, subject to certain exceptions, they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any of our common units or securities convertible into or exchangeable or exercisable for any of our common units, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common units, whether any of these transactions are to be settled by delivery of our common units or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus. Credit Suisse Securities (USA) LLC, in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release the common units and other securities from lock-up agreements, Credit Suisse Securities (USA) LLC will consider, among other factors, the holder’s reasons for requesting the release and the number of common units or other securities for which the release is being requested.

The underwriters have reserved for sale at the initial public offering price up to         % of the common units being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing common units in the offering. The number of common units available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved common units. Any reserved common units not so purchased will be offered by the underwriters to the general public on the same terms as the other common units. Any common units sold in the directed unit program to directors and executive officers will be subject to the 180-day lock-up agreements described above.

We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

We have applied to list our common units on The NASDAQ Global Market under the symbol “TUSK.”

In connection with the listing of our common units on The NASDAQ Global Market, the underwriters will undertake to sell round lots of 100 common units or more to a minimum of 400 beneficial owners.

Prior to this offering, there has been no public market for our common units. The initial public offering price for our common units will be determined by negotiation between us and the underwriters. The principal factors to be considered in determining the initial public offering price include the following:

 

•

the general condition of the securities markets;

 

•

market conditions for initial public offerings;

 

•

the market for securities of companies in businesses similar to ours;

 

•

the history and prospects for the industry in which we compete;

 

•

our past and present operations and earnings and our current financial position;

 

•

the history and prospects for our business;

 

•

an assessment of our management; and

 

•

other information included in this prospectus and otherwise available to the underwriters.

 

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We cannot assure you that the initial public offering price will correspond to the price at which our common units will trade in the public market subsequent to this offering or that an active trading market will develop and continue after this offering.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have from time to time performed, and may in the future perform, various financial advisory, commercial banking and investment banking services for us and for our affiliates in the ordinary course of business for which they have received and would receive customary compensation.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investments and securities activities may involve securities and/or instruments of the issuer. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

 

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

•

Over-allotment involves sales by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of common units over-allotted by the underwriters is not greater than the number of common units that they may purchase in the over-allotment option. In a naked short position, the number of common units involved is greater than the number of common units in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing common units in the open market.

 

•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

 

•

Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of our common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Market or otherwise and, if commenced, may be discontinued at any time.

 

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A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representative may agree to allocate a number of common units to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

FINRA Conduct Rules

Because FINRA is expected to view the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each such state being referred to herein as a Relevant Member State), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (each such date being referred to herein as a Relevant Implementation Date) it has not made and will not make an offer of common units to the public in that Relevant Member State prior to the publication of a prospectus in relation to the common units which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of common units to the public in that Relevant Member State at any time:

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year, (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

(d) in any other circumstances that do not require the publication by the Partnership of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of common units to the public” in relation to any common units in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the common units to be offered so as to enable an investor to decide to purchase or subscribe the common units, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

United Kingdom

Each underwriter has represented and agreed that:

(a) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000, or the FSMA) received by it in connection with the issue or sale of the common units in circumstances in which Section 21(1) of the FSMA does not apply to the Partnership; and

 

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(b) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the common units in, from or otherwise involving the United Kingdom.

Hong Kong

The common units may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder or (iii) in other circumstances that do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), and no advertisement, invitation or document relating to the common units may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the common units may not be circulated or distributed, nor may the common units be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the common units are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the common units under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan, or the Financial Instruments and Exchange Law, and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

 

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LEGAL MATTERS

The validity of the common units that are offered hereby by us and the selling unitholders will be passed upon by Akin Gump Strauss Hauer  & Feld LLP. Certain legal matters will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The audited combined financial statements of Redback Energy Services as of December 31, 2013 and 2012 and for the years then ended included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited combined financial statements of Stingray Pressure Pumping LLC and Affiliate as of December 31, 2013 and 2012 and for the year ended December 31, 2013 and the period from March 20, 2012 (inception) to December 31, 2012 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The financial statements of Mammoth Energy Partners LP as of June 30, 2014 and for the period from February 5, 2014 (inception) to June 30, 2014 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses of certain drilling rigs of Lantern Drilling Company acquired by Bison Drilling and Field Services, LLC for the years ended December 31, 2013 and 2012, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act covering the securities offered by this prospectus. This prospectus, which constitutes a part of that registration statement, does not contain all of the information that you can find in that registration statement and its exhibits. Certain items are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information about us and the common units offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance such statement is qualified by reference to each such contract or document filed as part of the registration statement. When we complete this offering, we will be required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read any materials we file with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

 

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Appendix A

 

 

 

 

FORM OF

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

MAMMOTH ENERGY PARTNERS LP

 

 

 

 

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TABLE OF CONTENTS

 

				Page
ARTICLE I
DEFINITIONS
Section 1.1		Definitions			A-1
Section 1.2		Construction			A-10
ARTICLE II
ORGANIZATION
Section 2.1		Formation			A-11
Section 2.2		Name			A-11
Section 2.3		Registered Office; Registered Agent; Principal Office; Other Offices			A-11
Section 2.4		Purpose and Business			A-11
Section 2.5		Powers			A-11
Section 2.6		Term			A-12
Section 2.7		Title to Partnership Assets			A-12
ARTICLE III
RIGHTS OF LIMITED PARTNERS
Section 3.1		Limitation of Liability			A-12
Section 3.2		Management of Business			A-12
Section 3.3		Outside Activities of the Limited Partners			A-12
Section 3.4		Rights of Limited Partners			A-13
ARTICLE IV
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
Section 4.1		Certificates			A-13
Section 4.2		Mutilated, Destroyed, Lost or Stolen Certificates			A-14
Section 4.3		Record Holders			A-14
Section 4.4		Transfer Generally			A-15
Section 4.5		Registration and Transfer of Limited Partner Interests			A-15
Section 4.6		Transfer of the General Partner Interest			A-16
Section 4.7		Restrictions on Transfers			A-16
Section 4.8		Eligibility Certificates; Ineligible Holders			A-16
Section 4.9		Redemption of Partnership Interests of Ineligible Holders			A-17
ARTICLE V
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
Section 5.1		Contributions by the General Partner and its Affiliates			A-18
Section 5.2		Contributions by Initial Limited Partners			A-19

 

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				Page
Section 5.3		Interest and Withdrawal			A-19
Section 5.4		Capital Accounts			A-19
Section 5.5		Issuances of Additional Partnership Interests and Derivative Instruments			A-21
Section 5.6		Preemptive Right			A-22
Section 5.7		Splits and Combinations			A-22
Section 5.8		Fully Paid and Non-Assessable Nature of Limited Partner Interests			A-22
Section 5.9		Deemed Capital Contributions by Partners			A-23
ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS
Section 6.1		Allocations for Capital Account Purposes			A-23
Section 6.2		Allocations for Tax Purposes			A-25
Section 6.3		Distributions to Record Holders			A-27
ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS
Section 7.1		Management			A-27
Section 7.2		Replacement of Fiduciary Duties			A-29
Section 7.3		Certificate of Limited Partnership			A-29
Section 7.4		Restrictions on the General Partner’s Authority			A-29
Section 7.5		Reimbursement of the General Partner			A-30
Section 7.6		Outside Activities			A-30
Section 7.7		Indemnification			A-31
Section 7.8		Limitation of Liability of Indemnitees			A-32
Section 7.9		Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties			A-33
Section 7.10		Other Matters Concerning the General Partner			A-35
Section 7.11		Purchase or Sale of Partnership Interests			A-35
Section 7.12		Registration Rights of the General Partner and its Affiliates			A-36
Section 7.13		Reliance by Third Parties			A-37
ARTICLE VIII
BOOKS, RECORDS, ACCOUNTING AND REPORTS
Section 8.1		Records and Accounting			A-38
Section 8.2		Fiscal Year			A-38
Section 8.3		Reports			A-38
ARTICLE IX
TAX MATTERS
Section 9.1		Tax Returns and Information			A-39
Section 9.2		Tax Elections			A-39
Section 9.3		Tax Controversies			A-39
Section 9.4		Withholding			A-39

 

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				Page
ARTICLE X
ADMISSION OF PARTNERS
Section 10.1		Admission of Limited Partners			A-40
Section 10.2		Admission of Successor General Partner			A-40
Section 10.3		Amendment of Agreement and Certificate of Limited Partnership			A-40
ARTICLE XI
WITHDRAWAL OR REMOVAL OF PARTNERS
Section 11.1		Withdrawal of the General Partner			A-41
Section 11.2		Removal of the General Partner			A-42
Section 11.3		Interest of Departing General Partner and Successor General Partner			A-42
Section 11.4		Withdrawal of Limited Partners			A-43
ARTICLE XII
DISSOLUTION AND LIQUIDATION
Section 12.1		Dissolution			A-43
Section 12.2		Continuation of the Business of the Partnership After Dissolution			A-44
Section 12.3		Liquidator			A-44
Section 12.4		Liquidation			A-45
Section 12.5		Cancellation of Certificate of Limited Partnership			A-45
Section 12.6		Return of Contributions			A-45
Section 12.7		Waiver of Partition			A-45
Section 12.8		Capital Account Restoration			A-45
ARTICLE XIII
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
Section 13.1		Amendments to be Adopted Solely by the General Partner			A-46
Section 13.2		Amendment Procedures			A-47
Section 13.3		Amendment Requirements			A-47
Section 13.4		Special Meetings			A-48
Section 13.5		Notice of a Meeting			A-48
Section 13.6		Record Date			A-48
Section 13.7		Adjournment			A-48
Section 13.8		Waiver of Notice; Approval of Meeting; Approval of Minutes			A-49
Section 13.9		Quorum and Voting			A-49
Section 13.10		Conduct of a Meeting			A-49
Section 13.11		Action Without a Meeting			A-49
Section 13.12		Right to Vote and Related Matters			A-50

 

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				Page
ARTICLE XIV
MERGER
Section 14.1		Authority			A-50
Section 14.2		Procedure for Merger or Consolidation			A-50
Section 14.3		Approval by Partners of Merger or Consolidation			A-51
Section 14.4		Certificate of Merger			A-52
Section 14.5		Amendment of Partnership Agreement			A-52
Section 14.6		Effect of Merger or Consolidation			A-52
ARTICLE XV
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
Section 15.1		Right to Acquire Limited Partner Interests			A-53
ARTICLE XVI
GENERAL PROVISIONS
Section 16.1		Addresses and Notices; Written Communications			A-54
Section 16.2		Further Action			A-54
Section 16.3		Binding Effect			A-55
Section 16.4		Integration			A-55
Section 16.5		Creditors			A-55
Section 16.6		Waiver			A-55
Section 16.7		Counterparts			A-55
Section 16.8		Applicable Law; Forum, Venue and Jurisdiction; Waiver of Trial by Jury; Attorney Fees			A-55
Section 16.9		Invalidity of Provisions			A-56
Section 16.10		Consent of Partners			A-56
Section 16.11		Facsimile Signatures			A-56
Section 16.12		Third Party Beneficiaries			A-56

 

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Appendix A

FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED

PARTNERSHIP OF MAMMOTH ENERGY PARTNERS LP

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF MAMMOTH ENERGY PARTNERS LP, dated as of                     , 2014, is entered into by and among Mammoth Energy Partners GP LLC, a Delaware limited liability company, as the General Partner, and Mammoth Energy Holdings LLC, a Delaware limited liability company, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Adjusted Capital Account” means, with respect to any Partner, the balance in such Partner’s Capital Account at the end of each taxable period of the Partnership, after giving effect to the following adjustments:

(a) Credit to such Capital Account any amounts which such Partner is (x) obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) or (y) deemed obligated to restore pursuant to the penultimate sentences of Treasury Regulation Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

(b) Debit to such Capital Account the items described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5) and 1.704-1(b)(2)(ii)(d)(6).

The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Sections 5.4(d)(i) or 5.4(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries Controls, is Controlled by or is under common Control with, the Person in question.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of (a) a Contributed Property means the fair market value of such property at the time of contribution and (b) an Adjusted Property means the fair market value of such Adjusted Property on the date of the Revaluation Event as described in Section 5.4(d), in each case as determined by the General Partner.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of Mammoth Energy Partners LP, as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

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“Bad Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such Person, board or committee reached such determination, or engaged in or failed to engage in such act or omission, with the belief that such determination, action or omission was adverse to the interest of the Partnership.

“Board of Directors” means the board of directors of the General Partner.

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for U.S. federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with U.S. federal income tax accounting principles.

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.4. The “Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Capital Account Difference” has the meaning assigned to such term in Section 6.1(b)(xii).

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions).

“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property, and (b) with respect to any other Partnership property, the adjusted basis of such property for U.S. federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable to the Partnership or any Limited Partner for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means a certificate in such form (including global form if permitted by applicable rules and regulations) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.3, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“claim” (as used in Section 7.12(c)) has the meaning assigned to such term in Section 7.12(c).

“Closing Date” means the first date on which Common Units are issued and delivered by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

 

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“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

“Code” means the U.S. Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” has the meaning assigned to such term in Section 11.3(a).

“Commission” means the United States Securities and Exchange Commission.

“Common Unit” means a Unit representing, when outstanding, a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement.

“Conflicts Committee” means a committee of the Board of Directors composed entirely of one or more directors, each of whom is determined by the Board of Directors, after reasonable inquiry, (a) to not be an officer or employee of the General Partner (b) to not be an officer or employee of any Affiliate of the General Partner or a director of any Affiliate of the General Partner (other than any Group Member), (c) to not be a holder of any ownership interest in the General Partner or any of its Affiliates, including any Group Member, that would be likely to have an adverse impact on the ability of such director to act in an independent manner with respect to the matter submitted to the Conflicts Committee, other than Common Units and awards that are granted to such director under the Equity Incentive Plan, and (d) to be independent under the independence standards for directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which any class of Partnership Interests is listed or admitted to trading.

“Contribution Date” means the date on which the transactions contemplated by the Wexford Contribution Agreement, the Gulfport Contribution Agreement and the Rhino Contribution Agreement are consummated.

“Contributed Property” means each property, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Control” or “control” (including the terms “controlled” and “controlling”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Conversion” means the conversion of the Predecessor into the Partnership pursuant to the Delaware Act on August 8, 2014.

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(b)(xi).

 

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“Current Market Price” means, in respect of any class of Partnership Interests, as of the date of determination, the average of the daily Closing Prices per Partnership Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

“Derivative Instruments” means options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative instruments (other than equity interests in the Partnership) relating to, convertible into or exchangeable for Partnership Interests.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“EDGAR” means the Commission’s Electronic Data Gathering, Analysis and Retrieval system and any successor to such system.

“Eligibility Certificate” has the meaning assigned to such term in Section 4.8(b).

“Eligibility Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Holder.

“Eligible Holder” means a Person that satisfies the eligibility requirements established by the General Partner for Partners pursuant to Section 4.8.

“Equity Incentive Plan” means the Mammoth Energy Partners LP Equity Incentive Plan, as it may be amended, restated or modified from time to time, or any equity compensation plan successor thereto.

“Event Issue Value” means, with respect to any Common Unit as of any date of determination, (i) in the case of a Revaluation Event that includes the issuance of Common Units pursuant to a public offering and solely for cash, the price paid for such Common Units, or (ii) in the case of any other Revaluation Event, the Closing Price of the Common Units on the date of such Revaluation Event or, if the General Partner determines that a value for the Common Unit other than such Closing Price more accurately reflects the Event Issue Value, the value determined by the General Partner.

“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“General Partner” means Mammoth Energy Partners GP LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as the general partner of the Partnership, in their capacity as the general partner of the Partnership.

“General Partner Interest” means the non-economic management interest of the General Partner in the Partnership (in its capacity as general partner and without reference to any Limited Partner Interest held by it), which includes any and all rights, powers and benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement. The General Partner Interest does not include any rights to profits or losses or any rights to receive distributions from operations or upon the liquidation or winding-up of the Partnership.

“Good Faith” means, with respect to any determination, action or omission, of any Person, board or committee, that such determination, action or omission was not taken in Bad Faith.

 

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“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction.

“Group” means two or more Persons that with or through any of their respective Affiliates or Associates have any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Gulfport” means Gulfport Energy Corporation, a Delaware corporation.

“Gulfport Contribution Agreement” means that certain Contribution Agreement, dated as of                     , 2014, by and between Gulfport and the Partnership, together with the additional conveyance documents and instruments contemplated or referenced thereunder.

“Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

“Indemnified Persons” has the meaning assigned to such term in Section 7.12(c).

“Indemnitee” means (a) any General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of any Group Member, a General Partner, any Departing General Partner or any of their respective Affiliates, (e) any Person who is or was serving at the request of a General Partner, any Departing General Partner or any of their respective Affiliates as an officer, director, manager, managing member, general partner, employee, agent, fiduciary or trustee of another Person owing a fiduciary or similar duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement because such Person’s service, status or relationship exposes such Person to potential claims, demands, actions, suits or proceedings relating to the Partnership Group’s business and affairs.

“Ineligible Holder” has the meaning assigned to such term in Section 4.8(c).

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement, including any offer and sale of Common Units pursuant to an exercise of the Over-Allotment Option.

“Investor Rights Agreement” means that certain Investor Rights Agreement, dated as of                     , 2014, by and among the Partnership, the General Partner, Mammoth Energy Holdings and Gulfport.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

 

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“Limited Partner” means, unless the context otherwise requires, the Organizational Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case in such Person’s capacity as a limited partner of the Partnership.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units or other Partnership Interests or a combination thereof or interest therein (but excluding Derivative Instruments), and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner hereunder.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the Partners have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Mammoth Energy Holdings” means Mammoth Energy Holdings LLC, a Delaware limited liability company.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the Commission under Section 6(a) of the Securities Exchange Act (or successor to such Section)) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution.

“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain for such taxable period over the Partnership’s items of loss and deduction for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall not include any items specially allocated under Section 6.1(b).

“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction for such taxable period over the Partnership’s items of income and gain for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall not include any items specially allocated under Section 6.1(b).

“Noncompensatory Option” has the meaning set forth in Treasury Regulation Section 1.721-2(f).

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

 

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“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means Mammoth Energy Holdings, in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Other Entity” has the meaning assigned to such term in Section 14.1.

“Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Partnership Interests of any class, none of the Partnership Interests owned by such Person or Group shall be entitled to be voted on any matter or be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Partnership Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Partnership Interests of any class directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Partnership Interests of any class directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning given to such term in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning given to such term in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), that, in accordance with the principles of Treasury Regulation Section 1.704-2(i)(1), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Mammoth Energy Partners LP, a Delaware limited partnership.

 

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“Partnership Group” means the Partnership and its Subsidiaries.

“Partnership Interest” means any class or series of equity interest (or, in the case of the General Partner, management interest) in the Partnership, which shall include any General Partner Interest and Limited Partner Interests but shall exclude Derivative Instruments.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

“Percentage Interest” means as of any date of determination, as to any Unitholder with respect to Units, the quotient obtained by dividing (i) the number of Units held by such Unitholder by (ii) the total number of Outstanding Units. The Percentage Interest with respect to the General Partner Interest shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Predecessor” means Stingray Energy Services, Inc., a Delaware corporation originally incorporated on February 4, 2014 as “Redback Inc.”

“Privately Placed Units” means any Common Units issued for cash or property other than pursuant to a public offering.

“Pro Rata” means when used with respect to (a) Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) all Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests, and (c) some but not all Partners or Record Holders, apportioned among such Partners or Record Holders in accordance with their relative Percentage Interests.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership in which the Closing Date occurs, the portion of such fiscal quarter after the Closing Date.

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) with respect to Partnership Interests of any class for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

 

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“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

“Registration Rights Agreement” means that certain Registration Rights Agreement, dated as of                     , 2014, by and between the Partnership and Mammoth Energy Holdings.

“Registration Statement” means the Registration Statement on Form S-1 (File No. 333-            ) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering, including any related registration statement filed pursuant to Rule 462(b) under the Securities Act.

“Required Allocations” means any allocation of an item of income, gain, loss and deduction pursuant to Sections 6.1(b)(i), 6.1(b)(ii), 6.1(b)(iv), 6.1(b)(v), 6.1(b)(vi), 6.1(b)(vii) or 6.1(b)(ix).

“Revaluation Event” means an event that results in an adjustment of the Carrying Value of each Partnership property pursuant to Section 5.4(d).

“Rhino” means Rhino Resource Partners LP, a Delaware limited partnership.

“Rhino Contribution Agreement” means that certain contribution agreement, dated as of             , 2014, by and between Rhino and the Partnership, together with the additional conveyance documents and instruments contemplated or referenced thereunder.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Special Approval” means approval by a majority of the members of the Conflicts Committee, whether in the form of approval or approval and recommendation to the Board of Directors.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general partner of such partnership, but only if such Person, directly or by one or more Subsidiaries of such Person, or a combination thereof, controls such partnership, directly or indirectly, at the date of determination or (c) any other Person in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b)(ii).

“Trading Day” means a day on which the principal National Securities Exchange on which the referenced Partnership Interests of any class are listed or admitted to trading is open for the transaction of business or, if such Partnership Interests are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the Partnership to act as registrar and transfer agent for any class of Partnership Interests; provided that if no Transfer Agent is specifically designated for any class of Partnership Interests, the General Partner shall act in such capacity.

“Treasury Regulation” means the United States Treasury regulations promulgated under the Code.

 

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“Underwriter” means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement dated                     , 2014, by and among the representatives of the Underwriters, the Partnership, the General Partner and the other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units.

“Unit Majority” means a majority of the Outstanding Common Units.

“Unitholders” means the holders of Units.

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d)).

“Unrestricted Person” means each Indemnitee, each Partner and each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner and any Person the General Partner designates as an “Unrestricted Person” for purposes of this Agreement.

“U.S. GAAP” means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

“Wexford Contribution Agreement” means that certain Contribution Agreement, dated as of                     , 2014, by and between Mammoth Energy Holdings and the Partnership, together with the additional conveyance documents and instruments contemplated or referenced thereunder.

“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” and words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” and “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement. The General Partner has the power to construe and interpret this Agreement and to act upon any such construction or interpretation. Any construction or interpretation of this Agreement by the General Partner and any action taken pursuant thereto and any determination made by the General Partner in Good Faith shall, in each case, be conclusive and binding on all Record Holders and all other Persons for all purposes.

 

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ARTICLE II

ORGANIZATION

Section 2.1 Formation. The General Partner and the Organizational Limited Partner previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act as a result of the Conversion. The General Partner and the Organizational Limited Partner hereby amend and restate the original Agreement of Limited Partnership of the Partnership in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act.

Section 2.2 Name. The name of the Partnership shall be “Mammoth Energy Partners LP”. The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” the letters “LP,” or “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Partners of such change in the next regular communication to the Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 2711 Centerville Road, Suite 400, Wilmington, Delaware 19808, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be Corporation Service Company. The principal office of the Partnership shall be located at 4727 Gaillardia Parkway, Suite 200, Oklahoma City, Oklahoma 73142 or such other place as the General Partner may from time to time designate by notice to the Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 4727 Gaillardia Parkway, Suite 200, Oklahoma City, Oklahoma 73142 or such other place as the General Partner may from time to time designate by notice to the Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be (a) to engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership Group of any business and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity and the General Partner in determining whether to propose or approve the conduct by the Partnership of any business shall be permitted to do so in its sole and absolute discretion.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

 

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Section 2.6 Term. The Partnership was formed as a result of the Conversion and, in accordance with the Delaware Act, commenced its existence upon the incorporation of the Predecessor and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership or one or more of the Partner’s designated Affiliates as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. No action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall be considered participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) nor shall any such action affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.6, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, each Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

 

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Section 3.4 Rights of Limited Partners.

(a) Each Limited Partner shall have the right, for a purpose that is reasonably related, as determined by the General Partner, to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense to obtain:

(i) true and full information regarding the status of the business and financial condition of the Partnership (provided that the requirements of this Section 3.4(a)(i) shall be satisfied to the extent the Limited Partner is furnished the Partnership’s most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the Commission pursuant to Section 13 of the Exchange Act);

(ii) a current list of the name and last known business, residence or mailing address of each Record Holder;

(iii) a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed; and

(iv) such other information regarding the affairs of the Partnership as the General Partner determines is just and reasonable.

(b) The rights pursuant to Section 3.4(a) replace in their entirety any rights to information provided for in Section 17-305(a) of the Delaware Act and each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have any rights as Partners to receive any information either pursuant to Sections 17-305(a) of the Delaware Act or otherwise except for the information identified in Section 3.4(a).

(c) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential.

(d) Notwithstanding any other provision of this Agreement or Section 17-305 of the Delaware Act, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby agrees to the fullest extent permitted by law that they do not have rights to receive information from the Partnership or any Indemnitee for the purpose of determining whether to pursue litigation or assist in pending litigation against the Partnership or any Indemnitee relating to the affairs of the Partnership except pursuant to the applicable rules of discovery relating to litigation commenced by such Person.

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP

INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates. Notwithstanding anything to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by physical certificates. Certificates that may be issued, if any, shall be executed on behalf of the Partnership by the Chairman of the Board, President, Chief Executive Officer or any Executive Vice

 

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President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. No Certificate for a class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent for such class of Partnership Interests; provided, however, that if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct, to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner or the Transfer Agent.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership and the General Partner shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding

 

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Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner hereunder as, and to the extent, provided herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction (i) by which the General Partner assigns its General Partner Interest to another Person, and includes a sale, assignment, gift, pledge, grant of security interest, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise, or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise (but not the pledge, grant of security interest, encumbrance, hypothecation or mortgage), including any transfer upon foreclosure or other exercise of remedies of any pledge, security interest, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of any Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in such Partner and the term “transfer” shall not mean any such disposition.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(c) Upon the receipt of proper transfer instructions from the registered owner of uncertificated Common Units, such uncertificated Common Units shall be cancelled, issuance of new equivalent uncertificated Common Units or Certificates shall be made to the holder of Common Units entitled thereto and the transaction shall be recorded upon the Partnership’s register.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.7, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or amendment of this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.

 

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Section 4.6 Transfer of the General Partner Interest.

(a) The General Partner may at its option transfer all or any part of its General Partner Interest without approval from any other Partner.

(b) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable U.S. federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if the General Partner determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for U.S. federal income tax purposes or (ii) preserve the uniformity of Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of a majority of the Outstanding Limited Partner Interests of such class.

(c) Nothing contained in this Agreement, other than Section 4.7(a), shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

Section 4.8 Eligibility Certificates; Ineligible Holders.

(a) If at any time the General Partner determines, with the advice of counsel, that any Group Member is subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner or its owner(s); then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or appropriate to obtain such proof of the nationality, citizenship or other related status of the Limited Partners and, to the extent relevant, their owners as the General Partner determines to be necessary or appropriate to eliminate or mitigate the risk of cancellation or forfeiture of any properties or interests therein.

 

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(b) Such amendments may include provisions requiring all Partners to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as a Partner (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its owners’) status as an Eligible Holder or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Limited Partner (or its owner) is not an Eligible Holder (an “Ineligible Holder”), the Partnership Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner may require that the General Partner be substituted for such Ineligible Holder as the Limited Partner in respect of the Ineligible Holder’s Partnership Interests.

(d) The General Partner shall, in exercising voting rights in respect of Partnership Interests held by it on behalf of Ineligible Holders, cast such votes in the same manner and in the same ratios as the votes of Partners (including the General Partner and its Affiliates) in respect of Partnership Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for purposes hereof as a purchase by the Partnership from the Ineligible Holder of the portion of his Partnership Interest representing his right to receive his share of such distribution in kind.

(f) At any time after he can and does certify that he has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Partnership Interests of such Ineligible Holder not redeemed pursuant to Section 4.9, such Ineligible Holder be admitted as a Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Partner and shall no longer constitute an Ineligible Holder and, if the General Partner was substituted for such Ineligible Holder as the Limited Partner in respect of the Ineligible Holder’s Partnership Interests, the General Partner shall cease to be deemed to be the owner in respect of such Ineligible Holder’s Partnership Interests.

Section 4.9 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Partner fails to furnish an Eligibility Certificate or other information requested within the period of time specified in amendments adopted pursuant to Section 4.8 or if upon receipt of such Eligibility Certificate, the General Partner determines, with the advice of counsel, that a Partner is an Ineligible Holder, the Partnership may, unless the Partner establishes to the satisfaction of the General Partner that such Partner is an Eligible Holder or has transferred his Limited Partner Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certificate to the General Partner prior to the date fixed for redemption as provided below, redeem the Partnership Interest of such Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Partner, at his last address designated on the records of the Partnership or the Transfer Agent, as applicable, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests) and that on and after the date fixed for redemption no further allocations or distributions to which the Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

 

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(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Partnership Interests of the class to be so redeemed multiplied by the number of Partnership Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 8% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Partner at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.9 shall also be applicable to Partnership Interests held by a Partner as nominee of a Person determined to be an Ineligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring his Partnership Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Partnership Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption will be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Contributions by the General Partner and its Affiliates.

(a) In connection with the Conversion, the General Partner was admitted as the sole General Partner of the Partnership and the Organizational Limited Partner was issued an initial Limited Partner Interest equal to a 100% Percentage Interest and was admitted as the Organizational Limited Partner of the Partnership. As of the Contribution Date, the initial Limited Partner Interest held by the Organizational Limited Partner will be redeemed as provided for in the Wexford Contribution Agreement and the initial Capital Contribution of the Organizational Limited Partner made in connection with the incorporation of the Predecessor will be refunded.

(b) On the Contribution Date and pursuant to the Wexford Contribution Agreement, the Organizational Limited Partner contributed, as a Capital Contribution, all of its equity interests in Redback Energy Services LLC, Redback Coil Tubing LLC, Muskie Proppant LLC, Panther Drilling Systems LLC, Bison Drilling and Field Services LLC, Bison Trucking LLC, Great White Sand Tiger Lodging Ltd., Stingray Pressure Pumping LLC and Stingray Logistics LLC to the Partnership in exchange for              Common Units.

(c) On the Contribution Date and pursuant to the Gulfport Contribution Agreement, Gulfport contributed, as a Capital Contribution, all of its equity interests in Stingray Pressure Pumping LLC, Stingray Logistics LLC, Muskie Proppant LLC, Bison Drilling and Field Services LLC and Bison Trucking LLC to the Partnership in exchange for              Common Units.

(d) On the Contribution Date and pursuant to the Rhino Contribution Agreement, Rhino contributed, as a Capital Contribution, all of its equity interests in Muskie Proppant LLC in exchange for             Common Units.

 

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Section 5.2 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(c) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

Section 5.3 Interest and Withdrawal. No interest on Capital Contributions shall be paid by the Partnership. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon dissolution of the Partnership may be considered as the withdrawal or return of its Capital Contribution by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.4 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made by the Partner with respect to such Partnership Interest, (ii) all items of Partnership income and gain computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.4(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for U.S. federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.4, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (x) any other Group Member that is classified as a partnership or is disregarded for U.S. federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership or is disregarded for U.S. federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

 

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(iii) The computation of all items of income, gain, loss and deduction shall be made (x) except as otherwise provided in this Agreement and Treasury Regulation Section 1.704-1(b)(2)(iv)(m), without regard to any election under Section 754 of the Code that may be made by the Partnership, and (y) as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for U.S. federal income tax purposes.

(iv) To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(l)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(v) In the event the Carrying Value of Partnership property is adjusted pursuant to Section 5.4(d), any Unrealized Gain resulting from such adjustment shall be treated as an item of gain and any Unrealized Loss resulting from such adjustment shall be treated as an item of loss.

(vi) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the property’s Carrying Value as of such date.

(vii) Any deductions for depreciation, amortization or other cost recovery attributable to any Contributed Property or Adjusted Property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(viii) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

(c) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d) (i) Consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(f) and 1.704-1(b)(2)(iv)(h)(2), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of a Noncompensatory Option, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the Combined Interest to Common Units pursuant to Section 11.3(b), the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property; provided, however, that in the event of the issuance of a Partnership Interest pursuant to the exercise of a Noncompensatory Option where the right to share in Partnership capital represented by such Partnership Interest differs from the consideration paid to acquire and exercise such option, the Carrying Value of each Partnership property immediately after the issuance of such Partnership Interest shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property and the Capital Accounts of the Partners shall be adjusted in a manner consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(s); provided further, however, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, in the event of an issuance of a Noncompensatory Option to acquire a de minimis Partnership Interest, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests (or, in the case of a Revaluation Event resulting from the exercise of a Noncompensatory

 

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Option, immediately after the issuance of the Partnership Interest acquired pursuant to the exercise of such Noncompensatory Option) shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may first determine an aggregate value for the assets of the Partnership that takes into account the current trading price of the Common Units, the fair market value of all other Partnership Interests at such time, and the amount of Partnership Liabilities. The General Partner may allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate). Absent a contrary determination by the General Partner, the aggregate fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a Revaluation Event shall be the value that would result in the Capital Account for each Common Unit that is Outstanding prior to such Revaluation Event being equal to the Event Issue Value.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for the purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property immediately prior to such distribution for an amount equal to its fair market value, and has been allocated to the Partners, at such time, pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

Section 5.5 Issuances of Additional Partnership Interests and Derivative Instruments.

(a) The Partnership may issue additional Partnership Interests and Derivative Instruments for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Partners.

(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior or junior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may, or shall be required to, redeem the Partnership Interest (including sinking fund provisions); (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Interest will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and Derivative Instruments pursuant to this Section 5.5, (ii) the conversion of the General Partner’s (and its Affiliates’) Combined Interest to Common Units pursuant to the terms of this Agreement, (iii) reflecting the admission of such additional Partners in the books and records of the Partnership as the Record Holder of such Partnership Interests, and (iv) all additional issuances of Partnership

 

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Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or in connection with the conversion of the General Partner’s (and its Affiliates’) Combined Interest into Common Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.6 Preemptive Right. Except as provided in this Section 5.6 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests.

Section 5.7 Splits and Combinations.

(a) Subject to Section 5.7(d), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted retroactively to the beginning of the Partnership.

(b) Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision, or combination, the Partnership may issue Certificates or uncertificated Partnership Interests to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of any such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Partnership Interests. If a distribution, subdivision or combination of Partnership Interests would result in the issuance of fractional Units but for the provisions of Section 5.5(d) and this Section 5.7(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.8 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Sections 17-607 or 17-804 of the Delaware Act.

 

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Section 5.9 Deemed Capital Contributions by Partners. Consistent with the provisions of Treasury Regulation Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then (x) such property shall be treated as having been contributed to the Partnership by such Partner and (y) immediately thereafter the Partnership shall be treated as having transferred such property to the employee or other service provider.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.4(b)) for each taxable period shall be allocated among the Partners, as provided herein below.

(a) Net Income and Net Loss. After giving effect to the special allocations set forth in Section 6.1(b), Net Income and Net Loss for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income and Net Loss for such taxable period shall be allocated 100% to all Unitholders, Pro Rata.

(b) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for each taxable period in the following order:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(b), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income and gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(b) with respect to such taxable period (other than an allocation pursuant to Section 6.1(b)(vi) and Section 6.1(b)(vii). This Section 6.1(b)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(b)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(b), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income and gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(b), Sections 6.1(b)(vi) and 6.1(b)(vii), with respect to such taxable period. This Section 6.1(b)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations. If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to a Unit exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Unit, each Unitholder

 

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receiving such greater cash or property distribution shall be allocated gross income in an amount equal to the product of (A) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution with respect to the Unit receiving the smallest distribution and (B) the number of Units owned by the Unitholder receiving the greater distribution.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Section 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Section 6.1(b)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(b)(iv) were not in this Agreement.

(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(b)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as so adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(b)(iv) and this Section 6.1(b)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners, Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss. This Section 6.1(b)(vii) is intended to comply with Treasury Regulations Section 1.704-2(i)(1) and shall be interpreted consistently therewith.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners, Pro Rata.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) of the Code (including pursuant to Treasury Regulation Section 1.734-2(b)(1)) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts as a result of a distribution to a Partner in complete liquidation of such Partner’s interest in the Partnership, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis) taken into account pursuant to Section 5.4, and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

 

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(x) Economic Uniformity; Changes in Law. For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(b)(x) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Outstanding Limited Partner Interests or the Partnership.

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. In exercising its discretion under this Section 6.1(b)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(b)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(b)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(b)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Equalization of Capital Accounts With Respect to Privately Placed Units. Unrealized Gain or Unrealized Loss deemed recognized as a result of a Revaluation Event shall first be allocated to the (A) Unitholders holding Privately Placed Units, Pro Rata, or (B) Unitholders holding Common Units (other than Privately Placed Units), Pro Rata, as applicable, to the extent necessary to cause the Capital Account in respect of each Privately Placed Unit then Outstanding to equal the Capital Account in respect of each Common Unit (other than Privately Placed Units) then Outstanding.

(xiii) Allocations Regarding Certain Payments Made to Employees and Other Service Providers. Consistent with the provisions of Treasury Regulation Section 1.83-6(d), if any Partner (or its successor) transfers property (including cash) to any employee or other service provider of the Partnership Group and such Partner is not entitled to be reimbursed by (or otherwise elects not to seek reimbursement from) the Partnership for the value of such property, then any items of deduction or loss resulting from or attributable to such transfer shall be allocated to the Partner (or its successor) that made such transfer and was deemed to have contributed such property to the Partnership pursuant to Section 5.9.

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for U.S. federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

 

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(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for U.S. federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(b)(x)); provided that, in all events, the General Partner shall apply the “remedial allocation method” in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(c) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Units, so long as such conventions would not have a material adverse effect on the Limited Partners or Record Holders of any class or classes of Limited Partner Interests.

(d) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(e) All items of income, gain, loss, deduction and credit recognized by the Partnership for U.S. federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(f) Each item of Partnership income, gain, loss and deduction shall, for U.S. federal income tax purposes, be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Closing Date occurs shall be allocated to the Partners who are issued Units as a result of the transactions contemplated by the Wexford Contribution Agreement, the Gulfport Contribution Agreement, the Rhino Contribution Agreement and the Underwriting Agreement; and provided, further, that each item of Partnership income, gain, loss and deduction for the period beginning on the Contribution Date and ending the date immediately before the Closing Date shall be allocated to the Partners holding Units on the date immediately before the Closing Date; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income, gain, loss or deduction, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership’s Units are listed or admitted to trading on the first Business Day of the month in which such item is recognized for U.S. federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder or for the proper administration of the Partnership.

 

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(g) Allocations that would otherwise be made to a Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

(h) If, as a result of an exercise of a Noncompensatory Option, a Capital Account reallocation is required under Treasury Regulation Section 1.704-1(b)(2)(iv)(s)(3), the General Partner shall make corrective allocations pursuant to Treasury Regulation Section 1.704-1(b)(4)(x).

Section 6.3 Distributions to Record Holders.

(a) The Board of Directors may adopt a cash distribution policy, which it may change from time to time without amendment to this Agreement.

(b) The Partnership will make distributions, if any, to Unitholders Pro Rata.

(c) All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act.

(d) Notwithstanding Section 6.3(b), in the event of the dissolution and liquidation of the Partnership, cash shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(e) The General Partner may treat taxed paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of cash to such Partners, as determined appropriate under the circumstances by the General Partner.

(f) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through any Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, but without limitation on the ability of the General Partner to delegate its rights and power to other Persons, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no other Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted to a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.4, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Interests, and the incurring of any other obligations;

 

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(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation, grant of a security interest in or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.4 or Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if the same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of cash or cash equivalents by the Partnership;

(vii) the selection, employment, retention and dismissal of employees (including employees having titles such as “chief executive officer,” “president,” “chief financial officer,” “chief operating officer,” “general counsel,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors of the General Partner or the Partnership Group and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time);

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Partnership Interests from, or requesting that trading be suspended on, any such exchange;

(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests or of Derivative Instruments;

(xiv) the undertaking of any action in connection with the Partnership’s participation in the management of any Group Member; and

(xv) the entering into of agreements with any of its Affiliates, including any agreements to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

 

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(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Rhino Contribution Agreement, the Underwriting Agreement, the Wexford Contribution Agreement, the Gulfport Contribution Agreement, the Registration Rights Agreement, the Investor Rights Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in the case of each agreement other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own behalf or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners, the other Persons who may acquire an interest in Partnership Interests or are otherwise bound by this Agreement; (iii) agrees that the existence of the conflicts of interest described in the Registration Statement and any actions of the General Partner or any of its Affiliates or Associates or any other Indemnitee taken in connection therewith are hereby approved by all Partners and shall not constitute a breach of this Agreement or of any duty existing at law, in equity or otherwise; and (iv) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2 Replacement of Fiduciary Duties. Notwithstanding any other provision of this Agreement, to the extent that, at law or in equity, the General Partner or any other Indemnitee would have duties (including fiduciary duties) to the Partnership, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, all such duties (including fiduciary duties) are hereby eliminated, to the fullest extent permitted by law, and replaced with the duties expressly set forth herein. The elimination of duties (including fiduciary duties) and replacement thereof with the duties expressly set forth herein are approved by the Partnership, each of the Partners, each other Person who acquires an interest in a Partnership Interest and each other Person bound by this Agreement.

Section 7.3 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Partner.

Section 7.4 Restrictions on the General Partner’s Authority. Except as provided in Articles XII and XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, encumber, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

 

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Section 7.5 Reimbursement of the General Partner.

(a) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person (including Affiliates of the General Partner) to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.5 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(b) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment for such management fee of such management fee or fees exceeds the amount of such fee or fees.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof except and to the extent required under the rules of a National Securities Exchange to which the Partnership or its securities are subject), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including plans, programs and practices involving the issuance of Partnership Interests), or cause the Partnership to issue Partnership Interests in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates, any Group Member or their Affiliates, or any of them, in each case for the benefit of employees, officers, consultants and directors of the General Partner or its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliates are obligated to provide to any employees, officers, consultants and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests purchased by the General Partner or such Affiliates, from the Partnership or otherwise, to fulfill awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.5(a). Any and all obligations of the General Partner under any benefit plans, programs or practices adopted by the General Partner as permitted by this Section 7.5(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

Section 7.6 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership, shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (i) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (ii) the acquisition, ownership or disposition of debt securities or equity interests in any Group Member or (iii) the direct or indirect provision of management, advisory, and administrative services to its Affiliates or to other Persons.

(b) Each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in

 

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direct competition with the business and activities of any Group Member. No such business interest or activity shall constitute a breach of this Agreement, any fiduciary or other duty existing at law, in equity or otherwise, or obligation of any type whatsoever to the Partnership or other Group Member, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement.

(c) Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to any Group Member, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership or other Group Member, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement for breach of any fiduciary or other duty existing at law, in equity or otherwise, or obligation of any type whatsoever by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires such opportunity for itself, directs such opportunity to another Person or does not communicate such opportunity or information to any Group Member.

(d) Subject to the terms of Section 7.6(a), Section 7.6(b) and Section 7.6(c), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.6 is hereby approved by the Partnership and all Partners, and (ii) it shall be deemed not to be a breach of any fiduciary or other duty existing at law, in equity or otherwise, or obligation of any type whatsoever of the General Partner or of any other Unrestricted Person for the Unrestricted Person (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership; provided such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

(e) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the Closing Date and, except as otherwise expressly provided in Section 7.11, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Interests acquired by them.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in Bad Faith or engaged in willful misconduct or fraud or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

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claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates, the Indemnitees and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by an Indemnitee with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Limitation of Liability of Indemnitees.

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liable for monetary damages or otherwise to the Partnership, to another Partner, to any other Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, for losses sustained or liabilities incurred, of any kind or character, as a result of its or any of any other Indemnitee’s determinations, act(s) or omission(s) in their capacities as Indemnitees; provided, however, that an Indemnitee shall be liable for losses or liabilities sustained or incurred by the Partnership, the other Partners, any other Persons who acquire an interest in a Partnership Interest or any other Person bound by this Agreement, if it is determined by a final and non-appealable judgment entered by a court of competent jurisdiction that such losses or liabilities were the result of the conduct of that Indemnitee engaged in by it in Bad Faith or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

(b) The General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner if such appointment was not made in Bad Faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership, to the Partners, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership, to any Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement for its reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Whenever the General Partner, acting in its capacity as the general partner of the Partnership, or the Board of Directors or any committee of the Board of Directors (including the Conflicts Committee) or any Affiliates or Associates of the General Partner or Indemnitees cause the General Partner to make a determination or take or omit to take any action in such capacity, whether or not under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, then, unless another lesser standard is provided for in this Agreement, the General Partner, the Board of Directors, such committee or (subject to the last sentence of this Section 7.9(a)) such Affiliates, Associates or Indemnitees, shall make such determination, or take or omit to take such action, in Good Faith. The foregoing and other lesser standards provided for in this Agreement are the sole and exclusive standards governing any such determinations, actions and omissions of the General Partner, the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee) and (subject to the last sentence of this Section 7.9(a)) any Affiliate or Associate of the General Partner or Indemnitee and no such Person shall be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard (all of which duties, obligations and standards are hereby waived and disclaimed), under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, or under the Delaware Act or any other law, rule or regulation or at equity. Any such determination, action or omission by the General Partner, the Board of Directors of the General Partner or any committee thereof (including the Conflicts Committee) or of any Affiliates or Associates of the General Partner or Indemnitees, will for all purposes be presumed to have been in Good Faith. In any proceeding brought by or on behalf of the Partnership, any Limited Partner, any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement, challenging such determination, act or omission, the Person bringing or prosecuting such proceeding shall have the burden of proving that such determination, action or omission was not in Good Faith. Notwithstanding anything in this Agreement to the contrary, neither this Section 7.9 nor any other provision of

 

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this Agreement creates or establishes any fiduciary or other duties owed to the Partnership, any Limited Partner, any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement on the part of any Affiliate or Associate of the General Partner or Indemnitee and any obligation to act or omit to act in Good Faith on the part of any Affiliate or Associate of the General Partner or Indemnitee is only to the extent that such any Affiliate or Associate of the General Partner or Indemnitee would otherwise have owed the Partnership, any Limited Partner, any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement a fiduciary or other higher standard of duty.

(b) Whenever the General Partner makes a determination or takes or omits to take any action, or any of its Affiliates or Associates or any Indemnitee causes it to do so, acting in its individual capacity, whether or not under this Agreement, any Group Member Agreement or any other agreement contemplated hereby, then the General Partner, or such Affiliates, Associates or Indemnitees causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or omit to take such action free of any fiduciary duty or duty of good faith, or other duty or obligation existing at law, in equity or otherwise whatsoever to the Partnership, to another Partner, to any Person who acquires an interest in a Partnership Interest or to any other Person bound by this Agreement, and the General Partner, or such Affiliates, Associates or Indemnitees causing it to do so, shall not, to the fullest extent permitted by law, be required to act in Good Faith or pursuant to any fiduciary or other duty or standard imposed by this Agreement, any Group Member Agreement or any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(c) For purposes of Section 7.9(a) and Section 7.9(b) of this Agreement, “acting in its capacity as the general partner of the Partnership” means and is solely limited to, the General Partner exercising its authority as a general partner under this Agreement, other than when it is “acting in its individual capacity.” For purposes of this Agreement, “acting in its individual capacity” means: (i) any action by the General Partner or its Affiliates other than through the exercise of the General Partner of its authority as a general partner under this Agreement; and (ii) any action or inaction by the General Partner by the exercise (or failure to exercise) of its rights, powers or authority under this Agreement that are modified by: (A) the phrase “at the option of the General Partner,” (B) the phrase “in its sole discretion” or “in its discretion” or (iii) some variation of the phrases set forth in clauses (i) and (ii). For the avoidance of doubt, whenever the General Partner votes, acquires Partnership Interests or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be and be deemed to be “acting in its individual capacity.”

(d) Whenever a potential conflict of interest exists or arises between the General Partner (acting in its individual capacity or in its capacity as the general partner of the Partnership) or any of its Affiliates or Associates or any Indemnitee, on the one hand, and the Partnership, any Group Member or any Partner, any other Person who acquires an interest in a Partnership Interest or any other Person who is bound by this Agreement on the other hand, the General Partner may in its discretion submit any determination, action or omission of the General Partner or any of its Affiliates or Associates or any Indemnitee with respect to such conflict of interest (i) for Special Approval or (ii) for approval by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner or its Affiliates). If the General Partner does not submit the determination, action or omission as provided in either clauses (i) or (ii) in the preceding sentence, then any such determination, action or omission shall be governed by Section 7.9(a) above. If any such determination, action or omission (A) receives Special Approval; or (B) receives approval of a majority of the Common Units (excluding Common Units owned by the General Partner or its Affiliates), then such determination, action or omission shall be conclusively deemed to be approved by the Partnership, all the Partners, each Person who acquires an interest in a Partnership Interest and each other Person who is bound by this Agreement, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any fiduciary or other duty or obligation existing at law, in equity or otherwise or obligation of any type whatsoever.

(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates or any other Indemnitee shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group or (ii) permit any Group Member to use any facilities or assets of the General

 

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Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts or transactions shall be in its sole discretion.

(f) The Partners, and each Person who acquires an interest in a Partnership Interest or is otherwise bound by this Agreement hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

(g) For the avoidance of doubt, whenever the Board of Directors, any committee of the Board of Directors (including the Conflicts Committee), the officers of the General Partner, any Affiliates or Associates of the General Partner or Indemnitees make a determination on behalf of the General Partner, or cause the General Partner to take or omit to take any action, whether in the General Partner’s capacity as the General Partner or in its individual capacity, the standards of care applicable to the General Partner shall apply to such Persons, and such Persons shall be entitled to all benefits and rights of the General Partner hereunder, including waivers and modifications of duties, protections and presumptions, as if such Persons were the General Partner hereunder.

(h) The Limited Partners expressly acknowledge and agree that none of the General Partner, the Board of Directors or any committee thereof is under any obligation to consider the separate interests of the Limited Partners (including, without limitation, the tax consequences to Limited Partners) in deciding whether to cause the Partnership to take (or decline to take) any actions, and that none of the General Partner or any other Indemnitee shall be liable to the Limited Partners for monetary damages or equitable relief or losses sustained, liabilities incurred or benefits not derived by Limited Partners in connection with such decisions.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner, the Board of Directors (or any committee thereof) and any other Indemnitee may rely upon, and shall be protected from liability to the Partnership, any Partner, any Person who acquires an interest in a Partnership Interest, and any other Person bound by this Agreement in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner, the Board of Directors (or any committee thereof) and any other Indemnitee may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner or such Indemnitee reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in Good Faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its or the Partnership’s duly authorized officers, a duly appointed attorney or attorneys-in-fact.

Section 7.11 Purchase or Sale of Partnership Interests. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests or Derivative Instruments. As long as any Partnership Interests are held by any Group Member, such Partnership Interests shall not be entitled to any vote and shall not be considered to be Outstanding. Notwithstanding any other provision of this Agreement or otherwise applicable provision of law or equity, any Partnership Interests or Derivative Instruments that are purchased or otherwise acquired by the Partnership or any Group Member may, in the sole discretion of the General Partner, be canceled or held by the Partnership in treasury and, if so held in treasury, shall no longer be deemed to be Outstanding for any purpose. For the avoidance of doubt, Partnership Interests or Derivative Instruments that are canceled or held by the Partnership in treasury (i) shall not be allocated Net Income (Loss) pursuant to Article VI, (ii) shall not be entitled to distributions pursuant to Article VI, and (iii) shall neither be entitled to vote nor be counted for quorum purposes.

 

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Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any of its Affiliates (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Interests that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Interests (the “Holder”) to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Interests specified by the Holder; provided, however, that the aggregate offering price of any such offering and sale of Partnership Interests covered by such registration statement as provided for in this Section 7.12(a) shall not be less than $5.0 million; provided further, that the Partnership shall not be required to effect more than two registrations pursuant to this Section 7.12(a) in any twelve-month period; and provided further, however that if the General Partner determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Interests for cash (other than an offering relating solely to a benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Interests held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the Partnership Interests of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of Partnership Interests pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder that in their opinion the inclusion of all or some of the Holder’s Partnership Interests would adversely and materially affect the timing or success of the offering, the Partnership shall include in such offering only that number or amount, if any, of Partnership Interests held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in

 

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limitation of the Partnership’s obligation under Section 7.7 the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) against any losses, claims, demands, actions, causes of action, assessments, damages, liabilities (joint or several), costs and expenses (including interest, penalties and reasonable attorneys’ fees and disbursements), resulting to, imposed upon, or incurred by the Indemnified Persons, directly or indirectly, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Interests were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus or issuer free writing prospectus as defined in Rule 433 of the Securities Act (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Section 7.12(a) and Section 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be the General Partner, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Interests with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Interests for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.

(e) The rights to cause the Partnership to register Partnership Interests pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Interests, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Interests with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(f) Any request to register Partnership Interests pursuant to this Section 7.12 shall (i) specify the Partnership Interests intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Interests for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Interests, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Interests.

(g) The Partnership may enter into separate registration rights agreements with the General Partner or any of its Affiliates.

Section 7.13 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the

 

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General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available to such Partner to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 105 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means, to each Record Holder of a Unit or other Partnership Interest as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner, and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(b) As soon as practicable, but in no event later than 50 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit or other Partnership Interest, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

 

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(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for U.S. federal, state and local income tax purposes on the basis of the accrual method and the taxable period or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal, state and local income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for U.S. federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Partnership Interest will be deemed to be the lowest quoted closing price of the Partnership Interests on any National Securities Exchange on which such Partnership Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(f) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner shall designate the Organizational Limited Partner, or such other Partner as the General Partner shall designate, as the Tax Matters Partner (as defined in the Code) and the Tax Matters Partner is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings. Each Partner agrees that notice of or updates regarding tax controversies shall be deemed conclusively to have been given or made by the Tax Matters Partner if the Partnership has either (i) filed the information for which notice is required with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such information is publicly available on such system or (ii) made the information for which notice is required available on any publicly available website maintained by the Partnership, whether or not such Partner remains a Partner in the Partnership at the time such information is made publicly available.

Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other U.S. federal, state or local law,

 

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including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code or established by any foreign law. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests or the issuance of any Limited Partner Interests in accordance herewith, and except as provided in Section 4.8, each transferee or other recipient of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer or issuance is reflected in the books and records of the Partnership, (ii) shall become bound by the terms of, and shall be deemed to have agreed to be bound by, this Agreement, (iii) shall become the Record Holder of the Limited Partner Interests so transferred or issued, (iv) represents that the transferee or other recipient has the capacity, power and authority to enter into this Agreement, and (v) makes the consents, acknowledgments and waivers contained in this Agreement, all with or without execution of this Agreement. The transfer of any Limited Partner Interests and/or the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Record Holder without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.8.

(b) The name and mailing address of each Record Holder shall be listed on the books and records of the Partnership maintained for such purpose by the General Partner or the Transfer Agent. The General Partner shall update its books and records from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(a).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

 

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ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”):

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A) through (C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi)(A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a limited liability company or a partnership, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Sections 11.1(a)(iv), 11.1(a)(v), 11.1(a)(vi)(A), 11.1(a)(vi)(B), 11.1(a)(vi)(C) or 11.1(a)(vi)(E) occurs, the withdrawing General Partner shall give notice to the Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 11:59 pm, prevailing Central Time, on                     , 2024, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner under the Delaware Act or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not previously so treated or taxed); (ii) at any time after 11:59 pm, prevailing Central Time, on                     , 2024, the General Partner voluntarily withdraws by

 

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giving at least 90 days’ advance notice to the Partners, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the other Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives notice of withdrawal pursuant to Section 11.1(a)(ii), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Partners as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1, unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Removal of the General Partner. The General Partner may be removed if such removal is approved by the Partners holding at least 66 2/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Partners holding a majority of the outstanding Common Units (including Common Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the Partners to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the Partners under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ general partner interest (or equivalent interest), if any, in the other Group Members (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Partners under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market

 

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value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.5, including any employee related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing General Partner (or its Affiliates) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.

Section 11.4 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Partnership Interest becomes a Record Holder of the Partnership Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Partnership Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or Section 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and such successor is admitted to the Partnership pursuant to Section 10.2;

 

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(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon (a) an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or Section 11.1(a)(iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), 11.1(a)(v) or 11.1(a)(vi), then, to the maximum extent permitted by law, within 180 days thereafter, a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as the successor General Partner a Person approved by a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of the limited liability of any Limited Partner under the Delaware Act and (y) neither the Partnership nor any successor limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a Unit Majority. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a majority of the Outstanding Common Units. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.4) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

 

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Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and, to the extent reasonably practicable, such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the winding up of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership.

 

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ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any other Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for U.S. federal income tax purposes;

(d) a change that the General Partner determines (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which any class of Partnership Interests are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.7 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or their directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Interests or any Derivative Instruments pursuant to Section 5.5;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or Section 7.1(a);

 

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(k) a merger or conveyance pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Amendments to this Agreement may be proposed only by the General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so in its sole discretion. An amendment shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 or Section 13.3, a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has either (a) filed such amendment with the Commission via EDGAR and such amendment is publicly available thereon or (b) made such amendment available on any publicly available website maintained by the Partnership.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no provision of this Agreement (other than Section 11.2 or Section 13.4) that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) or requires a vote or approval of Partners (or a subset of Partners) holding a specified Percentage Interest to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing or increasing such percentage, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced or increased, as applicable, or the affirmative vote of Partners whose aggregate Percentage Interests constitute not less than the voting requirement sought to be reduced or increased, as applicable.

(b) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3 or Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Percentage Interests of all Limited Partners voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

 

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(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of Partners (including the General Partner and its Affiliates) holding at least 90% of the Percentage Interests of all Limited Partners.

Section 13.4 Special Meetings. All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the specific purposes for which the special meeting is to be called and the class or classes of Units for which the meeting is proposed. No business may be brought by any Limited Partner before such special meeting except the business listed in the related request. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date. For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment. Prior to the date upon which any meeting of Limited Partners is to be held, the General Partner may postpone such meeting one or more times for any reason by giving notice to each Limited Partner entitled to vote at the meeting so postponed of the place, date and hour at which such meeting would be held. Such notice shall be given not fewer than two days before the date of such meeting and otherwise in accordance with this Article XIII. When a meeting is postponed, a new Record Date need not be fixed unless such postponement shall be for more than 45 days. Any meeting of Limited Partners may be adjourned by the General Partner one or more times for any reason, including the failure of a quorum to be present at the meeting with respect to any proposal or the failure of any proposal to receive sufficient votes for approval. No Limited Partner vote shall be required for any adjournment. A meeting of Limited Partners may be adjourned by the General Partner as to one or more proposals regardless of whether action has been taken on other matters. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the

 

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adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes. The transaction of business at any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting. The holders of a majority, by Percentage Interest, of Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Partners of such class or classes unless any such action by the Partners requires approval by holders of a greater Percentage Interest, in which case the quorum shall be such greater Percentage Interest. At any meeting of the Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of holders of Partnership Interests that, in the aggregate, represent a majority of the Percentage Interest of those present in person or by proxy at such meeting shall be deemed to constitute the act of all Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the holders of Partnership Interests that in the aggregate represent at least such greater or different percentage shall be required; provided, however, that if, as a matter of law or provision of this Agreement, approval by plurality vote of Partners (or any class thereof) is required to approve any action, no minimum quorum shall be required. The Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by holders of the required Percentage Interest specified in this Agreement.

Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage, by Percentage Interest, of the Partnership Interests of the class or classes for which a meeting has been called (including Partnership Interests deemed owned by the General Partner), as the case may be, that would be necessary to authorize or take such action at a meeting at which all the Limited Partners entitled to vote at such meeting were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have

 

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not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite percentage of Units acting by written consent without a meeting.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts, business trusts, associations, real estate investment trusts, common law trusts or unincorporated businesses or entities, including a partnership (whether general or limited (including a limited liability partnership or limited liability limited partnership)) (each an “Other Entity”), whether such Other Entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“Merger Agreement”) in accordance with this Article XIV.

Section 14.2 Procedure for Merger or Consolidation.

(a) Merger or consolidation of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger or consolidation of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Partner and, in declining to consent to a merger or consolidation, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

 

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(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the name and jurisdiction of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, then the cash, property or general or limited partner interests, rights, securities or obligations of any Other Entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their general or limited partner interests, securities or rights, and (ii) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any Other Entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed no later than the time of the filing of the certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Partners of Merger or Consolidation.

(a) Except as provided in Section 14.3(d) and Section 14.3(e), the General Partner, upon its approval of the Merger Agreement, shall direct that the Merger Agreement be submitted to a vote of Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Section 14.3(d) and Section 14.3(e), the Merger Agreement shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement.

(c) Except as provided in Section 14.3(d) and Section 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger pursuant to Section 14.4, the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.

 

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(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or any Group Member under the Delaware Act or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the General Partner determines that the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into an Other Entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for U.S. federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Partnership Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Partnership Interest of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests Outstanding immediately prior to the effective date of such merger or consolidation.

Section 14.4 Certificate of Merger. Upon the required approval by the General Partner and the Unitholders of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Amendment of Partnership Agreement. Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.

Section 14.6 Effect of Merger or Consolidation.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

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(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) A merger or consolidation effected pursuant to this Article shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than     % of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed. Notwithstanding the foregoing, if, at any time, the General Partner and its Affiliates hold less than 75% of the total Limited Partner Interests of any class then Outstanding, from and after that time, the General Partner’s right set forth in this Section 15.1(a) shall be exercisable if the General Partner and its Affiliates subsequently hold more than 80% of the total Limited Partner Interests of such class.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be filed and distributed as may be required by the Commission or any National Securities Exchange on which such Limited Partner Interests are listed. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment (in the case of Limited Partner Interests evidenced by Certificates), at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Articles IV, V, VI, and XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests (in the case of Limited Partner Interests evidenced by Certificates), and such Limited Partner Interests shall

 

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thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Articles IV, V, VI, and XII).

(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy information or materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment, information, materials or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice, information, materials or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment, information, materials or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy information or materials via electronic mail or by the Internet or (ii) the rules of the Commission and applicable law shall permit any demand, report or proxy information or materials (including but not limited to those demanded pursuant to Section 3.4(a)) to be delivered electronically or made available via the Internet (including but not limited to EDGAR or a publicly available website maintained by the Partnership), any such notice, demand, request, report or proxy information or materials shall be deemed given or made when delivered or made available via such mode of delivery or access. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1(a) executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1(a) is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 16.1(a). The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing,” “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

 

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Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Partnership Interest, pursuant to Section 10.1(a) without execution hereof.

Section 16.8 Applicable Law; Forum, Venue and Jurisdiction; Waiver of Trial by Jury; Attorney Fees.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a fiduciary or other duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding;

 

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(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in this clause (v) shall affect or limit any right to serve process in any other manner permitted by law;

(vi) IRREVOCABLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY SUCH CLAIM, SUIT, ACTION OR PROCEEDING; AND

(vii) agrees that if such Partner or Person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought in any such claim, suit, action or proceeding, then such Partner or Person shall be obligated to reimburse the Partnership and its Affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

Section 16.9 Invalidity of Provisions. If any provision or part of a provision of this Agreement is or becomes, for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby, and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Section 16.10 Consent of Partners. Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.11 Facsimile Signatures. The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on Certificates representing Units is expressly permitted by this Agreement.

Section 16.12 Third Party Beneficiaries. Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee, and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

 

FIRST AMENDED AND RESTATED AGREEMENT OF

LIMITED PARTNERSHIP OF

MAMMOTH ENERGY PARTNERS LP

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EXHIBIT A

to the First Amended and Restated

Agreement of Limited Partnership of

Mammoth Energy Partners LP

Certificate Evidencing Common Units

Representing Limited Partner Interests in

Mammoth Energy Partners LP

 

No.	Common Units

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of Mammoth Energy Partners LP, as amended, supplemented or restated from time to time (the “Partnership Agreement”), Mammoth Energy Partners LP, a Delaware limited partnership (the “Partnership”), hereby certifies that                      (the “Holder”) is the registered owner of              Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 4727 Gaillardia Parkway, Suite 200, Oklahoma City, Oklahoma 73142. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF MAMMOTH ENERGY PARTNERS LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF MAMMOTH ENERGY PARTNERS LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE MAMMOTH ENERGY PARTNERS LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). MAMMOTH ENERGY PARTNERS GP LLC, THE GENERAL PARTNER OF MAMMOTH ENERGY PARTNERS LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF MAMMOTH ENERGY PARTNERS LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR U.S. FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement and (iii) made the waivers and given the consents and approvals contained in the Partnership Agreement.

 

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This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar. This Certificate shall be governed by and construed in accordance with the laws of the State of Delaware.

 

Dated:		Mammoth Energy Partners LP
		By:		Mammoth Energy Partners GP LLC
		By:
		Name:
		Title:
		By:
		Name:
		Title:

 

Countersigned and Registered by:
[                                                                                                ]
as Transfer Agent and Registrar

 

By:
		Authorized Signature

 

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[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM - as tenants in common		UNIF GIFT/TRANSFERS MIN ACT
TEN ENT - as tenants by the entireties		Custodian
JT TEN -         as joint tenants with right of survivorship and not as tenants in common		(Cust)                    (Minor) Under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

ASSIGNMENT OF COMMON UNITS OF

MAMMOTH ENERGY PARTNERS LP

 

FOR VALUE RECEIVED,              hereby assigns, conveys, sells and transfers unto
(Please print or typewrite name and address of assignee)		(Please insert Social Security or other identifying number of assignee)
Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint              as its attorney-in-fact with full power of substitution to transfer the same on the books of Mammoth Energy Partners LP.
Date:		NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15
		(Signature)
		(Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

 

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Appendix B

GLOSSARY OF OIL AND NATURAL GAS TERMS

Blowout. An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of salt water, oil, natural gas or a mixture of these. Blowouts can occur in all types of exploration and production operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant open-hole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) down-hole and intervention efforts will be averted.

Bottomhole assembly. The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.

Cementing. To prepare and pump cement into place in a wellbore.

Coiled tubing. A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft. to 15,000 ft. (610 m to 4,570 m) or greater length.

Completion. A generic term used to describe the assembly of down-hole tubulars and equipment required to enable safe and efficient production from an oil or gas well. The point at which the completion process begins may depend on the type and design of the well.

Directional drilling. The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken down-hole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a down-hole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes.

Down-hole. Pertaining to or in the wellbore (as opposed to being on the surface).

Down-hole motor. A drilling motor located in the drill string above the drilling bit powered by the flow of drilling mud. Down-hole motors are used to increase the speed and efficiency of the drill bit or can be used to steer the bit in directional drilling operations. Drilling motors have become very popular because of horizontal and directional drilling applications and the increase of day rates for drilling rigs.

 

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Drilling rig. The machine used to drill a wellbore.

Drillpipe. Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.

Drillstring. The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.

Horizontal drilling. A subset of the more general term “directional drilling,” used where the departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting it as deviation from vertical, which would then be 85 degrees. Because a horizontal well typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical well.

Hydraulic fracturing. A stimulation treatment routinely performed on oil and gas wells in low-permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation. Proppant, such as grains of sand of a particular size, is mixed with the treatment fluid to keep the fracture open when the treatment is complete. Hydraulic fracturing creates high-conductivity communication with a large area of formation and bypasses any damage that may exist in the near-wellbore area.

Hydrocarbon. A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.

Mud motors. A positive displacement drilling motor that uses hydraulic horsepower of the drilling fluid to drive the drill bit. Mud motors are used extensively in directional drilling operations.

Natural gas liquids. Components of natural gas that are liquid at surface in field facilities or in gas-processing plants. Natural gas liquids can be classified according to their vapor pressures as low (condensate), intermediate (natural gasoline) and high (liquefied petroleum gas) vapor pressure.

Nitrogen pumping unit. A high-pressure pump or compressor unit capable of delivering high-purity nitrogen gas for use in oil or gas wells. Two basic types of unit are commonly available: a nitrogen converter unit that pumps liquid nitrogen at high pressure through a heat exchanger or converter to deliver high-pressure gas at ambient temperature, and a nitrogen generator unit that compresses and separates air to provide a supply of high-pressure nitrogen gas.

Plugging. The process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Plugging work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging work.

Plug. A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

Pressure pumping. Services that include the pumping of liquids under pressure.

Producing formation. An underground rock formation from which oil, natural gas or water is produced. Any porous rock will contain fluids of some sort, and all rocks at considerable distance below the Earth’s surface will initially be under pressure, often related to the hydrostatic column of ground waters above the reservoir. To produce, rocks must also have permeability, or the capacity to permit fluids to flow through them.

 

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Proppant. Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

Resource Play. Accumulation of hydrocarbons known to exist over a large area.

Shale. A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.

Tight sands. A type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.

Tubulars. A generic term pertaining to any type of oilfield pipe, such as drillpipe, drill collars, pup joints, casing, production tubing and pipeline.

Unconventional resource. An umbrella term for oil and natural gas that is produced by means that do not meet the criteria for conventional production. What has qualified as “unconventional” at any particular time is a complex function of resource characteristics, the available exploration and production technologies, the economic environment, and the scale, frequency and duration of production from the resource. Perceptions of these factors inevitably change over time and often differ among users of the term. At present, the term is used in reference to oil and gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, fractured reservoirs and tight gas sands are considered unconventional resources.

Wellbore. The physical conduit from surface into the hydrocarbon reservoir.

Well stimulation. A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.

Wireline. A general term used to describe well-intervention operations conducted using single-strand or multi-strand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term commonly is used in association with electric logging and cables incorporating electrical conductors.

Workover. The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.

 

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INDEX TO FINANCIAL STATEMENTS

 

Redback Energy Services
Report of Independent Registered Public Accounting Firm			F-2
Combined Balance Sheets as of December 31, 2013 and 2012			F-3
Combined Statements of Comprehensive Loss for the Years Ended December 31, 2013 and 2012			F-4
Combined Statement of Changes in Shareholders’ and Members’ Equity for the Years Ended December  31, 2013 and 2012			F-5
Combined Statements of Cash Flows for the Years Ended December 31, 2013 and 2012			F-6
Notes to Combined Financial Statements			F-7
Condensed Combined Balance Sheets (Unaudited) as of June 30, 2014 and December 31, 2013			F-25
Condensed Combined Statements of Comprehensive (Loss) Income (Unaudited) for the Six Months Ended June 30, 2014 and 2013			F-26
Condensed Combined Statements of Changes in Shareholders’ and Members’ Equity (Unaudited) for the Six Months Ended June 30, 2014			F-27
Condensed Combined Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2014 and 2013			F-28
Notes to Unaudited Condensed Combined Financial Statements			F-29
Stingray Pressure Pumping LLC and Affiliate
Report of Independent Certified Public Accountants			F-44
Combined Balance Sheets as of December 31, 2013 and 2012			F-45
Combined Statements of Operations for the year ended December 31, 2013 and for the Period from March  20, 2012 (inception) to December 31, 2012			F-46
Combined Statements of Members’ Equity for the year ended December 31, 2013 and for the Period from March 20, 2012 (inception) to December 31, 2012			F-47
Combined Statements of Cash Flows for the year ended December 31, 2013 and for the Period from March  20, 2012 (inception) to December 31, 2012			F-48
Notes to Combined Financial Statements			F-49
Condensed Combined Balance Sheets (Unaudited) as of June 30, 2014 and December 31, 2013			F-59
Condensed Combined Statements of Operations (Unaudited) for the Six Months Ended June 30, 2014 and 2013			F-60
Condensed Combined Statements of Members’ Equity (Unaudited) for the Six Months Ended June 30, 2014			F-61
Condensed Combined Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2014 and 2013			F-62
Notes to Unaudited Condensed Combined Financial Statements			F-63
Certain Drilling Rigs of Lantern Drilling Company
Report of Independent Certified Public Accountants			F-72
Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2013 and 2012			F-73
Notes to the Statements of Revenues and Direct Operating Expenses			F-74
Mammoth Energy Partners LP
Report of Independent Registered Public Accounting Firm			F-76
Balance Sheet as of June 30, 2014			F-77
Statement of Operations for the Period from February 5, 2014 (inception) to June 30, 2014			F-78
Statement of Unitholders’ Equity for the Period from February 5, 2014 (inception) to June 30, 2014			F-79
Statement of Cash Flows for the Period from February 5, 2014 (inception) to June 30, 2014			F-80
Notes to Financial Statements			F-81

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Manager

Redback Energy Services

We have audited the accompanying combined balance sheets of Redback Energy Services (the “Company”) as of December 31, 2013 and 2012, and the related combined statements of comprehensive loss, shareholders’ and members’ equity, and cash flows for the years then ended. 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. We were not engaged to perform an audit of the Company’s 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 also 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 combined financial statements referred to above present fairly, in all material respects, the financial position of Redback Energy Services as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

May 14, 2014 (except for Note 10, as to which the date is August 12, 2014)

 

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Redback Energy Services

COMBINED BALANCE SHEETS

 

		December 31,
		2013				2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	8,284,231				9,074,919
Accounts receivable, net			17,290,449				9,828,958
Receivables from related parties			8,157,727				3,639,220
Inventories			3,468,442				908,877
Prepaid expenses			4,593,679				3,183,391
Other current assets			2,133,130				814,665
Total current assets			43,927,658				27,450,030
Property and equipment, net			155,244,177				117,655,811
Goodwill			88,248				88,248
Intangible assets, net			214,271				241,771
Other non-current assets			3,168,766				3,065,822
Total assets		$	202,643,120				148,501,682
LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	18,711,992				18,332,614
Accrued expenses and other current liabilities			9,433,582				2,101,249
Income taxes payable			2,138,425				9,138
Payables to related parties			7,238,119				3,773,361
Line of credit			10,913,308				3,820,000
Current maturities of long-term debt			8,711,671				3,030,527
Total current liabilities			57,147,097				31,066,889
Long-term debt, net of current maturities			22,904,605				7,213,362
Deferred income taxes			1,481,412				1,060,474
Other liabilities			395,888				364,228
Total liabilities			81,929,002				39,704,953
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ AND MEMBERS’ EQUITY
Common stock, par value $0.01 per share, unlimited authorized shares; issued and outstanding 100 shares			1				1
Contributed capital—common shareholders			21,201,185				21,071,120
Members’ equity			95,168,922				89,637,066
Retained earnings (accumulated deficit)			5,928,873				(1,926,111	)
Accumulated other comprehensive (loss) income			(1,584,863	)			14,653
Total shareholders’ and members’ equity			120,714,118				108,796,729
Total liabilities and shareholders’ and members’ equity		$	202,643,120				148,501,682

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

 

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Redback Energy Services

COMBINED STATEMENTS OF COMPREHENSIVE LOSS

 

		Year Ended December 31,
		2013				2012
REVENUE
Services revenue		$	74,658,564			$	34,279,035
Services revenue—related parties			40,123,922				23,623,868
Product revenue			7,753,438				—
Product revenue—related parties			10,012,446				—
			132,548,370				57,902,903
COST AND EXPENSES
Services cost of revenue (exclusive of depreciation and amortization)			66,873,791				27,223,748
Services cost of revenue (exclusive of depreciation and amortization)—related parties			22,604,371				14,374,814
Product cost of revenue (exclusive of depreciation and amortization)			16,748,971				—
Product cost of revenue (exclusive of depreciation and amortization) )—related parties			1,803,721				—
Selling, general and administrative			9,159,640				4,378,514
Selling, general and administrative—related parties			4,453,591				2,063,729
Depreciation and amortization			18,995,400				8,149,172
Impairment of long-lived assets			937,803				2,435,716
			141,577,288				58,625,693
Operating loss			(9,028,918	)			(722,790	)
OTHER INCOME (EXPENSE)
Interest income			207,479				97
Interest expense			(1,905,065	)			(273,744	)
Interest expense—related parties			(107,236	)			—
Other, net			(422,127	)			(49,164	)
			(2,226,949	)			(322,811	)
Loss before income taxes			(11,255,867	)			(1,045,601	)
Provision for income taxes			2,715,022				1,012,824
Net loss		$	(13,970,889	)		$	(2,058,425	)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment, net of tax of $0 for 2012 and 2011			(1,599,516	)			307,657
Comprehensive loss		$	(15,570,405	)		$	(1,750,768	)
PRO FORMA LIMITED PARTNERSHIP DATA (UNAUDITED)
Historical loss before income taxes		$	(11,255,867	)
Pro forma provision for income taxes			3,670,962
Pro forma net loss		$	(14,926,829	)
Pro forma loss per member unit—basic and diluted		$
Weighted average pro forma member units outstanding—basic and diluted

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

 

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Redback Energy Services

COMBINED STATEMENTS OF SHAREHOLDERS’ AND MEMBERS’ EQUITY

 

		Common Stock								Contributed Capital— Common Shareholders				Members’ Equity				Retained Earnings (Accumulated Deficit)				Accumulated Other Comprehensive (Loss) Income				Total
		Shares				Amount
Balance at January 1, 2012			100			$	1			$	18,871,120			$	38,172,981			$	(5,651,453	)		$	(293,004	)		$	51,099,645
Capital contributions			—				—				2,200,000				56,894,537				—								59,094,537
Equity based compensation			—				—				—				363,404												363,404
Dividends paid			—				—				—				—				(10,089	)			—				(10,089	)
Other comprehensive income, net of tax of $0																							307,657				307,657
Net (loss) income			—				—				—				(5,793,856	)			3,735,431				—				(2,058,425	)
Balance at December 31, 2012			100			$	1			$	21,071,120			$	89,637,066			$	(1,926,111	)		$	14,653			$	108,796,729
Capital contributions			—				—				—				26,979,347				—				—				26,979,347
Equity based compensation			—				—				130,065				388,260												518,325
Dividends paid			—				—				—				—				(9,878	)			—				(9,878	)
Other comprehensive loss, net of tax of $0																							(1,599,516	)			(1,599,516	)
Net (loss) income			—				—				—				(21,835,751	)			7,864,862				—				(13,970,889	)
Balance at December 31, 2013			100			$	1			$	21,201,185			$	95,168,922			$	5,928,873			$	(1,584,863	)		$	120,714,118

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

 

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Redback Energy Services

COMBINED STATEMENTS OF CASH FLOWS

 

		Year Ended December 31,
		2013				2012
Cash flows from operating activities
Net loss		$	(13,970,889	)			(2,058,425	)
Adjustments to reconcile net loss to cash provided by operating activities:
Equity based compensation			518,325				363,404
Depreciation and amortization			19,713,131				8,341,924
Bad debt expense			1,647,524				13,000
Loss on disposal of property and equipment			632,587				68,774
Impairment of long-lived assets			937,803				2,435,716
Deferred income taxes			501,928				1,003,110
Changes in assets and liabilities:
Accounts receivable			(9,295,600	)			(7,073,580	)
Receivables from related parties			(6,178,475	)			604,817
Inventories			(3,145,529	)			(981,166	)
Prepaid expenses and other assets			1,078,289				(4,698,243	)
Accounts payable			4,501,111				6,475,791
Accrued expenses and other liabilities			4,744,740				1,715,847
Income taxes payable			2,212,323				8,690
Payables to related parties			264,842				(1,428,408	)
Net cash provided by operating activities			4,162,110				4,791,251
Cash flows from investing activities:
Purchases of property and equipment			(62,234,868	)			(63,601,005	)
Purchases of property and equipment—related parties			(1,721,561	)			(7,982,825	)
Other, net			633,874				—
Net cash used in investing activities			(63,322,555	)			(71,583,830	)
Cash flows from financing activities:
Borrowings from lines of credit			14,433,308				3,670,000
Repayments of lines of credit			(7,340,000	)			—
Proceeds from issuance of notes payable—related parties			3,500,000				3,985,580
Repayments of notes payable—related parties			—				(3,985,580	)
Proceeds from issuance of long-term debt			34,740,903				11,927,901
Repayments of long-term debt			(13,368,516	)			(1,639,292	)
Debt issuance costs			(350,981	)			(104,970	)
Capital contributions			26,979,347				59,113,728
Dividends paid			(9,878	)			(10,091	)
Net cash provided by financing activities			58,584,183				72,957,276
Effect of foreign exchange rate on cash			(214,426	)			40,033
Net (decrease) increase in cash and cash equivalents			(790,688	)			6,204,730
Cash and cash equivalents at beginning of period			9,074,919				2,870,189
Cash and cash equivalents at end of period		$	8,284,231				9,074,919
SUPPLEMENTAL CASH FLOW DISCLOSURE:
NONCASH INVESTING AND FINANCING ACTIVITIES:
Purchases of property and equipment included in trade accounts payable		$	2,839,078			$	8,179,522
Purchases of property and equipment included in payables to related parties		$	42,415			$	1,436,723
OTHER CASH FLOW ITEMS:
Cash paid for interest		$	1,461,480			$	253,662
Cash paid for income taxes		$	1,005			$	4,503

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

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

1.	Organization

Redback Energy Services (“Company”) is a combination of entities under the common control of Wexford Capital LP (“Wexford”). The following operating entities are included in these combined financial statements: Bison Drilling and Field Services, LLC (“Bison”), formed November 15, 2010; Bison Trucking LLC, formed August 9, 2013; Panther Drilling Systems LLC (“Panther”), formed December 11, 2012; Redback Energy Services, LLC (“Energy Services”), formed October 6, 2011; Redback Coil Tubing, LLC (“Coil Tubing”), formed May 15, 2012; Muskie Proppant LLC (“Muskie”), formed September 14, 2011; and Great White Sand Tiger Lodging Ltd. (“Lodging”), formed October 1, 2007; collectively referred to as the “Operating Entities”. Under the organizational documents of the Operating Entities, equity holders are not liable for the debts and obligations of the Company. Mammoth Energy Partners LP (“Mammoth”) was originally formed by Wexford in February 2014 as a holding company under the name Redback Inc., which changed its name to Stingray Energy Services, Inc. in May 2014, and was converted to a Delaware limited partnership in August 2014 in connection with its proposed initial public offering (“IPO”). Immediately prior to the completion of the IPO, all of the outstanding equity interests in the Operating Entities will be contributed to Mammoth in exchange for common units representing limited partner interests of Mammoth. Mammoth will not conduct any material business operations prior to the IPO other than certain activities related to the preparation of the registration statement for the IPO.

The contribution of the Operating Entities will be treated as a combination of entities under common control. The accompanying combined financial statements and related notes of the Company include the assets and liabilities of the Operating Entities at their historical carrying values and the results of their operations and cash flows as if they were combined for all periods presented, or for the periods from their inception, if formed after December 31, 2011.

Operations

The Company provides contract land and directional drilling services and completion and production services for oil and natural gas exploration and production. The Company’s contract land and directional drilling services provides drilling rigs and directional tools for both vertical and horizontal drilling of oil and natural gas wells. The Company’s completion and production services includes coil tubing units used to enhance the flow of oil or natural gas, equipment and personnel used in connection with the completion and early production of oil and natural gas wells, and the production of natural sand proppant that is used primarily for hydraulic fracturing in the oil and gas industry. The Company also provides lodging and related services for people working in the oil sands located in Northern Alberta, Canada.

All of the Company’s operations are in North America. The Company operates in the Permian Basin, the Utica Shale, the Eagle Ford Shale, the Marcellus Shale, the Granite Wash, the Cana Woodford Shale, the Cleveland Sand and the oils sands located in Northern Alberta, Canada. The Company’s business depends in large part on the conditions in the oil and natural gas industry and specifically on the amount of capital spending by its customers. Any prolonged increase or decrease in oil and natural gas prices affects the levels of exploration, development and production activity, as well as the entire health of the oil and natural gas industry. Changes in the commodity prices for oil and natural gas could have a material effect on the Company’s results of operations and financial condition.

 

2.	Summary of Significant Accounting Policies

(a) Principles of Combination

The combined financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). All material intercompany accounts and transactions have been eliminated.

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

(b) Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the allowance for doubtful accounts, depreciation and amortization of property and equipment, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets.

(c) Cash and Cash Equivalents

All highly liquid investments with a maturity of three months or less when acquired are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. Cash balances from time to time may exceed the insured amounts; however the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks on such accounts. The Company had $755,596 and $525,053 of restricted cash included in other current assets in the accompanying Combined Balance Sheets at December 31, 2013 and 2012, respectively, which represented monies held in trust for letters of credit issued to rail car lessors for future lease payments.

(d) Accounts Receivable

The Company records trade accounts receivable at the amounts invoiced to customers, net of an allowance for doubtful accounts. All of the Company’s trade accounts receivable are due from companies in the oil and gas industry, and credit is extended under standard industry terms and conditions, and the Company does not require collateral. Trade accounts receivable are generally due within 30 days of invoicing and are considered past due if not collected in accordance with contractual terms. The Company considers a number of factors in determining the amount of an allowance, including the length of time trade accounts receivable are past due, the customer’s current ability to pay, and the condition of the general economy and industry as a whole. If the Company determines that a customer may not be able to pay, the Company would increase the allowance for doubtful accounts through a charge to income in the period in which that determination is made. If a final determination is made that an account is not collectible, a charge would be made directly to the allowance for doubtful accounts.

Following is a roll forward of the allowance for doubtful accounts for the years ended December 31, 2013 and 2012:

 

Balance, January 1, 2012		$	—
Additions charged to expense			13,000
Deductions for uncollectible receivables written off			—
Balance, December 31, 2012			13,000
Additions charged to expense			1,608,147
Deductions for uncollectible receivables written off			—
Balance, December 31, 2013		$	1,621,147

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

(e) Inventory

Inventory consists of raw sand and processed sand available for sale, chemicals and other products sold as a bi-product of coil tubing operations, and supplies used in performing services. Inventory is stated at the lower of cost or market (net realizable value) on a first-in, first-out basis.

Inventory also consists of coil tubing strings of various widths, diameters, and lengths that are used in providing specialized services to customers who are primarily operators of oil or gas wells. The strings are used at various rates based on factors such as well conditions (i.e. pressure and friction), vertical and horizontal length of the well, running speed of the string in the well, and total running feet accumulated to the string. The Company obtains usage information from data acquisition software and other established assessment methods and attempts to amortize the strings over their estimated useful life. In no event will a string be amortized over a period longer than 12 months. Amortization is included in cost of revenue on the Combined Statements of Comprehensive Loss and amounted to $585,964 and $172,670, for the years ended December 31, 2013 and 2012, respectively.

(f) Prepaid Expenses

Prepaid expenses primarily consist of insurance costs and payments made to a sand supplier (see Note 11). Insurance costs are expensed over the periods that these costs benefit. The payments made to the sand supplier will be recovered through future sand purchases and delivery to the Company over approximately five years. A portion of the prepayments to the sand supplier are included in other non-current assets in the accompanying Combined Balance Sheets.

(g) Property and Equipment

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs that do not increase the capacity, improve the efficiency or safety, or improve or extend the useful life, are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is recorded in operations. Depreciation is calculated using the straight-line method over the shorter of the estimated useful life, or the remaining lease term, as applicable. Depreciation does not begin until property and equipment is placed in service. Once placed in service, depreciation on property and equipment continues while being repaired, refurbished, or between periods of deployment.

(h) Long-Lived Assets

The Company reviews long-lived assets for recoverability in accordance with the provisions of FASB Accounting Standard Codification (“ASC”) Topic 360, Impairment or Disposal of Long-Lived Assets, which requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Recoverability of assets is measured by comparing the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. These evaluations for impairment are significantly impacted by estimates of revenues, costs and expenses, and other factors. If long-lived assets are considered to be impaired, the impairment to be recognized is measured by the amount in which the carrying amount of the assets exceeds the fair value of the assets. In 2013, the Company recognized an impairment loss of $937,803 in the accompanying Combined Statements of Comprehensive Loss for two spudder rigs and related equipment from its drilling segment. The Company made the decision in late 2013, to discontinue offering spudder rig drilling services and has classified the carrying value of the spudder rigs and related equipment in other non-current assets as “held for sale” at December 31, 2013. The impairment was determined by comparing the

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

fair market value, as determined through an appraisal, with the carrying values of the spudder rigs and related equipment. The impairment charge also includes estimates for the costs to sell. The appraisal primarily relied on the market approach to value, which utilized a sales comparison approach based on research of secondary markets for similar assets. As a result of a moratorium on mining for sand on certain properties in the completion and production segment, the Company recognized an impairment loss of $2,435,716 in the accompanying Combined Statements of Comprehensive Loss for the year ended December 31, 2012. The impairment was determined by comparing the fair values of the long-lived assets, as determined through a market analysis, with the carrying values of the related assets. The market analysis was based on the per acre price of properties adjacent to the Company’s properties. The original carrying value of the Company’s property was based on per acre costs ranging from $7,989 to $17,787; whereas the price per acre of adjacent properties averaged $2,500. Based on this market analysis, the Company reduced the carrying amount of its properties to $2,500 per acre.

(i) Goodwill

Goodwill is tested for impairment as of October 1 each year, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The impairment test is a two-step process. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the implied value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities as if the reporting unit had been acquired in a business combination. The fair value of the reporting unit is determined using the discounted cash flow approach, excluding interest. The impairment for goodwill is measured as the excess of its carrying value over its implied value. No impairments existed in the years ended December 31, 2013 or 2012.

(j) Amortizable Intangible Assets

Intangible assets subject to amortization include customer relationships. Customer relationships are amortized based on an estimated attrition factor of their useful life.

(k) Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, amounts receivable from or payable to related parties, lines of credit, and long-term debt. The carrying amount of cash and cash equivalents, trade receivables, and trade payables approximates fair value because of the short-term nature of the instruments. The fair value of the lines of credit and long-term debt approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities.

(l) Revenue Recognition

The Company generates revenue from multiple sources within its operating segments. In all cases, revenue is recognized when services are performed, collection of the receivable is probable, persuasive evidence of an arrangement exists, and the price is fixed and determinable. Services are sold without warranty or right of return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue.

Contract drilling services are provided under daywork or footage contracts, and revenue is recognized as the work progresses based on the days completed or the feet drilled, as applicable. Mobilization revenue and costs for daywork and footage contracts are recognized over the days of actual drilling.

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

Directional drilling services are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Proceeds from customers for the cost of oilfield downhole rental equipment that is involuntarily damaged or lost in-hole are reflected as revenues.

Completion and production services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted, or hourly basis, and revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and the personnel. Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. The labor charges and the use of consumable supplies are reflected on completed field tickets.

Revenue from remote accommodation services is recognized when rooms are occupied and services have been rendered. Advanced deposits on rooms and special events are deferred until services are provided to the customer.

The timing of revenue recognition may differ from contract billing or payment schedules, resulting in revenues that have been earned but not billed (“unbilled revenue”) or amounts that have been billed, but not earned (“deferred revenue”). The Company had $2,367,491 and $1,617,271 of unbilled revenue included in trade accounts receivable at December 31, 2013 and 2012, respectively. The Company had $107,316 of deferred revenue included in accrued expenses and other current liabilities at December 31, 2012. There was no deferred revenue at December 31, 2013.

(m) Accounting for Equity-Based Compensation

The Company records equity-based payments at fair value on the date of grant, and expenses the value of these equity-based payments in compensation expense over the applicable vesting periods.

(n) Income Taxes

Except for Lodging, no provision for federal income tax is included in the accompanying financial statements as federal income taxes, if any, are payable by the members. Limited liability companies are subject to taxation in Texas where the Company does business; therefore, the Company may provide for income taxes attributable to that state on a current basis.

Lodging is subject to corporate income taxes, and such taxes are provided in the financial statements pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 740, Income Taxes. Under FASB ASC 740, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities as a result of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

The Company evaluates tax positions taken or expected to be taken in preparation of its tax returns and disallows the recognition of tax positions that do not meet a “more likely than not” threshold of being sustained upon examination by the taxing authorities. As of December 31, 2013 and 2012, no uncertain tax positions existed. Penalties and interest, if any, are recognized in general and administrative expense. The Company’s 2012, 2011 and 2010 income tax returns remain open to examination by the applicable taxing authorities.

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

(o) Foreign Currency Translation

For foreign operations, assets and liabilities are translated at the year-end exchange rate, and income statement items are translated at the average exchange rate for the year. Resulting translation adjustments are recorded within accumulated other comprehensive income (loss). Assets and liabilities denominated in foreign currencies, if any, are re-measured at the balance sheet date. Resulting transaction gains or losses are included as a component of current period earnings.

(p) Comprehensive Loss

Comprehensive loss consists of net loss and other comprehensive income (loss). Other comprehensive income (loss) included certain changes in equity that are excluded from net loss. Specifically, cumulative foreign currency translation adjustments are included in accumulated other comprehensive income (loss).

(q) Unaudited Pro Forma Income Taxes and Loss Per Member Unit

Prior to the completion of a proposed IPO by Mammoth of its member units, all of the equity interest in the Operating Entities will be contributed to Mammoth and the Operating Entities will become wholly-owned subsidiaries of Mammoth (the “Proposed Contribution Transaction”). Mammoth, a holding company formed in February 2014, that will not conduct any material business operations prior to the Proposed Contribution Transaction other than certain activities related to the preparation of the registration statement for the IPO, will be treated as a partnership under the Internal Revenue Code and will not be subject to income taxes.

In contemplation of the proposed IPO, the Company has presented a pro forma tax provision for income taxes due to the domestication of Sand Tiger’s parent, Great White Dunvegan North SARL.

In contemplation of a proposed IPO, the Company has presented pro forma loss per member unit for the most recent annual period. Pro forma basic and diluted loss per member unit has been computed by dividing net loss attributable to the Company by the number of member units of membership determined as if the member units were outstanding for all of 2013.

(r) Concentrations of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents in excess of federally insured limits and trade receivables. The Company’s accounts receivable have a concentration in the oil and gas industry and the customer base consists primarily of independent oil and natural gas producers. At December 31, 2013, one external customers from the remote accommodation services segment accounted for 11% of our trade accounts receivable balance. At December 31, 2012, one external customers from the completion and production services segment accounted for 18% of the trade accounts receivable balance. No external customers accounted for greater than 10% of the Company’s total revenue for the years ended December 31, 2013 or 2012.

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

3.

Inventory

A summary of the Company’s inventory is shown below:

 

		December 31,
		2013				2012
Raw materials		$	293,566			$	264,117
Work in process			574,027				19,118
Finished goods			1,737,198				176,894
Supplies			863,651				448,748
Total inventory		$	3,468,442			$	908,877

 

4.	Property, Plant and Equipment

Property, plant and equipment include the following:

 

		Useful Life		December 31,
				2013				2012
Land				$	1,637,595			$	1,324,344
Land improvements		15 years or life of lease			3,717,810				3,310,439
Buildings		15-20 years			30,207,179				24,891,622
Drilling rigs and related equipment		3-15 Years			69,671,150				49,012,821
Coil tubing equipment		4-10 years			17,326,676				14,329,973
Other machinery and equipment		7-20 years			40,279,358				24,430,584
Vehicles, trucks and trailers		5-10 years			14,391,824				6,340,114
Other property and equipment		3-12 years			2,243,513				793,638
					179,475,105				124,433,535
Buildings and equipment not yet in service					8,741,116				8,127,828
					188,216,221				132,561,363
Less: accumulated depreciation and amortization					32,972,044				14,905,552
Property, plant and equipment, net				$	155,244,177			$	117,655,811

Depreciation and amortization expense was $18,894,379 and $8,121,672 for the years ended December 31, 2013 and 2012, respectively.

 

5.	Goodwill and Intangible Assets

As of December 31, the Company had the following definite lived intangible asset recorded:

 

		2013				2012
Customer relationships		$	275,000			$	275,000
Less: accumulated amortization			60,729				33,229
		$	214,271			$	241,771

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

The original life of customer relationship was 10 years and remaining average useful life is 7.79 years. Amortization expense was $27,500 for both years ended December 31, 2013 and 2012 and is estimated to reflect the pattern of economic benefits of the intangible assets to the Company. Aggregate expected amortization expense for future periods is expected to be as follows:

 

Year ended December 31:		Amount
2014		$	27,500
2015			27,500
2016			27,500
2017			27,500
2018			27,500
Thereafter			76,771
		$	214,271

Goodwill was $88,248 at December 31, 2013 and 2012. There were no changes to the carrying value of goodwill in 2013 or 2012.

 

6.	Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities included the following:

 

		December 31,
		2013				2012
Accrued compensation, benefits and related taxes		$	2,083,497			$	923,049
Financed insurance premiums			3,229,941				808,542
Other			4,120,144				369,658
		$	9,433,582			$	2,101,249

Financed insurance premiums are due in monthly installments, bear interest at rates ranging from 1.79% to 3.00% in 2013 and 3.03% to 3.43% in 2012, are unsecured, and mature within the twelve month period following the close of the year.

 

7.

Debt

Certain of the Company’s Operating Entities have entered into lines of credit and long-term debt agreements with banks. All debt is collateralized by substantially all assets of the respective Operating Entities. The debt also contains various customary affirmative and restrictive covenants. At December 31, 2013, Bison was in violation of a restrictive covenant under its long term debt with a bank that requires a minimum tangible net worth of $30 million. Bison’s actual tangible net worth was $28.9 million. The Company received a one-time waiver from the bank for the December 31, 2013 violation. Bison expects to be fully compliant in future periods. There were no debt covenant violations at December 31, 2012.

Lines of Credit

In July 2012, Bison entered into a $5.0 million revolving credit facility with a bank. Borrowings under the revolving credit facility were subject to a borrowing limitation based on 80% of eligible accounts receivable balances which are further limited to a concentration of 40% of total accounts receivable for a related party and 20% of total accounts receivable for all other customers. Bison made quarterly interest payments on

 

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amounts borrowed under the facility at the prime rate plus an interest rate spread ranging from 1.75% to 2.75% (based on the senior leverage ratio). At December 31, 2012, the Company had outstanding borrowings of $3,670,000 under this facility with a maturity date of July 15, 2013. In May, 2013, Bison terminated its revolving credit facility and repaid all amounts outstanding with the proceeds from a new $5.0 million credit facility entered into with a different bank. Borrowings under the new revolving credit facility are subject to a borrowing limitation based on 80% of eligible accounts receivable balances which are further limited to a concentration of 40% of total accounts receivable for a related party and 20% of total accounts receivable for all other customers. Bison makes monthly interest payments on amounts borrowed under the facility at the greater of prime rate plus .75% or 4.25% (4.25% at December 31, 2013). At December 31, 2013, Bison had outstanding borrowings of $3,350,154 under this facility and the amount available for borrowing was $510,660. The revolving credit facility matures on June 1, 2014.

In April 2012, Energy Services entered into a $1.5 million revolving credit facility with a bank, and in April 2013, Energy Services amended its revolving credit facility and increased its size from $1.5 million to $2.0 million and extended the maturity date to March 17, 2014. Borrowings under the revolving credit facility are subject to a borrowing base equal to 75% of the outstanding trade receivables of Energy Services. Interest is payable monthly at the greater of the prime rate plus 1.00% or 6.00% (6.00% at December 31, 2013). At December 31, 2013 and 2012, Energy Services had outstanding borrowings of $769,175 and $150,000 under this facility. Energy Services had $1,131,612 available for borrowing under this facility at December 31, 2013. The facility was renewed for one year on April 1, 2014, under substantially the same terms.

In June 2013, Energy Services formed a new division known as Redback Pump Downs (“Pump Downs”) and entered into a $1.5 million revolving credit facility with a bank. Borrowings under the revolving credit facility are secured by 75% of the outstanding eligible trade receivables of Pump Downs. Interest is payable monthly at the greater of the prime rate plus 1.00% or 5.25% (5.25% at December 31, 2013). At December 31, 2013, Pump Downs had outstanding borrowings of $282,500 under this facility and the amount available for borrowing was $112,484. The revolving credit facility matures on June 20, 2014.

In October 2013, Energy Services entered into an $8.5 million revolving credit facility with a bank. Borrowings under the revolving credit facility are subject to a borrowing base equal to 60% of the aggregate amount of certain eligible equipment of Energy Services and Pump Downs. Interest is payable monthly at the greater of prime rate plus 1.00% or 5.25% (5.25% at December 31, 2013). As of December 31, 2013, Energy Services had $2,816,550 outstanding under this facility and the amount available for borrowing was $5,691,150. The revolving credit facility matures on October 9, 2014.

In October 2012, Coil Tubing entered into a secured loan agreement with a bank which contained a revolving credit facility in the amount of $3.0 million maturing on October 5, 2013, with interest payable monthly at the greater of the prime rate or 4.50%. There was no balance outstanding against the revolving line of credit at December 31, 2012. The revolving credit facility was refinanced with a different bank in October 2013 with a maximum borrowing amount of $3.0 million. Borrowings under the revolving credit facility are subject to a borrowing base equal to 80% of Coil Tubing’s eligible accounts receivable. Interest is payable monthly at the greater of prime rate of 4.45% (4.45% at December 31, 2013). At December 31, 2013 Coil Tubing had $1,556,897 outstanding under this facility and the amount available for borrowing was $233,858. The revolving credit facility matures on October 9, 2014.

On January, 2013, Muskie entered into a line of credit with a bank in the amount of $3,000,000. This credit facility is secured by a real estate mortgage. The Company makes monthly interest payment on the amounts borrowed under the facility at the prime rate plus 1.5% (4.75% at December 31, 2013). At December 31, 2013, Muskie had $2,138,032 outstanding under the line of credit, which matured on February 1, 2014. In January 2014, this line of credit was renewed through February 1, 2015.

 

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Long-term Debt

In July 2012, Bison entered into a $10.0 million term loan agreement with a bank. The Company began making quarterly interest payment on September 30, 2012 and quarterly principal and interest payments of $625,000 on December 1, 2012. Amounts borrowed bore interest at LIBOR plus an interest rate spread ranging from 2.5% to 3.5% (based on the senior leverage ratio). As of December 31, 2012, $9,375,000 was outstanding under this agreement, with a maturity date of July 16, 2016. In May 2013, Bison terminated its $10.0 million term loan agreement and repaid all amounts outstanding with the proceeds from a new $30.0 million term loan agreement entered into with a different bank. The new term loan bears interest at the greater of prime plus 0.75% or 4.50% (4.50% at December 31, 2013). Bison was required to make principal payments of $175,000, plus interest, beginning July 1, 2013 and on the first day of each month thereafter through the last day of September 2013. Beginning on October 1, 2013 and on the first day of each month thereafter, Bison was required to make monthly payments pursuant to a 42 month amortization of the remaining principal balance. At December 31, 2013, $27,519,817 was outstanding under this agreement with a maturity date of April 1, 2017. The term loan was increased by $25.0 million in January 2014 in connection with a drilling rig acquisition (see Note 13).

In April 2012, Energy Services entered into a secured loan agreement with a bank which has an aggregate maximum credit amount of $1.5 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 6.00%. The agreement allowed for a 6-month period of loan advances, during which only interest payments were due, followed by 30 monthly installments of principal and interest beginning November 30, 2012 and maturing May 30, 2014. The total amount advanced during the advancing period was $1,004,612. At December 31, 2012, $868,889 was outstanding under this agreement. In April 2013, Energy Services amended its secured loan agreement with a bank and increased its aggregate maximum credit amount from $1.5 million to $3.0 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 6.00%. The loan was converted from an amortizing note to an interest only advancing note with a maturity date of March 31, 2014, which would automatically be extended six months if Energy Services was in compliance with all required covenants. In October 2013, this secured loan agreement was terminated and repaid in full with proceeds from the $8.5 million revolving credit facility entered into with a different bank as described more fully in the “Lines of Credit” section of this footnote.

In October 2012, Coil Tubing entered into a secured loan agreement with a bank which has an aggregate maximum credit amount of $1.2 million. The outstanding borrowings bear interest at the greater of the prime rate or 4.50% (4.50% at December 31, 2012). The agreement allowed for a 6-month period of loan advances, during which only interest payments were due, followed by 29 monthly installments of principal and interest beginning May 5, 2013 and maturing October 5, 2015. There we no amounts outstanding under this agreement at December 31, 2012. In February, 2013 Coil Tubing amended its secured loan agreement with a bank and increased its aggregate maximum credit amount from $1.2 million to $2.4 million. The outstanding borrowings bore interest at the greater of the prime rate or 4.50%. The agreement allowed for a period of loan advances, whereby only monthly interest payments were due and the advancing period was extended from April 5, 2013 to July 31, 2013. Beginning on August 31, 2013 monthly installments of principal and interest were due through a maturity date of July 31, 2016. This secured loan agreement was terminated and repaid in full in October 2013, and Coil Tubing entered into a new secured loan agreement with a different bank and increased the available credit to $8.0 million and extended the period for which advances may be made through June 14, 2014. The note bears interest at a floating rate of the greater of prime plus a margin that ranges from 0.00% to 1.00% based on the ratio of funded debt to EBITDA, or 4.45% (4.45% at December 31, 2013), and requires monthly interest payments through June 14, 2014. After that time, monthly principal and interest payments will be made through the maturity date of October 14, 2017. At December 31, 2013, $4,096,459 was outstanding under this secured loan agreement.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS

 

In June 2013, Energy Services entered into a secured loan agreement with a bank in connection with its formation of Pump Downs which had an aggregate maximum credit amount of $4.0 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 5.25%. The agreement allowed for a six month period of loan advances, during which only monthly interest payments were due. Beginning on July 21, 2014, monthly installments of principal and interest were to be paid through the maturity date of June 21, 2016. In October 2013, this secured loan agreement was terminated and repaid in full with proceeds from the $8.5 million revolving credit facility entered into with a different bank as described more fully in the “Lines of Credit” section of this footnote.

Maturities of long-term debt as of December 31, 2013 are as follows:

 

2014		$	8,711,671
2015			9,768,492
2016			10,158,749
2017			2,977,364
		$	31,616,276

 

8.	Income Taxes

The components of income tax expense attributable to the Company for the years ended December 31, are as follows:

 

		2013				2012
U.S. current income tax expense		$	5,211			$	8,690
U.S. deferred income tax expense			86,209				41,332
Foreign current income tax expense			2,207,649				1,024
Foreign deferred income tax expense			415,953				961,778
		$	2,715,022			$	1,012,824

As of December 31, deferred tax assets and liabilities attributable to the Company consisted of the following:

 

		2013				2012
Deferred tax assets:
Loss carryforwards		$	—			$	321,158
Other			73,855				35,198
Total deferred tax assets			73,855				356,356
Less: valuation allowance			—				—
Total deferred tax assets, net			73,855				356,356
Deferred tax liabilities:
Property, plant, and equipment			(1,525,687	)			(1,390,399	)
Other			(29,580	)			(26,431	)
Total deferred tax liabilities			(1,555,267	)			(1,416,830	)
Net deferred tax liabilities		$	(1,481,412	)		$	(1,060,474	)

 

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In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the Company’s ability to generate future taxable income during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. The Company determined that no valuation allowance was required at December 31, 2013 and 2012. In 2012, the net change in the valuation allowance was $208,931.

At December 31, 2012, Lodging had unused tax loss carryforwards of $1,286,550 which were fully utilized in 2013. There were no unused tax loss carryforwards at December 31, 2013.

The reconciliation of the income tax provision computed at the Company’s effective tax rate is as follows:

 

		2013				2012
Loss before income taxes		$	(11,255,867	)		$	(1,045,601	)
Statutory income tax rate			35	%			35	%
Expected income tax expense			(3,939,553	)			(365,960	)
Non taxable entity			7,530,115				1,992,879
Foreign rate differential			(1,048,847	)			(469,823	)
Other			173,307				69,872
Change in valuation allowance			—				(214,144	)
		$	2,715,022			$	1,012,824

 

9.	Equity Based Compensation

All of the Operating Entities, except for Lodging, operate under limited liability company agreements (the “Agreements”) which define the rights and responsibilities of the members and provide for prioritization of the allocation of profits and losses and capital distributions.

Upon formation of certain Operating Entities, specified members of management were granted the right to receive distributions from their respective Operating Entity, after each contributing member’s unreturned capital balance is reduced to zero—referred to as “Pay-out”. The specified member’s right to receive a post Pay-out distribution is generally subject to continued employment. The Company has valued the post Pay-out distribution rights using the option pricing method as of the grant dates that coincide with the formation of the respective Operating Entities. The exercise price was based on the contributing members’ contribution at the formation date. No dividend yield was included because the Company does not plan to pay dividends. For Coil Tubing, valuation assumptions included a risk free interest rate of 0.59%, and expected life of four years, and an expected volatility of 53.26%. For Energy Services, valuation assumptions included a risk free interest rate of 0.83%, an expected life of four years, and an expected volatility of 70.72%. For Panther, valuation assumptions included a risk free interest rate of 0.47%, and expected life of four years, and an expected volatility of 37.27%. No compensation cost has been recognized during the years ended December, 31, 2013 and 2012, because Pay-out was not deemed probable, and the post Pay-out right does not vest until Pay-out is reached. At December 31, 2013 and 2012, the Company had $1,262,129 in unrecognized compensation costs associated with these post Pay-out distribution rights.

One member of management of Energy Services was granted post Pay-out distribution rights that vest in 50 equal installments over a 50 month period commencing on November 30, 2011, subject to continued employment. If full vesting occurs prior to Pay-out, the member would retain the full right without regard to continued employment. The Company has valued the post Pay-out distribution right using the option pricing method as of the October 7, 2011 grant date and has recognized $26,904 of compensation expense in

 

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NOTES TO COMBINED FINANCIAL STATEMENTS

 

selling, general and administrative expense in the accompanying Combined Statements of Comprehensive Loss in each of the years ended December 31, 2013 and 2012. Unrecognized compensation cost was $53,807 and $80,711 at December 31, 2013 and 2012, respectively.

On September 30, 2012, two specified members of Bison management were each granted 72,917 restricted stock units (“RSU”) in Bison. The RSU’s vest in 4 equal installments beginning on January 1, 2013 and each anniversary date thereafter. The RSU’s were valued at cost which was based on a transaction by a prior member selling its interest at cost in June 2012. Vesting is subject to continued employment; however, the specified members of Bison would retain full rights to any vested RSU’s without regard to employment. The Company has recognized $336,500 of compensation expense in selling, general and administrative expense in the accompanying Combined Statements of Comprehensive Loss in each of the years ended December 31, 2013 and 2012. Unrecognized compensation cost was $673,000 at December 31, 2013.

 

10.	Related Party Transactions

The Company has amended this disclosure as of August 12, 2014, to correct mathematical errors in prior disclosure and change in format of presentation. Management does not believe these changes are individually or in the aggregate material to the financial statements, accordingly these revisions to address the immaterial error corrections have been made at the time of reissuance in accordance with Staff Accounting Bulletin Topic 1N.

The Company provides directional drilling services to an entity under common ownership with Wexford. For the year ending December 31, 2013, the Company recognized $372,553 of revenue from this entity. Receivables from related parties included $282,298 from this entity at December 31, 2013. There was no revenue or receivables from this entity for directional drilling services at December 31, 2012.

The Company provides trucking and rental services to an entity under common ownership with Wexford. For the year ending December 31, 2013, the Company recognized $48,540 of revenue from this entity. Receivables from related parties included $48,540 from this entity at December 31, 2013. There was no revenue or receivables from this entity for trucking and rental services at December 31, 2012.

The Company provides contract land drilling support services to an entity under common ownership with Wexford. For the years ended December 31 2013 and 2012, the Company recognized $4,074,217 and $3,847,272 of revenue, respectively from this entity. Receivables from related parties included $221,085 and $261,803 from this entity at December 31, 2013 and December 31, 2012, respectively.

The Company provides contract land drilling services to an entity under common ownership with Wexford. For the years ended December 31, 2013 and 2012, the Company recognized $9,858,606 and $13,073,798 of revenue, respectively from this entity. Receivables from related parties included $512,327 and $2,014,337 from this entity at December 31, 2013 and December 31, 2012, respectively.

The Company provides lodging and related services to an entity under common ownership with Wexford. For the years ended December 31, 2013 and 2012, the Company recognized $12,789,152 and $6,541,273 of revenue, respectively, from this entity. Receivables from related parties included $3,596,891 and $962,935 from this entity as of December 31, 2013 and 2012, respectively.

The Company sells natural sand proppant to an entity under common ownership with Wexford. For the year ended December 31, 2013, the Company recognized $746,368 of revenue from this related party. There was no revenue from this entity for natural sand proppant at December 31, 2012. There were no receivables from this entity for natural sand proppant at December 31, 2013 and 2012.

 

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The Company sells natural sand proppant to entities under common ownership with Wexford. For the year ended December 31, 2013, the Company recognized $9,266,078 of revenue from this related party. Receivables from related parties included $1,576,199 from this entity as of December 31, 2013. There was no revenue or receivables from this entity for natural sand proppant at December 31, 2012.

The Company provided directional drilling services to a member. For the years ended December 31, 2013 and 2012, the Company recognized $12,906,194 and $138,725, respectively, of revenue from this related party. Receivables from related parties included $1,849,897 and $138,725 at December 31, 2013 and December 31, 2012, respectively.

The Company rents equipment and pays for goods and services on behalf of an entity under common ownership with Wexford. For the year ended December 31, 2013, the Company recognized $57,990 of revenue from this entity. There were no receivables from this entity as of December 31, 2013.

The Company rents equipment and provides other services on behalf of a related party entity that is under common ownership with Wexford. For the years ended December 31, 2013 and 2012, the Company recognized $16,670 and $22,800 of revenue, respectively, from this entity. Receivables from related parties included $70,490 and $59,531 at December 31, 2013 and 2012, respectively.

The Company pays fees to an entity under common ownership with Wexford to transload sand at a rail transloading facility. For the year ended December 31, 2013, the Company incurred $300,781 in costs which are included in product cost of revenue-related parties in the accompanying Combined Statements of Comprehensive Loss. Accounts payable-related parties included $31,509 of transloading fees at December 31, 2013. No such fees were incurred during the year ended December 31, 2012.

The Company purchases equipment and contracts for repairs and maintenance on equipment from an entity under common ownership with Wexford. During the years ended December 31, 2013 and 2012, the Company purchased $1,681,672 and $7,982,825 of equipment from this entity. The Company also contracted for repairs and maintenance services of $245,204 for the year ended December 31, 2013. At December 31, 2013 and 2012, payables to related parties included $1,335,819 and $1,436,723, respectively related to repairs and maintenance and equipment purchases.

The Company rents rotary steerable equipment in connection with its directional drilling services from an entity under common ownership with Wexford. For the years ended December 31, 2013, Cost of services—related parties in the accompanying Combined Statements of Comprehensive Loss included $1,425,860 of such equipment rental costs.

In July 2013, Muskie received a $3,500,000 loan from its members. Muskie accrues interest for the loan at the prime rate plus 2.5% (5.75% at December 31, 2013). The loan matures on July 31, 2014. Amounts payable to related parties includes $3,623,278 for the loan and unpaid interest at December 31, 2013.

An entity under common management with the Company and Wexford provide technical, administrative and payroll services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on estimates of office space provided and time devoted to the Company. During the years ended December 31, 2013 and 2012, the Company incurred total costs under these arrangements of $25,260,782 and $15,593,278, respectively. Of the total costs incurred, $20,363,671 and $14,020,856 is included in Services cost of revenue—related parties for the years ended December 31, 2013 and 2012, respectively. Product cost of revenue – related parties includes $1,502,940 for the year ended December 31, 2013. $3,394,171 and $1,572,422 is included in Selling, general and administrative expenses—related parties for the years ended December 31, 2013 and 2012, in the accompanying Combined Statements of Comprehensive Loss. As of December 31, 2013 and 2012, the Company owed the administrative services affiliate $717,666 and $703,031, respectively, and such amounts are included in payables to related parties in the accompanying balance sheets.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS

 

An entity under common management with the Company and Wexford provide technical, administrative and payroll services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on estimates of office space provided and time devoted to the Company. $695,637 and $394,032 is included in Selling, general and administrative expenses—related parties for the years ended December 31, 2013 and 2012, in the accompanying Combined Statements of Comprehensive Loss. As of December 31, 2013 and December 31, 2012, the Company owed the administrative services affiliate $303,339 and $292,287, respectively, and such amounts are included in payables to related parties in the accompanying balance sheets.

From time to time, the Company pays for goods and services on behalf of related party entities under common control, or these related parties pay for goods and services on behalf of the Company. During the years ended December 31, 2013 and 2012, the Company incurred $638,120 and $380,839, respectively, of costs which are included in Selling, general and administrative expenses—related parties, in the accompanying Combined Statements of Comprehensive Loss. At December 31, 2013 and 2012, receivables from related parties included $0 and $201,889 related to these arrangements. At December 31, 2013 and December 31, 2012 payables to related parties included $1,199,818 and $1,131,162, respectively, related to these arrangements.

Wexford provides technical, administrative and payroll services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on estimates of office space provided and time devoted to the Company. During the years ended December 31, 2013 and 2012, the Company incurred $295,299 and $70,894, respectively, of costs which are included in Selling, general and administrative expenses—related parties, in the accompanying Combined Statements of Comprehensive Loss. As of December 31, 2013 and December 31, 2012, the Company owed $26,690 and $210,158, respectively, and such amounts are included in payables to related parties in the accompanying balance sheets.

 

11.	Commitments and Contingencies

In September 2010, Windsor Permian, LLC (now known as Diamondback O&G LLC) (“Windsor Permian”) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with Robert A. Stein the (“Plaintiff”), and Windsor Permian purchased the property subject to that agreement. Windsor Permian subsequently contributed the property to the Company. In an amended complaint filed November 2012 by the Plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the Plaintiff seeks damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with Plaintiff’s contract but that the interference did not cause the Plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference. The parties involved have agreed upon a schedule for pretrial activities. Subsequently, the Plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss Plaintiff’s claims on the grounds that the damage claim is speculative and that Plaintiff cannot prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013, and on March 13, 2014, the first

 

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judicial district court of Goodhue County, Minnesota, issued a decision in favor of the defendants. On April 9, 2014, counsel for both Plaintiff and the defendants have agreed that neither party will pursue an appeal from any order issued in the case, and that each side would likewise waive any entitlement to taxable costs. If there is no appeal within 60 days of the decision, the case will be closed. Management has determined that the possibility of loss is remote; however litigation is inherently uncertain and management cannot determine the amount of loss, if any that may result.

The Company is routinely involved in various legal matters arising from the normal course of business. There were no legal matters outstanding, other than what is described in the immediately preceding paragraph, which are expected to have a material adverse effect on the financial position or results of operations of the Company.

The Company entered into a purchase agreement on August 15, 2012, with a sand supplier. The Company is subject to a monthly commitment for the purchase of a minimum amount of sand. The Company must purchase 548 tons per day which equates to 200,020 tons of sand on an annual basis. If the minimum purchase requirement is not met, the shortfall is settled on a monthly basis. Future commitments related to this agreement are:

 

2014		$	1,000,100
2015			1,000,100
2016			1,000,100
2017			328,800
Total Commitments		$	3,329,100

Shortfall expense incurred under this purchase agreement for the period ended December 31, 2012 was $585,750. The Company purchased the monthly minimum amount of sand in 2013. The Company has identified an alternative source for sand and does not believe the loss of the primary supplier under the purchase agreement would have a material adverse effect on the Company.

In October 1, 2013, a specified member of management was granted a long-term incentive award (“LTIA”) equal to 2% of the net proceeds from the sale or other disposition of Muskie and/or Lodging. The distribution of the LTIA is subject to certain adjustments, including deductions for costs and expenses related to the disposition and recovery of specified capital by members’ or equity holders, as applicable. The LTIA vests in 4 equal installments on December 31 of each year, beginning on December 31, 2013. Vesting is subject to continued employment; however the specified member of management would retain full right to any vested portion without regard to employment. No amounts have been accrued or disclosed for the LTIA as the sale or disposition of Muskie and/or Lodging is not deemed probable and the LTIA distribution is not estimable.

The Company leases real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2022. Aggregate future minimum lease payments under these non-cancelable operating leases in effect at December 31, 2013 are as follows:

 

2014		$	2,538,504
2015			2,375,407
2016			1,776,865
2017			1,216,448
2018			805,600
Thereafter			2,511,700
Total minimum lease payments		$	11,224,524

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

For the years ended December 31, 2013 and 2012, the Company recognized rent expense of $2,011,365 and $219,550, respectively.

The Company has entered into employment contracts with certain key employees for remaining periods up to two years. In the event of termination without good cause, these employees may receive compensation owed under the contracts. The maximum that could be paid under the contracts at December 31, 2013 is $890,000.

The Company has entered into an agreement in which certain key employees would receive bonuses in the event of a sale or initial public offering. The maximum amount that could be paid under the agreement at December 31, 2013 is $3.0 million upon a sale or $1.5 million upon an initial public offering.

 

12.	Operating Segments

The Company is organized into four reportable segments based on the nature of services provided and the basis in which management makes business and operating decisions. The Company principally provides oilfield services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and natural gas producers.

The Company’s four segments consist of contract land and directional drilling services, completion and production—services, completion and production—natural sand proppant production, and remote accommodation services. The drilling segment provides contract land and directional drilling services. The completion and production—services segment provides pressure control services, flowback services, and equipment rental services. The completion and production—natural sand proppant production segment produces and sells sand for use in hydraulic fracturing. The remote accommodation services business provides housing, kitchen and dining, and recreational service facilities for oilfield workers that are located in remote areas away from readily available lodging.

During 2012 and 2013, the drilling segment primarily served customers in the Permian Basin in West Texas and the Utica Shale in Eastern Ohio. The completion and production operations primarily served customers in the Permian Basin in West Texas, the Eagle Ford Shale in South Texas the Granite Wash in Oklahoma and Texas, and the Cana Woodford Shale and the Cleveland Sand in Oklahoma. The remote accommodation operation served customers in the oil sands of Northern Alberta, Canada.

 

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Redback Energy Services

NOTES TO COMBINED FINANCIAL STATEMENTS

 

The following table sets forth certain financial information with respect to the Company’s reportable segments:

 

						Completion and Production
		Contract Land and Directional Drilling Services				Services				Natural Sand Proppant Production				Remote Accommodation Services				Total
2013
Revenue from external customers		$	36,587,676			$	25,833,044			$	7,753,438			$	12,237,844			$	82,412,002
Revenue from related parties		$	23,202,563			$	4,132,207			$	10,012,446			$	12,789,152			$	50,136,368
Interest expense		$	1,566,327			$	254,165			$	191,809			$	—			$	2,012,301
Depreciation and amortization expense		$	9,942,018			$	4,201,754			$	3,542,751			$	1,308,877			$	18,995,400
Impairment of long-lived assets		$	937,803			$	—			$	—			$	—			$	937,803
Income tax provision		$	60,564			$	35,682			$	(4,826	)		$	2,623,602			$	2,715,022
Net income (loss)		$	(11,757,041	)		$	(1,097,151	)		$	(8,981,559	)		$	7,864,862			$	(13,970,889	)
Total expenditures for property plant and equipment		$	36,487,192			$	20,519,804			$	1,400,382			$	5,549,051			$	63,956,429
Goodwill		$	—			$	88,248			$	—			$	—			$	88,248
Intangible assets, net		$	—			$	214,271			$	—			$	—			$	214,271
Total Assets		$	86,498,444			$	46,693,764			$	37,342,376			$	32,108,536			$	202,643,120
2012
Revenue from external customers		$	13,606,762			$	13,044,251			$	—			$	7,628,022			$	34,279,035
Revenue from related parties		$	13,235,323			$	3,847,272			$	—			$	6,541,273			$	23,623,868
Interest expense		$	211,845			$	61,899			$	—			$	—			$	273,744
Depreciation and amortization expense		$	5,267,479			$	1,590,147			$	291,175			$	1,000,371			$	8,149,172
Impairment of long-lived assets		$	—			$	—			$	2,435,716			$	—			$	2,435,716
Income tax provision		$	47,276			$	2,746			$	—			$	962,802			$	1,012,824
Net income (loss)		$	(1,537,305	)		$	(83,460	)		$	(4,173,091	)		$	3,735,431			$	(2,058,425	)
Total expenditures for property, plant and equipment		$	28,954,479			$	17,939,950			$	19,241,826			$	5,447,575			$	71,583,830
Goodwill		$	—			$	88,248			$	—			$	—			$	88,248
Intangible assets, net		$	—			$	241,771			$	—			$	—			$	241,771
Total Assets		$	55,231,386			$	35,168,097			$	34,047,339			$	24,054,860			$	148,501,682

 

13.	Subsequent Events

The Company has evaluated the period after December 31, 2013 through May 14, 2014, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

On January 29, 2014, Bison acquired five used drilling rigs for $50.6 million. The acquisition will be accounted for as a business combination and was financed through $25.6 million of member contributions and $25.0 million of additional long-term debt. Bison amended its existing long-term debt agreement with a bank to add $25.0 million in borrowings, suspend monthly principal payments until May 31, 204, and extend the maturity date to April 30, 2017. All other terms of the debt agreement remained substantially the same.

 

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Redback Energy Services

CONDENSED COMBINED BALANCE SHEETS

(Unaudited)

 

		June 30,				December 31,
		2014				2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	7,357,561			$	8,284,231
Accounts receivable, net			33,717,695				17,290,449
Receivables from related parties			9,385,538				8,157,727
Inventories			1,910,647				3,468,442
Prepaid expenses			2,830,267				4,593,679
Other current assets			5,940,038				2,133,130
Total current assets			61,141,746				43,927,658
Property and equipment, net			214,506,722				155,244,177
Goodwill			88,248				88,248
Intangible assets, net			200,521				214,271
Other non-current assets			4,190,159				3,168,766
Total assets		$	280,127,396			$	202,643,120
LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	21,384,800			$	18,711,992
Accrued expenses and other current liabilities			13,452,123				9,433,582
Income taxes payable			31,430				2,138,425
Payables to related parties			5,227,456				7,238,119
Line of credit			14,971,920				10,913,308
Current maturities of long-term debt			16,639,782				8,711,671
Total current liabilities			71,707,511				57,147,097
Long-term debt, net of current maturities			38,818,693				22,904,605
Deferred income taxes			1,634,305				1,481,412
Other liabilities			445,059				395,888
Total liabilities			112,605,568				81,929,002
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ AND MEMBERS’ EQUITY
Common stock, par value $.01 per share, unlimited authorized shares; issued and outstanding (200 shares at June 30, 2014; 100 shares at December 31, 2013)		$	2			$	1
Contributed capital-common stockholders			21,201,185				21,201,185
Members’ equity			138,983,834				95,168,922
Retained earnings			8,781,048				5,928,873
Accumulated other comprehensive loss			(1,444,241	)			(1,584,863	)
Total shareholders’ and members’ equity			167,521,828				120,714,118
Total liabilities and shareholders’ and members’ equity		$	280,127,396			$	202,643,120

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

 

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Redback Energy Services

CONDENSED COMBINED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

		Six Months Ended June 30,
		2014				2013
REVENUE
Services revenue		$	73,974,060			$	34,474,662
Services revenue—related parties			10,089,838				23,319,329
Product revenue			16,941,105				1,881,325
Product revenue—related parties			4,885,257				3,610,231
			105,890,260				63,285,547
COST AND EXPENSES
Services cost of revenue (exclusive of depreciation and amortization)			62,353,688				31,041,857
Services cost of revenue (exclusive of depreciation and amortization)—related parties			698,015				11,199,509
Product cost of revenue (exclusive of depreciation and amortization)			18,107,068				5,438,561
Product cost of revenue (exclusive of depreciation and amortization)—related parties			1,196,926				630,963
Selling, general and administrative			4,467,572				3,016,249
Selling, general and administrative—related parties			1,614,574				2,145,079
Depreciation and amortization			15,033,616				8,486,342
			103,471,459				61,958,560
Operating income			2,418,801				1,326,987
OTHER INCOME (EXPENSE)
Interest income			106,809				247
Interest expense			(1,762,492	)			(801,279	)
Interest expense—related parties			(101,184	)			—
Other, net			(149,685	)			153,114
			(1,906,552	)			(647,918	)
Income before income taxes			512,249				679,069
Provision for income taxes			1,058,634				1,416,945
Net loss		$	(546,385	)		$	(737,876	)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment, net of tax of $0 for 2014 and 2013			140,622				(160,585	)
Comprehensive loss		$	(405,763	)		$	(898,461	)
PRO FORMA LIMITED PARTNERSHIP DATA (UNAUDITED)
Historical income before income taxes		$	512,249
Pro forma provision for income taxes			1,333,620
Pro forma net loss		$	(821,371	)
Pro forma loss per member unit—basic and diluted		$
Weighted average pro forma member units outstanding—basic and diluted

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

 

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CONDENSED COMBINED STATEMENTS OF SHAREHOLDERS’ AND MEMBERS’ EQUITY

(Unaudited)

 

		Common Stock								Contributed Capital- Common Shareholders				Members’ Equity				Retained Earnings				Accumulated Other Comprehensive Loss				Total
		Shares				Amount
Balance at December 31, 2013			100			$	1			$	21,201,185			$	95,168,922			$	5,928,873			$	(1,584,863	)		$	120,714,118
Capital contributions			100				1				—				47,024,431				—				—				47,024,432
Equity based compensation			—				—				—				194,128				—				—				194,128
Dividends paid			—				—				—				—				(5,087	)			—				(5,087	)
Other comprehensive loss, net of tax of $0			—				—				—				—				—				140,622				140,622
Net loss			—				—				—				(3,403,647	)			2,857,262				—				(546,385	)
Balance at June 30, 2014			200			$	2			$	21,201,185			$	138,983,834			$	8,781,048			$	(1,444,241	)		$	167,521,828

 

 

 

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

 

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Redback Energy Services

CONDENSED COMBINED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		Six Months Ended June 30,
		2014				2013
Cash flows from operating activities
Net loss		$	(546,385	)		$	(737,876	)
Adjustments to reconcile net loss to cash used in operating activities:
Equity based compensation			194,128				181,701
Depreciation and amortization			15,289,091				8,840,095
Bad debt expense			—				39,377
Loss on disposal of property and equipment			163,025				47,590
Equity in loss of investee			—				(1,443	)
Deferred income taxes			152,893				408,753
Changes in assets and liabilities:
Accounts receivable			(16,412,356	)			(3,875,662	)
Receivables from related parties			(1,283,447	)			(10,092,287	)
Inventories			644,882				(3,131,544	)
Prepaid expenses and other assets			(2,041,082	)			307,875
Accounts payable			3,633,022				(6,812,915	)
Payables to related parties			(1,958,937	)			3,313,764
Accrued expenses and other current liabilities			3,378,542				3,140,997
Income taxes payable			(2,275,501	)			1,009,306
Net cash used in operating activities			(1,062,125	)			(7,362,269	)
Cash flows from investing activities:
Purchases of property and equipment			(74,871,014	)			(16,957,219	)
Purchases of property and equipment—related parties			(257,454	)			(1,488,000	)
Proceeds from disposal of property and equipment			575,195				971,000
Other, net			—				981,656
Net cash used in investing activities			(74,553,273	)			(16,492,563	)
Cash flows from financing activities:
Borrowings from lines of credit			11,131,840				15,148,956
Repayments of lines of credit			(7,073,228	)			(12,839,438	)
Proceeds from issuance of long-term debt			27,200,000				17,049,341
Repayments of long-term debt			(3,357,801	)			(10,357,046	)
Debt issuance costs			(272,985	)			(307,543	)
Capital contributions			47,024,431				17,313,449
Capital distributions			—				(120,000	)
Dividends paid			(5,087	)			(10,018	)
Net cash provided by financing activities			74,647,170				25,877,701
Effect of foreign exchange rate on cash			41,558				(151,922	)
Net (decrease) increase in cash and cash equivalents			(926,670	)			1,870,947
Cash and cash equivalents at beginning of period			8,284,231				9,074,919
Cash and cash equivalents at end of period		$	7,357,561			$	10,945,866

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

 

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Redback Energy Services

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

 

1.	Organization and Basis of Presentation

Redback Energy Services (“Company”) is a combination of entities under the common control of Wexford Capital LP (“Wexford”). The following operating entities are included in these combined financial statements: Bison Drilling and Field Services, LLC (“Bison”), formed November 15, 2010; Bison Trucking LLC, formed August 9, 2013; Panther Drilling Systems LLC (“Panther”), formed December 11, 2012; Redback Energy Services, LLC (“Energy Services”), formed October 6, 2011; Redback Coil Tubing, LLC (“Coil Tubing”), formed May 15, 2012; Muskie Proppant LLC (“Muskie”), formed September 14, 2011; and Great White Sand Tiger Lodging Ltd. (“Lodging”), formed October 1, 2007; collectively referred to as the “Operating Entities”. Under the organizational documents of the Operating Entities, equity holders are not liable for the debts and obligations of the Company. Mammoth Energy Partners LP (“Mammoth”) was originally formed by Wexford in February 2014 as a holding company under the name Redback, Inc., changed its name to Stingray Energy Services, Inc. in May 2014, and was converted to a Delaware limited partnership in August 2014 in connection with its proposed initial public offering (“IPO”). Immediately prior to the completion of the IPO, Wexford will cause all of the outstanding equity interests in the Operating Entities will be contributed to Mammoth in exchange for common units representing limited partner interest of Mammoth. Mammoth will not conduct any material business operations prior to the IPO other than certain activities related to the preparation of the registration statement for the IPO.

The contribution of the Operating Entities will be treated as a combination of entities under common control. The accompanying condensed combined financial statements and related notes of the Company include the assets and liabilities of the Operating Entities at their historical carrying values and the results of their operations and cash flows if they were combined for all periods presented, or for the periods from their inception if formed after December 31, 2012.

These unaudited condensed combined financial statements should be read in conjunction with the audited combined financial statements for the year ended December 31, 2013. In the opinion of management, the statements reflect all adjustments necessary for a fair presentation of the results of interim periods. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles general accepted in the United State of America (“U.S. GAAP”), which are not required for interim purposes, have been condensed or omitted. These financial statements reflect all adjustments, consisting only of normal, recurring adjustments that, in the opinion of the Company’s management, are necessary for a fair presentation of the financial position, results of operations and cash flows for the periods presented. Operating results for the six month period ended June 30, 2014 are not necessarily indicative of the results that may be expected for any subsequent quarter or for the year ending December 31, 2014.

Operations

The Company provides contract land and directional drilling services and completion and production services for oil and natural gas exploration and production. The Company’s contract land and directional drilling services provides drilling rigs and directional tools for both vertical and horizontal drilling of oil and natural gas wells. The Company’s completion and production services includes coil tubing units used to enhance the flow of oil or natural gas, equipment and personnel used in connection with the completion and early production of oil and natural gas wells, and the production of natural sand proppant that is used primarily for hydraulic fracturing in the oil and gas industry. The Company also provides lodging and related services for people working in the oil sands located in Northern Alberta, Canada.

All of the Company’s operations are in North America. The Company operates in the Permian Basin, the Utica Shale, the Eagle Ford Shale, the Marcellus Shale, the Granite Wash, the Cana Woodford Shale, the Cleveland Sand and the oils sands located in Northern Alberta, Canada. The Company’s business depends in

 

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NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

 

large part on the conditions in the oil and natural gas industry and specifically on the amount of capital spending by its customers. Any prolonged increase or decrease in oil and natural gas prices affects the levels of exploration, development and production activity, as well as the entire health of the oil and natural gas industry. Changes in the commodity prices for oil and natural gas could have a material effect on the Company’s results of operations and financial condition.

 

2.	Summary of Significant Accounting Policies

(a) Principles of Combination

The combined financial statements are prepared in accordance with U.S. GAAP. All material intercompany accounts and transactions have been eliminated.

(b) Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the allowance for doubtful accounts, depreciation and amortization of property and equipment, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets.

(c) Cash and Cash Equivalents

All highly liquid investments with an original maturity of three months or less are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. Cash balances from time to time may exceed the insured amounts; however the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks on such accounts. The Company had $756,721 and $755,596 of restricted cash included in other current assets in the accompanying Condensed Combined Balance Sheets at June 30, 2014 and December 31, 2013, respectively, which represented monies held in trust for letters of credit issued to rail car lessors for future lease payments.

(d) Accounts Receivable

Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses. The Company grants credit to customers in the ordinary course of business and generally does not require collateral. Most areas in which the Company operates provide for a mechanic’s lien against the property on which the service is performed if the lien is filed within the statutorily specified time frame. Customer balances are generally considered delinquent if unpaid by the 30^th day following the invoice date and credit privileges may be revoked if balances remain unpaid.

The Company regularly reviews receivables and provides for estimated losses through an allowance for doubtful accounts. In evaluating the level of established reserves, the Company makes judgments regarding its customers’ ability to make required payments, economic events, and other factors. As the financial condition of customers change, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event the Company was to determine that a customer may not be able to make required payments, the Company would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made of their uncollectability.

 

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NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

 

(e) Inventory

Inventory consists of raw sand and processed sand available for sale, chemicals and other products sold as a bi-product of coil tubing operations, and supplies used in performing services. Inventory is stated at the lower of cost or market (net realizable value) on a first-in, first-out basis.

Inventory also consists of coil tubing strings of various widths, diameters, and lengths that are used in providing specialized services to customers who are primarily operators of oil or gas wells. The strings are used at various rates based on factors such as well conditions (i.e. pressure and friction), vertical and horizontal length of the well, running speed of the string in the well, and total running feet accumulated to the string. The Company obtains usage information from data acquisition software and other established assessment methods and attempts to amortize the strings over their estimated useful life. In no event will a string be amortized over a period longer than 12 months. Amortization is included in services cost of revenue in the Condensed Combined Statements of Comprehensive Income (Loss) and totaled $912,913 and $217,710, for the six months ended June 30, 2014 and 2013, respectively.

(f) Prepaid Expenses

Prepaid expenses primarily consist of insurance costs and payments made to a sand supplier. Insurance costs are expensed over the periods that these costs benefit. The payments made to the sand supplier will be recovered through future sand purchases and delivery to the Company over approximately five years. A portion of the prepayments to the sand supplier are included in other non-current assets in the accompanying Condensed Combined Balance Sheets.

(g) Property and Equipment

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs that do not increase the capacity, improve the efficiency or safety, or improve or extend the useful life, are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is recorded in operations. Depreciation is calculated using the straight-line method over the shorter of the estimated useful life, or the remaining lease term, as applicable. Depreciation does not begin until property and equipment is placed in service. Once placed in service, depreciation on property and equipment continues while being repaired, refurbished, or between periods of deployment.

(h) Long-Lived Assets

The Company reviews long-lived assets for recoverability in accordance with the provisions of FASB Accounting Standard Codification (“ASC”) Topic 360, Impairment or Disposal of Long-Lived Assets, which requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Recoverability of assets is measured by comparing the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. These evaluations for impairment are significantly impacted by estimates of revenues, costs and expenses, and other factors. If long-lived assets are considered to be impaired, the impairment to be recognized is measured by the amount in which the carrying amount of the assets exceeds the fair value of the assets. No indications of impairment existed during the six months ended June 30, 2014 or 2013.

(i) Goodwill

Goodwill is tested for impairment as of October 1 each year, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The impairment test is a two-step process. First, the

 

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NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

 

fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the implied value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities as if the reporting unit had been acquired in a business combination. The fair value of the reporting unit is determined using the discounted cash flow approach, excluding interest. The impairment for goodwill is measured as the excess of its carrying value over its implied value. No impairments existed during the six months ended June 30, 2014 or 2013.

(j) Amortizable Intangible Assets

Intangible assets subject to amortization include customer relationships. Customer relationships are amortized based on an estimated attrition factor of their useful life. The original life of customer relationship was 10 years and remaining average useful life is 8 years. Amortization expense was $13,750 for the six months ended June 30, 2014 and 2013. There were no acquisitions of intangible assets during the six months ended June 30, 2014 or 2013.

(k) Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, amounts receivable or payable to related parties, lines of credit and long-term debt. The carrying amount of cash and cash equivalents, trade receivables, and trade payables approximates fair value because of the short-term nature of the instruments. The fair value of the lines of credit and long-term debt approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities.

(l) Revenue Recognition

The Company generates revenue from multiple sources within its operating segments. In all cases, revenue is recognized when services are performed, collection of the receivable is probable, persuasive evidence of an arrangement exists, and the price is fixed and determinable. Services are sold without warranty or right of return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue.

Contract drilling services are provided under daywork or footage contracts, and revenue is recognized as the work progresses based on the days completed or the feet drilled, as applicable. Mobilization revenue and costs for daywork and footage contracts are recognized over the days of actual drilling.

Directional drilling services are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Proceeds from customers for the cost of oilfield downhole rental equipment that is involuntarily damaged or lost in-hole are reflected as revenues.

Completion and production services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted, or hourly basis, and revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and personnel. Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. The labor charges and the use of consumable supplies are reflected on the completed field tickets.

Revenue from remote accommodation services is recognized when rooms are occupied and services have been rendered. Advanced deposits on rooms and special events are deferred until services are provided to the customer.

 

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NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

 

The timing of revenue recognition may differ from contract billing or payment schedules, resulting in revenues that have been earned but not billed (“unbilled revenue”) or amounts that have been billed, but not earned (“deferred revenue”). The Company had $5,749,553 and $2,895,974 of unbilled revenue included in trade accounts receivable at June 30, 2014 and December 31, 2013, respectively. There was no deferred revenue at June 30, 2014 and December 31, 2013.

(m) Accounting for Equity-Based Compensation

The Company records equity-based payments at fair value on the date of grant, and expenses the value of these equity-based payments in compensation expense over the applicable vesting periods.

(n) Income Taxes

Except for Lodging, no provision for federal income tax is included in the accompanying financial statements as federal income taxes, if any, are payable by the members. Limited liability companies are subject to taxation in Texas where the Company does business; therefore, the Company may provide for income taxes attributable to that state on a current basis.

Lodging is subject to corporate income taxes, and such taxes are provided in the financial statements pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 740, Income Taxes. Under FASB ASC 740, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities as a result of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

The Company evaluates tax positions taken or expected to be taken in preparation of its tax returns and disallows the recognition of tax positions that do not meet a “more likely than not” threshold of being sustained upon examination by the taxing authorities. During the six months ended June 30, 2014 and 2013, no uncertain tax positions existed. Penalties and interest, if any, are recognized in general and administrative expense. The Company’s 2013, 2012, and 2011 income tax returns remain open to examination by the applicable taxing authorities.

(o) Foreign Currency Translation

For foreign operations, assets and liabilities are translated at the period-end exchange rate, and income statement items are translated at the average exchange rate for the period. Resulting translation adjustments are recorded within accumulated other comprehensive income (loss). Assets and liabilities denominated in foreign currencies, if any, are re-measured at the balance sheet date. Resulting transaction gains or losses are included as a component of current period earnings.

(p) Comprehensive Loss

Comprehensive loss consists of net loss and other comprehensive income (loss). Other comprehensive income (loss) included certain changes in equity that are excluded from net loss. Specifically, cumulative foreign currency translation adjustments are included in accumulated other comprehensive income (loss).

 

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(q) Unaudited Pro Forma Income Taxes and Earnings (Loss) Per Share

Prior to the completion of a proposed IPO by Mammoth of its member units, all of the equity interest in the Operating Entities will be contributed to Mammoth and the Operating Entities will become wholly-owned subsidiaries of Mammoth (the “Proposed Contribution Transaction”). Mammoth, a holding company formed in February 2014, will not conduct any material business operations prior to the Proposed Contribution Transaction other than certain activities related to the preparation of the registration statement for the IPO, and will be treated as a partnership under the Internal Revenue Code and will not be subject to income taxes.

In contemplation of the proposed IPO, the Company has presented a pro forma provision for income taxes due to the domestication of Sand Tigers parent, Great White Dunvegan North SARL.

The Company has presented pro forma loss per member unit for the most recent interim period. Pro forma basic and diluted loss per member unit has been computed by dividing net loss attributable to the Company by the number of member units of membership determined as if the member units were outstanding for all of the six months ended June 30, 2014.

(r) Concentrations of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents in excess of federally insured limits and trade receivables. The Company’s accounts receivable have a concentration in the oil and gas industry and the customer base consists primarily of independent oil and natural gas producers. At June 30, 2014 one external customer from the contract land and directional drilling services segment accounted for 14% of the Company’s trade accounts receivable balance. Additionally, at June 30, 2014 one external customer from the sand proppant segment accounted for 12% of the Company’s trade accounts receivable balance. At December 31, 2013, one external customer from the remote accommodation services segment accounted for 11% of our trade accounts receivable balance.

 

3.

Inventory

A summary of the Company’s inventory is shown below:

 

		June 30,				December 31,
		2014				2013
Raw materials		$	113,133			$	293,566
Work in process			238,502				574,027
Finished goods			361,880				1,737,198
Supplies			1,197,132				863,651
Total inventory		$	1,910,647			$	3,468,442

 

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4.	Property, Plant and Equipment

Property, plant and equipment include the following:

 

		Useful Life		June 30, 2014				December 31, 2013
Land				$	1,637,594			$	1,637,595
Land improvements		15 years or life of lease			3,717,810				3,717,810
Buildings		15-20 years			31,870,199				30,207,179
Drilling rigs and related equipment		3-15 years			122,416,278				69,671,150
Coil tubing equipment		4-10 years			21,685,603				17,326,676
Other machinery and equipment		7-20 years			36,447,651				40,279,358
Vehicles, trucks and trailers		5-10 years			20,790,147				14,391,824
Other property and equipment		3-12 years			11,951,856				2,243,513
					250,517,138				179,475,105
Buildings and equipment not yet in service					11,073,743				8,741,116
					261,590,881				188,216,221
Less: accumulated depreciation and amortization					47,084,159				32,972,044
Property, plant and equipment, net				$	214,506,722			$	155,244,177

Depreciation and amortization expense was $15,033,616 and $8,486,342 for the six months ended June 30, 2014 and 2013, respectively.

 

5.

Debt

Certain of the Company’s Operating Entities have entered into lines of credit and long-term debt agreements with banks. All debt is collateralized by substantially all assets of the respective Operating Entities. The debt also contains various customary affirmative and restrictive covenants. At June 30, 2014, Bison was in violation of the minimum fixed coverage ratio under its long term debt, which requires a ratio of 1.35 to 1. The ratio at June 30, 2014 was 1.20 to 1. Bison received a waiver from the bank for the June 30, 2014 violation.

At June 30, 2014, Energy Services was in violation of the debt service coverage ratio, which requires a minimum ratio of 1.25 to 1. The ratio at June 30, 2014 was 1.13 to 1. Energy Services received a waiver from the bank for the June 30, 2014 violation and expects to be in compliance in future periods.

At December 31, 2013, Bison was in violation of a restrictive covenant under its long term debt with a bank that requires a minimum tangible net worth of $30 million. Bison’s actual tangible net worth was $28.9 million. Bison received a waiver from the bank for the December 31, 2013 violation.

At June 30, 2014, Bison was in violation of the maximum leverage ratio covenant which requires a ratio of 3.00 to 1. The ratio at June 30, 2014 was 4.31 to 1. The Company received a waiver from the bank and expects to be compliant in future periods.

Lines of Credit

In May 2013, Bison entered into a $5.0 million credit facility with a bank. Borrowings under the revolving credit facility are subject to a borrowing limitation based on 80% of eligible accounts receivable balances which are further limited to a concentration of 40% of total accounts receivable for a related party and 20% of total accounts receivable for all other customers. Bison makes monthly interest payments on amounts borrowed under the facility at the greater of prime rate plus 0.75% or 4.25% (4.25% at June 30, 2014). In

 

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May 2014, Bison amended its facility to increase its size to $7.0 million and extend the maturity date. At June 30, 2014 and December 31, 2013, Bison had outstanding borrowings of $4,778,770 and $3,350,154 under this facility. Bison had $2,221,230 available at June 30, 2014. The revolving credit facility matures on June 1, 2015.

In April 2013, Energy Services amended its revolving credit facility with a bank and increased its size from $1.5 million to $2.0 million. The revolving credit facility matures on April 1, 2015. Borrowings under the revolving credit facility are subject to a borrowing base equal to 75% of the outstanding trade receivables of Energy Services. Interest is payable monthly at the greater of the prime rate plus 1.00% or 6.00% (6.00% at June 30, 2014). At June 30, 2014 and December 31, 2013, Energy Services had outstanding borrowings of $1,144,695 and $769,175 under this facility, respectively. The amount available for borrowing was $855,305 at June 30, 2014.

In June 2013, Energy Services formed a new division known as Redback Pump Downs (“Pump Downs”) and entered into a $1.5 million revolving credit facility with a bank. Borrowings under the revolving credit facility are secured by 75% of the outstanding eligible trade receivables of Pump Downs. Interest is payable monthly at the greater of the prime rate plus 1.00% or 5.25% (5.25% at June 30, 2014). At June 30, 2014 and December 31, 2013, Pump Downs had outstanding borrowings of $282,500 under this facility. The amount available for borrowing was $501,908 at June 30, 2014. The revolving credit facility matures on May 30, 2015.

In October 2013, Energy Services entered into an $8.5 million revolving credit facility with a bank. Borrowings under the revolving credit facility are subject to a borrowing base equal to 60% of the aggregate amount of certain eligible equipment of Energy Services and 35% of all equipment of Pump Downs. Interest is payable monthly at the greater of prime rate plus 1.00% or 5.25% (5.25% at June 30, 2014). As of June 30, 2014 and December 31, 2013, Energy Services had $5,325,984 and $2,816,550 outstanding under this facility. The amount available for borrowing was $3,958,311 at June 30, 2014. The revolving credit facility matures on October 9, 2014.

On October 5, 2012, Coil Tubing entered into a secured loan agreement with a bank which contained a revolving credit facility in the amount of $3.0 million maturing on October 5, 2013, with interest payable monthly at the greater of the prime rate or 4.50%. The revolving credit facility was refinanced with a different bank in October 2013 with a maximum borrowing amount of $3.0 million. Borrowings under the revolving credit facility are subject to a borrowing base equal to 80% of Coil Tubings’ eligible accounts receivable. Interest is payable monthly at the greater of prime rate or 4.45% (4.45% at June 30, 2014). At June 30, 2014 and December 31, 2013, Coil Tubing had $1,556,897 and $1,556,897 outstanding under this facility. The amount available for borrowing was $1,443,103 at June 30, 2014. The revolving credit facility matures on October 9, 2014.

On January 31, 2013, Muskie entered into a line of credit with a bank in the amount of $3,000,000. This credit facility is secured by a real estate mortgage. The Company makes monthly interest payment on the amounts borrowed under the facility at the prime rate plus 1.5% (4.75% at June 30, 2014). At June 30, 2014 and December 31, 2013, Muskie had $1,882,574 and $2,138,032 outstanding under the line of credit, which matured on February 1, 2014. In January 2014, this line of credit was renewed through February 1, 2015.

Long-term Debt

In May 2013, Bison entered into a $30.0 million term loan agreement with a bank. The term loan bears interest at the greater of prime plus 0.75% or 4.5% (4.5% at June 30, 2014). Bison was required to make principal payments of $175,000, plus interest, beginning July 1, 2013 and on the first day of each month thereafter through the last day of September 2013. Beginning on October 1, 2013 and on the first day of

 

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each month thereafter, Bison was required to make monthly payments pursuant to a 42 month amortization of the remaining principal balance. The term loan was increased by $25.0 million in January 2014 in connection with a drilling rig acquisition. At June 30, 2014 and December 31, 2013, Bison had $49,162,016 and $27,519,817 outstanding under this facility, respectively. The term loan matures on April 1, 2017.

In April 2012, Energy Services entered into a secured loan agreement with a bank which has an aggregate maximum credit amount of $1.5 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 6.00%. The agreement allowed for a 6-month period of loan advances, during which only interest payments were due, followed by 30 monthly installments of principal and interest beginning November 30, 2012 and maturing May 30, 2014. The total amount advanced during the advance period was $1,004,612. In April 2013, Energy Services amended its secured loan agreement with a bank and increased its aggregate maximum credit amount from $1.5 to $3.0 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 6.00%. The loan was converted from an amortizing note to an interest only advancing note with a maturity date of March 31, 2014, which would automatically be extended six months if Energy Services was in compliance with all required covenants. In October 2013, this secured loan agreement was terminated and repaid in full with proceeds from the $8.5 million revolving credit facility entered into with a different bank as described more fully in the “Lines of Credit” section of this footnote.

In February 2013, Coil Tubing amended its secured loan agreement with a bank and increased its aggregate maximum credit amount from $1.2 million to $2.4 million. The agreement allowed for a period of loan advances, whereby only monthly interest payments were due and the advancing period was extended from April 5, 2013 to July 31, 2013. Beginning on August 31, 2013 monthly installments of principal and interest were due through a maturing date of July 31, 2016. This secured loan agreement was terminated and repaid in full in October 2013, and Coil Tubing entered into a new secured loan agreement with a different bank and increased the available credit to $8.0 million and extended the period for which advances may be made through June 14, 2014. The note bears interest at a floating rate of the greater of prime plus a margin that ranges from 0.00% to 1.00% based on the ratio of funded debt to EBITDA, or 4.45% (4.45% at June 30, 2014). The note requires monthly interest payments through June 14, 2014. After that time, monthly principal and interest payments will be made through the maturity date of October 14, 2017. At June 30, 2014 and December 31, 2013, Coil Tubing had borrowings of $6,296,459 and $4,096,459 under this secured loan agreement.

 

6.	Equity Based Compensation

All of the Operating Entities, except for Lodging, operate under limited liability company agreements (the “Agreements”) which define the rights and responsibilities of the members and provide for prioritization of the allocation of profits and losses and capital distributions.

Upon formation of certain Operating Entities, specified members of management were granted the right to receive distributions from their respective Operating Entity, after each contributing member’s unreturned capital balance is reduced to zero—referred to as “Pay-out”. The specified member’s right to receive a post Pay-out distribution is generally subject to continued employment. The Company has valued the post Pay-out distribution rights using the option pricing method as of the grant dates that coincide with the formation of the respective Operating Entities. The exercise price was based on the contributing members’ contributions at the formation date. The expected volatilities were derived from pricing data from several publicly traded companies. No dividend yield was included because the Company does not plan to pay dividends. For Coil Tubing, valuation assumptions included a risk free interest rate of 0.59%, and expected life of four years, and an expected volatility of 53.26%. For Energy Services, valuation assumptions included a risk free interest rate of 0.83%, an expected life of four years, and an expected volatility of

 

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70.72%. No compensation cost has been recognized during the six months ended June 30, 2014 and 2013, because Pay-out was not deemed probable, and the post Pay-out right does not vest until Pay-out is reached. At June 30, 2014, the Company had $1,262,197 in unrecognized compensation costs associated with these post Pay-out distribution rights.

One member of management was granted post Pay-out distribution rights that vest in 50 equal installments over a 50 month period which commenced on November 30, 2011, subject to continued employment. If full vesting occurs prior to Pay-out, the member would retain the full right without regard to continued employment. The Company has valued the post Pay-out distribution right using the option pricing method as of the October 7, 2011 grant date and has recognized $6,726 of compensation expense in selling, general and administrative expense in the accompanying Condensed Combined Statements of Operations for both six month periods ended June 30, 2014 and 2013. Unrecognized compensation cost was $60,533 at June 30, 2014.

 

7.	Related Party Transactions

The Company provides directional drilling services to an entity under common ownership. For the six months ended June 30, 2014, the Company recognized $168,673 of revenue from this entity. Receivables from related parties included $11,265 and $282,298 from this entity at June 30, 2014 and December 31, 2013, respectively.

The Company provides directional drilling services to an entity under common ownership. For the six months ended June 30, 2014, the Company recognized $662,043 of revenue from this entity. Receivables from related parties included $662,043 at June 30, 2014.

The Company provides trucking and rental services to an entity under common ownership with Wexford. For the six months ended June 30, 2014, the Company recognized $261,763 of revenue from this entity. Receivables from related parties included $106,108 and $48,540 from this entity at June 30, 2014 and December 31, 2013, respectively.

The Company provides contract land drilling support services to an entity under common ownership with Wexford. For the six months ended June 30, 2014 and 2013, the Company recognized $550,014 and $2,444,540 of revenue, respectively from this entity. Receivables from related parties included $119,135 and $221,085 from this entity at June 30, 2014 and December 31, 2013, respectively.

The Company provides contract land drilling services to an entity under common ownership with Wexford. For the six months ended June 30, 2014 and 2013, the Company recognized $2,326,401 and $6,777,665 of revenue, respectively from this entity. Receivables from related parties included $848,354 and $512,327 from this entity at June 30, 2014 and December 31, 2013, respectively.

The Company provides lodging and related services to an entity under common ownership with Wexford. For the six months ended June 30, 2014 and 2013, the Company recognized $2,106,868 and $6,730,184 of revenue, respectively from this entity. Receivables from related parties included $1,216,286 and $3,596,891 from this entity at June 30, 2014 and December 31, 2013, respectively

The Company sells natural sand proppant to an entity under common ownership with Wexford. For the six months ended June 30, 2014, the Company recognized $4,885,257 of revenue from the sale of sand. For the six months ended June 30, 2013, the Company recognized $2,863,864 of revenue from the sale of sand. Receivables from related parties included $3,959,131 and $1,576,199 at June 30, 2014 and December 31, 2013, respectively.

 

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The Company sells natural sand proppant to an entity under common ownership. For the six months ended June 30, 2013, the Company recognized $746,367 of revenue from the sale of sand. There were no receivables at June 30, 2014 or December 31, 2013.

The Company provided directional drilling services to a member. For the six months ended June 30, 2014, the Company recognized $3,536,917 of revenue from this related party. For the six months ended June 30, 2013, the Company recognized $7,366,940 of revenue from the sale of directional drilling. Receivables from related parties included $1,624,379 and $1,849,897 at June 30, 2014 and December 31, 2013, respectively.

The Company provides completion and production services to an entity under common ownership with Wexford. For the six months ended June 30, 2014, the Company recognized $446,359 of revenue from this entity. Receivables from related parties included $446,359 at June 30, 2014.

The Company rents equipment to an entity under common ownership with Wexford. For the six months ended June 30, 2014, the Company recognized $30,800 of revenue from this entity.

The Company rents equipment, provides other services and pays for goods and services on behalf of a related party entity that is under common ownership with Wexford. As of June 30, 2014 and December 31, 2013, receivables from related parties included $25,522 and 70,490, respectively.

The Company pays fees to an entity under common ownership with Wexford to transload sand at a rail transloading facility. For the six months ended June 30, 2014, the Company incurred $243,689 in costs which are included in product cost of revenue-related parties in the accompanying Condensed Combined Statements of Comprehensive Loss. Accounts payable-related parties included $30,495 and $31,509 of transloading fees at June 30, 2014 and December 31, 2013, respectively. No such fees were incurred during the six months ended June 30, 2013.

The Company purchases equipment and contracts for repairs and maintenance on equipment from an entity under common ownership with Wexford. During the six months ended June 30, 2014 and 2013, the Company purchased $97,454 and $1,448,000 of equipment from this entity, respectively. The Company also contracted for repairs and maintenance services of $174,387 and $49,625 for the six months ended June 30, 2014 and June 30, 2013, respectively. At June 30, 2014 and December 31, 2013, payables were $75,919 and $1,335,819, respectively, related to repairs and maintenance and equipment purchases. As of May 9, 2014 this entity was sold and is no longer a related party. Costs incurred before the sale date have been classified in Service Cost of Revenue—related party and costs incurred after the sale date have been classified in Service Cost of Revenue. The entire payable balance as of June 30, 2014 is reflected in Accounts Payables on the balance sheet while the December 31, 2013 balance is still reflected in Payables to Related Parties.

The Company rents rotary steerable equipment in connection with its directional drilling services from an entity under common ownership with Wexford. For the six months ended June 30, 2014 and June 30, 2013, Cost of services—related parties in the accompanying Combined Statements of Comprehensive Loss included $216,888 and $398,590 of such equipment rental costs.

In July 2013, Muskie received a $3,500,000 loan from its members. Muskie accrues interest for the loan at the prime rate plus 2.5% (5.75% at December 31, 2013). The loan matures on July 31, 2014. Amounts payable to related parties includes $3,708,419 and $3,623,278 for the loan and unpaid interest at June 30, 2014 and December 31, 2013.

An entity under common management with the Company and Wexford provide technical, administrative and payroll services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on estimates of office space provided and time devoted to the Company. During the six months ended June 30, 2014 and 2013, the Company incurred total costs under these arrangements of $2,511,689 and $12,689,164, respectively. Of the total costs

 

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incurred, $269,589 and $10,533,743 is included in Services cost of revenue—related parties for the six months ended June 30, 2014 and 2013, respectively. Product cost of revenue—related parties includes $953,237 and $630,963 for the six months ended June 30, 2014 and 2013, respectively. $1,288,863 and $1,524,458 is included in Selling, general and administrative expenses—related parties for the six months ended June 30, 2014 and 2013, in the accompanying Condensed Combined Statements of Comprehensive Loss. As of June 30, 2014 and December 31, 2014, the Company owed the administrative services affiliate $492,445 and $717,666, respectively, and such amounts are included in payables to related parties in the accompanying balance sheets.

An entity under common management with the Company and Wexford provide technical, administrative and payroll services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on estimates of office space provided and time devoted to the Company. $296,886 and $430,980 is included in Selling, general and administrative expenses—related parties for the six months ended June 30, 2014 and June 30, 2013, in the accompanying Condensed Combined Statements of Comprehensive Loss. As of June 30, 2014 and December 31, 2013, the Company owed the administrative services affiliate $357,286 and $303,339, respectively, and such amounts are included in payables to related parties in the accompanying balance sheets.

From time to time, the Company pays for goods and services on behalf of related party entities under common control, or these related parties pay for goods and services on behalf of the Company. During the six months ended June 30, 2014 and 2013, the Company incurred $35,801 and $248,219, respectively, of costs which are included in Selling, general and administrative expenses—related parties, in the accompanying Condensed Combined Statements of Comprehensive Loss. At June 30, 2014 and December 31, 2013 payables to related parties included $532,623 and $1,199,818, respectively, related to these arrangements.

Wexford provides technical, administrative and payroll services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on estimates of office space provided and time devoted to the Company. $158,973 is included in Selling, general and administrative expenses—related parties for the six months ended June 30, 2013, in the accompanying Condensed Combined Statements of Comprehensive Loss. As of June 30, 2014 and December 31, 2014, the Company owed the administrative services affiliate $76,013 and $26,690, respectively, and such amounts are included in payables to related parties in the accompanying balance sheets.

An entity provides technical services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on time devoted to the Company. $30,175 is included in Selling, general and administrative expenses—related parties for the six months ended June 30, 2014, in the accompanying Condensed Combined Statements of Comprehensive Loss. As of June 30, 2014, the Company owed the administrative services affiliate $30,175 and is included in payables to related parties in the accompanying balance sheets.

From time to time, the Company pays for goods and services on behalf of related party entities under common control. At June 30, 2014 receivables from related parties included $366,955 related to these arrangements.

 

8.	Commitments and Contingencies

In September 2010, Windsor Permian, LLC (now known as Diamondback O&G LLC) (“Windsor Permian”) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with Robert A Stein the (“Plaintiff”), and Windsor Permian purchased the property subject to

 

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that agreement. Windsor Permian subsequently contributed the property to the Company. In an amended complaint filed November 2012 by the Plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the Plaintiff seeks damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with Plaintiff’s contract but that the interference did not cause the Plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference. The parties involved have agreed upon a schedule for pretrial activities. Subsequently, the Plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss Plaintiff’s claims on the grounds that the damage claim is speculative and that Plaintiff cannot prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013, and Judgment was entered in the Defendants’ favor on March 13, 2014. Counsel for both Plaintiff and Defendant have agreed that neither party will pursue an appeal from any Order issued in the case, and that each side would likewise waive any entitlement to taxable costs as of April 9, 2014. If there remains no appeal within 60 days of the Order, as the parties have agreed, then the case is effectively disposed of and the file is closed.

In July 2014 a collective action complaint was filed against Panther alleging violations under the Fair Labor Standards act relating to non-payment of overtime pay. The case is in the early stages of the discovery process and a trial date has not been set. Although this case is still in the beginning stages of litigation, a loss has been estimated to be probable. In accordance with ASC 450, as of June 30, 2014 the balance sheet includes an accrual for an outcome should an adverse decision or settlement occur. The Company will vigorously pursue a favorable ruling, but as further information or estimations arise pertaining to this case the Company will assess the need to revise our accrual at that time. However, based on information available presently, there is not a reasonable possibility that losses will exceed our current estimate.

The Company is routinely involved in various legal matters arising from the normal course of business. There were no legal matters outstanding, other than what is described in the immediately preceding paragraph, which are expected to have a material adverse effect on the financial position or results of operations of the Company.

 

9.	Operating Segments

The Company is organized into four reportable segments based on the nature of services provided and the basis in which management makes business and operating decisions. The Company principally provides oilfield services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and natural gas producers.

The Company’s four segments consist of contract land and directional drilling services, completion and production—services, completion and production—natural sand proppant production, and remote accommodation services. The drilling segment provides contract land and directional drilling services. The completion and production—services segment provides pressure control services, flowback services, and equipment rental services. The completion and production—natural sand proppant production segment produces and sells sand for use in hydraulic fracturing. The remote accommodation services business provides housing, kitchen and dining, and recreational service facilities for oilfield workers that are located in remote areas away from readily available lodging.

 

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During 2012 and 2013, the drilling segment primarily served customers in the Permian Basin in West Texas and the Utica Shale in Eastern Ohio. The completion and production operations primarily served customers in the Permian Basin in West Texas, the Eagle Ford Shale in South Texas the Granite Wash in Oklahoma and Texas, and the Cana Woodford Shale and the Cleveland Sand in Oklahoma. The remote accommodation operation served customers in the oil sands of Northern Alberta, Canada.

The completion and production operations primarily served customers in the Permian Basin in West Texas, the Eagle Ford Shale in South Texas, the Utica Shale in Ohio, the Granite Wash in Oklahoma and Texas, and the Cana Woodford Shale and the Cleveland Sand in Oklahoma. The remote accommodation operation served customers in the oil sands of Northern Alberta, Canada.

The following table sets forth certain financial information with respect to the Company’s reportable segments:

 

						Completion and Production
		Contract Land and Directional Drilling Services				Services				Natural Sand Proppant Production				Remote Accomodation Services				Total
2014
Revenue from external customers		$	44,867,511			$	21,626,914			$	16,941,105			$	7,479,635			$	90,915,165
Revenue from related parties		$	6,955,797			$	1,027,173			$	4,885,257			$	2,106,868			$	14,975,095
Interest expense		$	1,358,067			$	371,958			$	32,467			$	—			$	1,762,492
Interest expense from related parties		$	—			$	—			$	101,184			$	—			$	101,184
Depreciation and amortization expense		$	9,664,269			$	2,770,284			$	1,847,745			$	751,318			$	15,033,616
Income tax provision		$	82,936			$	17,592			$	5,026			$	953,080			$	1,058,634
Net income (loss)		$	(4,315,249	)		$	1,492,864			$	(581,262	)		$	2,857,262			$	(546,385	)
Total expenditures for property, plant and equipment		$	64,313,749			$	6,720,503			$	1,223,687			$	2,613,075			$	74,871,014
Total expenditures for property, plant and equipment from related parties		$	—			$	257,454			$	—			$	—			$	257,454
Goodwill		$	—			$	88,248			$	—			$	—			$	88,248
Intangible assets, net		$	—			$	200,521			$	—			$	—			$	200,521
Total Assets		$	148,960,163			$	57,289,668			$	41,420,739			$	32,456,826			$	280,127,396
2013
Revenue from external customers		$	17,791,041			$	10,518,782			$	1,881,325			$	6,164,839			$	36,355,987
Revenue from related parties		$	14,144,605			$	2,444,540			$	3,610,231			$	6,730,184			$	26,929,560
Interest expense		$	655,714			$	99,704			$	45,861			$	—			$	801,279
Depreciation and amortization expense		$	4,367,154			$	1,835,675			$	1,687,877			$	595,636			$	8,486,342
Income tax provision		$	31,027			$	24,566			$	(3,107	)		$	1,364,459			$	1,416,945
Net income (loss)		$	(565,338	)		$	(742,861	)		$	(3,521,433	)		$	4,091,756			$	(737,876	)
Total expenditures for property, plant and equipment		$	9,320,215			$	5,921,512			$	1,054,752			$	660,740			$	16,957,219
Total expenditures for property, plant and equipment from related parties		$	—			$	1,488,000			$	—			$	—			$	1,488,000
Goodwill		$	—			$	88,248			$	—			$	—			$	88,248
Intangible assets, net		$	—			$	228,021			$	—			$	—			$	228,021
Total Assets		$	70,871,149			$	37,586,127			$	38,612,316			$	27,171,075			$	174,240,667

 

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Redback Energy Services

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

 

10.	Subsequent Events

The Company has evaluated the period after June 30, 2014 through September 23, 2014, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

Credit Facilities

In July 2014, Energy Services entered into a promissory note with a bank for $2 million. The loan bears interest at a rate of 3.25% and matures in July 2019.

 

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Members

Stingray Pressure Pumping LLC and Affiliate

We have audited the accompanying combined financial statements of Stingray Pressure Pumping LLC and Affiliate (Stingray Logistics LLC) (both Delaware limited liability companies), which comprise the combined balance sheets as of December 31, 2013 and 2012, and the related combined statements of operations, members’ equity, and cash flows for the year ended December 31, 2013 and the period from March 20, 2012 (inception) to December 31, 2012, and the related notes to the financial statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these combined financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the combined financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the combined financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Stingray Pressure Pumping LLC and Affiliate as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the year ended December 31, 2013 and the period from March 20, 2012 (inception) to December 31, 2012 in accordance with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

September 23, 2014

 

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Stingray Pressure Pumping LLC and Affiliate

COMBINED BALANCE SHEETS

 

		December 31,
		2013				2012
Assets
Current assets
Cash and cash equivalents		$	16,178,976			$	1,098,405
Accounts receivable
Related party			11,029,827				5,696,455
Inventories, net of reserve of $50,000 and $0			515,161				2,863,873
Prepaid expenses and other current assets			1,140,913				567,262
Total current assets			28,864,877				10,225,995
Property and equipment, net			75,467,523				26,948,093
Other noncurrent assets			187,373				—
Total assets		$	104,519,773			$	37,174,088
Liabilities and Members’ Equity
Current liabilities
Accounts payable trade		$	17,563,762			$	4,634,402
Accounts payable—related parties			3,941,426				1,188,084
Accrued expenses and other current liabilities			2,290,913				1,012,374
Current maturities of long-term debt			16,702,602				337,979
Total current liabilities			40,498,703				7,172,839
Long-term debt			28,207,586				1,025,915
Total liabilities			68,706,289				8,198,754
Commitments and contingencies
Members’ equity			35,813,484				28,975,334
Total liabilities and members’ equity		$	104,519,773			$	37,174,088

 

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

 

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Stingray Pressure Pumping LLC and Affiliate

COMBINED STATEMENTS OF OPERATIONS

 

		Year ended December 31, 2013				March 20, 2012 (inception) to December 31, 2012
Revenue—related party		$	82,482,891			$	8,506,191
Costs and expenses
Cost of services			57,553,562				6,709,852
Cost of services—related parties			11,002,824				1,147,989
Selling, general and administrative			1,148,035				544,374
Selling, general and administrative—related parties			412,972				860,082
Depreciation			7,937,518				1,237,129
Total costs and expenses			78,054,911				10,499,426
Operating income (loss)			4,427,980				(1,993,235	)
Other income (expense)
Interest expense			(1,090,096	)			(10,923	)
Other			266				(508	)
			(1,089,830	)			(11,431	)
Net income (loss)		$	3,338,150			$	(2,004,666	)

 

 

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

 

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Stingray Pressure Pumping LLC and Affiliate

COMBINED STATEMENTS OF MEMBERS’ EQUITY

 

Balance at March 20, 2012 (inception)		$	—
Members’ contributions			30,972,712
Stock subscriptions receivable			7,288
Net loss			(2,004,666	)
Balance at December 31, 2012			28,975,334
Members’ contributions			3,500,000
Net income			3,338,150
Balance at December 31, 2013		$	35,813,484

 

 

 

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

 

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Stingray Pressure Pumping LLC and Affiliate

COMBINED STATEMENTS OF CASH FLOWS

 

		Year ended December 31, 2013				March 20, 2012 (inception) to December 31, 2012
Cash flows from operating activities
Net income (loss)		$	3,338,150			$	(2,004,666	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation			7,937,518				1,237,129
Amortization of debt issuance costs			129,630				—
Gain on disposal of property and equipment			(265	)			—
Change in operating assets and liabilities
Related party receivables			(5,333,372	)			(5,696,455	)
Inventories			2,348,712				(2,863,873	)
Prepaid expenses and other assets			(322,374	)			(559,974	)
Accounts payable			9,912,785				4,634,402
Accounts payable—related parties			1,024,513				1,188,084
Accrued expenses and other liabilities			998,698				1,012,374
Net cash provided by (used in) operating activities			20,033,995				(3,052,979	)
Cash flows from investing activities
Purchase of property and equipment			(50,980,175	)			(26,820,674	)
Cash proceeds from sale of equipment			35,804				—
Net cash used in investing activities			(50,944,371	)			(26,820,674	)
Cash flows from financing activities
Proceeds from debt			50,000,000				—
Principal payments on debt			(6,940,773	)			(654	)
Debt issuance costs			(575,568	)			—
Members’ contributions			3,507,288				30,972,712
Net cash provided by financing activities			45,990,947				30,972,058
Net increase in cash and cash equivalents			15,080,571				1,098,405
Cash and cash equivalents at beginning of period			1,098,405				—
Cash and cash equivalents at end of period		$	16,178,976			$	1,098,405
Supplemental Disclosure of Non-Cash Investing and Financing Activities:
Seller-financed vehicle acquisitions		$	487,067			$	1,364,548
Fixed assets in accounts payable at period end		$	5,025,245			$	—
Cash paid for interest, net of capitalized		$	799,856			$	10,923

 

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

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

Note A – Nature of Operations and Summary of Significant Accounting Policies

Stingray Pressure Pumping LLC (“Pressure Pumping”) was formed March 20, 2012 (“Inception”) as a Delaware limited liability company and is based in Oklahoma. Stingray Logistics LLC (“Logistics”) was formed November 19, 2012 as a Delaware limited liability company and is based in Oklahoma. Both of the entities were formed by Wexford Capital LP (“Wexford”) and Gulfport Energy Corporation (“Gulfport”), are under common control and are referred to collectively as “Stingray” or the “Company”.

Operations

Stingray provides production and completion services and oilfield rentals for oil and natural gas exploration companies. Production and completion services include the hauling of proppant and other goods, cementing in the casing pipe, and hydraulic fracturing and other pressure pumping services. The Company operates primarily within the Utica Shale in Ohio and surrounding areas.

Certain management, administrative and treasury functions were provided by the Company to Stingray Cementing LLC and Stingray Energy Services LLC, both of which are under the common control of Wexford and Gulfport. For purposes of presenting the combined financial statements, allocations were required to determine the cost of general and administrative activities performed by the Company. The allocations were made based upon underlying salary costs of employees performing related functions or specifically identified invoices processed, depending on the nature of the cost. Management believes that the allocation methodology was reasonable; however, the reimbursements of expenses incurred by the Company are not necessarily indicative of the expenses that would have been incurred on a stand-alone basis nor are they indicative of costs that may be incurred in the future.

A summary of significant accounting policies are as follows:

 

1.

Principles of Combination

The combined financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP). All material accounts and transactions between the entities within the Company have been eliminated in the combined financial statements.

 

2.

Cash and Cash Equivalents

All highly liquid investments with a maturity of three months or less when acquired are considered cash equivalents. The Company maintains its cash in accounts which may, at times, exceed federally insured limits. At December 31, 2013, the Company had approximately $16,731,000 of its cash and cash equivalents with two financial institutions. The Company had no restricted cash included in its cash or current asset balances at December 31, 2013. The Company has not experienced any losses in these accounts and believes it is not exposed to any significant credit risk.

 

3.

Accounts Receivable

Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses. The Company grants credit to customers in the ordinary course of business and generally does not require collateral. Most areas in which the Company operates provide for a mechanic’s lien against the property on which the service is performed if the lien is filed within the statutorily specified time frame. Customer balances are generally considered delinquent if unpaid by

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

 

the 30^th day following the invoice date and credit privileges may be revoked if balances remain unpaid. At December 31, 2013 and 2012, all of the Company’s accounts receivable are due from a related party (See Note M- Related Party Transactions).

The Company regularly reviews receivables and provides for estimated losses through an allowance for doubtful accounts. In evaluating the level of established reserves, the Company makes judgments regarding its customers’ ability to make required payments, economic events, and other factors. As the financial condition of customers change, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event the Company was to determine that a customer may not be able to make required payments, the Company would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made of their uncollectability.

The Company did not recognize any allowance for doubtful accounts as of December 31, 2013 and December 31, 2012.

 

4.

Inventories

Inventories are stated at the lower of cost or market, determined on a weighted average cost basis. Inventories consist of consumable supplies. The Company assesses the valuation of its inventories based upon specific usage and future utility. A charge to results of operations is taken when factors that would result in a need for a reduction in the valuation, such as excess or obsolete inventory, are determined. As of December 31, 2013 and 2012 the reserves were $50,000 and $0, respectively.

 

5.

Property and Equipment

Property and equipment are recorded at cost. Expenditures for major additions and improvements are capitalized while minor replacements, maintenance and repairs, which do not increase the capacity, improve the efficiency or safety, or extend the useful life of such assets, are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is reflected in operations.

Depreciation is calculated using the straight-line method over the shorter of the estimated useful life, or the remaining lease term, as applicable. The useful lives of the major classes of property and equipment are as follows:

 

Buildings		39 years
Office equipment, furniture and fixtures		3-5 years
Machinery and equipment		3-5 years
Vehicles and trailers		5 years

 

6.

Long-Lived Assets

Long-lived assets, primarily property and equipment are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of such assets is evaluated by measuring the carrying amount of the assets against the estimated undiscounted future cash flows associated with the assets. If such evaluations indicate that the future undiscounted cash flows from the assets are not sufficient to recover the carrying amount of such assets, the assets are adjusted to their estimated values. There was no impairment recorded for the year ended December 31, 2013 or the period from Inception to December 31, 2012.

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

 

7.

Debt Issuance Costs

The Company capitalizes certain costs in connection with obtaining its borrowings, such as lender’s fees and related attorney’s fees. These costs are charged to interest expense over the contractual term

of the debt using the effective interest method.

 

8.

Revenue Recognition

The Company recognizes revenue when services are performed, collection of the receivable is probable, persuasive evidence of an arrangement exists, and the price if fixed and determinable. Services are sold without warranty or right of return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue.

Pressure Pumping services are typically provided pursuant to a per stage pricing agreement, hourly or spot market basis. Each stage is short-term in nature and is typically completed over the course of or within a few hours of starting the stage. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the mobilization of equipment to location, the services performed, the personnel on the job and any additional equipment used on the job. Additional revenue is generated through the sale of consumable supplies that are incidental to the service being performed. Revenue from consumable supplies is recognized as the consumables are used in the delivery of the overall services. The use of consumable supplies is reflected on completed field tickets.

Logistics generates revenues on a day rate, hourly rate or contracted basis, and revenue is recognized when the services are completed and collectability is reasonably assured.

 

9.

Cost of Services

The primary components of cost of services are those salaries, consumable supplies, repairs and maintenance and general operational costs that are directly associated with the services performed for the customers. Cost of services – related parties reflects expenses from related parties.

 

10.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the allowance for doubtful accounts, depreciation and amortization of property and equipment and the future cash flows and fair values used to assess recoverability and impairment of long-lived assets.

 

11.

Equity-Based Compensation

The Company records equity-classified, equity-based payments at fair value on the date of the grant, and expenses the value of the equity-based payments in compensation expenses over the applicable vesting periods.

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

 

12.

Income Taxes

Each of the operating entities comprising the Company are limited liability companies and as such are treated as pass-through entities for income tax purposes. As a pass-through entity, income taxes on net earnings are payable by the members and are not reflected in the financial statements.

As required by Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 740, Income Taxes, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. During the year ended December 31, 2013 and from Inception to December 31, 2012, there were no financial statement benefits or obligations recognized related to uncertain tax positions.

The Company’s accounting policy relating to income tax penalties and interest assessments is to accrue for these costs and record a charge to selling, general and administrative expense for tax penalties and a charge to interest expense for interest assessments during the period the Company has unrecognized tax benefits.

 

13.

Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, related party receivables, trade accounts payable, related party payables and long-term debt. The carrying value of cash and cash equivalents, trade receivables, related party receivables, trade payables and related party payables are considered representative of their fair value due to the short term nature of these instruments. The fair value of long-term debt is deemed representative of fair value based on bearing interest rates and having terms comparable to market conditions.

 

14.

Concentrations of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents occasionally in excess of federally insured limits and trade receivables. The Company’s accounts receivable have a concentration in the oil and natural gas industry and the customer bases consists primarily of independent oil and natural gas producers.

Sales to one related party customer accounted for 100% of net sales and 75% of accounts receivable at December 31, 2013 and 94% of accounts receivable at December 31, 2012.

 

15.

Concentration of Key Raw Material Suppliers

Pressure Pumping relies on a limited number of suppliers for sand and chemicals. These key materials are critical for certain of the Company’s operations. The loss of one or more of these suppliers or the limited availability of these materials may negatively impact the Company’s revenues or increase the operating costs.

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

 

16.

Environmental Matters

Estimated remediation costs are accrued using currently available facts, existing environmental permits, technology and enacted laws and regulations. For sites where we are primarily responsible for remediation, our cost estimates are developed based on internal evaluations and are not discounted. Accruals are recorded when it is probable that we will be obligated to pay for environmental sit evaluation, remediation or related activities, and such costs can be reasonably estimated. As additional information becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal are expensed as incurred.

Note B – Inventory

Inventory consists of the following as of December 31:

 

		2013				2012
Proppant		$	55,900			$	2,863,873
Chemicals			459,261				—
		$	515,161			$	2,863,873

Note C – Prepaid and Other Current Assets

Prepaid and other current assets consists of the following as of December 31:

 

		2013				2012
Prepaid Expenses		$	48,562			$	43,723
Prepaid Insurance			820,687				514,753
Debt Issuance Costs			271,664				—
Other			—				8,786
		$	1,140,913			$	567,262

Note D – Property and Equipment

Net property and equipment consists of the following as of December 31:

 

		2013				2012
Buildings		$	1,094,583			$	460,213
Office equipment, furniture and fixtures			302,309				29,928
Machinery and equipment			59,887,982				27,004,030
Vehicles and trailers			3,984,695				447,158
			65,269,569				27,941,329
Less accumulated depreciation and amortization			(9,170,699	)			(1,237,129	)
			56,098,870				26,704,200
Deposits on equipment and equipment in process of assembly			18,550,159				89,920
Land			818,494				153,973
		$	75,467,523			$	26,948,093

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

 

Deposits on equipment and equipment in process of assembly represents deposits placed with vendors for equipment that is in the process of assembly and purchased equipment that is being outfitted for its intended use. The equipment is not depreciated until it has been placed in service.

Depreciation expense charged to operations totaled $7,937,518 and $1,237,129 for the year ended December 31, 2013 and the period from Inception to December 31, 2012, respectively.

Capitalized interest totaled $147,755 for the year ended December 31, 2013. There was no interest capitalized from Inception to December 31, 2012.

Note E – Other Non-current Assets

Other non-current assets consist of the following as of December 31:

 

		2013				2012
Debt Issuance Costs		$	174,273			$	—
Deposits			13,100				—
		$	187,373			$	—

Note F – Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following as of December 31:

 

		2013				2012
Insurance		$	970,283			$	399,484
Materials			—				114,303
Repairs/Maintenance			—				48,482
Freight			—				103,145
Payroll			941,020				110,000
Fuel			—				202,920
Interest			160,610				—
Commercial Activity Taxes			219,000				—
Other			—				34,040
		$	2,290,913			$	1,012,374

Note G – Long-Term Debt

Long-term debt consists of the following as of December 31:

 

		2013				2012
Term loans		$	43,424,096			$	—
Vehicle loans			1,486,092				1,363,894
			44,910,188				1,363,894
Less current portion			16,702,602				337,979
Total		$	28,207,586			$	1,025,915

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO COMBINED FINANCIAL STATEMENTS

 

On July 3, 2013, the Company entered into a $50,000,000 term loan with a third party lender. The loan subjects the Company to certain financial reporting requirements and financial covenants. The loan requires maintenance of a minimum tangible net worth of $30,000,000. The loan also requires that debt to tangible net worth not to exceed 1.75 to 1.00. The loan is secured by certain specified equipment. The loan matures over 36 months and requires a monthly payments of principal and interest. As of December 31, 2013, the monthly payments were $1,488,000. The maturity date is August 1, 2016. The loans bears interest at the rate of New York Prime Rate plus 0.75% and is subject to a floor of 4.50%. The outstanding balance at December 31, 2013 was $43,424,096. The interest rate at December 31, 2013 was 4.50%. The Company was in compliance with the financial covenants at December 31, 2013.

On various dates between November 26, 2012 and October 25, 2013, the Company entered into borrowing agreements to finance the purchase of certain vehicles and trailers. The agreements are secured by certain specified vehicles. The cost of the vehicles and trailers serving as collateral for the borrowing agreements was $3,224,465 at December 31, 2013. The loan agreements are for 48 months and require monthly payments of principal and interest. As of December 31, 2013, the monthly payments were $43,312. The outstanding balance at December 31, 2013 and December 31, 2012 was $1,486,092 and $1,363,894, respectively. The interest rates on the loans are fixed and range from 5.25% to 5.99%.

At December 31, 2013, the aggregate maturities of long-term debt are as follows:

 

2014		$	16,702,602
2015			17,465,560
2016			10,642,762
2017			—
2018			99,264
Total		$	44,910,188

The Company incurs loan origination fees that are initially capitalized and are included in “other current assets” and “other noncurrent assets” in the combined balance sheets. The balance of unamortized origination fees were $445,937 and $0 as of December 31, 2013 and 2012, respectively. These costs are amortized as a charge to interest expense using the effective interest method. The Company recorded amortization of $129,630 and $0 for the year ended December 31, 2013 and the period ended December 31, 2012, respectively.

Note I – Operating Leases

The Company has committed to various housing, facility and equipment leases some of which have renewal and purchase options. The lease terms vary from one to six months.

Rent expense for the year ended December 31, 2013 and the period from Inception to December 31, 2012 was $432,052 and $223,976, respectively. For the year ended December 31, 2013, $369,641 was included in Cost of Services and $62,411 was included in Selling, General and Administrative activities on the Combined Statements of Operations. From inception to December 31, 2012, $214,400 was included in Cost of Services and $9,576 was included in Selling, General and Administrative activities on the Combined Statements of Operations.

Note J – Members’ Equity

Each of Pressure Pumping and Logistics operates under a limited liability company agreement (the “Agreement”) and will continue perpetually until terminated pursuant to statute or any provision of the Agreements. No member shall be liable for the expenses, liabilities or obligations of the Company.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS

 

Each Agreement provides for specific voting rights of the members. For matters that require vote, members shall have one vote for each whole percentage interest held by the member at the time of vote.

Distributions and profit and loss allocations are based on the pro rata share of each member’s ownership percentages.

Each Agreement places limits on the transfer of members’ interests. Encumbrances are prohibited unless they are a Permitted Encumbrance, as defined in the Agreement.

Note K – Commitments and Contingencies

The Company is, from time to time, involved in routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims and employment related disputes. In the opinion of management, none of the pending litigation, disputes or claims against the Company, if decided adversely, is expected to have a material effect on the Company’s financial condition, results of operations, or cash flows.

The Company has entered into contracts with a certain key employee that in the event of either an initial public offering (“IPO”) or sale of substantially all of the assets of the Company to a third party buyer this employee would receive a cash payment in the amount of 1% of the difference between the net proceeds from a sale of the Company and the total investment in the Company of its owners or a stock grant in the event of an IPO. The amount of any grant of stock would be determined by the Company’s approved stock plan.

The Company has firm purchase commitments for equipment of approximately $2,218,338 as of December 31, 2013.

Note L – Equity-Based Compensation

Upon formation of each Stingray entity, specified members of management were granted the right to receive capital distributions under the various Agreements, after each contributing member’s unreturned capital balance is reduced to zero – referred to as “Pay-out”. The specified member’s right to receive a post Pay-out distribution is generally subject to continued employment. The Company has valued the post Pay-out distribution rights using the option pricing method as of the grant dates that coincide with the formation of the respective entities. The exercise price was based on the contributing members’ contributions at the formation date. No dividend yield was included because the Company does not plan to pay dividends. For Pressure Pumping, valuation assumptions included a risk free interest rate of 0.95%, expected life of four years, and an expected volatility of 49.39%. For Logistics, valuation assumptions included a risk free interest rate of 0.47%, an expected life of four years, and an expected volatility of 45.91%. No compensation cost has been recognized during the year ended December 31, 2013 and from Inception through December 31, 2012, because Pay-out was not deemed probable, and the post Pay-out right does not vest until Pay-out is reached. At December 31, 2013, the Company had $1,579,051 in unrecognized compensation costs associated with these post Pay-out distribution rights.

Note M – Related Party Transactions

The Company provides certain services to Gulfport Energy Corporation, a member of the Company (“Gulfport”). For the year ended December 31, 2013, all of the Company’s revenues were generated through transactions with Gulfport. During the period from Inception through December 31, 2012, all of the Company’s revenues were generated through transactions with Gulfport. Accounts receivable from Gulfport as of December 31, 2013 and 2012 were $8,237,652 and $5,329,426, respectively.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS

 

Gulfport also provided administrative and payroll services to the Company under a shared services agreement. These amounts totaled $411,207 during 2013 and $1,786,326 from Inception through December 31, 2012. During the year ended December 31, 2013, the entire amount was for selling, general and administrative activities. From Inception to December 31, 2012, $926,244 was for cost of services revenue activities and $860,082 was for selling, general and administrative activities. As of December 31, 2013 and 2012, the Company owed Gulfport $0 and $928,020, respectively.

The Company purchases sand used in its hydraulic fracturing operations from an affiliate. During the year ended December 31, 2013, the Company purchased $9,266,078 in sand and the entire amount is included in cost of services revenue activities. As of December 31, 2013, related party accounts payable included $1,576,199 payable to the affiliate.

The Company rented certain equipment used in its hydraulic fracturing operations from an affiliate. During the year ended December 31, 2013, the Company rented $65,410 in equipment from the affiliate and the entire amount is included in cost of services revenue activities. As of December 31, 2013, related party accounts payable included $65,410 payable to the affiliate.

The Company also rented certain equipment used in its hydraulic fracturing operations from an affiliate. During the year ended December 31, 2013 and from Inception to December 31, 2012, the Company rented $113,483 and $0, respectively, in equipment from the affiliate and the entire amount is included in cost of services revenue activities. As of December 31, 2013 and 2012, related party accounts payable included $113,483 and $0, respectively, payable to the affiliate.

The Company also provides certain management, administrative and treasury functions to an affiliate. During the year ended December 31, 2013 and from Inception to December 31, 2012, the Company paid $107,487 and $0, respectively, of payroll expenses related to these services which were passed through to the affiliate. The Company also pays certain other costs on behalf of the affiliate which are passed through to the affiliate. At December 31, 2013 and 2012, accounts receivable due from the affiliate were $1,789,434 and $0, respectively.

In November of 2012, certain equipment was purchased for the Company and paid for by an affiliate resulting in an $89,920 payable to the affiliate at December 31, 2013 and 2012.

The Company also provides certain management, administrative and treasury functions to an affiliate. During the years ended December 31, 2013 and 2012, the Company paid $169,528 and $257,327, respectively, of payroll expenses related to these services which were passed through to the affiliate. The Company also pays certain other costs on behalf of the affiliate which are passed through to the affiliate. At December 31, 2013 and 2012, accounts receivable due from the affiliate were $1,002,741 and $367,029, respectively.

The Company purchases equipment and contracts for repairs and maintenance on equipment from an affiliate. During the year ended December 31, 2013 and for the period from Inception through December 31, 2012, the Company purchased equipment, including deposits for equipment not yet delivered of $10,298,205 and $0, respectively. The Company also contracted for repairs and maintenance services during the year ended December 31, 2013 of $1,666,229. As of December 31, 2013 and 2012, related party accounts payable included $2,091,122 and $170,144, respectively.

The Company receives some administrative services from certain affiliates. These amounts totaled $2,115 during 2013. Of this amount, $350 was for cost of services revenue activities and $1,765 was for selling, general and administrative activities. As of December 31, 2013, related party accounts payable included $5,292.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS

 

Note N – 401(k) Plans

The Company provides a 401(k) retirement plan that enables workers to defer up to specific percentages of their annual compensation and contribute such amount to the plan. The Company provides a contribution of 3% for each employee and could also contribute additional amounts at their sole discretion. For the year ended December 31, 2013 and the period from Inception to December 31, 2012, the contributions were $252,633 and $92,629, respectively.

Note O – Subsequent Events

The Company has evaluated events and transactions that occurred subsequent to December 31, 2013 through September 23, 2014, the date these financials were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

On January 16, 2014, the Company paid down all outstanding principal and interest of $489,217 on the term loan dated July 17, 2013 using a portion of the proceeds from the term loan dated December 4, 2013.

 

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Stingray Pressure Pumping LLC and Affiliate

CONDENSED COMBINED BALANCE SHEETS

(unaudited)

 

		June 30, 2014				December 31, 2013
Assets
Current assets
Cash and cash equivalents		$	12,654,269			$	16,178,976
Accounts receivable
Trade			131,415				—
Related party			16,824,852				11,029,827
Inventories, net of allowance of $50,000			2,546,257				515,161
Prepaid expenses and other current assets			716,088				1,140,913
Total current assets			32,872,881				28,864,877
Property and equipment, net			76,686,175				75,467,523
Other noncurrent assets			638,679				187,373
Total assets		$	110,197,735			$	104,519,773
Liabilities and Members’ Equity
Current liabilities
Accounts payable trade		$	26,076,129			$	17,563,762
Accounts payable—related parties			4,598,544				3,941,426
Accrued expenses and other current liabilities			2,170,355				2,290,913
Current maturities of long-term debt			17,089,951				16,702,602
Total current liabilities			49,934,979				40,498,703
Long-term debt			19,572,984				28,207,586
Total liabilities			69,507,963				68,706,289
Commitments and contingencies
Members’ equity			40,689,772				35,813,484
Total liabilities and members’ equity		$	110,197,735			$	104,519,773

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

 

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Stingray Pressure Pumping LLC and Affiliate

CONDENSED COMBINED STATEMENTS OF OPERATIONS

(unaudited)

 

		Six months ended June 30,
		2014				2013
Revenue—related party		$	60,765,844			$	30,297,938
Revenue			4,081,329				—
			64,847,173				30,297,938
Costs and expenses
Cost of services			49,637,183				20,902,085
Cost of services—related parties			5,277,566				3,782,328
Selling, general and administrative			1,182,788				429,160
Selling, general and administrative—related parties			32,136				236,015
Depreciation			8,030,205				2,991,434
Total costs and expenses			64,159,878				28,341,022
Operating income			687,295				1,956,916
Other income (expense)
Interest expense			(855,487	)			(42,866	)
Other			44,480				(4,040	)
			(811,007	)			(46,906	)
Net (loss) income		$	(123,712	)		$	1,910,010

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

 

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CONDENSED COMBINED STATEMENT OF MEMBERS’ EQUITY

(unaudited)

 

Balance at December 31, 2013			35,813,484
Member’ contributions			5,000,000
Net loss			(123,712	)
Balance at June 30, 2014		$	40,689,772

 

 

 

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

 

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CONDENSED COMBINED STATEMENTS OF CASH FLOWS

(unaudited)

 

		Six months ended June 30,
		2014				2013
Cash flows from operating activities
Net loss (income)		$	(123,712	)		$	1,910,010
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation			8,030,205				2,991,434
Amortization of debt issuance costs			150,596				—
Gain on disposal of property and equipment			(30,948	)			(1,582	)
Change in operating assets and liabilities
Trade receivables			(131,415	)			—
Related party receivables			(3,344,402	)			(7,248,449	)
Inventories			(2,031,096	)			159,830
Prepaid expenses and other assets			189,878				208,297
Accounts payable			11,528,942				6,169,227
Accounts payable—related parties			(3,339,737	)			761,510
Accrued expenses and other liabilities			159,283				(452,038	)
Net cash provided by operating activities			11,057,594				4,498,239
Cash flows from investing activities
Purchase of property and equipment			(11,495,048	)			(6,924,723	)
Cash proceeds from sale of equipment			160,000				35,804
Net cash used in investing activities			(11,335,048	)			(6,888,919	)
Cash flows from financing activities
Principal payments on debt			(8,247,253	)			(179,265	)
Members’ contributions			5,000,000				3,507,288
Net cash (used in) provided by financing activities			(3,247,253	)			3,328,023
Net increase in cash and cash equivalents			(3,524,707	)			937,343
Cash and cash equivalents at beginning of period			16,178,976				1,098,405
Cash and cash equivalents at end of period		$	12,654,269			$	2,035,748
Supplemental Disclosure of Non-Cash Investing and Financing Activities:
Seller-financed vehicle acquisitions		$	—			$	650
Fixed assets in accounts payable at period end		$	5,358,729			$	1,133,528
Fixed assets in accounts receivable at period end		$	2,450,623			$	—
Cash paid for interest, net of capitalized		$	719,342			$	42,866

 

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

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

Note A – Nature of Operations and Summary of Significant Accounting Policies

Stingray Pressure Pumping LLC (“Pressure Pumping”) was formed March 20, 2012 (“Inception”) as a Delaware limited liability company and is based in Oklahoma. Stingray Logistics LLC (“Logistics”) was formed November 19, 2012 as a Delaware limited liability company and is based in Oklahoma. Both of the entities were formed by Wexford Capital LP (“Wexford”) and Gulfport Energy Corporation (“Gulfport”), are under common control and are referred to collectively as “Stingray” or the “Company”.

Operations

Stingray provides production and completion services for oil and natural gas exploration companies. Production and completion services include the hauling of proppant and other goods and hydraulic fracturing and other pressure pumping services. The Company operates primarily within the Utica Shale in Ohio and surrounding areas.

Certain management, administrative, and treasury functions were provided by the Company to Stingray Cementing LLC and Stingray Energy Services LLC, both of which are under the common control of Wexford Capital LP and Gulfport Energy Corporation. For purposes of presenting the combined financial statements, allocations were required to determine the cost of general and administrative activities performed by the Company. The allocations were made based upon underlying salary costs of employees performing related functions or specifically identified invoices processed, depending on the nature of the cost. Management believes that the allocation methodology was reasonable; however, the reimbursements of expenses incurred by the Company are not necessarily indicative of the expenses that would have been incurred on a stand-alone basis nor are they indicative of costs that may be incurred in the future.

A summary of significant accounting policies are as follows:

 

1.

Principles of Combination

The accompanying combined condensed financial statements include the accounts of Stingray Pressure Pumping LLC and Stingray Logistics LLC. All significant intercompany transactions and balances have been eliminated.

These unaudited condensed combined financial statements should be read in conjunction with the audited combined financial statements for the year ended December 31, 2013. In the opinion of management, the statements reflect all adjustments necessary for a fair presentation of the results of interim periods. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles general accepted in the United State of America, which are not required for interim purposes, have been condensed or omitted. These financial statements reflect all adjustments, consisting only of normal, recurring adjustments that, in the opinion of the Company’s management, are necessary for a fair presentation of the financial position, results of operations and cash flows for the periods presented. Operating results for the six month period ended June 30, 2014 are not necessarily indicative of the results that may be expected for any subsequent quarter or for the year ending December 31, 2014.

 

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NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

2.

Cash and Cash Equivalents

All highly liquid investments with an original maturity of three months or less are considered cash equivalents. The Company maintains its cash in accounts which may, at times, exceed federally insured limits. At June 30, 2014 and December 31, 2013, the Company had approximately $12,797,000 and $16,731,000, respectively, of its cash and cash equivalents with two financial institutions. The Company had no restricted cash included in its cash or current asset balances at June 30, 2014. The Company has not experienced any losses in these accounts and believes it is not exposed to any significant credit risk.

 

3.

Accounts Receivable

Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses. The Company grants credit to customers in the ordinary course of business and generally does not require collateral. Most areas in which the Company operates provide for a mechanic’s lien against the property on which the service is performed if the lien is filed within the statutorily specified time frame. Customer balances are generally considered delinquent if unpaid by the 30^th day following the invoice date and credit privileges may be revoked if balances remain unpaid. At June 30, 2014 and December 31, 2013, substantially all of the Company’s accounts receivable are due from a related party (See Note H—Related Party Transactions).

The Company regularly reviews receivables and provides for estimated losses through an allowance for doubtful accounts. In evaluating the level of established reserves, the Company makes judgments regarding its customers’ ability to make required payments, economic events, and other factors. As the financial condition of customers change, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event the Company was to determine that a customer may not be able to make required payments, the Company would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made of their uncollectability.

The Company did not recognize any allowance for doubtful accounts as of June 30, 2014 and December 31, 2013.

 

4.

Inventories

Inventories are stated at the lower of cost or market, determined on a weighted average cost basis. Inventories consist of consumable supplies. The Company assesses the valuation of its inventories based upon specific usage and future utility. A charge to results of operations is taken when factors that would result in a need for a reduction in the valuation, such as excess or obsolete inventory, are determined. As of June 30, 2014 and December 31, 2013, the reserve was $50,000.

 

5.

Property and Equipment

Property and equipment are recorded at cost. Expenditures for major additions and improvements are capitalized while minor replacements, maintenance and repairs, which do not increase the capacity, improve the efficiency or safety, or extend the useful life of such assets, are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is reflected in operations.

 

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NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

Depreciation is calculated using the straight-line method over the shorter of the estimated useful life, or the remaining lease term, as applicable.

The useful lives of the major classes of property and equipment are as follows:

 

Buildings		39 years
Office equipment, furniture and fixtures		3-5 years
Machinery and equipment		3-5 years
Vehicles and trailers		5 years

 

6.

Long-Lived Assets

Long-lived assets, primarily property and equipment are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of such assets is evaluated by measuring the carrying amount of the assets against the estimated undiscounted future cash flows associated with the assets. If such evaluations indicate that the future undiscounted cash flows from the assets are not sufficient to recover the carrying amount of such assets, the assets are adjusted to their estimated values. There was no impairment recorded for the periods ended June 30, 2014 or June 30, 2013.

 

7.

Debt Issuance Costs

The Company capitalizes certain costs in connection with obtaining its borrowings, such as lender’s fees and related attorney’s fees. These costs are charged to interest expense over the contractual term of the debt using the effective interest method.

 

8.

Revenue Recognition

The Company recognizes revenue when services are performed, collection of the receivable is probable, persuasive evidence of an arrangement exists, and the price is fixed and determinable. Services are sold without warranty or right of return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue.

Pressure Pumping services are typically provided pursuant to a per stage pricing agreement, hourly or spot market basis. Each stage is short-term in nature and is typically completed over the course of or within a few hours of starting the stage. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the mobilization of equipment to location, the services performed, the personnel on the job and any additional equipment used on the job. Additional revenue is generated through the sale of consumable supplies that are incidental to the service being performed. Revenue from consumable supplies is recognized as the consumables are used in the delivery of the overall services. The use of consumable supplies is reflected on completed field tickets.

Logistics generates revenues on a day rate, hourly rate or contracted basis, and revenue is recognized when the services are completed and collectability is reasonably assured.

 

9.

Cost of Services

The primary components of cost of services are those salaries, consumable supplies, repairs and maintenance and general operational costs that are directly associated with the services performed for the customers. Cost of services—related parties reflects expenses from related parties.

 

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NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

10.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include but are not limited to the allowance for doubtful accounts, inventory valuation allowance, depreciation and amortization of property and equipment and the future cash flows and fair values used to assess recoverability and impairment of long-lived assets.

 

11.

Equity-Based Compensation

The Company records equity-classified, equity-based payments at fair value on the date of the grant, and expenses the value of the equity-based payments in compensation expenses over the applicable vesting periods.

 

12.

Income Taxes

Each of the operating entities comprising the Company are limited liability companies and as such are treated as pass-through entities for income tax purposes. As a pass-through entity, income taxes on net earnings are payable by the members and are not reflected in the financial statements.

As required by Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 740, Income Taxes, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. During the periods ended June 30, 2014 and June 30, 2013, there were no financial statement benefits or obligations recognized related to uncertain tax positions.

The Company’s accounting policy relating to income tax penalties and interest assessments is to accrue for these costs and record a charge to selling, general and administrative expense for tax penalties and a charge to interest expense for interest assessments during the period the Company has unrecognized tax benefits. The pass-through entities are not subject to tax examinations by tax authorities for years before 2012.

 

13.

Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, related party receivables, trade accounts payable, related party payables and long-term debt. The carrying value of cash and cash equivalents, trade receivables, related party receivables, trade accounts payable and related party payables are considered representative of their fair value due to the short term nature of these instruments. The fair value of long-term debt is deemed representative of fair value based on bearing interest rates and having terms comparable to market conditions.

 

14.

Concentrations of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents occasionally in excess of federally insured limits and trade receivables. The Company’s accounts receivable have a concentration in the oil and natural gas industry and the customer bases consists primarily of independent oil and natural gas producers.

 

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NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

Sales to one related party customer accounted for 94% and 100% of net sales for the periods ended June 30, 2014 and June 30, 2013, respectively, and approximately 80% and 75% of accounts receivable at June 30, 2014 and December 31, 2013, respectively.

 

15.

Concentration of Key Raw Material Suppliers

Pressure Pumping relies on a limited number of suppliers for sand and chemicals. These key materials are critical for certain of the Company’s operations. The loss of one or more of these suppliers or the limited availability of these materials may negatively impact the Company’s revenues or increase the operating costs.

 

16.

Environmental Matters

Estimated remediation costs are accrued using currently available facts, existing environmental permits, technology and enacted laws and regulations. For sites where we are primarily responsible for remediation, our cost estimates are developed based on internal evaluations and are not discounted. Accruals are recorded when it is probable that we will be obligated to pay for environmental site evaluation, remediation or related activities, and such costs can be reasonably estimated. As additional information becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal are expensed as incurred.

Note B – Inventory

Inventory consists of the following as of:

 

		June 30, 2014				December 31, 2013
Proppant		$	1,069,270			$	55,900
Chemicals			763,271				459,261
Supplies			713,716				—
		$	2,546,257			$	515,161

Note C – Property and Equipment

Net property and equipment consists of the following as:

 

		2014				2013
Buildings		$	1,094,583			$	1,094,583
Office equipment, furniture and fixtures			463,551				302,309
Machinery and equipment			85,863,359				59,887,982
Vehicles and trailers			4,451,003				3,984,695
			91,872,496				65,269,569
Less accumulated depreciation and amortization			(17,171,811	)			(9,170,699	)
			74,700,685				56,098,870
Deposits on equipment and equipment in process of assembly			1,654,887				18,550,159
Land			330,603				818,494
		$	76,686,175			$	75,467,523

 

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NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

Deposits on equipment and equipment in process of assembly represents deposits placed with vendors for equipment that is in the process of assembly and purchased equipment that is being outfitted for its intended use. The equipment is not depreciated until it has been placed in service.

Depreciation expense charged to operations totaled $8,030,205 and $2,991,434 for the six months ended June 30, 2014 and 2013, respectively.

Capitalized interest totaled $226,608 and $0 for the six months ended June 30, 2014 and 2013, respectively.

Note D – Long-Term Debt

Long-term debt consists of the following:

 

		June 30, 2014				December 31, 2013
Note payable to a bank with a maximum credit amount of $50 million. Outstanding borrowings bear an interest rate of the greater of “New York Prime” plus a margin of 0.75% or 4.50% (4.50% at June 30, 2014). The note has an effective date of August 1, 2013 and a maturity date of August 1, 2016, and is secured by certain specified equipment of Pressure Pumping.		$	35,396,548			$	43,424,096
Notes payable to a financial services company bearing interest from 5.25% to 5.99%. The notes are to be repaid in monthly installments totalling $43,312 at June 30, 2014 and mature between November 26, 2016 and September 26, 2017 and secured by certain specified vehicles owned by Logistics with an historical cost of $3,224,465.			1,266,387				1,486,092
Total long-term debt			36,662,935				44,910,188
Less: current maturities of long-term debt			(17,089,951	)			(16,702,602	)
Long-term debt less current maturities		$	19,572,984			$	28,207,586

The Company was in compliance with its financial covenants at June 30, 2014.

Note E – Members’ Equity

Both Pressure Pumping and Logistics operate under a limited liability company agreement (the “Agreement”) and will continue perpetually until terminated pursuant to statute or any provision of the Agreements. No member shall be liable for the expenses, liabilities or obligations of the Company.

Each Agreement provides for specific voting rights of the members. For matters that require vote, members shall have one vote for each whole percentage interest held by the member at the time of vote. Distributions and profit and loss allocations are based on the pro rata share of each member’s ownership percentages.

Each Agreement places limits on the transfer of members’ interests. Encumbrances are prohibited unless they are a Permitted Encumbrance, as defined in the Agreement.

Note F – Commitments and Contingencies

The Company is, from time to time, involved in routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims and employment related disputes. In the opinion of management, none of the pending litigation, disputes or claims against the Company, if decided adversely, is expected to have a material effect on the Company’s financial condition, results of operations, or cash flows.

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

The Company has entered into contracts with a certain key employee that in the event of either an initial public offering (“IPO”) or sale of substantially all of the assets of the Company to a third party buyer this employee would receive a cash payment in the amount of 1% of the difference between the net proceeds from a sale of the Company and the total investment in the Company of its owners or a stock grant in the event of an IPO. The amount of any grant of stock would be determined by the Company’s approved stock plan.

The Company has firm purchase commitments for equipment of approximately $3,153,000 as of June 30, 2014.

Note G – Equity-Based Compensation

Upon formation of each Stingray entity, specified members of management were granted the right to receive capital distributions under the various Agreements, after each contributing member’s unreturned capital balance is reduced to zero—referred to as “Pay-out”. The specified member’s right to receive a post Pay-out distribution is generally subject to continued employment. The Company has valued the post Pay-out distribution rights using the option pricing method as of the grant dates that coincide with the formation of the respective entities. The exercise price was based on the contributing members’ contributions at the formation date. No dividend yield was included because the Company does not plan to pay dividends. For Pressure Pumping, valuation assumptions included a risk free interest rate of 0.95%, expected life of four years, and an expected volatility of 49.39%. For Logistics, valuation assumptions included a risk free interest rate of 0.47%, an expected life of four years, and an expected volatility of 45.91%. No compensation cost has been recognized for the six months ended June 30, 2014 or 2013, because Pay-out was not deemed probable, and the post Pay-out right does not vest until Pay-out is reached. At June 30, 2014, the Company had $1,579,051 in unrecognized compensation costs associated with these post Pay-out distribution rights.

Note H – Related Party Transactions

The Company provides certain services to Gulfport Energy Corporation, a principal member of the Company (“Gulfport”). For the six months ended June 30, 2014 and 2013, $60,765,844 and $30,297,938, respectively, of the Company’s revenues were generated through transactions with Gulfport. Accounts receivable from Gulfport as of June 30, 2014 and December 31, 2013 were $13,561,705 and $8,237,652 respectively.

Gulfport also provided administrative and payroll services to the Company under a shared services agreement. These amounts totaled $51,701 and $235,720 for the six months ended June 30, 2014 and 2013, respectively. During the six months ended June 30, 2014 and 2013, the entire amount was for selling, general and administrative activities. As of June 30, 2014 and December 31, 2013, the Company had an outstanding accounts payable balance of $48,233 and $0, respectively, with Gulfport.

The Company purchases sand used in its hydraulic fracturing operations from an affiliate. During the six months ended June 30, 2014 and June 30, 2013, the Company purchased $4,885,257 and $2,863,864, respectively, in sand and the entire amount is included in cost of services revenue activities. As of June 30, 2014 and December 31, 2013, related party accounts payable included $3,959,131 and $1,576,199, respectively.

The Company rented certain equipment used in its hydraulic fracturing operations from an affiliate. During the six months ended June 30, 2014 and June 30, 2013, the Company rented $30,800 and $0, respectively, in equipment from the affiliate and the entire amount is included in cost of services revenue activities. As of June 30, 2014 and December 31, 2013, related party accounts payable included $14,840 and $65,410, respectively, payable to the affiliate.

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

The Company also provided certain administrative and payroll services to the affiliate. These amounts totaled $28,825 and $0 for the six months ended June 30, 2014 and 2013, respectively. As of June 30, 2014 and December 31, 2013, related party accounts receivable included $16,914 and $0, respectively, receivable from the affiliate.

The Company also rented certain equipment used in its hydraulic fracturing operations from an additional affiliate. These amounts totaled $59,316 and $8,675 for the six months ended June 30, 2014 and 2013, respectively and the entire amount is included in cost of services revenue activities. As of June 30, 2014 and December 31, 2013, related party accounts payable included $105,815 and $113,483, respectively, payable to the affiliate.

The Company also provides certain management, administrative, and treasury functions to the affiliate. During the six months ended June 30, 2014 and 2013, the Company paid $57,453 and $61,793, respectively, of payroll expenses related to these services which were passed through to the affiliate. The Company also pays certain other costs on behalf of the affiliate which are passed through to the affiliate. At June 30, 2014 and December 31, 2013, related party accounts receivable included $2,433,756 and $1,789,434, respectively.

In November of 2012, certain equipment was purchased for the Company and paid for by an affiliate resulting in an $89,920 payable to the affiliate at June 30, 2014 and December 31, 2013.

The Company also provides certain management, administrative, and treasury functions to the affiliate. During the six months ended June 30, 2014 and 2013, the Company paid $76,477 and $69,790, respectively, of payroll expenses related to these services which were passed through to the affiliate. The Company also pays certain other costs on behalf of the affiliate which are passed through to the affiliate. At June 30, 2014 and December 31, 2013, accounts receivable due from the affiliate were $794,977 and $1,002,741, respectively.

The Company purchases equipment and contracts for repairs and maintenance on equipment from a former affiliate. As of the six months ended June 30, 2014 and 2013, the Company purchased equipment, including deposits for equipment not yet delivered of $2,149,993 and $364,785, respectively. The Company also contracted for repairs and maintenance services during the six months ended June 30, 2014 and June 30, 2013 of $302,193 and $909,789, respectively. As of June 30, 2014, the entity was no longer considered an affiliate and therefore all outstanding balances were included in accounts payable trade. As of December 31, 2013, related party accounts payable included $2,091,122 to the affiliate.

The Company received legal and administrative services which were paid for by a certain affiliates. These amounts totaled $542,384 during the six months ended June 30, 2014 and the entire amount is included in other noncurrent assets. There were no legal and administrative services paid for the Company by these affiliates during the six months ended June 30, 2013. As of June 30, 2014, related party accounts payable included $366,956 to the affiliate.

The Company received administrative services from certain affiliates. These amounts totaled $26,760 and $295, during the six months ended June 30, 2014 and June 30, 2013, respectively, and the entire amount is included in selling, general and administrative activities. As of June 30, 2014 and December 31, 2013, related party accounts payable included $13,649 and $5,292, respectively.

The Company also provides some administrative services to these certain affiliates. These amounts totaled $17,500 during the six months ended June 30, 2014 and the entire amount is included in selling, general and administrative activities. There were no administrative services provided by these affiliates during the six months ended June 30, 2013. As of June 30, 2014, related party accounts receivable included $17,500.

 

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Stingray Pressure Pumping LLC and Affiliate

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(unaudited)

 

A tabular summary of transactions with related parties for the six months ended June 30 follows:

 

		2014				2013
Revenues		$	60,765,844			$	30,297,938
Purchased materials		$	4,885,257			$	2,863,864
Purchased services		$	424,445			$	1,154,479
Capital asset purchases		$	2,149,993			$	364,785

Note I – Subsequent Events

The Company has evaluated events and transactions that occurred subsequent to June 30, 2014 through September 23, 2014, the date these financials were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements.

 

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Members

Bison Drilling and Field Services, LLC

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of Certain Drilling Rigs (the “Statements”) of Lantern Drilling Company (“Lantern Rigs”) acquired by Bison Drilling and Field Services, LLC (“Bison”) for the years ended December 31, 2013 and 2012, and the related notes to the statements.

Management’s responsibility for the financial statements

Bison management is responsible for the preparation and fair presentation of these statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Lantern Rigs as described in Note A for the years ended December 31,2013 and 2012, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

As described in Note A, the accompanying statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete financial presentation of the Lantern Rigs’ revenues and expenses. Our opinion is not modified with respect to this matter.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

May 14, 2014

 

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CERTAIN DRILLING RIGS OF

LANTERN DRILLING COMPANY

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

 

		Year Ended December 31,
		2013				2012
Revenues:
Contract drilling services revenue		$	33,101,567			$	31,713,240
Direct operating expenses:
Contract drilling operating expenses			22,228,925				21,798,694
Operating lease rental expense			13,602,448				13,434,164
General and administrative expenses			497,221				252,900
			36,328,594				35,485,758
Direct operating expenses in excess of revenues		$	(3,227,027	)		$	(3,772,518	)

See accompanying notes to statements of revenues and direct operating expenses.

 

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CERTAIN DRILLING RIGS OF

LANTERN DRILLING COMPANY

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

NOTE A—BASIS OF PRESENTATION

The accompanying statements present the revenues and direct operating expenses for five drilling rigs (the “Rigs”) that were operated by Lantern Drilling Company (“Lantern”) in Texas and Louisiana during the years ended December 31, 2013 and 2012. Lantern is a wholly-owned subsidiary of Forest Oil Permian Corporation (“Forest Permian”) and provides contract land drilling services for oil and natural gas exploration and production. Forest Permian is a wholly-owned subsidiary of Forest Oil Corporation (“Forest Oil”). As discussed in Note E, the Rigs were acquired by Bison Drilling and Field Services, LLC (“Bison”) on January 29, 2014.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Lantern. The historical statements presented are not indicative of the financial condition or results of operations of the Lantern Rigs due to the omission of certain operating expenses, and such amounts may not be indicative of future operations. The statements do not include depreciation because the Rigs were owned by third party financial institutions that leased the Rigs to Forest Oil under operating leases and Forest Oil sub-leased the Rigs to Lantern. The statements also do not include corporate overhead, interest expense or income taxes because those costs are not directly related to revenue producing activities of the Rigs and are not separately identifiable by rig.

Historical financial statements reflecting the financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented because Lantern did not own the Rigs and such information was not available to prepare the full financial statements required by Securities and Exchange Commission Regulation S-X, Rule 3-05. Accordingly, the historical statements of revenues and direct operating expenses of the Rigs are presented in lieu of financial statements required under Rule 3-05.

NOTE B—SIGNIFICANT ACCOUNTING POLICIES

Use of estimates

The preparation of the accompanying statements in conformity with generally accepted accounting principles requires making estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. The estimates include revenue and expense accruals and estimates for allocations of certain operating expenses to individual rigs. Actual results could materially differ from these estimates.

Revenue recognition

Lantern earns contract drilling revenue, mobilization revenue and equipment rental revenue, primarily under day work contracts. Revenues on day work contracts are recognized based on the days completed at the day rate each contract specifies.

NOTE C—RELATED PARTY TRANSACTIONS

Lantern provided drilling services to Forest Oil. For the years ended December 31, 2013 and 2012, contract drilling services revenue included $25,057,254 and $29,543,396, respectively, from Forest Oil.

Certain employees of Forest Oil provided direct management services to Lantern. General and administrative expenses in the accompanying Statements of Direct Revenues and Operating Expenses represents the management fee charged by Forest Oil to Lantern for such services. The management fee was based on payroll, benefits and overhead for the direct management employees.

 

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CERTAIN DRILLING RIGS OF

LANTERN DRILLING COMPANY

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012—(Continued)

 

NOTE D—COMMITMENTS

In August 2007, Forest Oil sold one of the five rigs to a financial institution, and between June and December 2010 Forest Oil sold the other four rigs to various financial institutions. In all cases, Forest Oil leased the rigs back from the financial institutions under long-term non-cancellable operating leases having varying terms and expiration dates through July 2017. Lantern sub-leased the rigs from Forest Oil. For the years ended December 31, 2013 and 2012, Lantern recognized $13,602,448 and $13,434,164, respectively, of operating lease rental expense. The operating leases were paid in full and terminated in January 2014.

NOTE E—SUBSEQUENT EVENTS

Lantern has evaluated the period after December 31, 2013 through May 14, 2014, the date the statements of revenues and direction operating expenses were available to be issued, noting no subsequent events other than what is identified below.

On January 29, 2014, Bison, a third party, acquired the Rigs directly from the financial institutions that leased the Rigs to Lantern. The amounts paid by Bison to acquire the Rigs along with approximately $3.1 million paid by Forest Oil, were used to pay off the operating leases in their entirety and terminate the lease agreements.

 

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Report of Independent Registered Public Accounting Firm

Board of Directors

Mammoth Energy Partners GP LLC

We have audited the accompanying balance sheet of Mammoth Energy Partners LP, (a Delaware limited partnership) (the “Company”), as of June 30, 2014 and the related statements of operations, unitholders’ equity, and cash flows for the period from February 5, 2014 (inception) to June 30, 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 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 statement is free of material misstatement. We were not engaged to perform an audit of the Company’s 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above presents fairly, in all material respects, the financial position of Mammoth Energy Partners LP as of June 30, 2014 and the results of its operations and its cash flows for the period from February 5, 2014 (inception) to June 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

September 23, 2014

 

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Mammoth Energy Partners LP

BALANCE SHEET

June 30, 2014

 

Assets
Current Assets
Cash and cash equivalents		$	277,992
Receivables from related parties			1,274,453
Total current assets			1,552,445
Total assets		$	1,552,445
Liabilities and Unitholders’ Equity
Current Liabilities
Accounts payable		$	1,552,345
Payables to related parties			84,223
Accrued expenses and other current liabilities			32,003
Total current liabilities			1,668,571
Total liabilities			1,668,571
Unitholders’ equity			(116,126	)
Total liabilities and unitholders’ equity		$	1,552,445

 

 

The accompanying notes are an integral part of these financial statements

 

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Mammoth Energy Partners LP

STATEMENT OF OPERATIONS

 

		February 5, 2014 (inception) to June 30, 2014
Revenue
Revenue		$	—
Revenue—related parties			—
			—
Cost and Expenses
Cost of services			—
Cost of services—related parties			—
Selling, general and administrative			116,226
Selling, general and administrative—related parties			—
Depreciation and amortization			—
			116,226
Operating loss			(116,226	)
Other Income (expense)
Interest expense			—
Other			—
			—
Net loss		$	(116,226	)

 

 

The accompanying notes are an integral part of these financial statements

 

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Mammoth Energy Partners LP

STATEMENT OF UNITHOLDERS’ EQUITY

 

		Unitholders				Predecessor Common				Total
Balance at February 5, 2014 (inception)		$	—			$	—			$	—
Contributions			—				100				100
Exchange of predecessor shares for units			100				(100	)			—
Net loss			(116,226	)			—				(116,226	)
Balance at June 30, 2014		$	(116,126	)		$	—			$	(116,126	)

 

 

 

The accompanying notes are an integral part of these financial statements

 

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Mammoth Energy Partners LP

STATEMENT OF CASH FLOWS

 

		February 5, 2014 (inception) to June 30, 2014
Cash flows from operating activities
Net loss		$	(116,226	)
Adjustments to reconcile loss to cash provided by operating activities:
Changes in assets and liabilities:
Accounts receivable			—
Receivables from related parties			(1,274,453	)
Prepaid expenses and other assets			—
Accounts payable			1,552,345
Payables to related parties			84,223
Accrued expenses and other liabilities			32,003
Net cash provided by operating activities			277,892
Cash flows from investing activities:
Net cash used in investing activities			—
Cash flows from financing activities:
Contributions			100
Net cash provided by financing activities			100
Net increase in cash and cash equivalents			277,992
Cash and cash equivalents at beginning of period			—
Cash and cash equivalents at end of period		$	277,992

 

 

The accompanying notes are an integral part of these financial statements

 

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Mammoth Energy Partners LP

NOTES TO FINANCIAL STATEMENTS

 

1.	Organization and Basis of Presentation

Mammoth Energy Partners LP (“Mammoth” or “the Company”) was originally formed by Wexford Capital LP (“Wexford”) in February 2014 as a holding company under the name Redback, Inc., which changed its name to Stingray Energy Services, Inc. in May 2014, and was converted to a Delaware limited partnership in August 2014 in connection with its proposed initial public offering (“IPO”).

Mammoth Energy intends to offer common units representing limited partner interests pursuant to an initial public offering. Prior to the closing of such offering, all the equity interests in Redback Energy Services LLC, Redback Coil Tubing LLC, Muskie Proppant LLC, Bison Drilling & Field Services LLC, Bison Trucking LLC, Panther Drilling Systems LLC, and Great White Sand Tiger Lodging Ltd will be contributed to Mammoth in return for common units and, as a result, such entities will become wholly-owned subsidiaries of Mammoth. In addition, at the same time, two other entities, Stingray Pressure Pumping LLC and Stingray Logistics LLC in which Wexford and its affiliates currently own, in the aggregate, a non-controlling 50% interest, will be contributed to Mammoth by all equity interest holders in these entities in return for common units, at which time the entities will also become wholly owned subsidiaries of Mammoth.

Operations

Mammoth is intended to hold the ownership of various operational entities related to drilling services. However, Mammoth is not expected to provide or utilize these services and therefore will maintain minimal operational activity. Mammoth will employ management and personnel for the purpose of the direction of the Company, but intends to allocate most, if not all, of these costs to its proposed wholly-owned subsidiaries.

 

2.	Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

All highly liquid investments with a maturity of three months or less when acquired are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. Mammoth had no restricted cash included in its cash balance at June 30, 2014.

(b) Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(c) Income Taxes

Mammoth is a limited partnership and, as such, is treated as a pass-through entity for income tax purposes. As a pass-through entity, income taxes on net earnings are payable by the members and are not reflected in the financial statements.

As required by the Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”), Income Taxes, Mammoth recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more-likely-than-not-threshold, the amount recognized in the financial statement is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. At June 30, 2014 there were no financial statement benefits or obligations recognized related to uncertain tax positions.

 

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Mammoth’s accounting policy related to income tax penalties and interest assessments is to accrue for these costs and record a charge to selling, general and administrative expense for tax penalties and a charge to interest expense for interest assessments during the period that Mammoth has unrecognized tax benefits. Mammoth is not subject to any tax examinations by tax authorities.

(d) Financial Instruments

Mammoth’s financial instruments consisted primarily of cash and cash equivalents, related party receivables, trade accounts payable and related party payables. The carrying of these instruments are considered representative of their fair value due to the short term nature of these instruments.

 

3.	Related Party Transactions

Mammoth incurred legal and administrative services on behalf of certain affiliates in relation to the proposed IPO. These amounts total $1,758,980 for the six months ended June 30, 2014. These amounts are payable by Mammoth and are fully reimbursed by related parties. As of June 30, 2014, $1,552,345 of these costs are included in trade payables and $1,274,453 are included in related party receivables in the accompanying balance sheet.

An entity under common ownership with Wexford provides administrative services to Mammoth. The costs of these services primarily relate to payroll services. The reimbursement amount is generally based on estimates of time devoted to Mammoth. $116,226 is included in selling, general and administrative expenses – related parties for the six months ended June 30, 2014 in the accompanying statement of operations. As of June 30, 2014 Mammoth owed the affiliate $84,223 and is included in payables to related parties in the accompanying balance sheet.

 

4.	Subsequent Events

The Company has evaluated the period after June 30, 2014 through September 23, 2014, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements.

 

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Dealer Prospectus Delivery Obligation

Until                     , 2014 (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Mammoth Energy Partners LP

                 Common Units Representing Limited Partner Interests

 

 

Prospectus

 

 

                    , 2014

 

 

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

The following table sets forth the fees and expenses in connection with the issuance and distribution of the securities being registered hereunder. Except for the SEC registration fee and FINRA filing fee, all amounts are estimates.

 

SEC registration fee		$	12,880
FINRA filing fee		$	14,850
NASDAQ Global Market listing fee			*
Accounting fees and expenses			*
Legal fees and expenses			*
Blue Sky fees and expenses (including counsel fees)			*
Printing and Engraving expenses			*
Transfer Agent and Registrar fees and expenses			*
Miscellaneous expenses			*
Total		$	*

 

*	To be completed by amendment.

Item 14. Indemnification of Directors and Officers of Our General Partner.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” is incorporated herein by reference and discloses that we will generally indemnify the directors, officers and affiliates of the general partner to the fullest extent permitted by law against all losses, claims, damages or similar events. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

Section 18-108 of the Delaware Limited Liability Company Act provides that a Delaware limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of Mammoth Energy Partners GP LLC, our general partner, provides for the indemnification of its directors and officers against liabilities they incur in their capacities as such. We and our general partner will also enter into indemnification agreements with each of the current directors and executive officers of our general partner effective upon the closing of this offering. These agreements will require us to indemnify these individuals to the fullest extent permitted by law against expenses incurred as a result of any proceeding in which they are involved by reason of their service to us and, if requested, to advance expenses incurred as a result of any such proceeding. We also intend to enter into indemnification agreements with future directors and executive officers of our general partner.

The underwriting agreement that we expect to enter into with the underwriters, the form of which will be filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions that will indemnify and hold harmless the directors and officers of our general partner.

Item 15. Recent Sales of Unregistered Securities.

In connection with the contribution described in this registration statement, we intend to issue              common units to Mammoth Energy Holdings LLC,              common units to Gulfport and              common units to Rhino, in each case prior to the effective date of this registration statement. The common units described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering.

 

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Item 16. Exhibits and Financial Statement Schedules.

(A) Exhibits:

 

Exhibit Number		Number Description
1.1***		Form of Underwriting Agreement.
3.1*		Certificate of Limited Partnership of the Partnership.
3.2**		Form of First Amended and Restated Agreement of Limited Partnership of the Partnership (included as Appendix A in the prospectus included in the Registration Statement).
4.2**		Form of Registration Rights Agreement by and between the Partnership and Mammoth Energy Holdings LLC.
4.3**		Form of Investor Rights Agreement by and among the Partnership, Mammoth Energy Partners GP LLC, Mammoth Energy Holdings LLC and Gulfport Energy Corporation.
4.4**		Form of Registration Rights Agreement by and between the Partnership and Rhino Resource Partners LP.
5.1**		Form of Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of the securities being registered.
8.1*		Form of Opinion of Akin Gump Strauss Hauer & Feld LLP relating to tax matters.
10.1**		Form of Advisory Services Agreement by and among Mammoth Energy Partners LP, Mammoth Energy Partners GP LLC and Wexford Capital LP.
10.2*		Agreement, dated June 25, 2012, by and between Great White Sand Tiger Lodging Ltd. and Grizzly Oil Sands ULC, as amended by Addendum, dated March 26, 2013.
10.3*		Master Service Contract, effective May 16, 2013, by and between Muskie Proppant LLC and Diamondback E&P LLC.
10.4*		Transloading Agreement, effective May 7, 2013, by and between Muskie Proppant LLC and Hopedale Mining LLC.
10.5*		Business Loan Agreement, dated April 1, 2014, by and between Redback Energy Services LLC and Legacy Bank.
10.6*		Business Loan Agreement, dated June 21, 2013, by and between Redback Energy Services LLC and Legacy Bank.
10.7*		Business Loan Agreement, dated October 7, 2013, by and between Redback Energy Services LLC and Legacy Bank.
10.8*		Loan and Security Agreement, dated October 14, 2013, by and between Redback Coil Tubing LLC and Stillwater National Bank and Trust Company.
10.9*		Business Note, dated January 31, 2013, issued by Muskie Proppant LLC to Citizens State Bank of La Crosse.
10.10*		Loan and Security Agreement, dated July 3, 2013, by and between Stingray Pressure Pumping LLC and International Bank of Commerce.
10.11*		Master Service Agreement, dated February 22, 2013, by and between Gulfport Energy Corporation and Panther Drilling Systems LLC.
10.12*		Master Service Contract, effective September 9, 2013, by and between Panther Drilling Systems LLC and Diamondback E&P LLC.
10.13*		First Amendment, dated February 21, 2013, to Master Field Services Agreement, effective January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC.

 

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Exhibit Number		Number Description
10.14*		Loan and Security Agreement, dated May 31, 2013, by and between Bison and Field Services LLC and International Bank of Commerce.
10.15*		First Modification, dated August 27, 2013, to Loan and Security Agreement, dated May 31, 2013, by and between Bison Drilling and Field Services LLC and International Bank of Commerce.
10.16*		Second Modification, dated January 31, 2014, to Loan and Security Agreement, dated May 31, 2013, by and between Bison Drilling and Field Services LLC and International Bank of Commerce.
10.17*		Master Field Services Agreement, effective January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC.
10.18*		Master Drilling Agreement, effective January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC.
10.19*		Form of Junior Secured Promissory Note issued by Muskie Proppant LLC to Wexford affiliates.
10.20*		Master Service Agreement, dated June 11, 2012, by and between Gulfport Energy Corporation and Redback Energy Services LLC.
10.21*		Master Service Contract, effective October 17, 2013, by and between Bison Trucking LLC and Diamondback E&P LLC.
10.22*		Limited Loan Guaranty Agreement, dated July 3, 2013, by Wexford Spectrum Investors LLC and Wexford Spectrum Trading Limited on behalf of Stingray Pressure Pumping LLC for the benefit of International Bank of Commerce.
10.23*		Master Loan and Security Agreement, dated November 26, 2012, by and between Stingray Logistics LLC and Mack Financial Services, a division of VFS US LLC.
10.24*		Credit Sales Contract, dated September 25, 2013, by and between Stingray Logistics LLC and Enid Mack Sales Inc.
10.25*		Business Loan Agreement, dated July 22, 2014, by and between Redback Energy Services, LLC and UMB Bank, n.a.
10.26**†		Form of Equity Incentive Plan.
10.27**†		Form of Unit Option Agreement.
10.28**†		Form of Phantom Unit Award Agreement.
10.29**†		Form of Director and Officer Indemnification Agreement.
10.30**		Form of Contribution Agreement by and between Mammoth Energy Holdings LLC and the Partnership.
10.31**		Form of Contribution Agreement by and between Gulfport Energy Corporation and the Partnership.
10.32**		Form of Contribution Agreement by and between Rhino Resource Partners LP and the Partnership.
10.33**		Limited Loan Guaranty Agreement, dated January 31, 2014, by Lambda Investors LLC on behalf of Bison Drilling and Field Services LLC for the benefit of International Bank of Commerce.
10.34**		Limited Loan Guaranty Agreement, dated January 31, 2014, by Wexford Partners 11, L.P. on behalf of Bison Drilling and Field Services LLC for the benefit of International Bank of Commerce.
10.35**		First Modification, dated September 30, 2014, to Loan and Security Agreement, dated July 3, 2013, by and between Stingray Pressure Pumping LLC and International Bank of Commerce.

 

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Exhibit Number		Number Description
10.36**		Acknowledgement and Consent, dated September 2014, by Wexford Spectrum Investors LLC and Wexford Spectrum Trading Limited as Guarantors pursuant to Limited Loan Guaranty Agreement, dated July 3, 2013 on behalf of Stingray Pressure Pumping LLC for the benefit of International Bank of Commerce.
10.37**#		Amended & Restated Master Services Agreement for Pressure Pumping Services Agreement, effective as of October 1, 2014, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.
10.38**#		Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and Gulfport Energy Corporation.
10.39**		Business Loan agreement, dated September 8, 2014, by and between Panther Drilling Systems LLC and Bank7.
21.1**		List of Significant Subsidiaries of the Partnership.
23.1**		Consent of Grant Thornton LLP with respect to Redback Energy Services.
23.2**		Consent of Grant Thornton LLP with respect to the Stingray Pressure Pumping LLC and Affiliate.
23.3**		Consent of Grant Thornton LLP with respect to Mammoth Energy Partners LP.
23.4**		Consent of Grant Thornton LLP with respect to Lantern Drilling Company.
23.5**		Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 5.1).
23.6*		Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 8.1).
24.1*		Power of Attorney.
99.1*		Consent of Spencer D. Armour, III to being named as a director nominee.
99.2*		Consent of Aaron Gaydosik to being named as a director nominee.
99.3*		Consent of Joseph M. Jacobs to being named as a director nominee.
99.4*		Consent of Kenneth A. Rubin to being named as a director nominee.

 

*	Previously filed.

**	Filed herewith.

***	To be filed by amendment.

†	Management contract, compensatory plan or arrangement.

#	Confidential treatment requested as to certain portions, which portions have been omitted and filed separately with the Securities and Exchange Commission.

(B) Financial Statement Schedules.

All schedules are omitted because the required information is (i) not applicable, (ii) not present in amounts sufficient to require submission of the schedule or (iii) included in our financial statements and the accompanying notes included in the prospectus to this Registration Statement.

Item 17. Undertakings.

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification by the Registrant for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such

 

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indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer, or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered hereunder, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Oklahoma City, Oklahoma, on October 14, 2014.

 

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on October 14, 2014.

 

Signature		Title
/s/ Marc McCarthy      Marc McCarthy		Chairman of the Board and Director (Principal Executive Officer)
/s/ Phil Lancaster      Phil Lancaster		President
/s/ Mark Layton      Mark Layton		Chief Financial Officer (Principal Financial and Accounting Officer)

 

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EXHIBIT INDEX

 

Exhibit Number		Number Description
1.1***		Form of Underwriting Agreement.
3.1*		Certificate of Limited Partnership of the Partnership.
3.2**		Form of First Amended and Restated Agreement of Limited Partnership of the Partnership (included as Appendix A in the prospectus included in the Registration Statement).
4.2**		Form of Registration Rights Agreement by and between the Partnership and Mammoth Energy Holdings LLC.
4.3**		Form of Investor Rights Agreement by and among the Partnership, Mammoth Energy Partners GP LLC, Mammoth Energy Holdings LLC and Gulfport Energy Corporation.
4.4**		Form of Registration Rights Agreement by and between the Partnership and Rhino Resource Partners LP.
5.1**		Form of Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of the securities being registered.
8.1*		Form of Opinion of Akin Gump Strauss Hauer & Feld LLP relating to tax matters.
10.1**		Form of Advisory Services Agreement by and among Mammoth Energy Partners LP, Mammoth Energy Partners GP LLC and Wexford Capital LP.
10.2*		Agreement, dated June 25, 2012, by and between Great White Sand Tiger Lodging Ltd. and Grizzly Oil Sands ULC, as amended by Addendum, dated March 26, 2013.
10.3*		Master Service Contract, effective May 16, 2013, by and between Muskie Proppant LLC and Diamondback E&P LLC.
10.4*		Transloading Agreement, effective May 7, 2013, by and between Muskie Proppant LLC and Hopedale Mining LLC.
10.5*		Business Loan Agreement, dated April 1, 2014, by and between Redback Energy Services LLC and Legacy Bank.
10.6*		Business Loan Agreement, dated June 21, 2013, by and between Redback Energy Services LLC and Legacy Bank.
10.7*		Business Loan Agreement, dated October 7, 2013, by and between Redback Energy Services LLC and Legacy Bank.
10.8*		Loan and Security Agreement, dated October 14, 2013, by and between Redback Coil Tubing LLC and Stillwater National Bank and Trust Company.
10.9*		Business Note, dated January 31, 2013, issued by Muskie Proppant LLC to Citizens State Bank of La Crosse.
10.10*		Loan and Security Agreement, dated July 3, 2013, by and between Stingray Pressure Pumping LLC and International Bank of Commerce.
10.11*		Master Service Agreement, dated February 22, 2013, by and between Gulfport Energy Corporation and Panther Drilling Systems LLC.
10.12*		Master Service Contract, effective September 9, 2013, by and between Panther Drilling Systems LLC and Diamondback E&P LLC.
10.13*		First Amendment, dated February 21, 2013, to Master Field Services Agreement, effective January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC.

 

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Exhibit Number		Number Description
10.14*		Loan and Security Agreement, dated May 31, 2013, by and between Bison and Field Services LLC and International Bank of Commerce.
10.15*		First Modification, dated August 27, 2013, to Loan and Security Agreement, dated May 31, 2013, by and between Bison Drilling and Field Services LLC and International Bank of Commerce.
10.16*		Second Modification, dated January 31, 2014, to Loan and Security Agreement, dated May 31, 2013, by and between Bison Drilling and Field Services LLC and International Bank of Commerce.
10.17*		Master Field Services Agreement, effective January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC.
10.18*		Master Drilling Agreement, effective January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC.
10.19*		Form of Junior Secured Promissory Note issued by Muskie Proppant LLC to Wexford affiliates.
10.20*		Master Service Agreement, dated June 11, 2012, by and between Gulfport Energy Corporation and Redback Energy Services LLC.
10.21*		Master Service Contract, effective October 17, 2013, by and between Bison Trucking LLC and Diamondback E&P LLC.
10.22*		Limited Loan Guaranty Agreement, dated July 3, 2013, by Wexford Spectrum Investors LLC and Wexford Spectrum Trading Limited on behalf of Stingray Pressure Pumping LLC for the benefit of International Bank of Commerce.
10.23*		Master Loan and Security Agreement, dated November 26, 2012, by and between Stingray Logistics LLC and Mack Financial Services, a division of VFS US LLC.
10.24*		Credit Sales Contract, dated September 25, 2013, by and between Stingray Logistics LLC and Enid Mack Sales Inc.
10.25*		Business Loan Agreement, dated July 22, 2014, by and between Redback Energy Services, LLC and UMB Bank, n.a.
10.26**†		Form of Equity Incentive Plan.
10.27**†		Form of Unit Option Agreement.
10.28**†		Form of Phantom Unit Award Agreement.
10.29**†		Form of Director and Officer Indemnification Agreement.
10.30**		Form of Contribution Agreement by and between Mammoth Energy Holdings LLC and the Partnership.
10.31**		Form of Contribution Agreement by and between Gulfport Energy Corporation and the Partnership.
10.32**		Form of Contribution Agreement by and between Rhino Resource Partners LP and the Partnership.
10.33**		Limited Loan Guaranty Agreement, dated January 31, 2014, by Lambda Investors LLC on behalf of Bison Drilling and Field Services LLC for the benefit of International Bank of Commerce.
10.34**		Limited Loan Guaranty Agreement, dated January 31, 2014, by Wexford Partners 11, L.P. on behalf of Bison Drilling and Field Services LLC for the benefit of International Bank of Commerce.
10.35**		First Modification, dated September 30, 2014, to Loan and Security Agreement, dated July 3, 2013, by and between Stingray Pressure Pumping LLC and International Bank of Commerce.

 

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Exhibit Number		Number Description
10.36**		Acknowledgement and Consent, dated September 2014, by Wexford Spectrum Investors LLC and Wexford Spectrum Trading Limited as Guarantors pursuant to Limited Loan Guaranty Agreement, dated July 3, 2013 on behalf of Stingray Pressure Pumping LLC for the benefit of International Bank of Commerce.
10.37**#		Amended & Restated Master Services Agreement for Pressure Pumping Services Agreement, effective as of October 1, 2014, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.
10.38**#		Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and Gulfport Energy Corporation.
10.39**		Business Loan Agreement, dated September 8, 2014, by and between Panther Drilling Systems LLC and Bank7.
21.1**		List of Significant Subsidiaries of the Partnership.
23.1**		Consent of Grant Thornton LLP with respect to Redback Energy Services.
23.2**		Consent of Grant Thornton LLP with respect to the Stingray Pressure Pumping LLC and Affiliate.
23.3**		Consent of Grant Thornton LLP with respect to Mammoth Energy Partners LP.
23.4**		Consent of Grant Thornton LLP with respect to Lantern Drilling Company.
23.5**		Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 5.1).
23.6*		Consent of Akin Gump Strauss Hauer & Feld LLP (Contained in Exhibit 8.1).
24.1*		Power of Attorney.
99.1*		Consent of Spencer D. Armour, III to being named as a director nominee.
99.2*		Consent of Aaron Gaydosik to being named as a director nominee.
99.3*		Consent of Joseph M. Jacobs to being named as a director nominee.
99.4*		Consent of Kenneth A. Rubin to being named as a director nominee.

 

*	Previously filed.

**	Filed herewith.

***	To be filed by amendment.

†	Management contract, compensatory plan or arrangement.

#	Confidential treatment requested as to certain portions, which portions have been omitted and filed separately with the Securities and Exchange Commission.

 

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