As filed with the Securities and Exchange Commission on May 4, 2012

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Maxum Energy Logistics Partners, LP

(Exact Name of Registrant as Specified in its Charter)

Delaware

(State or other Jurisdiction of
Incorporation or Organization)

5172

(Primary Standard Industrial
Classification Code Number)

37-1652910

(IRS Employer
Identification Number)

20 Horseneck Lane

Greenwich, Connecticut 06830

(203) 861-1200

(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

Belinda Foxworth

20 Horseneck Lane

Greenwich, Connecticut 06830

(203) 861-1200

(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)

Copies to:

Joshua Davidson

Hillary H. Holmes

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002-4995

(713) 229-1234

William N. Finnegan IV

Charles E. Carpenter

Divakar Gupta

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

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

If any of the 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, 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		Smaller reporting company ¨

(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE



Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price (1) (2)	Amount of Registration Fee
Common units representing limited partner interests	$230,000,000	$26,358

(1)	Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

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 of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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

SUBJECT TO COMPLETION, DATED MAY 4, 2012

PRELIMINARY PROSPECTUS

Common Units

Representing Limited Partner Interests

Maxum Energy Logistics Partners, LP

This is the initial public offering of our common units representing limited partner interests. We are offering common units in this offering. We currently expect that the initial public offering price will be between $ and $ per common unit. Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “MXLP.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 22.

These risks include the following:

•

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

•

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended June 30, 2011 or the twelve months ended December 31, 2011.

•

We serve customers who are involved in drilling for and producing oil and natural gas. Adverse developments affecting the oil and natural gas industry or drilling activity, including sustained low natural gas prices, a decline in oil or natural gas liquids prices, reduced demand for oil and natural gas products and increased regulation of drilling and production, could have a material adverse effect on our results of operations.

•

We serve customers who mine for coal. Adverse developments affecting the coal mining industry or mining activity, including sustained low natural gas prices and regulatory developments, could have a material adverse effect on our results of operations.

•

The contracts we have with most of our customers do not obligate them to purchase product from us.

•

Our operations are subject to or otherwise affected by federal, state, and local laws and regulations relating to environmental protection that could require us to incur substantial costs and liabilities.

•

Our general partner and its affiliates, including Maxum Petroleum and its sponsors, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and the detriment of our public common unitholders.

•

Maxum Petroleum and other affiliates of our general partner are not restricted in their ability to compete with us.

•

You will experience immediate and substantial dilution in net tangible book value of $ per common unit.

•

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

•

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

•

Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


	Per Common Unit	Total
Public Offering Price	$	$
Underwriting Discount (1)	$	$
Proceeds to Maxum Energy Logistics Partners, LP (before expenses)	$	$

(1)

Excludes a structuring fee of an aggregate of % of the gross offering proceeds payable to Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC. Please read “Underwriting” beginning on page 186.

We have granted the underwriters a 30-day option to purchase up to an additional common units on the same terms and conditions as set forth above if the underwriters sell more than common units in this offering.

The underwriters expect to deliver the common units to purchasers on or about , 2012, through the book-entry facilities of The Depository Trust Company.


BofA Merrill Lynch		J.P. Morgan

[Inside cover art]

TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
Maxum Energy Logistics Partners, LP			1
Overview			1
Our Business Strategies			3
Our Competitive Strengths			4
Our Relationship with Maxum Petroleum			5
Risk Factors			6
Management of Maxum Energy Logistics Partners, LP			8
Formation Transactions and Partnership Structure			8
Ownership of Maxum Energy Logistics Partners, LP			10
Principal Executive Offices and Internet Address			11
Summary of Conflicts of Interest and Duties			11
The Offering			12
Summary Historical and Pro Forma Financial and Operating Data			17
Non-GAAP Financial Measures			19
RISK FACTORS			22
Risks Related to Our Business			22
Risks Inherent in an Investment in Us			38
Tax Risks to Common Unitholders			48
USE OF PROCEEDS			54
CAPITALIZATION			55
DILUTION			56
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			58
General			58
Our Minimum Quarterly Distribution			59
Unaudited Pro Forma Cash Available for Distribution for the Year Ended June 30, 2011 and the Twelve Months Ended December 31, 2011			61
Estimated Cash Available for Distribution for the Year Ending June 30, 2013			63
Assumptions and Considerations			66
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			69
Distributions of Available Cash			69
Distributable Cash Flow and Capital Surplus			69
Subordination Period			71
Distributions of Available Cash from Distributable Cash Flow during the Subordination Period			72
Distributions of Available Cash from Distributable Cash Flow after the Subordination Period			73
General Partner Interest			73
Incentive Distribution Rights			73
Percentage Allocations of Available Cash From Distributable Cash Flow			74
General Partner’s Right to Reset Incentive Distribution Levels			74
Distributions from Capital Surplus			77
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			78
Distributions of Cash Upon Liquidation			78
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			81
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			83
Business Overview			83
Our Operations			83
How We Evaluate Our Operations			84
Items Impacting the Comparability of Our Financial Results			86
General Trends and Outlook			87


Results of Operations			88
Liquidity and Capital Resources			96
Critical Accounting Policies and Estimates			99
Recent Accounting Pronouncements			101
Off-Balance Sheet Arrangements			101
Seasonality			101
Effects of Inflation			101
Quantitative and Qualitative Disclosures about Market Risk			102
INDUSTRY			103
Refined Petroleum Marketing and Distribution Industry			103
Our Customers’ Industries: E&P and Coal			105
BUSINESS			111
Overview			111
Our Business Strategies			112
Our Competitive Strengths			114
Our Relationship with Maxum Petroleum			115
Products and Services			117
Customers			119
Suppliers			120
Distribution Capabilities			120
Competition			122
Environmental			122
Insurance			126
Employee Safety, Transportation and Site Security			126
Regulation of Transportation			126
Employees			127
Legal Proceedings			127
MANAGEMENT			128
Management of Maxum Energy Logistics Partners, LP			128
Directors and Executive Officers of Our General Partner			129
Board Leadership Structure			132
Board Role in Risk Oversight			132
Committees of the Board of Directors			132
EXECUTIVE COMPENSATION			134
Compensation Discussion and Analysis			134
Compensation of Directors			135
Long-Term Incentive Plan			135
Reimbursement of Expenses of Our General Partner			137
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			138
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			140
Distributions and Payments to Our General Partner and Its Affiliates			140
Agreements Governing the Transactions			141
Omnibus Agreement			141
Transactions with Affiliates			142
Review, Approval or Ratification of Transactions with Related Persons			142
CONFLICTS OF INTEREST AND DUTIES			143
Conflicts of Interest			143
Duties of the General Partner			149
DESCRIPTION OF THE COMMON UNITS			151
The Units			151
Transfer Agent and Registrar			151
Transfer of Common Units			151


THE PARTNERSHIP AGREEMENT			153
Organization and Duration			153
Purpose			153
Capital Contributions			153
Voting Rights			154
Limited Liability			155
Issuance of Additional Partnership Interests			156
Amendment of the Partnership Agreement			156
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			159
Termination and Dissolution			159
Liquidation and Distribution of Proceeds			160
Withdrawal or Removal of the General Partner			160
Transfer of General Partner Units			161
Transfer of Ownership Interests in the General Partner			162
Transfer of Incentive Distribution Rights			162
Change of Management Provisions			162
Limited Call Right			162
Meetings; Voting			163
Status as Limited Partner			163
Redemption of Ineligible Holders			163
Indemnification			164
Reimbursement of Expenses			164
Books and Reports			164
Right to Inspect Our Books and Records			165
Registration Rights			165
UNITS ELIGIBLE FOR FUTURE SALE			166
Rule 144			166
Our Partnership Agreement and Registration Rights			166
Lock-Up Agreements			166
Registration Statement on Form S-8			167
MATERIAL FEDERAL INCOME TAX CONSEQUENCES			168
Partnership Status			168
Limited Partner Status			170
Tax Consequences of Unit Ownership			170
Tax Treatment of Operations			176
Disposition of Common Units			177
Uniformity of Units			179
Tax-Exempt Organizations and Other Investors			180
Administrative Matters			181
State, Local, Foreign and Other Tax Considerations			184
INVESTMENT IN MAXUM ENERGY LOGISTICS PARTNERS, LP BY EMPLOYEE BENEFIT PLANS			185
UNDERWRITING			186
VALIDITY OF THE COMMON UNITS			192
EXPERTS			192
WHERE YOU CAN FIND MORE INFORMATION			192
FORWARD-LOOKING STATEMENTS			193
INDEX TO FINANCIAL STATEMENTS			F-1
Appendix A—Form of Amended and Restated Agreement of Limited Partnership of Maxum Energy Logistics Partners, LP			A-1
Appendix B—Glossary of Industry Terms			B-1

iii

You should rely only on the information contained in this prospectus and any free writing prospectus provided by us. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the cover page of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources, as well as our good faith estimates.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including “Risk Factors” beginning on page 22 and the historical combined and pro forma condensed consolidated financial statements and the notes to those financial statements included elsewhere in this prospectus. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover page of this prospectus) and (2) no exercise by the underwriters of their option to purchase additional common units. We include a glossary of some of the terms used in this prospectus as Appendix B. References in this prospectus to “Maxum Energy,” “we,” “our,” “us” or like terms when used in a historical context refer to the businesses and assets of Petroleum Products, Inc., Petroleum Transport, Inc., Petroleum Fueling, Inc., Simons Petroleum, Inc., excluding the Pathway business (“Pathway”), and the assets of Maxum Acquisition LLC, which are used by Simons Petroleum, Inc., which are wholly owned subsidiaries of Maxum Petroleum, Inc. and which we refer to collectively as our “Predecessor.” When used in the present tense or prospectively, those terms refer to Maxum Energy Logistics Partners, LP and its subsidiaries. References in this prospectus to “Maxum Petroleum” refer to Maxum Petroleum, Inc. and its controlled affiliates (other than us). References to our general partner refer to Maxum Energy Logistics Partners GP, LLC, a wholly owned subsidiary of Maxum Petroleum. Please read “—Formation Transactions and Partnership Structure” beginning on page 8.

Maxum Energy Logistics Partners, LP

Overview

We are one of the largest independent marketers and distributors of refined petroleum products and related services to the drilling, exploration and production (“E&P”) and coal mining industries in the continental United States. We procure and sell diesel fuel, lubricating oil and custom-blended lubricants to companies engaged in the drilling for and production of oil and natural gas and in the mining of coal. We deliver these products to our customers at their well sites or mining locations. We also provide value-added logistics and energy management services necessary for drilling, production and mining activity, such as on-site refueling of equipment for drilling and hydraulic fracturing and coal mining operations and the design, fabrication and provision of storage tanks and other equipment to well sites and mining locations. Our services also include the provision of fuel additives; removal, recycling and disposal of used oil and lubricants; lubricant oil analysis; remote monitoring of fuel tanks; and maintenance and inspection of drilling, production and mining equipment. Within the E&P industry, we have three major customer groups: (i) E&P companies that hold oil and natural gas drilling rights, who purchase our fuel and services; (ii) drilling contractors providing services to E&P companies, who purchase our lubricants and services; and (iii) well completion companies providing hydraulic fracturing services for unconventional oil and natural gas wells, who purchase our fuel, lubricants and services. The well sites where we perform our services are located in the major U.S. unconventional oil and natural gas plays, including the Bakken, Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, Utica and Woodford Shales, and the Permian Basin. In the coal mining industry, we sell our fuel, lubricants and services to mining companies. Substantially all of the coal mining locations that we currently serve are located in the Central Appalachian region of the United States.

The following charts show our revenues by product and our product margins by product for the twelve months ended December 31, 2011:

Our extensive logistics platform has been tailored to the needs of our customers and can move with our customers to their new areas of operation in the United States. Our logistics platform features a fleet of approximately 730 transport or other delivery vehicles, the substantial majority of which are custom-equipped or modified primarily to deliver fuel and lubricants and provide services to remote, rugged or environmentally sensitive sites. These vehicles are built to our specifications, which include a stronger suspension system than on comparable vehicles to accommodate increased weight, and are operated by our skilled and extensively trained drivers. As of December 31, 2011, our logistics platform also included approximately 40 owned or leased distribution and warehouse facilities, supply procurement arrangements at approximately 380 fuel supply locations nationally, approximately 30 contracted rail cars, and over 11,000 tanks and other equipment located at customers’ sites.

We have more than 35 years of marketing and distribution experience serving the E&P industry and more than 70 years of experience serving the coal mining industry. During this time, we have developed strong relationships with our customers in both industries. These customers include BP, Chesapeake Energy, Devon, Encana and Helmerich & Payne in the E&P industry and Alpha Natural Resources, Arch Coal, Bluestone Coal, CONSOL Energy and Patriot Coal in the coal mining industry, among others. The average length of our relationships with our top ten customers is over 13 years. We tailor our products and services to each customer’s specific needs, making our services an integrated part of the customer’s operations. In addition, we are a critical link in the supply chain for customers who often lack the required internal staffing, resources, specialized equipment and market expertise to efficiently procure their own fuel and lubricants. We believe we have the necessary resources, capabilities, supplier relationships, infrastructure, technology and management expertise to expand our customer base and to increase the volume of products and services provided to current customers.

Our management team has a successful track record of identifying, executing and integrating strategic acquisitions. The businesses we have acquired have expanded our geographic footprint, diversified our product and service offerings and generated increased revenue and significant cost synergies. We continually look for strategic targets that could further increase our scale and expand our customer base. We expect to benefit from continuing industry consolidation trends. From the year ended June 30, 2009 to the twelve months ended December 31, 2011, through organic growth and acquisitions, we increased our fuel gallons sold from 411 million gallons to 495 million gallons, our lubricant gallons sold from 14 million gallons to 17 million gallons and our total product margin from $113.7 million to $142.4 million. For a reconciliation of product margin to the GAAP measure gross profit, please read “—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Our Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while maintaining the stability of our business. We expect to achieve this objective through the following strategies:

•

Increase Business with Existing Customers. We are focused on serving large customers in the E&P and coal mining industries and we intend to increase our business with existing customers across regions, products and services. As our customers increase activity in current production areas or expand into new areas, we believe our financial position, geographic reach and breadth of product and service offerings make us more attractive than many of our competitors as a source of the products and services required by our customers. We continue to invest capital and move resources into new production areas as drilling and well completion activity increases. In addition to geographic growth, a key component of our strategy is to expand the number of products and services we provide to existing customers. We believe this strategy will strengthen our overall relationships with our customers and increase our market share. As a result, the volumes of products we sell can increase at a faster pace than rig count growth in the areas we serve.

•

Attract New Customers. We plan to leverage our existing logistics infrastructure, industry knowledge and operating experience to attract new customers that are currently underserved by smaller, independent distributors. We believe that our superior financial resources, operational capabilities and the breadth of our product and service offerings give us an advantage over these competitors. For example, we have the ability to pursue customers in remote, rugged or environmentally sensitive areas, such as mountainous regions and mines, where we generally obtain higher product margins for our fuel and lubricant deliveries and services. We are capitalizing on the recent growth in drilling and exploration in unconventional oil and natural gas shale plays and liquids-rich plays, including the Bakken, Eagle Ford and Utica Shales, by expanding our oilfield service capabilities to service these areas.

•

Continue to Grow with Selective Acquisitions. We plan to pursue accretive acquisitions from third parties of businesses and assets that strengthen our competitive position. We may also acquire from Maxum Petroleum assets and businesses that it owns or may acquire in the future. We target businesses and assets that complement our existing products and services, increase our scale, improve our operating efficiencies and increase and diversify our geographic coverage and customer base.

•

Continue to Improve Cost Efficiencies. We seek to minimize our cost of fuel procurement and delivery through economies of scale, stable and long-term relationships with suppliers and customers and procurement software. We expect to continue to negotiate bulk purchases of fuel and lubricants at favorable prices due to the frequency and volume of our purchases. We also selectively seek to increase the number of our sole supplier relationships with larger customers. These relationships lead to higher asset utilizations and correspondingly lower operating costs because of increased scale within a location. We are able to further reduce costs by using our procurement software to analyze fuel prices at, and transportation costs from, each of the approximately 380 fuel supply locations nationally from which we have the ability to procure fuel in order to identify the lowest fuel price available in any region on any given day.

•

Operate Safely and Responsibly. We intend to maintain our long history of safe operations and environmental compliance by applying new technologies and investing in training programs for our personnel. We believe that higher safety requirements and employee training standards are points of differentiation for operators engaged in large-scale commercial distribution. We work diligently to

meet or exceed applicable safety and environmental regulations and we intend to continue to enhance our safety monitoring function as our business grows and operating conditions change.

Our Competitive Strengths

We believe we are distinguished by the following key competitive strengths:

•

Leading Position in a Growing Industry. We believe we are the largest independent distributor of fuels, lubricants and related services to the E&P industry in the continental United States with sales of approximately 308 million gallons of fuel and eight million gallons of lubricants during the twelve months ended December 31, 2011. As companies in the industries we serve seek to become more competitive, we believe they will continue to focus on their core business processes and outsource their procurement and logistics processes to third-party providers such as us. We have the purchasing power, financial resources, supplier relationships and product and service offerings to benefit significantly in the projected growth of demand for refined petroleum products for use in the E&P industry.

•

Large Geographic Footprint and Mobile Assets. Our large geographic footprint and the mobility of our logistics platform allow us to react quickly to customer movement and changing demand. We have strategically deployed assets that allow us to operate in 16 states to meet the demands of our more than 1,600 customers located across the United States. We believe that our relative size makes it easier for us than most of our competitors to provide services as our customers move their operations to new or remote locations. We expect to be able to seamlessly provide access to products in areas where we do not currently operate by relying on Maxum Petroleum’s assets.

•

Strong, Long-Standing Customer Relationships. We believe the manner in which we provide products and value-added services has resulted in customer loyalty and customer retention. We are able to provide products and services critical to the operations of our customers and become an integral part of their on-site operations. We provide the fuel, lubricants and related services required by drilling and mining equipment in remote, rugged or environmentally sensitive locations, on-site equipment monitoring and maintenance, fuel management programs, cost control programs and environmental services, all with short response times and round-the-clock service. We believe our extensive logistics platform makes it difficult for our customers to duplicate our infrastructure. The average length of our relationships with our top ten customers is over 13 years, and we have entered into sole supplier arrangements with a growing number of these customers.

•

Specialized Equipment and Products and Skilled Employees. We have used our intimate customer knowledge to tailor our extensive logistics platform and product offerings to the needs of our customers, becoming an integral part of their operations. The majority of our fleet of approximately 730 delivery vehicles are equipped or modified to deliver fuel, lubricants and other fluids to well and mine sites in remote, rugged or environmentally sensitive areas. Our fleet is operated by skilled drivers, each of whom receives extensive safety and environmental training and, in most cases, is approved by the safety departments of each customer for which he or she makes deliveries. In addition, we have developed specialized products that are blended for us to our specifications in order to meet our customers’ standards.

•

Long-Standing Relationships with Many Suppliers. One of the most critical issues for our customers is reliability of supply. We have strong relationships with, and purchase substantial quantities of fuel and lubricants from, many major oil companies and lubricant manufacturers, including Chevron, Citgo, Marathon Petroleum Corporation and Phillips 66. We are a significant customer of each of our key suppliers as a result of the volume and frequency of our fuel and lubricant

purchases. The average length of our relationships with our top ten suppliers is over 17 years. We believe our significant relationships with a large number of suppliers is uncommon in our industry. In times of constrained supply, we have been able to maintain access to the products we sell when other distributors have not been able to do so, due in part to our status as an important customer of both national and regional major oil companies as a result of the volume of fuel and lubricants we regularly purchase from them.

•

Strong Liquidity Position. Concurrent with the completion of this offering, we intend to enter into a new revolving credit facility. We expect that the revolving credit facility will provide for aggregate borrowings of up to $ million (with an accordion option to increase the maximum availability of the facility to up to $ million), subject to borrowing base availability. In addition, we expect to have approximately $ million of cash for working capital purposes immediately following the completion of this offering. This liquidity will provide us with the strength and flexibility to seek attractive acquisitions as they arise and expand our geographic and service offerings to our customers.

•

Experienced Management and Strong Sponsor. We are led by an experienced management team with significant operating and financial expertise. Our executive officers have an average of more than 20 years of relevant experience in the distribution and energy industries. Our senior management has a strong track record of identifying, completing and integrating acquisitions. We have also retained key managers of our acquired companies, which provides our management team with further depth and experience. In addition, our relationship with Maxum Petroleum will provide us with many advantages that we expect will enhance our results of operations.

Our Relationship with Maxum Petroleum

One of our principal attributes is our relationship with Maxum Petroleum. Maxum Petroleum is a leader in the independent energy logistics industry that markets and distributes a comprehensive offering of refined petroleum products and provides value-added logistics and energy management services to a diverse customer base in the United States and Panama. Maxum Petroleum is also one of the largest independent distributors of refined petroleum products to industrial and commercial customers in the country based on gallons of refined fuel and lubricants sold. For the twelve months ended December 31, 2011, including the assets to be contributed to us, Maxum Petroleum had revenues of $4.5 billion and sold 1.2 billion gallons of diesel fuel and 52.6 million gallons of lubricants. Maxum Petroleum’s procurement and logistics expertise, significant scale, strong supplier relationships, broad distribution platform, enterprise-wide information technology systems, suite of complementary and value-added services and experienced management team make it a leader in the refined petroleum marketing and distribution industry.

At the completion of this offering, Maxum Petroleum will own a 2.0% general partner interest in us, all of our incentive distribution rights and a % limited partner interest in us. Because of its ownership of the incentive distribution rights, Maxum Petroleum is positioned to directly benefit from facilitating accretive acquisitions and organic growth opportunities for us. However, Maxum Petroleum is under no obligation to make acquisition opportunities available to us, is not restricted from competing with us and may acquire or dispose of assets that would be useful in our business without any obligation to offer us the opportunity to purchase these assets. Please read “Certain Relationships and Related Party Transactions—Omnibus Agreement” beginning on page 141.

We believe that our relationship with Maxum Petroleum is an advantage that will enhance our results of operations. Together with Maxum Petroleum, we have increased purchasing power and can aggregate our demand to negotiate better prices for the products we sell. Maxum Petroleum also has relationships with key

suppliers, such as Phillips 66, Shell and Chevron, that reduce our costs and provide us with access to a reliable supply of lubricants. Our relationship with Maxum Petroleum will also provide us with access to its enterprise-wide information system and procurement software. In addition to the assets Maxum Petroleum will contribute to us at the completion of this offering, Maxum Petroleum owns or leases approximately 30 distribution and warehouse facilities in Arizona, California, Colorado, Illinois, Indiana and Washington, which we expect to be able to utilize to respond quickly to a business opportunity.

We believe we will also benefit from the quality and depth of Maxum Petroleum’s management and operations teams, which we believe are among the best in the industry. In addition, we may have the opportunity to purchase assets and businesses that Maxum Petroleum owns, including its lubricant blending business, or assets and businesses that Maxum Petroleum may acquire in the future, although it is under no obligation to make such opportunities available to us on acceptable terms or at all.

In addition, Maxum Petroleum is supported by strong financial sponsors with additional knowledge and resources. Maxum Petroleum’s two primary sponsors are Metalmark Capital LLC and Waud Capital Partners LLC.

While our relationship with Maxum Petroleum, its subsidiaries and its sponsors may provide significant benefits, it may also become a source of potential conflict. For example, none of Maxum Petroleum or its sponsors are restricted from competing with us. In addition, all of the initial executive officers and certain of the directors of our general partner also serve as officers and/or directors of Maxum Petroleum or its sponsors, and these officers and directors face conflicts of interest, including conflicts of interest regarding the allocation of their time between us and Maxum Petroleum or its sponsors. Please read “Conflicts of Interest and Duties” beginning on page 143.

Risk Factors

An investment in our common units involves risks associated with our business, our regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. For a more thorough description of the risks associated with an investment in our common units, you should carefully consider the risks described in “Risk Factors” beginning on page 22 of this prospectus and the other information in this prospectus before deciding whether to invest in our common units.

Risks Related to Our Business

•

The assumptions underlying the forecast of cash available for distribution that we include in “Our Cash Distribution Policy and Restrictions On Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

•

We serve customers who are involved in drilling for and producing oil and natural gas. Adverse developments affecting the oil and natural gas industry or drilling activity, including sustained low

natural gas prices, a decline in oil or natural gas liquids prices, reduced demand for oil and natural gas products and increased regulation of drilling and production, could have a material adverse effect on our results of operations.

•

The contracts we have with most of our customers do not obligate them to purchase product from us.

•

Risks Inherent in an Investment in Us

•

Our general partner’s affiliates, including Maxum Petroleum and its sponsors, are not restricted in their ability to compete with us.

•

You will experience immediate and substantial dilution in net tangible book value of $ per common unit.

•

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

•

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

•

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

Tax Risks to Common Unitholders

•

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

•

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

•

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

•

Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

Management of Maxum Energy Logistics Partners, LP

We are managed and operated by the board of directors and executive officers of our general partner, Maxum Energy Logistics Partners GP, LLC. Maxum Petroleum will own all of the ownership interests in our general partner and will be entitled to appoint the entire board of directors of our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. All of the initial officers of our general partner and some of its initial directors are also officers or directors of Maxum Petroleum. For information about the executive officers and directors of our general partner, please read “Management” beginning on page 128.

Under the listing requirements of the New York Stock Exchange, or NYSE, the board of directors of our general partner will be required to have at least three independent directors meeting the NYSE’s independence standards. At the completion of this offering, the board of directors of our general partner will be comprised of directors, including at least two independent directors. Maxum Petroleum will appoint a third independent director within the time periods prescribed by the NYSE.

In connection with the completion of this offering, we will enter into an omnibus agreement with Maxum Petroleum, our general partner and certain of their affiliates, pursuant to which we will agree upon certain aspects of our relationship with them, including the provision by Maxum Petroleum to us of certain administrative services and employees, our agreement to reimburse Maxum Petroleum for the cost of such services and employees, certain indemnification obligations, the use by us of the name “Maxum” and related marks, and other matters. Neither our general partner nor Maxum Petroleum will receive any management fee or other compensation in connection with our general partner’s management of our business. However, prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Maxum Petroleum, for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions—Omnibus Agreement” beginning on page 141.

Our general partner will own general partner units representing a 2.0% general partner interest in us, which will entitle it to receive 2.0% of all the distributions we make. Our general partner will also own all of our incentive distribution rights, which will entitle it to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $ per unit per quarter after the completion of this offering. In addition, Maxum Petroleum will own common units and subordinated units. Please read “Certain Relationships and Related Party Transactions” beginning on page 140.

Formation Transactions and Partnership Structure

We are a growth-oriented Delaware limited partnership formed by Maxum Petroleum to market and distribute refined petroleum products and to provide logistics and various services to the E&P industry and the coal mining industry. Maxum Petroleum Operating Company (“MPOC”) is a wholly owned subsidiary of Maxum Petroleum and indirectly owns all of our initial assets. At or prior to the completion of this offering, the following transactions, which we refer to as the formation transactions, will occur:

•

Subsidiaries of MPOC (the “Contributed Subsidiaries”) will distribute to MPOC or its other subsidiaries certain assets not intended to be contributed to us (consisting of (i) all trade accounts receivable, (ii) the business assets of Pathway, (iii) ETI Acquisition LLC and (iv) any cash on the balance sheets of the Contributed Subsidiaries immediately prior to the contribution of the Contributed Subsidiaries);

•

MPOC and its subsidiaries will contribute the Contributed Subsidiaries to us (other than the excluded assets described above);

•

We will issue to MPOC common units and subordinated units, representing an aggregate % limited partner interest in us;

•

We will issue to our general partner general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights;

•

We will issue common units to the public in this offering representing a % limited partner interest in us, and we will use the proceeds of this offering as described in “Use of Proceeds”;

•

We will enter into an omnibus agreement and certain other agreements with MPOC, our general partner and certain of their affiliates, as described under “Certain Relationships and Related Party Transactions—Omnibus Agreement” beginning on page 141; and

•

We will enter into a new $ million revolving credit facility, as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility” beginning on page 98.

We believe that conducting our operations through a publicly traded limited partnership will offer us the following advantages:

•

access to public equity and debt capital markets;

•

a lower cost of capital for expansions and acquisitions;

•

an enhanced ability to use equity securities as consideration in future acquisitions; and

•

an overall lower effective income tax rate to our unitholders than if we were a corporation.

Ownership of Maxum Energy Logistics Partners, LP

The following diagram depicts our simplified organizational and ownership structure after giving effect to the formation transactions and this offering.

LOGO


Public Common Units		%
Sponsor Units:
Common Units		%
Subordinated Units		%
General Partner Interest	2.0	%

Total	100.0	%

Principal Executive Offices and Internet Address

Our principal executive offices are located at 20 Horseneck Lane, Greenwich, Connecticut 06830, and our telephone number is (203) 861-1200. Our website is located at www. .com and will be activated immediately following this offering. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Our general partner has a duty to manage our partnership in a manner it subjectively believes is in our best interests. However, the officers and directors of our general partner also have duties to manage our general partner in a manner beneficial to its owner, Maxum Petroleum. Additionally, most of our initial executive officers and one or more of our directors may also be officers or directors of Maxum Petroleum. As a result, conflicts of interest may arise in the future between us and our common unitholders, on the one hand, and Maxum Petroleum and our general partner, on the other hand. For a more detailed description of the conflicts of interest of our general partner, please read “Risk Factors—Risks Inherent in an Investment in Us” beginning on page 38 and “Conflicts of Interest and Duties—Conflicts of Interest” beginning on page 143.

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner under applicable law with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement also provides that affiliates of our general partner, including Maxum Petroleum and its other subsidiaries and affiliates, are permitted to compete with us. We may enter into additional agreements in the future with Maxum Petroleum relating to the purchase of additional assets, the provision of certain services to us by Maxum Petroleum and other matters. In the performance of their obligations under these agreements, Maxum Petroleum and its subsidiaries are not held to a fiduciary duty standard of care to us, our general partner or our limited partners, but rather to the standard of care specified in these agreements. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each common unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions” beginning on page 140.

The Offering

Common units offered to the public

common units, or common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering

common units and subordinated units, representing a % and % limited partner interest in us, respectively. If the underwriters do not exercise their option to purchase additional common units, we will issue an additional common units to MPOC at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters will be issued to MPOC at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

Our general partner will own general partner units, representing a 2.0% general partner interest in us.

Use of proceeds

We expect the estimated net proceeds from this offering, after deducting underwriting discounts, the structuring fee and estimated offering expenses, to be $ million. We expect to use $ million of the net proceeds to fund a distribution to MPOC, and the remainder to pay accounts payable, to fund working capital and for other general partnership purposes. If the underwriters exercise their option to purchase additional common units in full, the estimated additional net proceeds will be approximately $ million. We expect to use the net proceeds from any exercise of such option to fund an additional cash distribution to MPOC.

Cash distributions

We intend to pay a minimum quarterly distribution of $ per unit ($ per unit on an annualized basis) to the extent we have sufficient distributable cash flow after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. Our ability to pay the minimum quarterly distribution is subject to various restrictions, risks and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 58.

We will pay a prorated distribution for the first quarter that we are publicly traded covering the period from the completion of this offering through September 30, 2012, based on the actual length of that period.

Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner during the subordination period (described below):

•

first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters;

•

second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $ ; and

•

third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $ .

If cash distributions to our unitholders exceed $ per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions” because they incentivize our general partner to increase distributions to our unitholders. In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, will have the right to reset the target distribution levels to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions” beginning on page 69.

Prior to making distributions, we will reimburse Maxum Petroleum for its provision of certain general and administrative services and any additional services we may request from Maxum Petroleum (including certain costs and expenses we will incur as a result of being a publicly traded partnership) each pursuant to the omnibus agreement. Please read “Certain Relationships and Related Party Transactions—Omnibus Agreement” beginning on page 141.

Pro forma cash available for distribution for the year ended June 30, 2011 was approximately $30.7 million. Pro forma cash available for distribution for the twelve months ended December 31, 2011 was approximately $29.8 million. The amount of available cash we will need to pay the minimum quarterly distribution for four quarters on our common units, subordinated units and general partner units to be outstanding immediately after this offering will be approximately $ million (or an average of approximately $ million per quarter). As a result, we would have generated available cash sufficient to pay the full minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis) on all of our common units but only approximately % and %, respectively, of the minimum quarterly distributions on all of our subordinated units

for the year ended June 30, 2011 and the twelve months ended December 31, 2011, respectively. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Year Ended June 30, 2011 and the Twelve Months Ended December 31, 2011” beginning on page 61.

We believe that, based on the financial forecasts and related assumptions included under the caption “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Year Ending June 30, 2013,” we will have sufficient cash available for distribution to make cash distributions for the year ending June 30, 2013, at the minimum quarterly distribution rate of $ per unit per quarter ($ per unit on an annualized basis) on all common units, subordinated units and general partner units outstanding immediately after the completion of this offering. However, our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast.

Subordinated units

Maxum Petroleum will initially indirectly own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. If we do not pay distributions on our subordinated units, our subordinated units will not accrue arrearages for those unpaid distributions.

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid at least (i) $ (the minimum quarterly distribution on an annualized basis) on each outstanding common, subordinated and general partner unit, for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2015, or (ii) $ (150% of the annualized minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit, in addition to any distribution made in respect of the incentive distribution rights, for any four consecutive quarter period ending on or after , 2013, in each case provided that there are no arrearages on our common units at that time. In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period” beginning on page 71.

General partner’s right to reset the target distribution levels

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels” beginning on page 74.

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” beginning on page 166 and “The Partnership Agreement—Issuance of Additional Partnership Interests” beginning on page 156.

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors. Our general partner may not be removed except by a vote of the holders of at least 66²/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon completion of this offering, Maxum Petroleum and its affiliates will own an aggregate of approximately % of our common units and all of our subordinated units, representing % of the outstanding common and subordinated units in the aggregate. This will give Maxum Petroleum the ability to prevent the involuntary removal of our general partner. Please read “The Partnership Agreement—Voting Rights” beginning on page 154.

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the remaining common units at a price not less than the then-current market price of the common units, as calculated in accordance

with our partnership agreement. For additional information about this right, please read “The Partnership Agreement—Limited Call Right” beginning on page 162.

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending June 30, 2015, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per common unit, we estimate that your average allocable taxable income per year will be no more than $ per common unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” beginning on page 171.

Material federal income tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences” beginning on page 168.

New York Stock Exchange listing

We intend to apply to list our common units on the New York Stock Exchange under the symbol “MXLP.”

Summary Historical and Pro Forma Financial and Operating Data

The following table shows summary historical financial and operating data of our Predecessor as of the dates and for the periods indicated and pro forma financial data for Maxum Energy Logistics Partners, LP as of the dates and for the periods indicated. The following table should be read together with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 83.

The summary historical financial data presented as of June 30, 2011 and 2010 and for the years ended June 30, 2011, 2010 and 2009 are derived from the historical audited financial statements of our Predecessor that are included elsewhere in this prospectus. The summary historical financial data of our Predecessor presented as of December 31, 2011 and for the six months ended December 31, 2011 and 2010 are derived from the unaudited historical financial statements that are included elsewhere in this prospectus.

The summary pro forma statement of operations data for the six months ended December 31, 2011 and the year ended June 30, 2011 and summary pro forma balance sheet data as of December 31, 2011 are derived from the unaudited pro forma financial data of Maxum Energy Logistics Partners, LP included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the completion of this offering had taken place on December 31, 2011, in the case of the pro forma balance sheet, and as of July 1, 2010, in the case of the pro forma statement of operations for the six months ended December 31, 2011 and for the year ended June 30, 2011. These transactions include:

•

the distribution by the Contributed Subsidiaries to MPOC or its other subsidiaries of certain assets not intended to be contributed to us (consisting of (i) all trade accounts receivable, (ii) the business assets of Pathway, (iii) ETI Acquisition LLC and (iv) any cash on the balance sheets of the Contributed Subsidiaries immediately prior to the contribution of the Contributed Subsidiaries);

•

the contribution of the Contributed Subsidiaries by MPOC and its subsidiaries to us (other than the excluded assets described above);

•

the receipt by us of net proceeds of $ million from the issuance and sale of common units to the public at an assumed initial public offering price of $ per unit (the midpoint of the price range set forth on the cover page of this prospectus); and

•

the application of the net proceeds from this offering in the manner described in “Use of Proceeds” beginning on page 54.

The pro forma financial data does not give effect to an estimated $3.0 million of additional general and administration expenses we expect to incur annually as a result of being a publicly traded partnership.


	Predecessor Historical															Maxum Energy Logistics Partners, LP Pro Forma
	Year Ended June 30,									Six Months Ended December 31,						Six Months Ended December 31, 2011		Year Ended June 30, 2011
	2011			2010			2009			2011			2010			Six Months Ended December 31, 2011		Year Ended June 30, 2011
										(unaudited)						(unaudited)
	(in thousands, except per unit data)
Statement of Operations Data:
Revenues	$	1,484,972		$	954,404		$	1,131,530		$	915,254		$	630,149		$	915,254	$	1,484,972
Gross profit		58,559			33,915			57,333			37,158			27,389			37,158		58,559
Operating income		18,200			3,764			31,049			12,152			9,574			12,152		18,200
Interest expense, net (1)		18,730			13,124			10,902			12,170			8,076			1,800		3,300
Net income (loss)		(289	)		(5,477	)		12,401			(108	)		840			10,047		14,750
Net income per unit

Balance Sheet Data (at end of period):
Working capital (2)	$	140,139		$	82,917		$	42,287		$	210,312		$	99,685		$	76,802
Property and equipment, net		52,953			40,901			33,918			61,454			43,277			61,454
Total assets		317,172			229,567			180,863			381,046			258,955			247,536
Total debt (1)		—			—			—			—			—			—
Total equity		228,899			162,888			115,374			305,669			179,577			184,859

Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	(37,393	)	$	(42,097	)	$	101,051		$	(61,402	)	$	(7,611	)
Investing activities	$	(28,465	)	$	(11,124	)	$	(21,840	)	$	(15,619	)	$	(8,007	)
Financing activities	$	66,300		$	52,991		$	(81,505	)	$	76,878		$	15,849
Depreciation and amortization		13,962			12,709			12,223			8,155			6,549

Other Financial Data:
Product margin (3)	$	124,054		$	87,999		$	113,683		$	75,586		$	57,277		$	75,586	$	124,054
Adjusted EBITDA (3)	$	41,526		$	21,969		$	45,724		$	24,402		$	19,403		$	24,402	$	41,526
Capital expenditures	$	23,547		$	13,179		$	10,260		$	16,346		$	8,413

Operating Data (gallons sold):
Fuels		469,819			383,273			410,975			253,817			228,220
Lubricants		16,940			14,004			13,963			8,472			8,300

(1)

Maxum Petroleum allocated to our Predecessor its proportionate share of Maxum Petroleum’s interest expense based on capital employed, but did not allocate debt to our Predecessor. Following this offering, Maxum Petroleum will not allocate any interest expense to us. We will enter into a revolving credit facility at the completion of this offering. We do not expect to have any borrowings outstanding under our revolving credit facility at the completion of this offering. Pro forma interest expense reflects interest on assumed borrowings under our revolving credit facility following the completion of the offering. Please read Note 2 to our pro forma condensed consolidated financial information.

(2)	Represents current assets less current liabilities.

(3)	Please read “—Non-GAAP Financial Measures” for the definitions of these items and reconciliations to their most comparable GAAP measures.

Non-GAAP Financial Measures

Product margin represents the spread between revenues from the sale of fuels, lubricants and other products and the purchase cost of those products. We define product margin as gross profit less service revenues plus distribution expenses and costs of service revenues.

Product margin is a non-GAAP supplemental financial measure that management and the external users of our combined financial statements may use to assess:

•

the margin on product sales required to cover the costs to deliver the products and our overhead costs and to provide an acceptable return on capital employed;

•

our pricing policies and efficiency of our procurement;

•

our margins as compared to those of other publicly traded partnerships in our industry; and

•

our margins as compared to those of potential acquisition targets.

We define Adjusted EBITDA as net income (loss) adjusted to exclude interest expense, income taxes, depreciation and amortization, unit-based compensation, severance expense, unrealized derivative gains and losses, acquisition expenses, and certain other expenses that are non-cash charges or that we consider not indicative of ongoing operations.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

•

our operating performance as compared to other publicly traded partnerships in our industry, without regard to historical cost basis or financing methods;

•

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;

•

our ability to incur and service debt and fund capital expenditures; and

•

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of product margin and Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to product margin is gross profit. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by (used in) operating activities. Our non-GAAP financial measures of product margin and Adjusted EBITDA should not be considered as alternatives to GAAP measures. Each of product margin and Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP measures. You should not consider either product margin or Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because product margin and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of product margin and Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

The following table presents a reconciliation of product margin to gross profit and Adjusted EBITDA to net income and net cash provided by (used in) operating activities, the most directly comparable GAAP financial measures, on a historical and pro forma basis for each of the periods indicated.


	Predecessor																		Maxum Energy Logistics Partners, LP Pro Forma
	Year Ended June 30,									Twelve Months Ended December 31,			Six Months Ended December 31,						Six Months Ended December 31,			Year Ended June 30,
	2011			2010			2009			2011			2011			2010			2011			2011
										(unaudited)			(unaudited)						(unaudited)
	(in thousands)
Reconciliation of Product Margin to Gross Profit:
Gross profit	$	58,559		$	33,915		$	57,333		$	68,328		$	37,158		$	27,389		$	37,158		$	58,559
Less:
Service revenues		20,920			10,848			10,994			30,133			17,611			8,398			17,611			20,920
Plus:
Costs of service revenues and distribution expenses (1)		86,415			64,932			67,344			104,168			56,039			38,286			56,039			86,415

Product margin	$	124,054		$	87,999		$	113,683		$	142,363		$	75,586		$	57,277		$	75,586		$	124,054

Reconciliation of Adjusted EBITDA to Net Income (Loss):
Net income (loss) attributable to Maxum Energy Logistics Partners, LP Predecessor	$	(289	)	$	(5,477	)	$	12,401		$	(1,237	)	$	(108	)	$	840		$	10,047		$	14,750
Plus:
Tax expense (benefit)		309			(3,163	)		7,806			(433	)		135			877			350			700
Interest expense		18,730			13,124			10,902			22,824			12,170			8,076			1,800			3,300
Depreciation and amortization		13,962			12,709			12,223			15,568			8,155			6,549			8,155			13,962
Equity-based compensation		572			405			1,193			660			348			260			348			572
Losses (gains) of sales of non-strategic assets		—			(412	)		—			—			—			—			—			—
Business transformation expense (2)		6,737			4,276			1,818			6,355			2,735			3,117			2,735			6,737
Loss from the early extinguishment of debt		199			—			—			16			—			183			—			199
Severance expense		685			388			—			318			(367	)		—			(367	)		685
Unrealized derivative losses (gains)		335			(180	)		(619	)		1,206			372			(499	)		372			335
Acquisition expenses		286			299			—			286			—			—			—			286
Miscellaneous expense (3)		—			—			—			962			962			—			962			—

Adjusted EBITDA	$	41,526		$	21,969		$	45,724		$	46,525		$	24,402		$	19,403		$	24,402		$	41,526


Reconciliation of Adjusted EBITDA to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	$	(37,393	)	$	(42,097	)	$	101,051		$	(91,184	)	$	(61,402	)	$	(7,611	)
Changes in assets and liabilities		50,433			50,539			(78,128	)		103,675			70,507			17,265
Tax expense (benefit)		309			(3,163	)		7,806			(433	)		135			877
Interest expense		18,730			13,124			10,902			22,824			12,170			8,076
Gains on sales of non-strategic assets		—			(412	)		—			—			—			—
Business transformation expense (2)		6,737			4,276			1,818			6,355			2,735			3,117
Severance expense		685			388			—			318			(367	)		—
Acquisition expenses		286			299			—			286			—			—
Others		1,739			(985	)		2,275			4,684			624			(2,321	)

Adjusted EBITDA	$	41,526		$	21,969		$	45,724		$	46,525		$	24,402		$	19,403

(1)

Costs of service revenues and distribution expenses are costs we incur to deliver products to our customers and to store, move and prepare products for shipment and to provide the services we provide to our customers. Direct distribution expenses include driver compensation, fuel expense and common carrier expenses. Indirect distribution expenses include depreciation, compensation of warehouse and dispatch employees, rent and other facilities expenses, vehicle maintenance and repair expenses and supplies and other related overhead expenses.

(2)

Maxum Petroleum launched a project to develop and implement an enterprise-wide information system, which was fully implemented into our operations on October 1, 2011. We refer to the expense associated with the information system as business transformation expense, a portion of which Maxum Petroleum allocated to us.

(3)	Includes a one-time $0.8 million cash payment in connection with the early termination of a customer contract relating to the termination of a hedge as a result of the bankruptcy of the counterparty to that hedge and a $0.2 million non-cash write-off of unamortized software costs.

RISK FACTORS

Limited partner interests are inherently different from shares of capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

Risks Related to Our Business

In order to pay the minimum quarterly distribution of $ per unit, or $ per unit on an annualized basis, we will require available cash of approximately $ million per quarter, or $ million per year, based on the number of common, subordinated and general partner units to be outstanding immediately after completion of this offering. We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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the rates we charge for our products and services;

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the volume of fuels and lubricants and the level of services that our customers purchase;

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our operating costs;

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changes in the level of drilling and production for oil and natural gas and of coal mining activity in the United States;

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the level of competition from other energy logistics companies and suppliers of refined petroleum products in our geographic markets;

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the creditworthiness of our customers;

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regulatory actions affecting the supply of, or demand for, oil, natural gas and coal; and

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prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

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the level and timing of capital expenditures we make;

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the level of our operating and general and administrative expenses, including reimbursements to our general partner and its affiliates, including Maxum Petroleum, for services provided to us;

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the cost of acquisitions, if any;

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levels of demand for higher or lower margin products and services;

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our debt service requirements and other liabilities;

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fluctuations in our working capital needs;

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our ability to borrow funds and access capital markets;

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restrictions on distributions contained in our debt agreements;

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the amount of cash reserves established by our general partner; and

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other business risks affecting our cash levels.

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

The amount of pro forma available cash generated during the year ended June 30, 2011 and the twelve months ended December 31, 2011 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units, but only approximately % and %, respectively, of the minimum quarterly distribution on all of our subordinated units, for each such period. For a calculation of our ability to make cash distributions to our unitholders based on our pro forma results for the year ended June 30, 2011 and the twelve months ended December 31, 2011, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions On Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the fiscal year ending June 30, 2013. Our forecasted amount of cash available for distribution for the year ending June 30, 2013 exceeds the unaudited pro forma cash available for distribution for the twelve months ended December 31, 2011 by approximately $25.9 million, or 86.9%. The major drivers of this expected increase in cash available for distribution are expected increased drilling and production activity by our E&P customers, expected gains in our E&P market share and expected improvements in our procurement efficiency. Our ability to realize these expectations is subject to factors affecting the E&P industry, our E&P customers, our coal mining customers, our suppliers and our relationships with our customers and suppliers, many of which are beyond our control, including those described in this “Risk Factors” section. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our independent registered accounting firm or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which 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 when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

For the year ended June 30, 2011 and the six months ended December 31, 2011, 62% and 65%, respectively, of our revenues were generated from customers who are engaged in drilling for and producing oil and natural gas. Developments that adversely affect oil and natural gas drilling and production services could adversely affect our customers’ demand for our products and services, resulting in a material adverse effect on our results of operations.

The predominant factor that would reduce demand for our products and services is reduced land-based drilling activity in the continental United States. The price of natural gas has been at historically low levels recently, with the near month NYMEX natural gas futures price at $2.16 per MMbtu as of April 27, 2012, compared to a high of $13.31 per MMbtu in July 2008. The lower prices of natural gas are due in part to increased production, especially from unconventional sources, like shale plays, and high levels of natural gas in storage. According to U.S. Energy Information Administration (“EIA”), the amount of natural gas produced in the continental United States increased from 52.1 bcf/d in December 2008 to 63.4 bcf/d in December 2011. Furthermore, the amount of natural gas in storage in the continental United States has increased from approximately 2.8 tcf as of December 2008 to approximately 3.5 tcf as of December 2011. As a result of this price decline and large amount of inventory, the number of land-based natural gas drilling rigs in the continental United States has declined from approximately 1,358 as of December 26, 2008 to approximately 790 as of December 30, 2011. Several of our customers have recently reduced their natural gas exploration and drilling activities. Oil prices have fluctuated significantly in recent years, reaching record highs in 2008, dropping below $40 per barrel in 2009 and trading on the NYMEX at a WTI spot price of $104.63 per barrel as of April 27, 2012. Sustained or further declines in the price of natural gas, as well as declines in the prices of oil or natural gas liquids, could have a further adverse impact on the level of drilling, exploration and production activity, which could materially and adversely affect the demand for our products and services and our results of operations.

Another factor that could reduce demand for our products and services is reduced drilling and production activity as a result of increased government regulation of that activity. Our customers’ drilling and production operations are subject to extensive federal, state, local and foreign laws and government regulations concerning emissions of pollutants and greenhouse gases; hydraulic fracturing; the handling of oil and natural gas and byproducts thereof and other materials and substances used in connection with oil and natural gas operations, including drilling fluids and wastewater, well spacing; production limitations; plugging and abandonment of wells; unitization and pooling of properties; and taxation. More stringent legislation or regulation or taxation of oil and natural gas drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our products and services. Please read “—Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs for our customers in the oil and natural gas and coal mining industries and reduced demand for our services” and “—Increased regulation of hydraulic fracturing could result in reductions or delays in oil and natural gas production by our customers, which could adversely impact our revenues” and “Business—Environmental” for more information about some of the regulations that impact our E&P customers’ operations and may reduce drilling and production activity.

Some of the other factors that could reduce the drilling and production activity of our customers are described below under “—In addition to commodity price and regulatory risks, other adverse developments generally affecting the E&P or coal mining industries could have a material adverse effect on our results of operations.”

For the year ended June 30, 2011 and the six months ended December 31, 2011, 23% and 21%, respectively, of our revenue were generated by customers who are engaged in coal mining. Developments that adversely affect coal mining activities could adversely affect our customers’ demand for our products and services, resulting in a material adverse effect on our results of operations.

Our customers may reduce their coal mining activity as a result of decreased demand for coal and low coal prices. The domestic electricity generation industry accounts for approximately 93% of domestic coal consumption. Demand for coal has been, and may be in the future, adversely impacted by low natural gas prices because natural gas-fired generation can, in some instances and over time, displace electricity generation from coal. This displacement generally occurs as coal becomes less economical due to low, sustained prices of other electricity-generating fuels, such as natural gas. Recently, the supply of natural gas in the U.S. has reached record high levels and the price of natural gas has declined to historically low levels, as described above. Also, transportation costs associated with coal are greater than costs associated with natural gas. A continuing decline in the price of natural gas, or sustained low natural gas prices, could result in lower coal prices and decreased coal consumption by electricity-generating utilities. For example, according to the EIA, the amount of electricity in the United States generated by coal-fired power plants decreased from 50% in December 2008 to 41% in December 2011. In addition, coal miners in our areas of operation produce a majority of the metallurgical coal mined in the United States. Metallurgical coal is used by steel companies to produce metallurgical coke for use in the steel making process and is exported at a higher rate than the thermal coal produced in other parts of the United States. As a result, these customers are exposed to the risk of declining export markets for coal they mine. The demand for U.S. coal exports is dependent upon a number of factors outside of our customers’ control, including the overall demand for electricity in foreign markets, currency exchange rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments, and environmental and other governmental regulations. A substantial or extended decline in coal prices or a decline in demand for coal, either domestic or abroad, could adversely affect our operating results as our customers reduce their mining activities.

The amount of coal consumed by the electric generation industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of alternative energy sources, including natural gas and nuclear energy and, in some states, renewable energy sources, including biomass, hydroelectric, wind and solar power. Domestically, state and federal mandates for increased use of electricity derived from renewable energy sources could also affect demand for coal. A number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of power supplied to consumers. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. Future environmental regulation of greenhouse gas, or GHG, emissions could, over time, accelerate the use by electricity generators of fuels other than coal. A decrease in coal consumption by the electric generation industry could adversely affect the price of coal, which could negatively affect our customers’ level of activity, financial condition and results of operations and, thereby, the demand for our products and services.

As a specific example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of pollutants, including sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted by electric power plants, which are the largest end-users of our customers’ coal. A series of

more stringent requirements relating to these and other air pollutants will, or are expected to become effective in coming years. More stringent air emissions limitations, which have been adopted or proposed, may require significant emissions control expenditures for many coal-fired power plants and could have the effect of making coal-fired plants less profitable or economically feasible and may deter the construction of new coal-fired plants. In addition, the U.S. Environmental Protection Agency, or EPA, has proposed regulations to address the management of coal ash that could result in treating coal ash as a hazardous waste, and doing so would increase regulatory obligations, costs and potential liability for handling coal ash for our coal customers’ utility customers. As a result, some power plants may, over time, shift to the use of other fuels that generate less of these emissions or they may close. From 1980 to 1989, 107 new coal-fired power plants went online in the U.S. compared to only 15 new coal-fired power plants from 2000 to 2009. In comparison, from 1980 to 1989, 321 new natural gas-fired power plants went online in the U.S. compared to 635 new natural gas-fired power plants from 2000 to 2009. Any shift in the use of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on our customers’ level of coal mining activity, which would reduce demand for our products and services. In addition, please read “—Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs for our customers in the oil and natural gas and coal mining industries and reduced demand for our services.”

Our customers may also reduce their coal mining activity as a result of governmental regulation relating to health, safety and the environment. Federal and state safety and health regulations in the coal mining industry are among the most comprehensive and pervasive systems for protection of employee safety and health affecting any segment of United States industry. Compliance with these requirements imposes significant costs on our customers and can result in reduced productivity. The coal mining industry is subject to increasingly strict regulation on matters such as:

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surface subsidence from underground mining;

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permits and other licensing requirements;

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remediation of contaminated soil, surface water and groundwater;

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the discharge of materials into the environment;

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storage, treatment and disposal of petroleum products and substances which are regarded as hazardous under applicable laws;

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protection of human health and safety, plant life and wildlife;

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reclamation and restoration of mining properties after mining is completed; and

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wetlands protection.

Compliance with these laws and regulations, and delays in the receipt of, or failure to receive or revocation of necessary government permits, can substantially increase the cost of coal mining or have a material adverse effect on our customers’ operations, which can result in a material reduction in the demand for our products and services. In addition, significant increases in, or the imposition of new, taxes on the coal that our customers’ produce can increase their cost of operations and cause a reduction in mining activity. High profile adverse events or accidents at coal mines may increase political pressure to intensify regulation of coal mining. Please read “Business—Environmental” for more information about the regulations that impact our customers’ operations and may reduce drilling and production activity. In addition, federal and state regulatory agencies, including the Mine Safety and Health Administration (“MSHA”), have the authority under certain circumstances following significant health, safety or environmental incidents or pursuant to permitting authority to order a mine to be temporarily or permanently closed.

New legislation or regulations may be adopted that would have a significant impact on the coal mining operations of our customers or on their customers’ ability to use coal. For example, in response to underground mine accidents in the last decade, state and federal legislatures and regulatory authorities have increased scrutiny of mine safety matters and adopted more stringent requirements governing all forms of mining, including increased sanctions for and disclosure regarding non-compliance. If these or similar measures are ultimately imposed by federal or state governments or pursuant to international treaty, our customers’ coal mining activities may be materially and adversely affected.

In addition to commodity price and regulatory risks, other adverse developments generally affecting the E&P or coal mining industries could have a material adverse effect on our results of operations.

In addition to the commodity price and regulatory risks discussed above, our customers are exposed to a variety of other risks that may reduce their demand for our products and services, including:

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U.S. and worldwide economic conditions;

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a reduction in production volumes or reserves estimates for oil and natural gas;

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an inability to obtain capital or financing on satisfactory terms for oil and natural gas drilling and production and coal mining operations;

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inadequate infrastructure facilities, including transportation and storage facilities, for their operations;

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operational delays, including those related to the permitting process, changes in geologic conditions, equipment failures and natural disasters;

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adverse weather and seasonal trends;

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the volatility and uncertainty of regional pricing differentials and premiums;

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increased taxes on hydrocarbons;

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local, state and federal political pressures relating to unconventional resources of oil and natural gas such as shale plays or use of resources perceived as having less environmental impact;

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demand for alternate fuels and alternative sources of supply; and

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the effect of energy conservation measures.

An adverse development in any of these areas could have an adverse impact on our customers’ operations or financial condition, which could in turn result in reduced demand for our products and services and less cash available for distributions to unitholders.

The contracts we have with most of our customers do not obligate them to purchase product from us.

Most of our product sales are generated pursuant to master service agreements under which our customers have an option, but not the obligation, to purchase product from us. Although some customers have

contracts under which they agree to purchase all of their products from us, they are typically under no obligation to purchase a minimum amount. Moreover, as these contracts expire or are terminated, they must be renegotiated or replaced. We may be unable to renegotiate or replace contracts or arrangements when they expire, and the terms of any renegotiated contracts may not be as favorable as those of the contracts or arrangements they replace. Whether these contracts or arrangements are successfully renegotiated or replaced is often subject to factors beyond our control. Such factors include sustained increases in fuel prices, the counterparty’s ability to pay for or accept the contracted volumes and a competitive marketplace for the products offered by us. If our customers do not purchase products from us under our master service agreements or otherwise, our sales would decline, and our financial condition, results of operations and cash available for distribution to our unitholders would be adversely affected.

We depend on a limited number of customers for a substantial portion of our revenues. The loss of, or a material nonpayment by, our key customers could adversely affect our results of operations, financial condition and ability to make cash distributions to our unitholders.

We rely on a limited number of customers for a substantial portion of our revenues. Our largest customer, Chesapeake Energy Corporation, accounted for approximately 18% of our revenues for the twelve months ended December 31, 2011. Our top 20 customers accounted for approximately 50% of our revenues for the same period. Our contracts with these customers generally do not obligate them to purchase products or services from us. In addition, some of these key customers may experience financial problems that could have an adverse effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us. Furthermore, some of our key customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Please read “—We are exposed to trade credit risk in the ordinary course of our business activities.” The loss of all or a portion of revenues from these key customers as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions to our unitholders.

Our business is subject to the risk of supplier concentration.

We depend on a limited number of suppliers for the sourcing of our refined petroleum products. As a result of this concentration in our supply chain, our business and operations would be negatively affected if any of our key suppliers were to experience significant disruption affecting the price, quality, availability or timely delivery of their products. The partial or complete loss of one of these suppliers, or a significant adverse change in our relationship with any of these suppliers, could result in lost revenue, added costs and distribution delays that could harm our business and customer relationships. During the twelve months ended December 31, 2011, based on total purchase cost, our largest supplier of fuel represented 26% of our distillate fuel purchases, and our largest supplier of lubricants represented 67% of our lubricant purchases. In addition, concentration in our supply chain can exacerbate our exposure to risks associated with the termination by key suppliers of our distribution agreements or any adverse change in the terms of such agreements, which could have a negative impact on our profitability.

A significant decrease in demand for refined petroleum products in the industries we serve would reduce our ability to make distributions to our unitholders.

A significant decrease in demand for refined petroleum products in the industries that we serve could significantly reduce our revenues and, therefore, reduce our ability to make or increase distributions to our unitholders. For instance, reduced demand for refined petroleum products, principally diesel fuel and lubricating oil, may be caused by recession or other adverse economic conditions, increased market prices of refined petroleum products for a sustained period, higher fuel taxes or other governmental or regulatory actions. These events may also increase, directly or indirectly, the cost of the refined petroleum products we provide and could lead to a decrease in market demand for refined petroleum products.

Certain of our operating costs and expenses are fixed and do not vary with the volumes we distribute. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes distributed and sold. As a result, we may experience declines in our product margin if our sales volumes decrease.

Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.

A prolonged economic slowdown, another recession in the United States, adverse events relating to the energy industry and local, regional and national economic conditions and factors, particularly a slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased spending by our customers.

Conservation measures and the use of alternative fuels by our customers could reduce demand for our fuels.

The majority of our revenue stems from the delivery of petroleum-based distillate fuel and related services. Fuel conservation measures, alternative fuel requirements, alternatives to oil and natural gas, technological advances in fuel economy and cost considerations could reduce demand for our distillate fuels. Any government-mandated controls or regulations that promote the use or development of alternative fuels, such as ethanol, could further reduce demand for our products. In addition, a number of drilling rig operators are experimenting with the use of compressed natural gas, or CNG, and liquefied natural gas, or LNG, to power their rigs instead of the fuels we currently provide. We cannot predict the impact of the changing demand for oil and natural gas products and services or the use of CNG or LNG in drilling rigs, and any major changes may have a material adverse effect on demand for our services, which would adversely affect our results of operations and cash available for distribution to unitholders.

Substantially all of our customers in the coal mining industry are located in the Central Appalachian region, which has experienced a substantial decline in coal production.

Customers located in the Central Appalachian region generated approximately 98% of the revenues we received from customers in the coal mining industry during the twelve months ended December 31, 2011. Total coal production in the Central Appalachian region declined approximately 29% from 2000 to 2010, while total U.S. coal production increased 1.0% over the same period, according to the EIA. The EIA projects coal production in the Central Appalachian region will decline 58% from 186 million tons in 2011 to 77 million tons by 2020 due primarily to production challenges, reserve degradation, difficulties acquiring permits needed to conduct mining operations, particularly mountain top removal, and additional, more costly and stringent safety regulations. As a result, our customers in the Central Appalachian region may reduce their coal mining activity by suspending mine operations until conditions improve. To the extent we are not able to replace reduced sales to customers in the Central Appalachian region with increased sales to other customers, our results of operations and cash available for distribution to unitholders would be adversely affected.

Our financial condition and results of operations are influenced by increases and decreases in the prices of refined petroleum products, which may adversely impact our product margins.

Although we generally charge our customers a spread over prevailing market prices, fluctuations in the price of petroleum products could still have adverse effects on our business and liquidity. For instance, increases in fuel prices will lead to increases in our inventory and accounts receivable, which would increase our working capital needs. This could require us to increase borrowings under our new revolving credit facility, which would increase interest expense and reduce the amount of borrowings available for other uses, such as acquisitions and capital expenditures. Moreover, when prices for refined petroleum products rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in

turn, may reduce consumption, thereby reducing demand for our customer’s products. Increases in fuel prices could also affect the amount of fuel we are able to purchase due to the credit limits we have with our suppliers. Furthermore, when fuel prices increase, we may be unable to promptly pass our additional costs to our customers, resulting in lower product margins for us, which could adversely affect our results of operations and cash available for distribution to unitholders.

Our risk management policies cannot eliminate all commodity risk or the impact of adverse market conditions, which can adversely affect our results of operations.

Although a substantial majority of our product purchases are delivered to the customer on the same day, we are exposed to commodity price risk for the portion of our purchases that are delivered more than one day after purchase. We may from time to time enter into forward fixed-price sales contracts with customers. In these transactions, we may buy product based on the price of one index and sell based on the price of another index, exposing us to commodity price risk related to the differences in the indices. We do not presently have derivative instruments to manage this inventory and commodity price risk.

We manage our processes to maintain substantial balance between purchases and sales for future delivery obligations. These steps, however, may not detect and prevent all violations of such risk management policies and procedures, particularly if intentional misconduct is involved. To the extent our policies and procedures fail to ensure balance between our business risk and risk management activities or to the extent our risk management policies are violated, we could suffer losses from adverse changes in the market for refined petroleum products, and such losses could be material.

We face intense competition, including against companies that have capital resources greater than ours and that control greater supplies of refined petroleum products.

Our competitors are numerous, ranging from terminal companies and major oil companies to other independent marketers and distributors of varying sizes, financial resources and experience. Some of our non-independent or integrated competitors have greater capital resources and control of or access to greater supplies of fuels and lubricants, which they may be able to purchase at lower cost than us. Other competitors, even if smaller in size, may have greater experience and stronger relationships in their local markets. In addition, we face competition from our existing suppliers who may choose to distribute their products directly to our customers using third party distributors. If we are unable to compete effectively on factors such as price, reliability, quality of service, responsiveness, product expertise, geographic reach and safety, we may lose existing customers or fail to acquire new customers, which could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. We describe the competition we face in greater detail under “Business—Competition.”

If the products we produce or purchase from our suppliers fail to meet the specifications we have agreed to supply to our customers, we could be subject to damages and our customer relationships could be adversely affected.

We purchase the refined petroleum products we resell from various suppliers. Our specially-blended lubricant products are intended to provide performance attributes for our customers’ products. If any of these products fail to meet the specifications requested by our customers, our customer relationships could be adversely affected as customers seek other suppliers who can provide similar products. We could be subject to claims and other liabilities for the replacement of the product or damages for costs incurred as a result of the product failing to perform in accordance with agreed specifications. Any of these occurrences could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to unitholders.

Our value-added services may be replicated by potential customers, existing customers or competitors, thereby reducing both the price we charge for such services and our revenues.

We provide a variety of value-added services to our customers, such as on-site equipment monitoring and maintenance, fuel management programs, cost control programs and environmental services. Customers may choose not to outsource these functions to us. Because our services are not proprietary, existing customers may decide to adopt some of our techniques and perform these functions internally. In addition, our existing and potential competitors, including major petroleum suppliers, may develop comparable services. This could erode our competitive advantage and reduce demand for our services, which could have a material adverse impact on our financial condition, results of operations and cash available for distribution to unitholders.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties of our forward contracts, options and swap agreements. We have experienced nonperformance by our customers and counterparties in the past and we take reserves for accounts more than 90 days past due. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. We may not be able to terminate contracts with customers that have a high risk of default at the times we deem appropriate, thereby exposing us to a larger amount of doubtful accounts. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with customers and other parties.

We may be unable to obtain a sufficient number of skilled workers and equipment.

We require personnel with specialized skills and experience who can perform physically demanding work in, and vehicles that can safely transport refined petroleum products to, remote, rugged or environmentally sensitive sites. The demand for skilled workers, including drivers, and equipment that can operate in challenging environments is high and the supply of each is limited. In addition, training and development of these workers requires us to invest capital in them. Our operations could suffer and our profitability diminish if we fail to hire and retain skilled workers or if we experience a shortage of delivery vehicles. Our ability to expand our operations could be limited if we are unable to increase the size of our skilled labor force. Moreover, changes in customer or regulatory vehicle specifications could result in substantial additional compliance costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.

We depend on key personnel for the success of our business.

We depend on the services of our senior management team and other key personnel. The loss of the services of any member of senior management or key employee could have a material adverse effect on our business. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available. In addition, we rely on the abilities of our regional managers, many of whom managed their businesses prior to our acquisition of them.

Our operations are subject to federal, state, and local laws and regulations relating to operational safety, transportation and security that could require us to incur substantial costs and liabilities.

The workplaces we operate are subject to the requirements of the Occupational Safety and Health Act (“OSHA”), the MSHA and comparable state statutes and regulations thereunder that regulate the protection of human health and safety. Hazard communication standards require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to our employees, state and local government authorities and local residents. In addition, the operation of our specialized vehicle fleet and its transportation of petroleum-based products are subject to extensive regulation by the U.S. Department of Transportation under the Federal Motor Carrier Safety Act and the Hazardous Materials Transportation Act. Federal and state agencies could also impose additional safety regulations to which we might be subject.

Our workplaces and transportation activities are also subject to the USA PATRIOT Act of 2001. The PATRIOT Act imposes rules applicable to shippers and carriers of hazardous materials that could be used in terrorist activities, including bulk flammable liquids such as refined petroleum products. These rules require operations such as ours to generate and implement site security plans and improvements to site security measures and impose security training requirements.

If we fail to comply with OSHA, MHSA or other federal, state or local safety or security requirements, including record keeping requirements, monitoring of occupational exposure to regulated substances and regulations relating to hazardous cargo in transport, we could become subject to fines and significant additional compliance costs.

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

For the delivery of fuel and other products to our customers, we operate a fleet of specialized trucks and delivery equipment. We are therefore subject to regulation as a motor carrier by the United States Department of Transportation (“DOT”) and various state agencies. These federal and state regulatory authorities exercise broad powers, generally governing such activities as the authorization to engage in motor carrier operations, driver licensing and insurance requirements, safety, equipment testing and transportation of hazardous materials. Our trucking operations, including the special modifications we make to our equipment and vehicles to operate in remote, rugged or environmentally sensitive areas, are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, fuel emissions limits, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period and limits on vehicle weight and size and other matters.

Our operations are subject to federal, state and local laws and regulations governing the product quality specifications of the refined petroleum products that we purchase, transport and sell.

Various federal, state and local agencies have the authority to prescribe specific product quality specifications to the sale of commodities, including many of our products. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce our ability to procure product and our sales volume, require us to incur additional handling costs and require us to make capital expenditures to upgrade our facilities and transportation assets. If we are unable to procure product or to recover these costs through increased sales, it may have an adverse impact on our results of operations. Failure to comply with these regulations could result in substantial penalties.

The risk of substantial environmental costs and liabilities is inherent in our operations, which involve the receipt and redelivery of refined petroleum products. We are subject to or otherwise affected by stringent federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment and related matters. Compliance with these laws and regulations increases our overall costs, including our capital costs to maintain and upgrade equipment and facilities. In addition, our overall costs may increase as a result of third parties’ environmental compliance obligations. We utilize a number of facilities that are owned and operated by third parties whose compliance with these stringent environmental requirements could increase the cost of doing business with these facilities. Also, the price we pay for refined petroleum products may increase due to our suppliers’ environmental compliance costs.

Various governmental authorities, including the EPA, have the power to enforce compliance with these laws, regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including fines, injunctions or both. Joint, several and strict liability may be incurred without regard to fault, or the legality of the original conduct, under federal and state environmental laws for the remediation of

contaminated areas at our facilities or at other properties where we or our predecessors have disposed of or released hazardous materials. Private parties, including the owners of properties located near our facilities and those with whom we do business, also may have the right to pursue legal actions against us to enforce compliance with environmental laws, as well as seek damages for personal injury or property damage in connection with environmental impacts or human exposure to petroleum products or hazardous materials. We may also be held liable for damages to natural resources. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us.

The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, that could significantly increase our costs, materially affect our operations, cash flow, and profitability, either through direct impacts on our services, or indirect impacts that affect our customers and reduce their demand for our services. We may incur increased costs because of stricter pollution control requirements, discovery of new or more extensive contamination, the failure of other responsible parties to address contamination, or liabilities resulting from non-compliance with required permits or other laws and regulations. New environmental regulations might adversely affect our products and activities, as well as our obligations related to waste management and control of air emissions. Because the laws and regulations applicable to our operations, and the enforcement and interpretation thereof, are subject to change, compliance with future laws, regulations or enforcement policies may have a material adverse effect on our results of operations. Please read “Business—Environmental” for more information.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs for our customers in the oil and natural gas and coal mining industries and reduced demand for our services.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and the other that regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities on an annual basis, beginning in 2012 for emissions occurring in 2011. Further, in March 2012, the EPA proposed the first Clean Air Act standard for carbon pollution from new power plants, which will require future coal plants to install new technology to reduce carbon emissions. This standard could lead to a decrease in the construction of new coal-fired power plants, which may reduce demand for coal and have a significant impact on the mining operations of our customers, thereby decreasing demand for our products and services.

The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental organizations over concerns related to GHG emissions from the new plants. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities. There have also been several public nuisance lawsuits brought against power, coal, oil and natural gas companies alleging that their operations are contributing to climate change.

The U.S. Congress has also from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require our customers to

incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas or coal. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our customers’ financial condition, levels of oil and natural gas drilling activity and operations and demand for our products and services.

Increased regulation of hydraulic fracturing could result in reductions or delays in oil and natural gas production by our customers, which could adversely impact our revenues.

A significant percentage of our E&P customers’ oil and natural gas production is being developed from unconventional sources, such as hydrocarbon shales. These reservoirs require hydraulic fracturing completion processes to release the oil or natural gas from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate production. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with shale development, including hydraulic fracturing. Along these lines, the federal Department of the Interior has been developing new environmental rules governing oil and gas operations including hydraulic fracturing on federal lands. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents related to this assertion of regulatory authority. In addition, some states and municipalities have adopted, and other states and municipalities are considering adopting, regulations that could prohibit hydraulic fracturing in certain areas or impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions for our customers that could reduce demand for our products and services, which would materially adversely affect our revenues, results of operations and cash available for distribution to unitholders.

We are exposed to performance risk in our supply chain.

The success of our business depends upon our ability to purchase, sell and deliver refined petroleum products to our customers. We rely upon our suppliers to timely produce the volumes and types of refined petroleum products for which they contract with us. In the event one or more of our suppliers does not perform in accordance with its contractual obligations, our sales could be significantly harmed. The supply of petroleum products may be decreased by political events, natural disasters, logistical issues associated with delivery schedules or otherwise. These factors, as well as terrorist activity, military action or other similar conditions, as well as extreme market demand, may also disrupt the availability or supply of crude oil and consequently decrease the supply of refined petroleum products. If any of these events were to occur, we may not be able to satisfy our supply requirements and may be required to pay more for product that we purchase on the open market, which could result in financial losses and adversely affect our financial condition, results of operations and cash available for distribution to our unitholders, and could possibly damage our customer relationships.

We may not be able to renew our leases or our agreements for distribution and storage facilities when they expire.

The properties that we own or lease or at which we maintain dedicated storage facilities play a key role in moving product to our customers. As of December 31, 2011, we leased or owned approximately 40 dedicated storage and distribution facilities. These include several key locations that would be difficult or impossible for us to replace or replicate. The agreements governing our lease arrangements are subject to expiration at various dates through August 2019. These agreements may not be renewed when they expire, or if renewed, may not be

renewed at similar rates and on similar terms. If we are unable to renew these agreements at rates and on terms comparable to those of today, it could have an adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders.

We may have the opportunity to grow and expand our business through acquisitions. If we do not make acquisitions on economically acceptable terms, our financial condition may be materially and adversely affected.

We may have the opportunity to grow and expand our business through acquisitions. Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated per unit from operations. We may be unable to make such accretive acquisitions for any of the following reasons:

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we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts for them;

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we are unable to fund or raise financing for such acquisitions on economically acceptable terms; or

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we are outbid by competitors.

In addition, we may consummate acquisitions, which at the time of consummation we believe will be accretive, but which ultimately may not be accretive.

If any of these events were to occur, our financial condition and our ability to increase cash distributions to unitholders may be materially and adversely affected.

We may need to obtain additional capital or financing to fund expansion of our asset base, which could increase our financial leverage and diminish our ability to make quarterly cash distributions.

In order to expand our asset base, we will need to make expansion capital expenditures. These expenditures may be significant because our fleet of specialized delivery vehicles and other assets require significant capital to purchase and modify. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations or incur borrowings or sell additional common units or other securities in order to fund our expansion capital expenditures. Using cash from operations will reduce cash available for distribution to our common unitholders. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for expansion capital expenditures through equity or debt financings, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

We do not have any commitment with our general partner or other affiliates, including Maxum Petroleum, to provide any direct or indirect financial assistance to us following the completion of this offering.

Acquisitions and expansions into new areas of operation in the future could expose us to increased operating risks.

As part of our growth strategy, we have made and intend to make acquisitions of other petroleum marketers and distributors and have expanded and intend to expand into new areas of operation in response to customer needs. This expansion could expose us to additional risks, including:

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mistaken assumptions about volumes, revenues and costs, including synergies and the overall costs of debt or equity;

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the potential disruption of our ongoing business, including the diversion of management’s time and attention from our core business;

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the risk of entering markets in which we have limited or no prior experience;

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expansions into new areas of operation may expose us to new operating risks;

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the incurrence of debt or significant cash expenditures;

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difficulty in cross-selling our other products and services in the market covered by acquired companies or in the new areas of operation; and

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problems with product and service quality, legal issues, contingent liabilities or other significant risks that we may not detect through the due diligence process.

Although we endeavor to evaluate the risks inherent in any particular transaction or any expansion, we may not properly ascertain all such risks. Difficulties encountered with acquisitions or expansion activities may have a material adverse effect on our business, financial condition and results of operations.

We may not be able to successfully integrate acquisitions into our business.

Our acquisition strategy requires that we successfully integrate acquired companies into our business practices as well as our procurement, management and enterprise-wide information technology systems. We may not be successful in implementing our business practices at acquired companies, and our acquisitions could face difficulty in transitioning from their previous information technology systems to our own. Any such difficulties could affect our financial performance and operations. If we are unsuccessful in taking advantage of these opportunities, our performance, results of operations and ability to increase distributions to unitholders will suffer.

Restrictions in our revolving credit facility could adversely affect our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

In connection with the completion of this offering, we expect to enter into a revolving credit facility which limits our ability to, among other things:

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incur additional debt;

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make cash distributions on, or redeem or repurchase, units;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain transactions with affiliates;

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merge or consolidate with another company or otherwise engage in a change of control; and

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transfer or otherwise dispose of assets.

In addition, we expect our revolving credit facility will also contain covenants requiring us to maintain certain financial ratios.

The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of this facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

A sustained failure of our information technology systems could adversely affect our business.

We use information technology systems to operate our business and communicate among our facilities. A sustained outage could adversely affect our business by preventing us from:

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acquiring adequate supplies on a cost effective basis and delivering them to our facilities and customers;

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directing products for delivery on a timely basis to locations and facilities where we have delivery obligations;

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directing products for delivery to markets in which we can generate an attractive product margin;

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marketing and selling products on a timely basis or at the best available prices; and

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being able to properly manage the needs of customers for whom we provide supply management services.

Our enterprise-wide information system was implemented only recently and is in the process of being fully integrated into our operations. If our information technology systems are disrupted due to problems with the integration of our information system or otherwise, our customers could determine that we have become an unreliable supplier and could elect to cease purchasing from us, or reduce the volume of product they purchase from us. Such a disruption to our information technology systems could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. In addition, we may not realize the benefits we anticipate from the implementation of our enterprise-wide information system.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases or mechanical failures. Some of these events are beyond our control. We are also exposed to the risks associated with the handling and transporting of hazardous materials, including vehicle accidents and spills. If any of these events were to occur, we could incur substantial losses because of breaches of contractual commitments, personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, any of which could result in curtailment or suspension of our operations, substantial fines or loss of customers.

We are not fully insured against all risks inherent in our business. In addition, we are not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates or such insurance may not cover the full amount of our losses. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased over the past several years and they may increase further in the future. It is possible that certain types of insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

Due to the specialized nature of our transport and delivery vehicles and other equipment, our ability to deploy our assets outside of our current business is limited. Adverse developments in our businesses would reduce our ability to make distributions to our unitholders.

Our assets are designed for use in the E&P and mining industries, particularly in remote, rugged or environmentally sensitive areas, and are of limited use in other businesses. Due to our lack of diversification in asset type, an adverse development in these businesses and industries, including adverse developments due to catastrophic events or weather and decreases in demand for refined petroleum products, could have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets.

Risks Inherent in an Investment in Us

Following this offering, Maxum Petroleum will indirectly own and control our general partner and will appoint all of the officers and directors of our general partner, some of whom will also be officers and/or directors of Maxum Petroleum. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to Maxum Petroleum. As a result, conflicts of interest may arise between Maxum Petroleum and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Maxum Petroleum over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

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Neither our partnership agreement nor any other agreement requires Maxum Petroleum to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Maxum Petroleum’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Maxum Petroleum, which may be contrary to our interests.

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Our general partner’s affiliates, including Maxum Petroleum and its sponsors, may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

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Our general partner is allowed to take into account the interests of parties other than us, such as Maxum Petroleum, in resolving conflicts of interest.

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All of the initial officers and certain of the directors of our general partner are also officers and/or directors of Maxum Petroleum and will owe fiduciary duties to Maxum Petroleum. The officers of our general partner will also devote significant time to the business of Maxum Petroleum and will be compensated by Maxum Petroleum accordingly.

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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner under applicable law with contractual standards governing its duties and 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 under applicable state law.

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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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Disputes may arise under any commercial agreements we may enter into with Maxum Petroleum and its affiliates.

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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash available for distribution to our unitholders.

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Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces distributable cash flow, or an expansion or investment capital expenditure, which does not reduce distributable cash flow. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.

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

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Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

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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 any of these entities 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 all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

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Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including Maxum Petroleum’s obligations under the omnibus agreement.

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

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Our general partner may transfer its incentive distribution rights without unitholder approval.

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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Please read “Conflicts of Interest and Duties.”

Maxum Petroleum, its sponsors and other affiliates of our general partner are not restricted in their ability to 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 and those activities incidental to its ownership of interests in us. Affiliates of our general partner, including Maxum Petroleum and its other subsidiaries, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. Maxum Petroleum will be under no obligation to make any acquisition opportunities available to us. Moreover, while Maxum Petroleum may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to accept any offer we might make with respect to such opportunity.

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, Maxum Petroleum and its sponsors. 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 common unitholders. Please read “Conflicts of Interest and Duties.”

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We will distribute all of our available cash after reserves to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may reduce the available cash that we can distribute to our unitholders.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional units. In addition, Maxum Petroleum will own common units and subordinated units, representing an aggregate of approximately % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

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the level of our quarterly distributions;

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our quarterly or annual earnings or those of other companies in our industry;

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the loss of a large customer or adverse events with respect to our customers;

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the loss of supplier relationships or adverse events with respect to our suppliers;

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announcements by us or our competitors of significant contracts or acquisitions or other strategic actions;

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changes in accounting standards, policies, guidance, interpretations or principles;

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general economic conditions;

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conditions that impact the E&P and coal mining industries;

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the public’s reaction to our press releases and filings with the SEC;

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the failure of securities analysts to cover our common units after this offering or changes in financial estimates, ratings or recommendations by analysts who track our partnership;

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new laws or regulations or new interpretations of existing laws or regulations applicable to our business;

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material litigation or government investigations;

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change in general conditions in the U.S. and global economies or financial markets;

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changes in key personnel;

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volume of trading in our common units;

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future sales of our common units by us or members of our management team; and

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other factors described in these “Risk Factors.”

You will experience immediate and substantial dilution in net tangible book value of $ per common unit.

The assumed initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $ per unit. Based on the assumed initial public offering price of $ per common unit, you will incur immediate and substantial dilution in pro forma net tangible book value of $ per common unit. This dilution results primarily because the assets contributed by Maxum Petroleum are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

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

We intend to apply to list our common units on the NYSE. Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management.”

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state law relating to fiduciary duties and replace those duties with several different contractual standards. 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 contractual or fiduciary duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision 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 corporate opportunities among us and its affiliates;

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whether to exercise its limited call right;

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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner

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

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whether to elect to reset target distribution levels;

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whether to transfer the incentive distribution rights or any units it owns to a third party; and

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

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties—Duties of the General Partner.”

Our partnership agreement restricts the remedies available to holders of our common 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, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other

action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different 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 will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

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our general partner and its officers and directors will not be liable for monetary damages 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 our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and

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our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

(a)

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;

(b)

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

(c)

determined by our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(d)

determined by our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee 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 and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, 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.

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 common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Maxum Petroleum, for expenses they incur and payments they make on our behalf. Under the omnibus agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services

necessary to run our business, and insurance expenses. Please read “Certain Relationships and Related Party Transactions—Omnibus Agreement.” Our partnership agreement provides that our general partner will determine in good faith 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 available cash to pay cash distributions to our common unitholders. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

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. Rather, the board of directors of our general partner will be appointed by Maxum Petroleum. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. 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. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

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

Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates, including Maxum Petroleum, 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 66²/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the completion of this offering, Maxum Petroleum will indirectly own % of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of unitholder dissatisfaction with the performance of our general partner in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement 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, cannot vote on any matter.

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 in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Maxum Petroleum to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of Maxum Petroleum selling or contributing additional assets to us, as Maxum Petroleum would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

We may issue additional units without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•

our existing unitholders’ proportionate ownership interest in us will decrease;

•

the amount of cash available for distribution on each unit may decrease;

•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•

because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

•

the ratio of taxable income to distributions may increase;

•

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

•

the market price of the common units may decline.

Maxum Petroleum may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, Maxum Petroleum will indirectly hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common

units at the end of the subordination period and may convert earlier under certain circumstances. In addition, we have agreed to provide Maxum Petroleum with certain registration rights. The sale of common or subordinated units by Maxum Petroleum in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% 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 that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. 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. At the completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, Maxum Petroleum will indirectly own approximately % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Maxum Petroleum will indirectly own approximately % of our outstanding common units. For additional information about this right, please read “The Partnership Agreement—Limited Call Right.”

Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of the incentive distribution rights, which is initially our general partner, have the right, at any time when there are no subordinated units outstanding and the holders received incentive distributions at the highest level to which they are entitled (48.0%) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed distributable cash flow for each such quarter), to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.

In the event of a reset of target distribution levels, the holders of the incentive distribution rights will be entitled to receive the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be

issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

•

we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

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, we may not make a distribution to you 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 an 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. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time of transfer and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

A restatement of net income or a reversal or change of estimates affecting net income made after the end of the subordination period but affecting net income during the subordination period will not retroactively affect the conversion of the subordinated units even if we would not have had sufficient distributable cash flow based on such restated or adjusted net income to permit conversion.

Our subordinated units will convert into common units upon the satisfaction of certain tests involving the calculation of distributable cash flow on a historical basis. Please read “Provisions of Our Partnership

Agreement Relating to Cash Distributions.” Distributable cash flow is calculated based on net income, which is a GAAP measure. If net income for a period during the subordination period is restated after the end of the subordination period or if estimates affecting net income made during the subordination period are reversed or changed after the end of the subordination period, it will not retroactively affect the conversion of subordinated units even if we would not have had sufficient distributable cash flow during the subordination period based on such restated or adjusted net income to permit conversion.

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. We expect SEC and NYSE rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements and our general partner will maintain director and officer liability insurance under a separate policy from Maxum Petroleum’s corporate director and officer insurance. We have included $3.0 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be materially higher than we currently estimate.

Tax Risks to Common Unitholders

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

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

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for 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%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits 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. Therefore, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

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 such additional tax on us by a state will reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The present 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 interpretation at any time. Recently, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships, which, if enacted, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.

Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

We are currently required to use a tax year ending June 30, which will make it difficult for us to timely provide you with the information you need to complete your tax return and may require you to report more than twelve months of our income on a single tax return.

Section 706 of the Internal Revenue Code of 1986, as amended (the “Code”), requires us to determine our taxable year based upon the taxable years of our partners. We are currently required to use a taxable year ending June 30. Because we will be unable to determine the taxable years of the holders of our units, we may not report on our required taxable year at some point in the future.

In the event our taxable year changes, a unitholder may be required to include in income for his taxable year his distributive share of more than twelve months of our income, gain, loss and deduction.

Because our taxable year ends June 30, a calendar-year unitholder who sells units during the period from July 1 to December 31 will have to include more than twelve months of our income on a single tax return. Tax information with respect to income allocated to the period from July 1 to the date of sale will not be available until after the end of our taxable year—June 30 of the subsequent calendar year—even though such income is includable on the unitholder’s tax return for the calendar year in which the sale is made. Such unitholders may be required to file returns before receiving tax information from us. In such case, unitholders may be required to file amended returns once tax information becomes available.

We are unable to provide Schedule K-1 tax information reports with respect to our taxable year ending June 30 until after the close of the calendar year in which our taxable year ended, but we are currently required to file our tax return no later than the March 15 following the close of that calendar year. This shortened period between the time at which unitholders receive the Schedule K-1 and the due date for our tax return hinders our ability to correct any errors that may appear on the Schedule K-1. Unitholders may be required to take positions inconsistent with the information provided on the Schedule K-1 in order to correct any such errors, and in such case, will be required to provide the IRS with notice of such inconsistent treatment.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. 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 and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

A portion of our operations are conducted by a subsidiary that is treated as a corporation for federal and state income tax purposes and is consequently subject to corporate-level federal and state income taxes.

A portion of our operations are conducted by Maxum Petroleum Products, Inc., our subsidiary that is treated as a corporation for federal income tax purposes as well as for purposes of the corporate income taxes imposed by many states. In the future, we may elect to conduct additional operations through this subsidiary or additional subsidiaries that are treated as corporations for federal and state income tax purposes. Maxum Petroleum Products, Inc. is, and any future subsidiaries that are treated as corporations would be, subject to corporate-level federal and state income tax, which reduces the cash available for distribution to us and, in turn, to our unitholders. If the IRS or a state taxing authority were to successfully assert that any subsidiary that is taxable as a corporation has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

Tax gain or loss on the 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 for federal income tax purposes 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 common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation 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 read “Material Federal Income Tax Consequences—Disposition of Common 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, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units 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 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. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. 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 read “Material 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 will adopt.

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes 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 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 for U.S. federal income tax purposes 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. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships 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 this 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. Our counsel has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common 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 to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common 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 cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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 technically terminated our partnership 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a year ending June 30, 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 we would be treated as a new partnership for 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. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely 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 they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We will initially own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

USE OF PROCEEDS

A $1.00 increase or decrease in the assumed initial public offering price of $ per common unit would cause the net proceeds from this offering, after deducting underwriting discounts, the structuring fee and estimated offering expenses, to increase or decrease, respectively, by approximately $ million.

CAPITALIZATION

The following table shows cash and cash equivalents and capitalization as of December 31, 2011:

•

on a historical basis with respect to our predecessor; and

•

on a pro forma basis after giving effect to the offering and other formation transactions described under “Prospectus Summary—Formation Transactions and Partnership Structure,” including the application of the net proceeds of the offering as described under “Use of Proceeds.”

This table is derived from, should be read in conjunction with and is qualified in its entirety by reference to, our audited historical financial statements and unaudited pro forma condensed consolidated financial statements, each as of December 31, 2011 and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	As of December 31, 2011
	Predecessor		Partnership
	Historical		As Adjusted
	(in thousands)
Cash and cash equivalents	$	517	$

Debt including current portion:
Revolving credit facility (1)	$	—	$
Partners’ capital/partner net investment:
Net parent equity		305,669
Partnership equity (2)
Common units—public
Common units—Maxum Petroleum
Subordinated units—Maxum Petroleum
General partner interest—Maxum Petroleum

Total partners’ capital/partner net investment		305,669

Total capitalization	$	305,669	$

(1)	In connection with the completion of this offering, we will enter into a $ million revolving credit facility. We do not expect to have any borrowings outstanding under our revolving credit facility at the completion of this offering.

(2)	On a pro forma basis, as of December 31, 2011, the public would have held common units, Maxum Petroleum would have held an aggregate of common units and subordinated units, and our general partner would have held general partner units.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of December 31, 2011, our net tangible book value was $ million, or $ per unit. Purchasers of common units in this offering will experience immediate and substantial dilution in net tangible book value per unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit		$
Pro forma net tangible book value per unit before the offering (a)	$
Increase in pro forma net tangible book value per unit attributable to purchasers in the offering

Less: Pro forma net tangible book value per unit after the offering (b)

Immediate dilution in pro forma net tangible book value per unit attributable to purchasers in the offering (c)(d)		$

(a)

Determined by dividing the number of units ( common units, subordinated units and general partner units) to be issued to subsidiaries of Maxum Petroleum for their contribution of assets and liabilities to Maxum Energy Logistics Partners, LP into the pro forma net tangible book value of the contributed assets and liabilities.

(b)	Determined by dividing the total number of units to be outstanding after the offering ( common units, subordinated units and general partner units) into our pro forma net tangible book value, after giving effect to the application of the net proceeds of the offering.

(c)	If the initial public offering price were to increase or decrease by $1.00 per common unit and the number of units to be offered remains the same, then dilution in net tangible book value per common unit would equal $ and $ , respectively.

(d)

Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by Maxum Petroleum and by the purchasers of common units in this offering upon completion of the transactions contemplated by this prospectus:


	Units Acquired				Total Consideration
	Number	Percent			Amount	Percent
Common Units owned by Maxum Petroleum and its affiliates (1)(2)(3)				%	$			%
Public Common Units				%				%

Total			100.0	%	$		100.0	%

(1)	The units acquired by our general partner and its affiliates consist of common units, subordinated units and general partner units.

(2)	Assumes the underwriters’ option to purchase additional units is not exercised.

(3)	The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by the general partner and its affiliates, as of December 31, 2011, after giving effect to the formation transactions is as follows:


		(in thousands)
Book value of net assets contributed		$
Less: Distribution to Maxum Petroleum from net proceeds of this offering

Total consideration		$

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Assumptions and Considerations” below. In addition, please 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 operating results, you should refer to our historical combined and pro forma condensed consolidated financial statements and related notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute rather than retain available cash, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Generally, our available cash for each fiscal quarter is all cash and cash equivalents on hand on the date of determination of available cash, less the amount of cash reserves established by our general partner at the date of determination of available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

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

There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except to distribute available cash as provided in our partnership agreement. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

•

Our cash distribution policy will be subject to restrictions on cash distributions under our revolving credit facility. Should we be unable to satisfy these restrictions, we would be prohibited from making cash distributions notwithstanding our cash distribution policy.

•

Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must subjectively believe that the determination is in our best interests.

•

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our common unitholders (excluding common units held by our general partner and its affiliates) other than in certain circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by our general partner and its affiliates) after the subordination period has ended. At the

completion of this offering, assuming no exercise of the underwriters’ option to purchase additional units, Maxum Petroleum will own our general partner as well as approximately % of our outstanding common units and all of our outstanding subordinated units, representing an aggregate % limited partner interest in us. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

•

Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

•

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you 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 expense, principal and interest payments on our debt, working capital requirements and anticipated cash needs. Our cash available for distribution to common unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.

•

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

•

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

Because we will distribute all of our available cash to our unitholders, we expect that 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 expansion capital expenditures. We do not have any commitment with our general partner or other affiliates, including Maxum Petroleum, to provide any direct or indirect financial assistance to us following the completion of this offering. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units and the incremental distributions on the incentive distribution rights may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate that there will be limitations in our revolving credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

Upon the completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per unit for each complete quarter, or $ per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above

under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 45 days after the end of each quarter, on or about the 15th day of each August, November, February and May to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately following the indicated distribution date. We do not expect to make distributions for the period that begins on July 1, 2012, and ends on the day prior to the completion of this offering other than the distribution to be made to Maxum Petroleum in connection with the completion of this offering as described in “Prospectus Summary—Formation Transactions and Partnership Structure” and “Use of Proceeds.” We will adjust our first distribution for the period from the completion of this offering through September 30, 2012 based on the actual length of the period. The amount of available cash needed to pay the minimum quarterly distribution on all of our common units, subordinated units and general partner units to be outstanding immediately after this offering for one quarter and on an annualized basis is summarized in the table below:


		Minimum Quarterly Distributions
		(in millions)
	Number of Units	One Quarter	Annualized
Publicly held common units		$	$
Common Units held by Maxum Petroleum		$	$
Subordinated Units held by Maxum Petroleum		$	$
General Partner Units		$	$
Total		$	$

As of the completion of this offering, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its initial 2.0% general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $ per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period.” We cannot guarantee, however, that we will pay the minimum quarterly distribution on our common units in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in our best interests. Please read “Conflicts of Interest and Duties.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. In addition, the audit committee of the board of directors of our general partner must approve any change in the application of an accounting policy or principle that results in a gain or loss and is not required by law, GAAP or the Public Company Accounting Oversight Board or similar regulatory body prior to its adoption.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $ per unit for the year ending June 30, 2013. In those sections, we present two tables, consisting of:

•

“Unaudited Pro Forma Cash Available for Distribution for the Year Ended June 30, 2011 and the Twelve Months Ended December 31, 2011,” in which we present the amount of cash we would have had available for distribution on a pro forma basis for the year ended June 30, 2011 and the twelve months ended December 31, 2011, derived from our audited and unaudited financial data that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

•

“Estimated Cash Available for Distribution for the Year Ending June 30, 2013,” in which we demonstrate our ability to generate sufficient cash available for distribution for us to pay the annualized minimum quarterly distribution on all units for the year ending June 30, 2013.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended June 30, 2011 and the Twelve Months Ended December 31, 2011

If we had completed this offering on July 1, 2010, our unaudited pro forma cash available for distribution for the year ended June 30, 2011 would have been approximately $30.7 million. This amount would have been sufficient to pay the minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis) on all of our common units and a cash distribution of $ per unit per quarter ($ per unit on an annualized basis), or approximately % of the minimum quarterly distribution, on all of our subordinated units for such period.

If we had completed this offering on January 1, 2011, our unaudited pro forma cash available for distribution for the twelve months ended December 31, 2011 would have been approximately $29.8 million. This amount would have been sufficient to pay the minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis) on all of our common units and a cash distribution of $ per unit per quarter ($ per unit on an annualized basis), or approximately % of the minimum quarterly distribution, on all of our subordinated units for such period.

Our unaudited pro forma cash available for distribution for the year ended June 30, 2011 and the twelve months ended December 31, 2011 includes $3.0 million of estimated incremental general and administrative expenses that we expect to incur annually as a result of becoming a publicly traded partnership. Incremental general and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting, tax returns and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance expenses and director compensation. These expenses are not reflected in the historical financial statements of our Predecessor or our pro forma financial statements included elsewhere in the prospectus.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering and related formation transactions been completed as of the dates indicated. In addition, cash available for distribution is primarily a cash accounting concept, while the historical financial statements of our Predecessor and our unaudited pro forma financial statements included elsewhere in the prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distribution that we might have generated had we completed this offering on the dates indicated. The pro forma amounts below are presented on a twelve-month basis, and there is no guarantee that we would have had available cash sufficient to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for each quarter within the twelve-month periods presented.

The following table illustrates, on a pro forma basis, for the year ended June 30, 2011 and the twelve months ended December 31, 2011 the amount of cash that would have been available for distribution to our unitholders, assuming that this offering and the related formation transactions had been completed at the beginning of such periods.

Maxum Energy Logistics Partners, LP

Unaudited Pro Forma Cash Available for Distribution


	Year Ended June 30, 2011			Twelve Months Ended December 31, 2011
	(in thousands, except per unit data)
Pro Forma Net Income:	$	14,750		$	16,854
Add:
Tax expense (a)		700			700
Interest expense		3,300			3,601
Depreciation and amortization		13,962			15,568
Equity-based compensation		572			660
Business transformation expense (b)		6,737			6,355
Loss from the early extinguishment of debt		199			16
Severance expense		685			318
Unrealized derivative losses		335			1,206
Acquisition expenses (c)		286			286
Miscellaneous expense (d)		—			962

Pro Forma Adjusted EBITDA (e)	$	41,526		$	46,526

Less:
Cash interest expense, net		3,300			3,601
Maintenance capital expenditures (f)		3,570			8,184
Expansion capital expenditures (g)		19,977			23,296
Incremental general and administrative expense of being a public company (h)		3,000			3,000
Cash portion of severance expense		111			318
Cash portion of miscellaneous expense		—			750
Tax expense (a)		700			700
Abandoned acquisition expenses (c)		189			189
Add:
Borrowings to fund expansion capital expenditures (g)		19,977			23,296

Pro Forma Cash Available for Distribution	$	30,656		$	29,784

Pro Forma Cash Distributions
Annual distribution per unit (based on a minimum quarterly distribution rate of $ per unit)	$			$
Annual distributions to:
Public common unitholders	$			$
Maxum Petroleum:
Common units
Subordinated units
General partner units

Total distributions to Maxum Petroleum

Total Distributions	$			$

Excess (Shortfall)	$			$

Percent of minimum quarterly distribution payable to common unitholders			%			%

Percent of minimum quarterly distribution payable to subordinated unitholders			%			%

(a)	Reflects income tax expense of Maxum Petroleum Products, Inc., a wholly-owned subsidiary of our operating company, which markets, sells and distributes products to end users.

(b)

Represents a cash expense equal to Maxum Petroleum’s allocation to us of our proportionate share of the cost of the development of an enterprise-wide information system, which was fully implemented into our operations on October 1, 2011. No additional business transformation expenses will be allocated to us after fiscal year 2012. Because Maxum Petroleum would not have allocated these expenses to us had the formation transactions and this offering been completed at the beginning of the periods presented, we have excluded these cash expenses in calculating pro forma Adjusted EBITDA and pro forma cash available for distribution.

(c)

Includes $0.2 million of acquisition-related expenses incurred in connection with one abandoned acquisition. In our determination of distributable cash flow under the partnership agreement, we adjust net income to add back acquisition-related expenses associated with (i) successful acquisitions or (ii) any other potential acquisitions that have not been abandoned. All such costs are required to be expensed in accordance with applicable accounting guidelines.

(d)	Includes a one-time $0.8 million cash payment in connection with the early termination of a customer contract relating to the termination of a hedge as a result of the bankruptcy of the counterparty to that hedge and a $0.2 million non-cash write-off of unamortized software costs.

(e)	For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

(f)

Maintenance capital expenditures are cash expenditures (including expenditures for the construction of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain our long-term operating income or operating capacity. Examples of maintenance capital expenditures are expenditures for the repair, refurbishment and replacement of our fleet of vehicles, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

(g)	Expansion capital expenditures are cash expenditures incurred for acquisitions of assets or capital improvements that we expect will increase our operating income or operating capacity over the long term, including purchases of new vehicles, storage facilities and other equipment.

(h)

Represents incremental annual general and administrative expenses related to being a publicly traded partnership, including expenses associated with annual and quarterly reporting, tax returns and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance expenses and director compensation.

Estimated Cash Available for Distribution for the Year Ending June 30, 2013

We forecast that our estimated cash available for distribution during the year ending June 30, 2013 will be approximately $55.7 million. This amount would exceed by $ million the amount needed to pay the minimum quarterly distribution of $ per unit on all of our common, subordinated and general partner units for the year ending June 30, 2013. This amount is approximately $25.9 million, or 86.9%, more than the unaudited pro forma cash available for distribution for the twelve months ended December 31, 2011. The major drivers of this expected increase in available cash for distribution are expected increased drilling and production activity by our E&P customers, expected gains in our E&P market share and expected improvements in our procurement efficiency.

We are providing the forecast of estimated cash available for distribution to supplement the historical financial statements of the Predecessor and our unaudited pro forma financial statements included elsewhere in the prospectus in support of our belief that we will have sufficient cash available for distribution to allow us to

pay cash distributions at the minimum quarterly distribution rate on all of our units for the year ending June 30, 2013. However, our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast. Please read “—Assumptions and Considerations” for further information as to the assumptions we have made for the forecast.

Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the year ending June 30, 2013. We believe that the assumptions underlying our forecast are reasonable, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay the minimum quarterly distribution or any other distribution on our common units. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, 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 forecast, including, among others, risks and uncertainties contained in “Risk Factors.” Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by us or any other person that the results contained in the forecast will be achieved. You should also read the cautionary statements under the heading “Forward-Looking Statements.”

We have prepared the following forecast to present the estimated cash available for distribution to our common unitholders during the forecasted period. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, 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 necessarily indicative of future results.

Neither our independent registered public accounting firm, or any other independent auditors, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The independent registered public accounting firm’s report included in this prospectus relates to historical financial information. It does not extend to prospective financial information and should not be read to do so.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the completion of this offering. In light of this, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all of our outstanding units for the year ending June 30, 2013, should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

Maxum Energy Logistics Partners, LP

Estimated Cash Available for Distribution


	Year Ending June 30, 2013
	(in thousands, except per unit data)

Revenues	$	1,939,987
Cost of Sales		1,851,991

Gross Profit		87,996

Expenses:
Selling, general and administrative		39,661

Operating Income		48,335

Other expense (income)
Interest expense, net		2,774
Other income, net		(936	)

Income (loss) before income taxes		46,497

Income tax expense (a)		700
Net Income		45,797

Adjustments to reconcile net income to estimated Adjusted EBITDA:
Add:
Interest expense, net		2,774
Depreciation and amortization		20,342
Income tax expense (a)		700

Estimated Adjusted EBITDA (b)	$	69,613

Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense, net	$	2,774
Expansion capital expenditures		11,113
Maintenance capital expenditures		10,487
Income tax expense (a)		700
Add:
Borrowings to fund expansion capital expenditures		11,113

Estimated Cash Available for Distribution	$	55,652

Minimum annual distribution per unit (based on a minimum quarterly distribution rate of $ per unit)
Annual distributions to: (c)
Public common unitholders
Maxum Petroleum:
Common units
Subordinated units
General partner units

Total distributions to Maxum Petroleum
Total distributions to our unitholders and general partner at the minimum distribution rate
Excess of cash available for distribution over aggregate annualized minimum quarterly distribution

(a)	Reflects income tax expense of Maxum Petroleum Products, Inc., a wholly-owned subsidiary of our operating company, which markets, sells and distributes products to end users.

(b)

Please read “Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.” Adjusted EBITDA should not be considered an alternative to net income, net cash provided by (used in) operating activities, or any other measure of financial performance calculated in accordance with GAAP.

(c)

The table reflects the number of common, subordinated and general partner units that we anticipate will be outstanding immediately following the completion of this offering, and the aggregate distribution amounts payable on those units during the forecast period at our minimum quarterly distribution rate of $ per unit on an annualized basis assuming that the underwriters’ option to purchase additional common units has not been exercised and the additional common units subject to the underwriters’ option are issued to Maxum Petroleum.

Assumptions and Considerations

We expect increases in drilling and production activity, increases in our E&P market share and improvements in our procurement efficiency for the year ending June 30, 2013 as compared to the twelve months ended December 31, 2011. This expectation is based on projections by industry research publications, our management’s view of our market position within the industry and our relationships with our customers and suppliers, and our management’s belief that current industry growth trends will continue. Please read “Industry” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Trends and Outlook.”

Volumes

We estimate volumes for the year ending June 30, 2013 based on the following assumptions:

•

Fuel volumes. We estimate that we will deliver approximately 540 million gallons of fuel for the fiscal year ending June 30, 2013 as compared to 495 million gallons for the twelve months ended December 31, 2011. We expect to sell more fuel to our E&P customers due to expected increases in drilling and production activity, as well as expected gains in our E&P market share. We have assumed fuel volumes sold to coal mining customers will remain consistent with volumes sold during the twelve months ended December 31, 2011.

•

Lubricant volumes. We estimate that we will deliver 18 million gallons of lubricants for the fiscal year ending June 30, 2013 as compared to 17 million gallons for the twelve months ended December 31, 2011. We expect to sell more lubricants to our E&P customers to support their increased drilling and production activity. We have assumed lubricant volumes sold to coal mining customers will remain consistent with volumes sold during the twelve months ended December 31, 2011.

Revenues

We estimate that our revenues will be approximately $1.94 billion for the fiscal year ending June 30, 2013 as compared to approximately $1.77 billion for the twelve months ended December 31, 2011. We estimate revenues for the year ending June 30, 2013 based on the following assumptions:

•

Commodity prices. We have assumed that the average sales price per unit of delivered fuels will approximate our average sales price for the twelve months ended December 31, 2011. We have assumed that the average sales price per unit of delivered lubricant will be higher than our average sales price for the twelve months ended December 31, 2011 in line with recent annual rates of increase. Because we are a margin-based business, the overall level of product prices has a limited effect on our cash available for distribution.

•

Services and Other Products. We estimate that our revenues from services and other products will increase to $83 million for the fiscal year ending June 30, 2013 as compared to $57 million for the twelve months ended December 31, 2011, which is attributable to increased activity levels of our current E&P customers, including increased hydraulic fracturing activity for the drilling of horizontal wells, which require a significantly greater amount of services than conventional wells.

Gross profit

Product and services margin. We estimate that our product and services margin for the fiscal year ending June 30, 2013 will be approximately $212 million (consisting of $162 million of product margin and $50 million of services margin), as compared to $171 million for the twelve months ended December 31, 2011 (consisting of $142 million of product margin and $29 million of services margin). The increase of $41 million, or 24%, over the twelve months ended December 31, 2011 includes $12 million resulting from increased volumes of fuels and lubricants sold, $8 million resulting from increased procurement efficiency, and $21 million of increased services margin resulting from increased E&P customer drilling activity. Services margin is the spread between services revenues and cost of services.

Distribution expenses. Distribution expenses include the costs of product distribution and the provision of services, which includes employment costs. We estimate that our distribution costs for the fiscal year ending June 30, 2013 will be approximately $124 million, as compared to $104 million for the twelve months ended December 31, 2011. The increase of $20 million, or 19%, is due to the increased volumes of fuels and lubricants sold.

Gross profit. As a result of the foregoing, gross profit will be approximately $88 million for the fiscal year ending June 30, 2013, as compared to $68 million for the twelve months ended December 31, 2011.

Although volatility in the price of our products can materially affect the total size of our revenue, cost of products sold and working capital requirements, it does not immediately affect our product margin. Increased working capital requirements may, however, cause us to incur additional debt, which would increase our interest expense.

Selling, general and administrative expense

We estimate that selling, general and administrative expenses for the fiscal year ending June 30, 2013 will be approximately $40 million. Our selling, general and administrative expenses for the twelve months ended December 31, 2011 were approximately $47 million. The decrease in selling, general and administrative expenses for the fiscal year ending June 30, 2013 is primarily due to the absence of business transformation expenses allocated by Maxum Petroleum and expected gains in efficiency, partially offset by an estimated $3 million of incremental annual selling, general and administrative expenses as a result of being a publicly traded partnership.

Interest expense, net

We estimate that interest expense, net for the fiscal year ending June 30, 2013 will be $2.8 million. Interest expense, net for the twelve months ended December 31, 2011 was approximately $3.6 million on a pro forma basis. The reduction in interest expense reflects that there will be no further allocations of interest expense to us from Maxum Petroleum following this offering. Interest expense, net for the fiscal year ending June 30, 2013 is based on anticipated borrowings during the period under a revolving credit facility that we plan to put in place at the completion of this offering. We have assumed an average outstanding debt balance of $75 million under our new revolving credit facility during the forecast period, with an assumed weighted average interest rate of 2.5%, and customary facility fees of $0.9 million. These borrowings are expected to be made to satisfy working capital needs and for expansion capital expenditures. We do not expect to have any borrowings outstanding under our revolving credit facility at the completion of this offering. We have assumed no interest income with respect to the cash that we maintain on our balance sheet during the forecast period.

Other income, net

We estimate that other income, net for the fiscal year ending June 30, 2013 will be $0.9 million. Other income, net for the twelve months ended December 31, 2011 was approximately the same on a pro forma basis. This income mostly relates to rental income and sales of obsolete or used vehicles taken out of service.

Depreciation and amortization

Depreciation and amortization expenses for the fiscal year ending June 30, 2013 are projected to be approximately $20.3 million as compared to $15.6 million for the twelve months ended December 31, 2011. The increase for the fiscal year ending June 30, 2013 is primarily due to recent and expected acquisitions of trucks, tanks and other equipment.

Expansion capital expenditures

Expansion capital expenditures are projected to be approximately $11.1 million for the fiscal year ending June 30, 2013 as compared to $23.3 million for the twelve months ended December 31, 2011. This decrease reflects a high level of investment activity during the twelve months ended December 31, 2011 that will not be necessary to support our business in the fiscal year ending June 30, 2013. We intend to fund expansion capital expenditures during the forecast period with borrowings under a revolving credit facility we intend to put in place at the completion of this offering.

Maintenance capital expenditures

Maintenance capital expenditures are projected to be approximately $10.5 million for the fiscal year ending June 30, 2013 as compared to $8.2 million for the twelve months ended December 31, 2011. Maintenance capital expenditures are incurred primarily to fund planned capital expenditures to replace obsolete or used vehicles taken out of service.

Sensitivity Analysis

Delivered volumes of product, product margin and service revenues are the primary factors that will influence whether the amount of cash available for distribution for the fiscal year ending June 30, 2013 is above or below our forecast. For example, a 5% decline in product and services margin would result in a $10.6 million decline in Adjusted EBITDA and cash available for distribution. A 5% increase in product and services margin would result in a $10.6 million increase in Adjusted EBITDA and cash available for distribution. If our actual product and services margin for the fiscal year ending June 30, 2013 is % lower than our forecast, we would have sufficient cash available to pay % of the aggregate annualized minimum quarterly distribution on the common units and % of the aggregate annualized minimum quarterly distribution on the subordinated units.

General considerations

Our forecast for the fiscal year ending June 30, 2013 reflects certain significant assumptions related to regulatory, industry and economic factors, including:

•

There will not be any new federal, state or local regulation of the oil, natural gas or coal mining sectors, or any new interpretation of existing regulations, that will be materially adverse to our business or our customers’ or suppliers’ businesses.

•

There will not be any material adverse change in oil, natural gas or coal prices or in market or general economic conditions.

•

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our operations, our customers’ operations or our suppliers.

•

We will not make any acquisitions, divestitures or significant expansion capital expenditures (other than as described above).

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2012, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through September 30, 2012 based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for each fiscal quarter, all cash and cash equivalents on hand on the date of determination of available cash with respect to such quarter, less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:

•

provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);

•

comply with applicable law, our debt instruments or other agreements; or

•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions on our subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter and the next four quarters).

Intent to Distribute the Minimum Quarterly Distribution

We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $ per unit, or $ on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

Distributable Cash Flow and Capital Surplus

General

All cash distributed to unitholders will be characterized as either “distributable cash flow” or “capital surplus.” We distribute available cash from distributable cash flow differently than available cash from capital surplus.

Definition of Distributable Cash Flow

Distributable cash flow will be determined by our general partner and is defined to mean, on a cumulative basis since the completion of this offering:

(i) net income, as determined in accordance with GAAP; plus or minus, as applicable,

(ii) any amounts necessary to offset the impact of any items included in net income, as determined in accordance with GAAP, that do not impact the amount of available cash (as more fully described below); plus

(iii) any acquisition-related expenses deducted from net income and associated with (a) successful acquisitions or (b) any other potential acquisitions that have not been abandoned; minus

(iv) any acquisition-related expenses covered by clause (iii)(b) immediately preceding that relate to (a) potential acquisitions that have since been abandoned or (b) potential acquisitions that have not been consummated within one year following the date such expense was incurred (except that if the potential acquisition is the subject of a pending purchase and sale agreement as of such one-year date, such one-year period of time shall be extended until the first to occur of the termination of such purchase and sale agreement or the first day following the closing of the acquisition contemplated by such purchase and sale agreement); and minus

(v) maintenance capital expenditures.

The types of items covered by clause (ii) above include, without limitation, (a) depreciation, depletion and amortization expense, (b) any gain or loss from the sale of assets not in the ordinary course of business, (c) any non-cash gains or items of income and any non-cash losses or expenses, including non-cash compensation expense, asset impairments, amortization of debt discounts, premiums or issue costs, mark-to-market activity associated with hedging and with non-cash revaluation and/or fair valuation of assets or liabilities, (d) earnings or losses from unconsolidated subsidiaries except to the extent of actual cash distributions received, and (e) any gain or loss as a result of a change in accounting policy or principle, provided that the application of any such change that is not required by law, GAAP or the Public Company Accounting Oversight Board or similar regulatory body to be adopted by us is approved by the audit committee of the board of directors of our general partner prior to its adoption.

If net income or other items affecting the calculation of distributable cash flow are restated for any quarter, then any subsequent determination of net income or such other items for such quarter or for a period including such quarter will reflect such restatement. Any restatement after the end of the subordination period will not retroactively affect the conversion of subordinated units.

For purposes of determining distributable cash flow, maintenance capital expenditures are cash expenditures (including expenditures for the construction of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures are expenditures to replace vehicles or equipment, to maintain the reliability, integrity and safety of vehicles and equipment and to comply with environmental laws and regulations.

As described above, distributable cash flow does not reflect actual cash on hand that is available for distribution to our unitholders. Our definition of distributable cash flow is generally designed and intended to adjust net income (as determined in accordance with generally accepted accounting principles) for items that do not impact the amount of available cash for distribution to our unitholders but may be required to be reflected in net income by applicable accounting rules and regulations. The actual cash used to pay a distribution may come from operating cash flow or other sources such as borrowings under our revolving credit facility.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from distributable cash flow until the sum of all available cash distributed since the closing of this offering equals the distributable cash flow as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of distributable cash flow, regardless of its source, as capital surplus. However, our partnership agreement includes a provision that will enable us, if we choose, to distribute up to $ million of cash we receive in the future from sources other than distributable cash flow, such as asset sales, issuances of securities and borrowings, without being required to classify such distribution as a distribution from capital surplus under our partnership agreement. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from distributable cash flow each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from distributable cash flow may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to pay the minimum quarterly distribution on the common units.

Subordination Period

The subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after June 30, 2015, that each of the following tests are met:

•

distributions of available cash from distributable cash flow on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $ (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•

the distributable cash flow generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $ (the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after June 30, 2013, that each of the following tests are met:

•

distributions of available cash from distributable cash flow on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $ (150% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

•

the distributable cash flow generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $ per unit (150% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

•

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Termination of the Subordination Period Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause:

•

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner;

•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

•

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

Distributions of Available Cash from Distributable Cash Flow during the Subordination Period

We will make distributions of available cash from distributable cash flow for any quarter during the subordination period in the following manner:

•

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—General Partner Interest” and “—Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Distributable Cash Flow after the Subordination Period

We will make distributions of available cash from distributable cash flow for any quarter after the subordination period in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

•

thereafter, in the manner described in “—Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional units in this offering, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from distributable cash flow after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

•

we have distributed available cash from distributable cash flow to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

•

we have distributed available cash from distributable cash flow on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from distributable cash flow for that quarter among the unitholders and our general partner in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “first target distribution”);

•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “second target distribution”);

•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $ per unit for that quarter (the “third target distribution”); and

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash From Distributable Cash Flow

The following table illustrates the percentage allocations of the additional available cash from distributable cash flow between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from distributable cash flow we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount” until available cash from distributable cash flow we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.


	Total Quarterly Distribution per Unit Target Amount	Marginal Percentage Interest in Distributions
	Total Quarterly Distribution per Unit Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$		98.0	%		2.0	%
First Target Distribution	above $		98.0	%		2.0	%
	up to $
Second Target Distribution	above $		85.0	%		15.0	%
	up to $
Third Target Distribution	above $		75.0	%		25.0	%
	up to $
Thereafter	above $		50.0	%		50.0	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount

and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from distributable cash flow for each quarter thereafter as follows:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;

•

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

•

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The following table illustrates the percentage allocations of available cash from distributable cash flow between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $ .


	Quarterly Distribution per Unit Prior to Reset	Marginal Percentage Interest in Distribution						Quarterly Distribution per Unit following Hypothetical Reset
	Quarterly Distribution per Unit Prior to Reset	Unitholders			General Partner
Minimum Quarterly Distribution	$		98.0	%		2.0	%	$
First Target Distribution	above $		98.0	%		2.0	%	above $
	up to $							up to $ (1)
Second Target Distribution	above $		85.0	%		15.0	%	above $
	up to $							up to $ (2)
Third Target Distribution	above $		75.0	%		25.0	%	above $
	up to $							up to $ (3)
Thereafter	above $		50.0	%		50.0	%	above $

(1)	This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

(2)	This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

(3)	This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from distributable cash flow that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding, our general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit would be $ per quarter for the two consecutive quarters prior to the reset.

Prior to Reset

Quarterly
Distribution
per Unit

Common
Unitholders Cash
Distribution

General Partner Cash Distributions

Common
Units

2.0% General
Partner Interest

IDRs

Total

Total
Distributions

Minimum Quarterly Distribution

—

First Target Distribution

above $

—

up to $

Second Target Distribution

above $

—

up to $

Third Target Distribution

above $

—

up to $

Thereafter

above $

—

The following table illustrates the total amount of available cash from distributable cash flow that would be distributed to the unitholders and the general partner, including in respect of IDRs, with respect to the quarter after the reset occurs. The table reflects that as a result of the reset there would be common units outstanding, our general partner has maintained its 2.0% general partner interest, and that the average distribution

to each common unit would be $ . The number of common units issued as a result of the reset was calculated by dividing (x) $ as the average of the amounts received by the general partner in respect of its IDRs for the two consecutive quarters prior to the reset as shown in the table above, or $ , by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive quarters prior to the reset as shown in the table above.

After Reset

Quarterly
Distribution
per Unit

Common
Unitholders Cash
Distribution

General Partner Cash Distributions

Common
Units Issued
As a Result of
Reset

2.0% General
Partner
Interest

IDRs

Total

Total
Distributions

Minimum Quarterly Distribution

—

First Target Distribution

above $

—

up to $

Second Target Distribution

above $

—

up to $

Third Target Distribution

above $

—

up to $

Thereafter

above $

—

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

•

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each hypothetical common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

•

thereafter, as if they were from distributable cash flow.

The preceding discussion is based on the assumptions that the general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any

distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages in the payment of the minimum quarterly distribution or our incentive distribution rights.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from distributable cash flow, with 50.0% being paid to the unitholders, pro rata, and 2.0% to our general partner and 48% to the holder of our incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•

the minimum quarterly distribution;

•

target distribution levels;

•

the unrecovered initial unit price;

•

the number of general partner units comprising the general partner interest; and

•

the arrearages in payment of the minimum quarterly distribution on the common units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be split into two subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our

creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

•

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

•

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

•

fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from distributable cash flow in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from distributable cash flow in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;

•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from distributable cash flow in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

•

first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

•

second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

•

thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows selected historical financial and operating data of our Predecessor as of the dates and for the periods indicated and pro forma financial data for Maxum Energy Logistics Partners, LP as of the date and for the periods indicated. The following table should be read together with, and is qualified in its entirety by reference to, the historical and pro forma financial information and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The selected historical financial and operating data below as of June 30, 2011 and 2010 and December 31, 2011 and for the years ended June 30, 2011, 2010 and 2009 and the six months ended December 31, 2011 and 2010 were derived from our audited combined balance sheets as of June 30, 2011 and 2010 and unaudited balance sheet as of December 31, 2011, and the audited combined statements of operations and cash flows for the years ended June 30, 2011, 2010 and 2009 and unaudited combined statements of operations and cash flows for the six months ended December 31, 2011 and 2010, included elsewhere in this prospectus. The selected historical financial and operating data below as of June 30, 2009, 2008 and 2007 and December 31, 2010 and for the years ended June 30, 2008 and 2007 was derived from our unaudited combined balance sheets as of June 31, 2009, 2008 and 2007 and December 31, 2010 and the unaudited combined statements of operations and cash flows for the years ended December 31, 2008 and 2007 not included in this prospectus.

The selected pro forma condensed consolidated statement of operations data for the six months ended December 31, 2011 and the year ended June 30, 2011 and selected pro forma condensed consolidated balance sheet data as of December 31, 2011 are derived from the unaudited condensed consolidated pro forma financial information of Maxum Energy Logistics Partners, LP included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the completion of this offering had taken place on December 31, 2011, in the case of the pro forma condensed consolidated balance sheet, and as of July 1, 2010, in the case of the pro forma condensed consolidated statements of operations for the six months ended December 31, 2011 and the year ended June 30, 2011. These transactions include:

•

the contribution of the Contributed Subsidiaries by MPOC and its subsidiaries to us (other than the excluded assets described above);

•

the application of the net proceeds from this offering in the manner described in “Use of Proceeds.”

The pro forma financial data does not give effect to an estimated $3.0 million of additional annual general and administration expenses we expect to incur annually as a result of being a publicly traded partnership.


	Predecessor Historical																			Maxum Energy Logistics Partners, LP Pro Forma
	Year Ended June 30,													Six Months Ended December 31,						Six Months Ended December 31, 2011		Year Ended June 30, 2011
	2011			2010			2009			2008		2007		2011			2010			Six Months Ended December 31, 2011		Year Ended June 30, 2011
														(unaudited)						(unaudited)
	(in thousands, except per unit data)
Statement of Operations Data:
Revenues	$	1,484,972		$	954,404		$	1,131,530		$	1,372,229	$	697,778	$	915,254		$	630,149		$	915,254	$	1,484,972
Gross profit		58,559			33,915			57,333			104,391		85,497		37,158			27,389			37,158		58,559
Operating income		18,200			3,764			31,049			22,866		21,549		12,152			9,574			12,152		18,200
Interest expense, net (1)		18,730			13,124			10,902			12,737		9,229		12,170			8,076			1,800		3,300
Net income (loss)		(289	)		(5,477	)		12,401			6,920		9,080		(108	)		840			10,047		14,750
Net income (loss) per unit

Balance Sheet Data (at end of period):
Working capital (2)	$	140,139		$	82,917		$	42,287		$	106,897	$	95,205	$	210,312		$	99,685		$	76,802
Property and equipment, net		52,953			40,901			33,918			35,236		31,922		61,454			43,277			61,454
Total assets		317,172			229,567			180,863			267,557		228,153		381,046			258,955			247,536
Total debt (1)		—			—			—			—		—		—			—			—
Total equity		228,899			162,888			115,374			184,478		162,274		305,669			179,577			184,859

Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	(37,393	)	$	(42,097	)	$	101,051						$	(61,402	)	$	(7,611	)
Investing activities	$	(28,465	)	$	(11,124	)	$	(21,840	)					$	(15,619	)	$	(8,007	)
Financing activities	$	66,300		$	52,991		$	(81,505	)					$	76,878		$	15,849
Depreciation and amortization	$	13,962		$	12,709		$	12,223						$	8,155		$	6,549

Other Financial Data:
Capital expenditures	$	23,547		$	13,179		$	10,260						$	16,346		$	8,413

Operating Data (gallons sold):
Fuels		469,819			383,273			410,975							253,817			228,220
Lubricants		16,940			14,004			13,963							8,472			8,300

(1)

(2)	Represents current assets less current liabilities.

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

The historical financial statements included in this prospectus reflect the assets, liabilities and operations of our Predecessor and the following discussion analyzes the financial condition and results of operations of our Predecessor. You should read the following discussion and analysis of financial condition and results of operations in conjunction with the historical and pro forma condensed consolidated financial statements, and the notes thereto, included elsewhere in this prospectus. For ease of reference, we refer to the historical financial results of our Predecessor as being “our” historical financial results.

Business Overview

We are one of the largest independent marketers and distributors of refined petroleum products and related services to the E&P and coal mining industries in the continental United States. We procure and sell diesel fuel, lubricating oil and custom-blended lubricants to companies engaged in the drilling for and production of oil and natural gas and in the mining of coal. We deliver these products to our customers at their well sites or mining locations. We also provide value-added logistics and energy management services necessary for drilling, production and mining activity, such as on-site refueling of equipment for drilling and hydraulic fracturing and coal mining operations and the design, fabrication and provision of storage tanks and other equipment to well sites and mining locations. Our services also include the provision of fuel additives; removal, recycling and disposal of used oil and lubricants; lubricant oil analysis; remote monitoring of fuel tanks; and maintenance and inspection of drilling, production and mining equipment. Within the E&P industry, we have three major customer groups: (i) E&P companies that hold oil and natural gas drilling rights, who purchase our fuel and services; (ii) drilling contractors providing services to E&P companies, who purchase our lubricants and services; and (iii) well completion companies providing hydraulic fracturing services for unconventional oil and natural gas wells, who purchase our fuel, lubricants and services. The well sites where we perform our services are located in the major U.S. unconventional oil and natural gas plays, including the Bakken, Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, Utica and Woodford Shales, and the Permian Basin. In the coal mining industry, we sell our fuel, lubricants and services to mining companies. Substantially all of the coal mining locations that we currently serve are located in the Central Appalachian region of the United States.

Our Operations

We manage our business to maximize the volume of the products we sell to our customers and the margin between the cost at which we purchase products from our suppliers and the price at which we are able to sell such products to our customers. We also seek to maximize the amount of energy logistics services we provide to our customers.

We charge our customers for delivered fuel in one of two ways. A customer may pay a price per gallon determined by adding an agreed-upon premium to a posted index price, plus a freight fee based on the customer’s location and the nature of its operations. Alternatively, a customer may pay a single, fixed amount per gallon of delivered fuel. Due to the frequency and volume of the purchases we make from our suppliers, we are often able to negotiate bulk purchase rates for fuel that are below the posted index price. We consider the difference between our cost for fuel and the posted index price to be a procurement margin. We consider the premium over the posted index price and the freight fee that we charge to our customers to be attributable to our delivery and logistics capabilities. In our experience, the value of these capabilities to customers determines our product margins more than the market price of the products we sell, even though the market price of our products is volatile. We generally obtain higher product margins for our fuel and lubricant deliveries to and services performed in remote, rugged or environmentally sensitive areas, such as mountainous regions and mines. Although volatility in the price of our products can materially affect the total size of our revenue, cost of products sold and working capital requirements, it does not immediately affect our product margin. Increased working capital requirements may, however, cause us to incur additional debt, which would increase our interest expense.

We generally do not maintain a significant inventory of our fuel products, which limits our commodity price exposure. Most of our product sales are generated pursuant to master service agreements under which our customers have an option, but not the obligation, to purchase fuel or lubricants from us. Although some customers have contracts under which they agree to purchase all of their fuel or lubricants from us, they are typically under no obligation to purchase a minimum amount.

We charge our customers for delivered lubricants at a single, fixed amount per gallon, which includes the cost of product plus delivery. For this type of a transaction, we purchase lubricants from our suppliers and hold them in our inventory for delivery to our customers’ locations. In addition, we make deliveries on behalf of our suppliers who have direct relationships with certain customers, primarily in the mining industry. For this type of a transaction, we purchase the product from our supplier, hold it in our inventory and deliver it upon supplier request to the end customer for a delivery fee.

We also generate revenues through our service offerings, primarily an on-site refueling service for our E&P and mining customers. We place our personnel and equipment at customer locations to provide round-the-clock fueling and support in order to ensure our customers’ critical equipment operates without disruption. We charge these customers a service fee in addition to charges per gallon of product sold. For certain services that complement our product distribution, such as equipment maintenance and our risk management and waste removal services, we do not charge our customers a separate fee for the service but only a fixed price for the delivery of fuel or lubricants.

How We Evaluate Our Operations

Our results are driven primarily by the volume of products that our customers demand from us and the product margin we earn on each gallon of fuel or lubricant delivered. Results are also driven by revenues on services we provide to our customers. Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) sales volumes, (ii) product margin, (iii) operating expenses and (iv) Adjusted EBITDA.

Sales Volumes

Our management views the volumes of fuel and lubricants sold as an important measure of demand for our services and our ability to grow market share and effectively utilize our assets. Demand for the services we provide generally increases as the volumes of fuel and lubricants sold increase.

Product Margin

Product margin is a non-GAAP supplemental financial measure that management and the external users of our combined financial statements may use to assess:

•

the margin on product sales required to cover the costs to deliver products and our overhead costs and to provide an acceptable return on capital employed;

•

our pricing policies and efficiency of our procurement;

•

our margins as compared to those of other publicly traded partnerships in our industry; and

•

our margins as compared to those of potential acquisition targets.

We believe that the presentation of product margin will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to

product margin is gross profit. Our non-GAAP financial measure of product margin should not be considered an alternative to gross profit. Product margin has important limitations as an analytical tool because it excludes some but not all items that affect gross profit. Product margin differs from gross profit because product margin excludes service revenues and distribution expenses and costs of service revenues. You should not consider product margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because product margin may be defined differently by other companies in our industry, our definition of product margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

For a reconciliation of product margin to gross profit, its most directly comparable GAAP financial measure, please read “Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Operating Expenses

Our management seeks to maximize the profitability of our operations in part by minimizing operating expenses, which are comprised of distribution expenses and selling, general and administrative expenses. Certain distribution expenses such as driver compensation, fuel expense and common carrier expense tend to correlate with the volume of fuel and lubricants delivered. Distribution expenses also include expenses that are less variable such as compensation of warehouse and dispatch employees, rent and other facilities expenses, vehicle maintenance and repair expenses, depreciation expense, supplies and other overhead expenses. These expenses increase significantly, however, when we mobilize operations and assets into new areas in response to customer movement or demand. Selling, general and administrative (“SG&A”) expenses include general management compensation, professional fees, amortization expense and allocations by Maxum Petroleum of its corporate overhead costs.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) adjusted to exclude interest expense, income taxes, depreciation and amortization, equity-based compensation, severance expense, unrealized derivative gains and losses, acquisition expenses, and certain other expenses that are non-cash charges or that we consider not to be indicative of ongoing operations.

•

our operating performance as compared to other publicly traded partnerships in our industry, without regard to historical cost basis or financing methods;

•

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;

•

our ability to incur and service debt and fund capital expenditures; and

•

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and cash flow from operations. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to net income or cash flow from operations. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and cash flows from operations. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

For a reconciliation of Adjusted EBITDA to net income and cash flow from operations, its most directly comparable GAAP financial measures, please read “Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Items Impacting the Comparability of Our Financial Results

Our future results of operations may not be comparable to the historical results of operations for the periods presented below for our Predecessor, for the reasons described below:

•

The historical financial statements of our Predecessor cover periods in which we experienced significant expansion into new geographic areas and growth through acquisitions. The impact of geographical expansions and acquisitions in the future may be different than the impact of historical activities.

•

We anticipate incurring approximately $3.0 million of general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax returns and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance expenses and director compensation. These incremental general and administrative expenses are not reflected in the historical combined statements of operations of our Predecessor.

•

From and after the completion of the offering, we will be required to reimburse Maxum Petroleum for the time and materials spent in performing certain general and administrative services on our behalf. These reimbursement expenses may be significantly different from the corporate overhead allocations that are reflected in the historical combined statements of operations of our Predecessor. Please read “Certain Relationships and Related Party Transactions—Omnibus Agreement.”

•

Our Predecessor’s historical combined financial statements include U.S. federal and state income tax expense calculated on a separate return basis. Due to our status as a partnership, most of our earnings will not be subject to U.S. federal income tax or state income taxes in the future.

•

Our Predecessor’s historical combined statements of operations include an allocation of Maxum Petroleum’s interest expense. Following the completion of this offering, we will have a revolving credit facility on which we will pay interest, and Maxum Petroleum will no longer allocate a proportionate share of its interest expense to us.

•

In May 2009, Maxum Petroleum launched a project to enable it to more effectively approach the market as a single entity with a single brand, which we refer to as the business transformation project. This project included the development and implementation of an enterprise-wide information system which was fully implemented into our operations on October 1, 2011. We believe that this project will transform our business processes so that we can procure and deliver our products and provide our services to our customers more effectively and efficiently. Maxum Petroleum has allocated to us our proportionate share of the cost of this project, which we refer to as business transformation expense. We expect the allocation of these expenses from Maxum Petroleum to diminish as we complete our implementation of the information system and integrate these new business processes. No additional business transformation expenses will be allocated to us after fiscal year 2012. We expect to begin to realize the full benefit from this project during fiscal year 2013.

•

In 2010 and 2011, we established facilities in the Marcellus, Eagle Ford and Bakken Shales which added to our fixed indirect distribution expenses in those periods. As our volume grows in these areas of operation, we expect to benefit from the operating leverage these upfront costs will provide.

•

Following the completion of this offering, we intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $ per unit per quarter ($ per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities. Historically, our Predecessor largely relied on cash flows generated internally and funding provided by Maxum Petroleum.

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Operating Environment

We serve customers in the E&P and coal mining industries. As a result, our business is substantially dependent on conditions in the energy industry and, in particular, the willingness of our customers to engage in drilling and production activities and coal mining. The level of customers’ activities and their demand for our services generally depend on their prevailing views of future supply and demand for oil, natural gas products, refined products, electric power and mined products, their cost structure and access to capital and the effect of government regulation.

With respect to the E&P industry, the number of land-based drilling rigs active in the United States has been growing steadily since the summer of 2009. We believe this trend will continue in the near-term. We have demonstrated our ability to secure the equipment and establish the infrastructure to meet the needs of our E&P customers as their operations expand in volume and geographically. Although recent prices for natural gas are at historic lows, the decrease in natural gas drilling activity has been offset by increased drilling activity in oil and liquids-rich formations. According to the Baker Hughes rig count, there were 710 natural gas rigs active on February 24, 2012, compared to 906 on February 25, 2011, representing a decrease of 21.6%. However, the Baker Hughes rig count indicated that there were 1,265 oil rigs active on February 24, 2012, compared to 783 on February 25, 2011, representing an increase of 61.6%. Further, hydraulic fracturing services are increasingly being deployed in traditionally oil-focused basins. According to Spears & Associates, the number of horizontal wells drilled is projected to grow from 16,000 in 2011 to 18,400 in 2012. Although the E&P industry is cyclical and oil prices are at historically high levels and remain volatile, we believe that many of the oil and liquids-rich plays are still economically attractive at oil prices substantially below the current prevailing market prices, which would support continued drilling activity even if oil prices decline. Accordingly, we expect to benefit as our customers increase their domestic exploration and production of natural gas, natural gas liquids and crude oil.

As companies increasingly focus on their core business, they have tended to outsource their procurement and logistics processes. This trend has given rise to the emergence of a growing number of third-party logistics providers in the last two decades. Major oil companies have increasingly transferred their distribution business to third-party logistics providers. We believe fuel refiners and lubricant manufacturers will become increasingly selective with regard to their distribution partners. Refiners and manufacturers increasingly view their relationship with distribution partners as an extension of their brand and logistics networks and not merely as an avenue to resell their products to end users. We expect to benefit from this selectivity because we have better access to capital, broader product and service offerings and a larger distribution network than most of our competitors.

As in the E&P industry, large coal mining operators rely increasingly on third-party logistics providers for products and services that are necessary to the operation of their core business. The coal customers’ demand for the products and services offered by these third-party providers is driven by domestic coal production.

Although total U.S. coal production has been increasing in recent years, the Central Appalachian region has faced declining production. However, we have been able to grow our sales volumes in this area from 86 million gallons in fiscal year 2008 to 116 million gallons in fiscal year 2011, a 35% increase. While near-term industry production challenges could increase and our strong volume growth relative to declining coal production in the Central Appalachian region could diminish, we believe the strength of our customer base and their coal reserves, increasing demand for coal exports, and the strength of our operating model provide us the opportunity for continued growth.

Acquisition Opportunities

We intend to selectively pursue asset acquisitions from third parties to the extent such acquisitions complement our existing asset base, allow us to capture operational efficiencies or expand our service offerings to our customers. We expect that we will engage in a higher level of acquisition activity as a result of the trend towards consolidation in our industry. We may also acquire additional assets from Maxum Petroleum.

Although we may incur significant expense in connection with an acquisition or expansion into a new geographic area, as we increase volumes and the number of customers in that area, we benefit from increased operating efficiencies and product margins.

Results of Operations

A summary of our combined statements of operations for the periods indicated is presented below (in thousands):


	Year Ended June 30,									Six Months Ended December 31,
										(unaudited)
	2011			2010			2009			2011			2010
Revenues	$	1,484,972		$	954,404		$	1,131,530		$	915,254		$	630,149
Cost of sales		1,426,413			920,489			1,074,197			878,096			602,760

Gross profit		58,559			33,915			57,333			37,158			27,389
Selling, general and administrative expenses		41,193			30,628			26,722			24,367			18,225
Other operating expense (income), net		(834	)		(477	)		(438	)		639			(410	)

Operating income		18,200			3,764			31,049			12,152			9,574
Interest expense, net		18,730			13,124			10,902			12,170			8,076
Miscellaneous income, net		(550	)		(720	)		(60	)		(45	)		(219	)

Income (loss) before income taxes		20			(8,640	)		20,207			27			1,717
Income tax expense (benefit)		309			(3,163	)		7,806			135			877

Net income (loss)	$	(289	)	$	(5,477	)	$	12,401		$	(108	)	$	840

Other Financial Data:
Adjusted EBITDA	$	41,526		$	21,969		$	45,724		$	24,402		$	19,403
Product margin	$	124,054		$	87,999		$	113,683		$	75,586		$	57,277

Operating Data:
Gallons Sold:
Fuels		469,819			383,273			410,975			253,817			228,220
Lubricants		16,940			14,004			13,963			8,472			8,300

A description of the recurring components of our statements of operations follows:

Revenues. Revenues include the amounts earned on the sales of fuels, lubricants and other products and on services provided to our customers. We recognize revenue when there is persuasive evidence of an arrangement between us and the customer, products have been delivered to the customer or services rendered, pricing is fixed or determinable and collection is reasonably assured. When we are the primary obligor in the sales arrangements with our customers and bear credit and inventory risk, we record revenue on a gross basis. When we act solely as delivery agent for lubricants being sold by a producer, revenue is recorded on a net basis. We record estimated reductions to revenue for customer rebate programs based on historical experience and estimated revenue levels. Sales and excise taxes collected from customers and remitted to governmental authorities are presented on a net basis in the combined statements of operations.

Cost of Sales. Cost of sales includes the cost of the products we purchase for resale and our distribution expenses. Distribution expenses include the costs we incur to deliver products to our customers and to store, move and prepare products for shipment and to provide the services we provide to our customers. Direct distribution expenses include driver compensation, fuel expense, and common carrier expenses. Indirect distribution expenses include compensation of warehouse and dispatch employees, rent and other facilities expenses, vehicle maintenance and repair expenses, depreciation expense, supplies and other related overhead expenses. Depreciation expense relates to our property and equipment, including primarily transportation equipment and storage facilities.

Gross Profit. Gross profit is the difference between revenues and cost of sales.

Selling, General and Administrative Expenses. Our SG&A expenses are comprised of expenses incurred by operations, corporate overhead allocations and an allocation of business transformation expenses. The expenses incurred by operations include compensation of the sales, general management and administrative employees that directly support our business operations as well as travel expenses, legal fees, insurance expense, property taxes and amortization of intangible assets and other administrative overhead, in each case related to our business operations. The corporate overhead allocation includes the cost of certain services provided by Maxum Petroleum for management, human resources, accounting, treasury, tax, legal, insurance and other corporate services. These allocations were based on measures that management believes are reasonable and reflect our cost of doing business. Maxum Petroleum also allocates to us our share of the business transformation expense.

Other Operating Income, Net. Other operating income, net is primarily rental income and the net gains and losses on sales of property and equipment, including sales of obsolete or used vehicles taken out of service.

Interest Expense, Net. Maxum Petroleum allocates to us our proportionate share of its interest expense. The allocation was based on the capital employed, defined as total assets less total liabilities, of our operations in proportion to the total capital employed by all of Maxum Petroleum’s operating units. No interest expense will be allocated to us after the completion of this offering. After the completion of this offering, we expect to incur interest expense on indebtedness under our revolving credit facility.

Miscellaneous Income (Expense), Net. Miscellaneous income (expense) is the net of non-operating miscellaneous income credits and expense charges.

Income Tax. Income taxes were computed on a separate return basis and include the impact of non-deductible expenses and changes in state tax rates on our net deferred tax liabilities.

Six Months Ended December 31, 2011 Compared to Six Months Ended December 31, 2010

Revenues. Revenues for the six months ended December 31, 2011 were $915.3 million, an increase of $285.1 million, or 45.2%, compared to the six months ended December 31, 2010. Revenues from fuel, lubricants, other products and services are shown below (in thousands).


	Six Months Ended December 31,
	2011		2010		Change
Fuels	$	820,971	$	558,577	$	262,394
Lubricants		62,404		53,007		9,397
Other products		14,268		10,167		4,101
Services		17,611		8,398		9,213

Total	$	915,254	$	630,149	$	285,105

Fuel revenues increased $262.4 million, or 47.0%, during the six months ended December 31, 2011 compared to the six months ended December 31, 2010. Higher average selling prices, as a result of higher oil prices, contributed $199.7 million of the increase. Volume was 25.6 million gallons, or 11.2%, higher for the six months ended December 31, 2011 compared to the six months ended December 31, 2010, and accounted for the remainder of the increase. Deliveries to our E&P customers, which increased 27.1 million gallons, or 20.3% accounted for most of the volume increase. According to Baker Hughes, the average number of active land-based rigs was approximately 18.7% higher during the six months ended December 31, 2011 compared to the six months ended December 31, 2010. Deliveries to our wholesale customers were 2.0 million gallons lower.

Lubricant revenues increased $9.4 million, or 17.7%, during the six months ended December 31, 2011 compared to the six months ended December 31, 2010. Higher average selling prices accounted for $8.3 million of this increase and the remainder was attributable to increased volumes.

Revenues from other products increased $4.1 million, or 40.3%, during the six months ended December 31, 2011 compared to the six months ended December 31, 2010 and reflect higher sales of coolants, equipment and related products to our E&P customers.

Service revenues increased $9.2 million, or 109.7%, during the six months ended December 31, 2011 compared to the six months ended December 31, 2010. Most of the increase relates to services provided to our customers engaged in hydraulic fracturing.

Gross Profit. Gross profit for the six months ended December 31, 2011 was $37.2 million, an increase of $9.8 million, or 35.7%, compared to gross profit for the six months ended December 31, 2010. The key components of gross profit are summarized in the following table (in thousands):


	Six Months Ended December 31,
	2011			2010			Change
Product margin	$	75,586		$	57,277		$	18,309
Service revenues		17,611			8,398			9,213
Distribution expenses		(56,039	)		(38,286	)		(17,753	)

Gross profit	$	37,158		$	27,389		$	9,769

The increase in product margin during the six months ended December 31, 2011 compared to the six months ended December 31, 2010 was primarily attributable to the following:

•

Fuel margins increased approximately $0.04 per gallon, contributing an increase of $10.3 million. This increase is net of a $1.0 million write-off of the fair value of a sales agreement that had been hedged by a futures contract with MF Global. This write-off was necessitated by the bankruptcy of MF Global. We have no further exposure to losses associated with the MF Global bankruptcy.

•

Higher fuel volume contributed $4.2 million.

•

Lubricant margins increased $0.35 per gallon, contributing an increase of $2.9 million.

The increase in services revenues also had a positive impact on gross profit. The costs of providing these services are included in distribution expenses. The increase in distribution expenses during the six months ended December 31, 2011 compared to the six months ended December 31, 2010 was primarily attributable to the following:

•

The direct costs associated with increased volume, additional services and higher fuel costs totaled $11.1 million.

•

Depreciation and other vehicle related expenses increased $3.4 million due primarily to vehicles added to service the increased volume.

•

The increase in the costs associated with staffing and operating our warehouse and distribution facilities was $2.7 million. This increase was primarily due to new facilities in the Marcellus, Eagle Ford and Bakken Shales.

•

Increases in other overhead costs within distribution expenses totaled $0.6 million.

Selling, General and Administrative Expenses. SG&A expenses were $24.4 million, an increase of $6.1 million, or 33.7%, during the six months ended December 31, 2011 compared to the six months ended December 31, 2010. The following table provides a summary of SG&A expenses (in thousands):


	Six Months Ended December 31,
	2011		2010		Change
Expenses incurred by operations	$	11,164	$	9,882	$	1,282
Corporate overhead allocation		10,468		5,226		5,242
Business transformation expense		2,735		3,117		(382	)

Total SG&A	$	24,367	$	18,225	$	6,142

The increase in expenses incurred by operations during the six months ended December 31, 2011 compared to the six months ended December 31, 2010 was primarily due to higher compensation expense. This increase is the result of additional administrative staff required by increased business activity. In addition, we added staff, which we expect to be temporary, to minimize disruptions during the implementation of our new information system. The allocation of corporate overhead includes higher bonus expense of $1.0 million and higher information technology costs of $3.4 million. Our operations began implementing the enterprise-wide information system in July 2011 and, as a result, a larger portion of the cost of corporate information technology services has been allocated to us since that date, thereby increasing our corporate overhead allocation of this cost. In addition, Maxum Petroleum began amortizing the cost of the information system in February 2011, and our share of the amortization expense was $1.5 million.

Other Operating Expense (Income), Net. Other operating expense, net was $0.6 million during the six months ended December 31, 2011, an increase of $1.0 million compared to other operating income, net of $0.4 million during the six months ended December 31, 2010. In November 2011, in connection with the MF Global bankruptcy, we made a payment of $0.8 million to terminate a customer sales agreement that was hedged by a futures contract with MF Global.

Operating Income. For the reasons described above, operating income for the six months ended December 31, 2011 was $12.2 million, an increase of $2.6 million, or 26.9%, compared to the six months ended December 31, 2010.

Interest Expense. Interest expense allocated by Maxum Petroleum for the six months ended December 31, 2011 was $12.2 million compared to $8.1 million allocated for the six months ended December 31, 2010. The increase was attributable to higher overall interest expense subject to allocation and the greater amounts of capital employed by our operations as a result of increased working capital and our investment in property and equipment.

Income Tax Expense. The income tax expense for the six months ended December 31, 2011 was $0.1 million compared to $0.9 million for the six months ended December 31, 2010. The effective tax rate for the six months ended December 31, 2011 was higher due to non-deductible expenses.

Net Loss. For the reasons described above, our net loss for the six months ended December 31, 2011 was $0.1 million, $0.9 million lower than net income recorded for the six months ended December 31, 2010.

Adjusted EBITDA. Adjusted EBITDA for the six months ended December 31, 2011 was $24.4 million, an increase of $5.0 million, or 25.8%, compared to the six months ended December 31, 2010. As explained above, operating income increased $2.6 million in the six months ended December 31, 2011 compared to the six months ended December 31, 2010. Operating income for the six months ended December 31, 2011 includes higher depreciation and amortization expenses of $1.6 million and higher unrealized losses on derivatives of $0.9 million than in the six months ended December 31, 2010, and an expense of $0.8 million to terminate a customer sales agreement. These items are excluded from the calculation of Adjusted EBITDA.

Year Ended June 30, 2011 Compared to Year Ended June 30, 2010

Revenues. Revenues for fiscal year 2011 were $1.5 billion, an increase of $530.6 million, or 55.6%, compared to fiscal year 2010. Revenues from fuel, lubricants, other products and services are shown below (in thousands):


	Year Ended June 30,
	2011		2010		Change
Fuels	$	1,334,155	$	843,833	$	490,322
Lubricants		108,201		85,925		22,276
Other products		21,696		13,798		7,898
Services		20,920		10,848		10,072

Total	$	1,484,972	$	954,404	$	530,568

Revenues from fuels increased $490.3 million, or 58.1%, during fiscal year 2011 compared to fiscal year 2010. Higher average selling prices, a result of higher oil prices, contributed $299.8 million of the increase. Volume was 86.5 million gallons, or 22.6%, higher in fiscal year 2011 and accounted for the remainder of the increase. The volume increase was primarily attributable to the following:

•

Increased deliveries to our E&P customers of 78.9 million gallons, representing a 39.0% increase, accounted for most of the volume increase. According to Baker Hughes, the average number of land-based rigs in operation was approximately 42% higher during fiscal year 2011 compared to fiscal year 2010.

•

Increased fuel deliveries to our coal mining customers totaled 15.3 million gallons.

•

Fuel sold primarily to our wholesale customers declined 7.7 million gallons.

Lubricant revenues in fiscal year 2011 were $108.2 million, an increase of $22.3 million, or 25.9%, compared to fiscal year 2010. Higher average selling prices and increased volume contributed to the increase. Lubricant volume increased by 2.9 million gallons during fiscal year 2011 compared to fiscal year 2010. Lubricants delivered to E&P customers increased 2.5 million gallons and lubricants delivered to coal mining customers increased 1.0 million gallons. Volume sold primarily to our wholesale customers declined 0.6 million gallons.

Revenues from other products in fiscal year 2011 were $21.7 million, which represented an increase of $7.9 million, or 57.2%, compared to fiscal year 2010 and reflected higher sales of coolants, fuel additives and related products to E&P customers.

Service revenues in fiscal year 2011 was $20.9 million, an increase of $10.1 million, or 92.8%, compared to fiscal year 2010. This change was attributable to increases in services provided to our E&P customers engaged in hydraulic fracturing.

Gross Profit. Gross profit in fiscal year 2011 was $58.6 million, an increase of $24.6 million, or 72.7%, compared to fiscal year 2010. The key components of gross profit are summarized in the following table (in thousands):


	Year Ended June 30,
	2011			2010			Change
Product margin	$	124,054		$	87,999		$	36,055
Service revenues		20,920			10,848			10,072
Distribution expenses		(86,415	)		(64,932	)		(21,483	)

Gross profit	$	58,559		$	33,915		$	24,644

The increase in product margin in fiscal year 2011 compared to fiscal year 2010 was primarily attributable to the following:

•

Fuel margins increased approximately $0.03 per gallon, contributing an increase of $12.9 million. Higher fuel volume contributed $12.6 million.

•

Improved lubricant margins and higher volume contributed $6.6 million.

•

Increased sales of other products contributed $4.0 million.

The increase in service revenues also had a positive impact on gross profit. The costs of providing these services are included in distribution expenses. Increases in distribution expenses in fiscal year 2011 compared to fiscal year 2010 were as follows:

•

The direct costs associated with increased volume, additional services and higher fuel costs totaled $13.9 million.

•

Depreciation and other vehicle related expenses increased $3.7 million due primarily to vehicles added to service the increased volume.

•

The increase in the costs associated with staffing and operating our warehouse and distribution facilities was $3.9 million. This increase was primarily due to new facilities in the Marcellus, Eagle Ford and Bakken Shales.

Selling, General and Administrative Expenses. SG&A expenses were $41.2 million in fiscal year 2011, an increase of $10.6 million, or 34.5%, compared to fiscal year 2010. The following table provides a summary of SG&A expenses (in thousands):


	Year Ended June 30,
	2011		2010		Change
Expenses incurred by operations	$	19,786	$	18,226	$	1,560
Corporate overhead allocation		14,670		8,126		6,544
Business transformation expense		6,737		4,276		2,461

Total selling, general and administrative expenses	$	41,193	$	30,628	$	10,565

Expenses incurred by operations increased $1.6 million in fiscal year 2011 compared to fiscal year 2010. Selling expenses and travel costs were $0.5 million higher in fiscal year 2011 due to the increase in business activity. Insurance costs were also higher in fiscal year 2011 due to a $0.5 million charge recorded to cover the deductible on a potential claim that may arise as a result of an incident that occurred during the year.

The increase in the allocation of corporate overhead expenses by Maxum Petroleum was primarily attributable to the following:

•

Bonus expense in fiscal year 2011 was $2.1 million. There were no bonuses paid in fiscal year 2010.

•

Information technology expenses increased $2.5 million. During fiscal year 2011 Maxum Petroleum added staff to maintain the enterprise-wide information system and began amortizing the capitalized cost of the information system.

•

We were allocated a greater percentage of overall corporate expenses due to the rate of our growth compared to the overall growth of Maxum Petroleum.

Operating Income. For the reasons described above, operating income for fiscal year 2011 was $18.2 million, an increase of $14.4 million as compared to fiscal year 2010.

Interest Expense. Interest expense allocated by Maxum Petroleum for fiscal year 2011 was $18.7 million compared to $13.1 million allocated for fiscal year 2010. The amount of interest allocated increased by $5.6 million and the percentage allocated to our operations increased from 38% to 44%. The increase in the percentage allocated was due to an increase in our working capital and property and equipment.

Income Tax. The income tax expense for fiscal year 2011 was $0.3 million. Income tax expense reflects non-deductible expenses and the impact of state tax rates on our net deferred tax liability. Our effective tax rate in fiscal year 2010 was 36.6%.

Net Loss. For the reasons described above, our net loss for fiscal year 2011 was $0.3 million, which was $5.2 million lower than the net loss recorded for fiscal year 2010.

Adjusted EBITDA. Adjusted EBITDA for fiscal year 2011 was $41.5 million, an increase of $19.6 million, or 89.0%, compared to fiscal year 2010. As explained above, operating income increased $14.4 million in 2011 compared to 2010. Operating income for 2011 includes higher business transformation expenses of $2.5 million, higher depreciation and amortization expenses of $1.3 million and higher unrealized losses on derivatives of $0.5 million. These items are excluded from the calculation of Adjusted EBITDA.

Year Ended June 30, 2010 Compared to Year Ended June 30, 2009

Revenues. Revenues for fiscal year 2010 totaled $954.4 million, a decrease of $177.1 million, or 15.7%, compared to fiscal year 2009. Revenues from fuels, lubricants and other products and services are shown below (in thousands):


	Year Ended June 30,
	2010		2009		Change
Fuels	$	843,833	$	991,451	$	(147,618	)
Lubricants		85,925		113,595		(27,670	)
Other products		13,798		15,490		(1,692	)
Services		10,848		10,994		(146	)

Total	$	954,404	$	1,131,530	$	(177,126	)

Revenues from fuels decreased $147.6 million, or 14.9%, in fiscal year 2010 compared to fiscal year 2009. Lower average selling prices, a result of lower oil prices, contributed $80.8 million of the decrease. Volume was 27.7 million gallons, or 6.7%, lower in fiscal year 2010, and accounted for the remaining $66.8 million of the decline.

The volume decline was primarily attributable to the following:

•

Fuel that was previously sold primarily to our wholesale customers declined 20.8 million gallons.

•

Reduced deliveries to our E&P customers of 12.0 million gallons, representing a 5.6% decrease, contributed to the decrease. According to Baker Hughes, the average number of land-based rigs declined approximately 20% from fiscal 2009 to fiscal 2010. Despite the decline in the aggregate number of active land-based rigs, we experienced volume growth in the Marcellus Shale.

•

Fuel deliveries to our coal mining customers increased 5.1 million gallons.

Lubricant revenues in fiscal 2010 were $85.9 million, a decrease of $27.7 million, or 24.4%, compared to fiscal year 2009. Lower average selling prices accounted for this decline. Lubricant volumes were essentially unchanged as lower volume to our E&P customers was partially offset by increases primarily to our metallurgical coal mining customers.

Gross Profit. Gross profit in fiscal year 2010 was $33.9 million, a decrease of $23.4 million, or 40.8%, compared to fiscal year 2009. This decline in gross profit was due to lower product margin as shown in the following table (in thousands):


	Year Ended June 30,
	2010			2009			Change
Product margin	$	87,999		$	113,683		$	(25,684	)
Service revenues		10,848			10,994			(146	)
Distribution expenses		(64,932	)		(67,344	)		2,412

Gross profit	$	33,915		$	57,333		$	(23,418	)

The decline in product margin in fiscal year 2010 compared to fiscal year 2009 was primarily attributable to the following:

•

Fuel margins decreased approximately $0.05 per gallon, contributing an $18.0 million decline. Lower margins were the result of competitive pressures as a result of lower customer demand and an oversupplied market for distillates in certain areas in which we operate. Lower fuel volume accounted for $5.3 million of the decline.

•

Lubricant margins were $0.15 per gallon lower contributing $2.2 million of the decline.

Direct distribution expenses in fiscal year 2010 declined $5.8 million compared to fiscal year 2009 reflecting the decline in gallons delivered. Warehouse and logistic compensation, facilities expense, depreciation and other vehicle expenses increased $3.4 million in fiscal 2010 compared to fiscal 2009 primarily due to new infrastructure required to service our E&P customers in the Marcellus Shale.

Selling, General and Administrative Expenses. SG&A expenses were $30.6 million, an increase of $3.9 million, or 14.6%, in fiscal year 2010 compared to fiscal year 2009. The following table provides a summary of SG&A expenses (in thousands):


	Year Ended June 30,
	2010		2009		Change
Expenses incurred by operations	$	18,226	$	18,419	$	(193	)
Corporate overhead allocation		8,126		6,485		1,641
Business transformation expense		4,276		1,818		2,458

Total SG&A	$	30,628	$	26,722	$	3,906

Expenses incurred by operations decreased $0.2 million in fiscal 2010 compared to 2009. Compensation expense decreased $1.3 million due to lower bonus expense and staff reductions, which was partially offset by a $0.6 million acceleration in the amortization of intangible assets of trade names. The allocation of corporate overhead increased in 2010 due to expenses incurred in building the corporate staff and moving into a new office in Greenwich, Connecticut. The business transformation project was launched in May 2009; accordingly, fiscal year 2010 was the first full year of expenses related to the project.

Operating Income. For the foregoing reasons, operating income for fiscal year 2010 was $3.8 million, a decrease of $27.3 million compared to fiscal year 2009.

Interest Expense. Interest expense allocated by Maxum Petroleum for fiscal year 2010 was $13.1 million compared to $10.9 million allocated for fiscal year 2009. This increase was primarily due to the increased percentage allocated to our operations, from 33% to 38% as our operations represented a higher percentage of Maxum Petroleum’s capital employed in 2010 than in 2009.

Income Tax Benefit. The income tax benefit for fiscal year 2010 was $3.2 million, reflecting an effective tax rate of 36.6% compared to an effective rate of 38.6% for fiscal year 2009.

Net Loss. For the reasons described above, our net loss for fiscal year 2010 was $5.5 million, $17.9 million lower than the net income recorded for fiscal year 2009.

Adjusted EBITDA. Adjusted EBITDA for fiscal year 2010 was $22.0 million, a decrease of $23.8 million, or 52.0%, compared to fiscal year 2009. As explained above, operating income decreased $27.3 million in 2010 compared to 2009. Operating income for 2010 includes higher business transformation expenses of $2.5 million, higher depreciation and amortization expenses of $0.5 million, lower unrealized gains on derivatives of $0.4 million and lower severance expenses of $0.4 million. These items are excluded from the calculation of Adjusted EBITDA.

Liquidity and Capital Resources

Cash Flow Summary

Our cash flows from operating, investing and financing activities, as reported in our combined financial statements, included elsewhere in this prospectus, are summarized as follows (in thousands):


	Year Ended June 30,									Six Months Ended December 31,
	2011			2010			2009			2011			2010
										(unaudited)
Net cash provided by (used in):
Operating activities	$	(37,393	)	$	(42,097	)	$	101,051		$	(61,402	)	$	(7,611	)
Investing activities		(28,465	)		(11,124	)		(21,840	)		(15,619	)		(8,007	)
Financing activities		66,300			52,991			(81,505	)		76,878			15,849

Operating Activities.

Working capital has a significant impact on the amount of cash we generate or use in our operating activities. We generally provide our fuel customers payment terms ranging from 10 to 30 days, whereas our fuel vendors generally require payment on purchases within 10 days. Accordingly, volume changes and changes in fuel prices can cause significant swings in accounts receivable that are not fully offset by corresponding changes in accounts payable as illustrated in the following table (in thousands):


	Years Ended June 30,									Six Months Ended December 31,
	2011			2010			2009			2011		2010
										(unaudited)
Changes in accounts receivable	$	60,723		$	51,918		$	(93,853	)	$	59,712	$	24,561
Changes in accounts payable		(4,529	)		(10,000	)		18,728			5,237		582

Net increase (decrease) in working capital	$	56,194		$	41,918		$	(75,125	)	$	64,949	$	25,143

During the six months ended December 31, 2011, cash flow used by operations totaled $61.4 million. An increased investment in working capital consumed $71.9 million, of which $64.9 million was attributable to the net impact of accounts receivable and accounts payable and the balance of which was attributable primarily to a change in inventory. During the six months ended December 31, 2010, working capital increased $18.1 million and operations used cash of $7.6 million. During both six-month periods the increases in working capital are primarily the results of higher selling prices and increased volumes reflected in accounts receivable that are not offset by corresponding increases in accounts payable.

Operations used cash of $37.4 million during fiscal year 2011. An increased investment of $56.0 million in working capital was the primary cause of this consumption of cash. The increase in working capital was primarily the result of higher selling prices and increased volumes reflected in accounts receivable that were not offset by corresponding increases in accounts payable.

Operations used cash of $42.1 million during fiscal year 2010. An increased investment of $50.0 million in working capital was the primary cause of this consumption of cash. At the end of fiscal year 2009, the decrease in our accounts receivable reflected the significant drop in drilling activity that occurred during the last quarter of that year. By the end of fiscal year 2010, drilling activity had increased and our accounts receivable increased significantly without a corresponding increase in accounts payable.

In fiscal year 2009, we generated $101.1 million of cash from operations. In fiscal year 2009 working capital was reduced by $67.9 million. The reduction in working capital was primarily due to lower accounts receivable that reflected lower selling prices and significantly lower volume.

Investing Activities.

We invested $16.3 million in new equipment during the six months ended December 31, 2011 compared to $8.4 million invested during the six months ended December 31, 2010.

We invested $23.5 million in new property and equipment in fiscal year 2011, compared to $13.2 million in fiscal year 2010 and $10.3 million in fiscal year 2009. This new property and equipment consisted primarily of trucks, storage facilities and other equipment.

We paid $5.1 million for the acquisition of DeCristo, Inc. in fiscal year 2011 and $8.6 million for the acquisition of Mid-State Industrial Lubricants Co. in fiscal year 2010.

Investing activities for fiscal year 2010 included a $10.4 million reduction in restricted cash related to margin requirements on accounts with securities firms used to purchase derivatives contracts in connection with customer fuel sale contracts. For fiscal year 2009, investing activities included an increase in restricted cash of $10.7 million.

Financing Activities.

Net cash provided by (used in) financing activities was provided by or provided to Maxum Petroleum. Maxum Petroleum uses a centralized approach to cash management whereby all of our cash receipts and cash disbursements are processed through Maxum Petroleum’s cash accounts.

Capital Resources

Historically, our sources of liquidity included cash generated from operations and funding provided by Maxum Petroleum. Following this offering, we will have separate bank accounts, but Maxum Petroleum will provide treasury services on our general partner’s behalf under our omnibus agreement. Our principal liquidity requirements are to finance our operations, fund capital expenditures and acquisitions and make cash distributions.

In addition to the retention of a portion of the net proceeds from this offering for working capital and capital expenditure needs, we expect our ongoing sources of liquidity following this offering to include cash generated from operations and borrowings under our revolving credit facility. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions. However, we are subject to business and operational risks that could adversely affect our cash flow and access to borrowings under our revolving credit facility. Increases or decreases in the value of our assets will increase or decrease our borrowing base, respectively.

We anticipate capital spending of $28.7 million and $21.6 million for the twelve months ending December 31, 2012 and fiscal year 2013, respectively, of which approximately $10.4 million and $10.5 million, respectively, will be maintenance capital expenditures and $18.3 million and $11.1 million, respectively, will be expansion capital expenditures. There can be no assurance that we will actually make such expenditures in the next twelve months or that such expenditures will result in our maintaining or increasing profits or expanding our business.

Distributions

We intend to pay a quarterly distribution at an initial rate of $ per unit, which equates to an aggregate distribution of approximately $ million per quarter, or approximately $ million on an annualized basis, based on the number of common, subordinated and general partner units anticipated to be outstanding immediately after the closing of this offering. We do not have a legal obligation to make distributions except as provided in our partnership agreement. Please read “Our Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Revolving Credit Facility

Upon the completion of this offering, we expect to enter into a $ million senior secured revolving credit agreement. We do not expect to have any borrowings outstanding under our revolving credit facility at the completion of this offering.

Contractual Obligations

The following table provides a summary of our significant contractual obligations at June 30, 2011 (in thousands):


	Payments by Year Ended June 30,										Thereafter		Total
	2012		2013		2014		2015		2016		Thereafter		Total
Operating leases	$	2,942	$	2,440	$	2,377	$	2,307	$	2,193	$	16,774	$	29,033

As described in Note 15 to our audited combined financial statements included elsewhere in this prospectus, we lease equipment and office and warehouse facilities under non-cancellable operating leases with remaining terms which extend to 17 years. Certain of these leases contain escalation and renewal options. We also lease certain vehicles and other equipment for terms extending to two years.

Critical Accounting Policies and Estimates

Use of Estimates

The preparation of the combined financial statements in conformity with accounting principles generally accepted in the United States requires management to make assumptions and estimates that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the periods presented. Estimates are used for, but not limited to, the allowance for doubtful accounts, depreciation and amortization, goodwill valuation, valuation of intangible assets and other long-lived assets, valuation of derivative instruments, income taxes, and other contingencies. Changes in the facts and circumstances may result in revised estimates and actual results could differ from these estimates.

Revenue Recognition

We recognize revenue when there is persuasive evidence of an arrangement between us and the customer, products have been delivered to the customer or services rendered, pricing is fixed or determinable and collection is reasonably assured.

When we are the primary obligor in the sales arrangements with our customers and bear credit and inventory risk, we record revenue on a gross basis. When we act solely as delivery agent for lubricants being sold by a producer, revenue is recorded on a net basis.

We record estimated reductions to revenue for customer rebate programs based on historical experience and estimated revenue levels.

Sales and excise taxes collected from customers and remitted to governmental authorities are presented on a net basis in the combined statements of operations.

Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and are stated at the amount reasonably expected to be collected. Credit is extended to customers based on an evaluation of each customer’s financial condition and terms generally require payment within 30 days of delivery. We evaluate the collectability of accounts receivable and determines the appropriate reserve for doubtful accounts based on a combination of factors. Accounts are generally reserved if they are past due over a specified period of time or have been referred to outside parties for collection. In addition, management will provide a reserve if it is aware of a specific customer’s inability to pay amounts due. Account balances are written off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Property and Equipment

Property and equipment are carried at historical cost less accumulated depreciation. Costs, including complete asset replacements and enhancements or upgrades that increase the original efficiency, productivity or capacity of property and equipment are capitalized. Ordinary maintenance and repairs are expensed as incurred, whereas betterments are capitalized.

Depreciation expense for financial reporting purposes is computed on a straight-line basis over the estimate useful lives of the assets or, for leasehold improvements, over the term of the lease, if shorter. Accelerated methods of depreciation are used for income tax purposes. Depreciation expense is included in distribution expenses.

Goodwill

Goodwill is recorded when the consideration paid for an acquisition exceeds the fair value of the net tangible and identifiable intangible assets acquired. We perform an impairment test of its goodwill annually, or whenever events or changes in circumstances indicate that the carrying amount may not be fully recoverable. Impairment of goodwill is evaluated at a reporting unit level. In performing the impairment test, we estimate the fair value of each of its reporting units by determining the present values of expected cash flows. The estimated fair value of each reporting unit is then compared to its carrying value. If the carrying value exceeds the fair value of the reporting unit, we compare the implied fair value of the affected reporting unit’s goodwill with the carrying value of that goodwill. The annual impairment test is performed using an income approach to estimate the fair value of each of its reporting units, discounting future cash flows with an assumed cost of capital.

Derivative Instruments

We have used exchange-traded futures contracts to hedge the price risk associated with diesel fuel inventories that are expected to be held for more than a few days. We, at times, designated such derivatives as fair value hedges; accordingly, when these derivatives are designated for fair value hedging, the related inventory is recorded at fair market value. We do not currently have any such inventories or contracts.

All derivatives are recognized as assets or liabilities in the combined balance sheets at fair value. Changes in the fair value of derivatives are reported in earnings in the statements of operations. Unrealized and realized gains and losses on customer contracts, which are not designated for hedge accounting, are reported in revenues in the combined statement of operations. Unrealized and realized gains and losses on inventory hedges, which are designated as fair value hedges, are recorded in cost of sales in the combined statement of operations, along with an offsetting gain or loss resulting from the mark-to-market adjustment of the hedged diesel fuel inventory.

To qualify for fair value hedge accounting, the hedging relationship between the hedging instruments and hedged items must be highly effective over an extended period of time in achieving the offset of changes in fair values attributable to the hedged risk at the inception of the hedge and on an ongoing basis. If it is determined that a derivative is not or has ceased to be highly effective as a hedge, we discontinue hedge accounting prospectively.

We have not elected to offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash arising from derivative instruments recognized at fair value executed with the same counterparty under a master netting arrangement.

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Recent Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance for “Improving Disclosures about Fair Value Measurements.” This guidance clarified existing guidance for disclosures about inputs and valuation techniques used in estimating fair value measurements, requires additional disclosures for significant transfers in and out of Levels 1 and 2, and requires a reconciliation of Level 3 activity to be presented on a gross basis. We adopted this guidance on July 1, 2010, and it did not have an effect on its combined financial statements, other than additional disclosures.

In May 2011, the FASB issued guidance titled “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” to improve the comparability of fair value measurements presented and disclosed in financial statements. This guidance amends the application of the “highest and best use” concept to be used only in the measurement of fair value of nonfinancial assets, clarifies that the measurement of the fair value of equity-classified financial instruments should be performed from the perspective of a market participant who holds the instruments as an asset, clarifies that an entity that manages a group of financial assets and liabilities on the basis of its net risk exposure can measure those financial instruments on the basis of its net exposure to those risks, and clarifies when premiums and discounts should be taken into account when measuring fair value. The fair value disclosure requirements also were amended. We adopted this guidance in fiscal year 2012, and it had no effect on its combined financial statements, other than additional disclosures.

In August 2011, the FASB guidance titled “Testing Goodwill for Impairment” which simplifies how entities test goodwill for impairment. Under this amended guidance, entities have the option to qualitatively assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an entity elects to perform the qualitative assessment and determines that it is not more likely than not that the reporting unit’s fair value is less than its carrying amount, no further evaluation would be necessary. This guidance will be effective for us in fiscal year 2013. We are in the process of evaluating the impact the amended guidance will have on its combined financial statements.

In December 2011, the FASB issued guidance which requires a company to disclose information about financial instruments that have been offset and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. This guidance will require us to provide both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset. This guidance is effective at the beginning of our 2013 fiscal year and will be applied retrospectively. We are in the process of evaluating the impact of this guidance on its combined financial statements.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

Seasonality

We do not experience significant seasonality of demand.

Effects of Inflation

We do not currently experience significant effects of inflation. However, if we were to experience a significant or steady increase in fuel prices as a result of inflation, it could increase our working capital requirements.

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Quantitative and Qualitative Disclosures about Market Risk

We are exposed to financial market risks associated with commodity prices. We manage a portion of the risk associated with commodity process using derivative financial and commodity instruments. We do not use derivative instruments for trading purposes.

Commodity Price Risk

We are subject to volatility in the cost of our products as a result of the market risk associated with the price of oil. We manage our exposure to this risk primarily through pricing agreements with our customers which enable us to raise prices if index prices increase. We offer sales programs with price risk management features, such as caps, floors and graduated discounts. We mitigate our exposure to commodity prices from these programs using derivative contracts. We are subject to basis risk, which is the risk that the change in the cash price of the commodity being hedged will not be completely offset by an equal and opposite change in the value of the hedging instrument. We have also used exchange-traded futures contracts to hedge the price risk associated with diesel fuel inventories that are expected to be held for more than a few days, although we do not currently have any such inventories or contracts.

The table below provides a summary of our commodity-related derivative instruments as of June 30, 2011 (in thousands):


Derivative Instrument	Settlement Period	Gallons		Asset Value
Futures	August 2011		714	$	9
Futures	August 2011		168		1
Options	September 2011		1,260		494
Options	June 2012		20,244		2,370
Swaps	January 2012		5,208		3,178
Swaps	December 2011		1,260		789

			28,854	$	6,841

The table below provides a summary of our commodity-related derivative instruments as of December 31, 2011 (in thousands):


Derivative Instrument	Settlement Period	Gallons		Asset (Liability) Value
Swaps	January 2012		798	$	423
Swaps	August 2012		3,360		(77	)
Swaps	September 2012		14,220		(353	)
Swaps	August 2012		—		44

			18,378	$	37

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INDUSTRY

The refined petroleum marketing and distribution industry consists primarily of (1) the marketing and distribution of fuels and lubricants and (2) the provision of value-added procurement and logistics services to a variety of end users, primarily in industrial and commercial applications. We serve consumers of diesel, lubricants and these services in the E&P and coal mining industries, where recent trends have encouraged production companies to outsource other important functions, such as fuel procurement, to third-party logistics suppliers. Moreover, large oil companies who supply the production companies have increasingly transferred their marketing and distribution business to third-party logistics providers. These trends have increased the size and scope of the refined petroleum marketing and distribution industry and help drive industry demand.

Refined Petroleum Marketing and Distribution Industry

Independent fuel distributors purchase products from refiners or other distributors and then resell them to fixed retail outlets, end users or other distributors. The refined petroleum marketing and distribution industry is a large and highly fragmented industry composed of approximately 6,880 domestic fuel marketers and distributors with annual aggregate revenues of approximately $750 billion, according to Petroleum Trends International, Inc. Approximately 5,400 domestic operators, or 78%, are relatively small and distribute less than 30 million gallons a year, as indicated in the chart below.

Number and Size of Independent Fuel Distributors in U.S. Market

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Source: Petroleum Trends International, Inc. (2007)

Fuel

Distillate fuel oils consist primarily of diesel, which is the primary product consumed in the commercial and industrial segment. Most of the distillate fuel sold to end users in the United States is sold by petroleum marketers and distributors and the major oil companies. According to the EIA, U.S. consumption of distillate fuel oil increased from an average 2.9 million barrels per day in 1991 to an average 3.6 million barrels per day in 2009. Continuing economic growth and global industrialization are expected to drive increased demand for distillate fuel, since it is the primary fuel used in transportation and various commercial and industrial applications. The EIA reports that domestic consumption of distillate fuel oil averaged 3.8 million barrels per day in 2010 and 2011 and is projected to increase to an average 4.4 million barrels per day by 2035.

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The chart below shows the historical growth in the consumption of distillate fuel oil in the United States.

U.S. Distillate Fuel Oil Consumption (MMBbl/d)

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Source: U.S. Energy Information Administration

Lubricants

Lubricants are oils and greases manufactured from refined petroleum products that are used to reduce friction, remove heat and minimize wear between moving parts or solid surfaces. Lubricants are critical to the specialized equipment used by our customers, such as engines, gear boxes, hydraulic systems and bearings and play a critical role in minimizing downtime, ensuring reliability and maximizing equipment life and productivity. Lubricant distributors in the United States primarily serve commercial and industrial users, automotive motor oil suppliers and original equipment manufacturers. Lubricants are becoming increasingly important due to the increased use of specialized equipment in industrialized manufacturing applications that are expected to drive continued growth in demand.

The chart below shows the projected growth in the sales of lubricants in the United States.

U.S. Lubricant Sales (gallons in billions)

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Source: Kline & Company (2010)

Outsourcing Trends

As companies increasingly focus on their core business, they have tended to outsource their procurement and logistics processes. This trend has given rise to the increased integration of third-party logistics providers in the operations of their customers and suppliers. For major oil companies, this has meant focusing more on upstream (exploration for and production of crude oil and natural gas) and less on downstream (refining, marketing and distribution) activities. For our E&P and coal mining customers, this has meant focusing directly on the drilling and production of oil and natural gas or the mining of coal and hiring third-parties to provide necessary on-site services that are separate from their core activities.

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We believe that refiners and lubricant manufacturers will become increasingly selective with regard to their distribution partners. Refiners and lubricant manufacturers increasingly view their relationship with distribution partners as an extension of their brand and logistics networks and not merely as an avenue to resell their products to end users. Distributors with better access to capital, broad product and service offerings and large networks, like we offer, are likely to have strong relationships with suppliers.

Specialization Among Larger Distributors

The basic delivery of fuel to retail outlets via a local distribution network generally entails the use of tanker trucks and semi-trucks suitable for delivery in easily accessible locations. This method is the most common business model in the industry. The ease of access to this type of equipment contributes to the large number of small-scale fuel distributors and the highly competitive dynamics of our industry. More specialized activities like remote delivery, environmentally sensitive location access, fuel management programs, equipment monitoring, and maintenance and environmental services require more specialized systems and equipment. Higher safety requirements and employee training standards also differentiate operators engaged in large-scale commercial distribution from the smaller-scale fuel distributors.

Our Customers’ Industries: E&P and Coal

We focus our efforts on distributing refined petroleum products, primarily diesel fuel and lubricants as well as limited amounts of gasoline, and providing value-added services to customers engaged in the E&P and coal mining industries. Approximately 86% of our revenues for the twelve months ended December 31, 2011 were to customers in these markets. Within the E&P industry, we have three major customer groups: (i) E&P companies that hold drilling rights for oil and natural gas who purchase our fuel and services to operate rigs; (ii) drilling contractors providing services to E&P companies who purchase our lubricants and services; and (iii) well completion companies providing hydraulic fracturing services for unconventional oil and natural gas wells who purchase our fuel, lubricants and services.

U.S. E&P Industry: Increased Drilling in Oil and Liquids-Rich Formations

Drilling activity in the United States, which we measure by rig count and well completion activity, drives the demand for the products and services we sell to our E&P customers. Total U.S. rig count has increased over the last three years. The Baker Hughes rig count indicates that there has been an increase in total land-based oil and natural gas rigs operating in the continental United States, growing from an average of 1,712 rigs in fiscal year 2011 to 1,979 rigs in fiscal year 2012 through April 24, 2012, an increase of 16%. This growth was led by an increase in active oil rigs from an average of 774 oil rigs in fiscal year 2011 to an average of 1,160 oil rigs in fiscal year 2012 through April 24, 2012, an increase of 50%. Further, hydraulic fracturing services are increasingly being deployed in traditionally oil-focused basins. According to Spears & Associates, the number of horizontal wells drilled grew from 6,800 in 2009 to 16,000 in 2011 and is estimated to grow to 18,400 in 2012. Although recent prices for natural gas are at historic lows, the decrease in natural gas drilling activity has been offset by increased drilling activity in oil and liquids-rich formations in North America, such as the Bakken, Eagle Ford Shale, Permian Basin and Utica Shale. Although the E&P industry is cyclical and oil prices are at historically high levels and remain volatile, we believe that many of the oil and liquids-rich plays are economically attractive even at oil prices substantially below the current prevailing market prices, which would support continued drilling activity even if oil prices decline. The EIA is projecting average onshore oil production in the continental U.S. to grow from 3.8 MMbl/d in 2011 to 4.2 MMbl/d in 2012, further increasing to 4.4 MMbl/d in 2013, an increase of 16% from 2011. While the number of drilling rigs supporting onshore natural gas production in the continental United States is declining, the EIA is projecting average natural gas production to grow from 60.2 Bcf/d in 2011 to 63.8 Bcf/d in 2012, and holding at that level in 2013, an increase of 6%.

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The following chart tracks total rig count and illustrates the offset caused by the recent increase in the overall oil rig count as compared to the decline in the overall natural gas rig count.

Oil Rig Count vs. Natural Gas Rig Count

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Source: Baker Hughes Rig Count.

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The following diagram is based on a database compiled by Schlumberger, the world’s largest oilfield services company. The data illustrates the year-over-year change in oil and natural gas rig count by play, depicting increased drilling activity in liquids-rich basins. We operate or have facilities in all of these plays. Many of these plays, including the Bakken, Niobrara, Marcellus and Eagle Ford, are located in challenging environments or remote regions, some of which we already serve with our specialized equipment using our existing facilities in nearby areas.

Rig Migration—Last Twelve Months Ended December 31, 2011

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Company map and analysis, based on Smith Bits, Schlumberger Limited data.

U.S. E&P Industry: Ongoing Development of Existing and Emerging Unconventional Resources

A recent phenomenon that has increased the demand for our products and services and has driven growth in the E&P industry has been the development of unconventional oil and natural gas-rich fields in the United States, often in remote or environmentally sensitive locations that have little infrastructure to support delivery of diesel fuel or lubricants. Unconventional oil and natural gas production, exemplified by the shift to horizontal drilling from vertical drilling and the use of hydraulic fracture stimulation, generally requires a greater amount of fuel and lubricants than conventional oil and natural gas activities due to the increase in total footage drilled and the higher service intensity required by the rigs and hydraulic fracturing fleets. For example, current trends in horizontal drilling involve longer laterals, more hydraulic fracturing stages and pad drilling, all of which requires more continuous runtime of equipment and well completion services.

We expect that, as E&P operators continue to develop unconventional oil and natural gas resources, employ more horizontal rigs, and conduct larger and more highly coordinated hydraulic fracture jobs, demand for fuel and lubricants will continue to grow. E&P operators often limit their fuel provider relationships to a select

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few distributors in a given geographic territory. Due to the capital intensity of operations in unconventional reservoirs, the cost of downtime on these projects is significant. Consequently, E&P operators place a large premium on quality and reliability and tend to do business with distributors who can provide safe and reliable service on short notice.

The following chart illustrates this recent trend in drilling activity in the United States, depicting an increasing amount of the number of wells and total footage drilled, both of which are indicators of the increase in overall demand for our products and services.

Wells and Footage Drilled

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Source: Spears & Associates (2012).

U.S. Coal Industry

Similar to E&P operators, large coal mining operators rely increasingly on third-party logistics providers for products and services that are necessary to the operation of their core business. Coal mining customers’ demand for the products and services offered by these third-party providers is driven by domestic coal production.

According to the EIA, the United States is home to approximately 27.5% of worldwide recoverable reserves, the largest amount of recoverable reserves of coal in the world. The U.S. Department of Energy estimates that current domestic recoverable coal reserves could supply enough electricity to satisfy domestic demand for approximately 200 years. Although annual coal production in the United States has increased from 613 million short tons per year in 1970 to 1.1 billion short tons per year in 2010, coal production has generally declined in recent periods. For example, according to the EIA, the amount of electricity in the United States generated by coal-fired power plants decreased from 50% in December 2008 to 41% in December 2011.

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The following chart illustrates U.S. coal production (million short tons per year) as reported by the EIA.

U.S. Coal Production, 1970-2010

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Source: U.S. Energy Information Administration.

While overall U.S. coal production has increased since 1970, since 2007, total U.S. coal production has declined and coal production in the Central Appalachian region, which is the second largest coal basin in the United States after the Powder River Basin (based on production) and is the area in which substantially all of our coal mining customers are located, has been declining and is expected to continue to decline due primarily to production challenges, reserve degradation, and difficulties acquiring permits needed to conduct mining operations. In addition, underground mining operations have become subject to additional, more costly and stringent safety regulations, which have had the effect of increasing their operating costs and capital expenditure requirements. Central Appalachian coal production (including both thermal and metallurgical coal) has declined approximately 29% from 261 million tons in 2000 to 186 million tons in 2010, according to the EIA. From 2008 to 2011, metallurgical coal production from the Central Appalachian region has increased from 46.5 million tons to 53.7 million tons. Substantially all of our coal mining customers are located in the Central Appalachian region.

Approximately 90% of overall domestic coal production is consumed within the United States, where coal is used primarily by power plants to generate electricity, by steel companies to produce coke for use in blast furnaces and by a variety of industrial users to treat power foundries, cement plants, paper mills, chemical plants and other manufacturing or processing facilities. As of January 2012, the EIA projected that domestic consumption of coal will grow at approximately 0.4% per year through 2035 as shown in the following table:


									Annual Growth 2010-2035
	Actual 2010		Projected 2012		Forecast
Sector	Actual 2010		Projected 2012		2020		2035
Electric Power		976		906		918		1,021		0.2	%
Other Industrial		51		47		49		48		(0.2	%)
Coke Plants		21		23		20		16		(1.1	%)
Residential / Commercial		3		3		3		3		0.0	%
Coal-to-Liquids		—		—		25		68		N/A

Total U.S. Coal Consumption		1,051		979		1,014		1,156		0.4	%

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Although the export market is small on a relative basis, recently the domestic coal market has benefited from meaningful growth in exports. Demand for coal has been supported by recovering global economies and continued growth in the Chinese and Indian steel markets, in particular. According to the EIA, exports of U.S. coal grew from 81 million tons in 2010 to 107 million tons in 2011. In addition, metallurgical coal, which is used by steel companies to produce metallurgical coke for use in the steel making process and is produced in the United States mostly from the Central Appalachian region that we serve, is exported at a higher rate than other types of coal mined in other areas of the United States. We expect these trends to continue as demand for U.S. coal increases, and coal companies continue to invest in additional infrastructure necessary to facilitate continued growth in exports.

The following chart illustrates U.S. coal exports (million short tons) from 2000 through 2011 as reported by the EIA.

U.S. Coal Exports, 2000-2011

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Source: U.S. Energy Information Administration.

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BUSINESS

Overview

Maxum Energy Logistics Partners, LP S-1