S-1 1 d548532ds1.htm FORM S-1 Form S-1
Table of Contents

As filed with the Securities and Exchange Commission on June 14, 2013

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

OCI Partners LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   2800   90-0936556
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)

 

  Mailing Address:   Physical Address:  
 

P.O. Box 1647

Nederland, Texas 77627

 

5470 N. Twin City Highway

Nederland, Texas 77627

 
(409) 723-1900

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

 

 

Frank Bakker

President and Chief Executive Officer

 

  Mailing Address:   Physical Address:  
 

P.O. Box 1647

Nederland, Texas 77627

 

5470 N. Twin City Highway

Nederland, Texas 77627

 
(409) 723-1900

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

 

 

With a copy to:

 

Brett E. Braden
Divakar Gupta
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400
 

G. Michael O’Leary

Stephanie C. Beauvais

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200

 

 

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, please 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.

 

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

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

  Proposed Maximum
Aggregate Offering
Price(1)
  Amount of
Registration Fee

Common units representing limited partner interests

  $480,000,000   $65,472

 

 

 

(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933.

 

 

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.

 

 

 


Table of Contents

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

Preliminary Prospectus dated June 14, 2013

PROSPECTUS

 

LOGO

                    Common Units

Representing Limited Partner Interests

OCI Partners LP

 

 

This is the initial public offering of common units representing limited partner interests of OCI Partners LP. We are offering              common units in this offering.

Prior to this offering, there has been no public market for our common units. We currently expect the initial public offering price will be between $             and $             per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “OCIP.”

We qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933 and, as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. Furthermore, as long as we remain an emerging growth company, we will qualify for certain limited exceptions from investor protection laws such as the Sarbanes-Oxley Act of 2002 and the Investor Protection and Securities Reform Act of 2010. Please read “Prospectus Summary—Our Emerging Growth Company Status.”

 

 

 

Investing in our common units involves a high degree of risk. Before purchasing any of our common units, you should carefully read the discussion of material risks of investing in our common units in “Risk Factors” beginning on page 21. These risks include the following:

 

 

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

 

 

The amount of our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly cash distributions over time.

 

 

For each of the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, we would not have generated sufficient cash available for distribution to have paid the per unit quarterly distribution that we project that we will be able to pay for the twelve months ending June 30, 2014.

 

 

We have a limited operating history. As a result, you may have difficulty evaluating our ability to pay quarterly cash distributions to our unitholders or our ability to be successful in implementing our business strategy.

 

 

Our gross profit is vulnerable to fluctuations in the prices at which we sell methanol and ammonia and the cost of natural gas, our primary feedstock.

 

 

Our facility faces operating hazards and interruptions, including unscheduled maintenance or downtime. We could face significant reductions in revenues and increases in expenses to the extent these hazards or interruptions cause a material decline in production and are not fully covered by our existing insurance coverage.

 

 

Our general partner and its affiliates, including our sponsor, 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 that of our unitholders.

 

 

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

 

 

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 state securities commission 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, before expenses, to OCI Partners LP

   $         $     
  (1) Excludes an aggregate structuring fee equal to            % of the gross proceeds from this offering payable to Merrill Lynch, Pierce, Fenner & Smith Incorporated. Please read “Underwriting.”

We have granted the underwriters an option to purchase up to an additional            common units from us at the initial public offering price, less the underwriting discount, within 30 days from the date of this prospectus.

The underwriters expect to deliver the common units to purchasers on or about            , 2013 through the book-entry facilities of the Depository Trust Company.

 

 

 

BofA Merrill Lynch   Barclays                   Citigroup

 

 

The date of this prospectus is                     , 2013.


Table of Contents

 

LOGO

 

LOGO


Table of Contents

TABLE OF CONTENTS

 

    

Page

 

PROSPECTUS SUMMARY

     1   

Overview

     1   

Our Competitive Strengths

     3   

Our Business Strategies

     4   

Our Sponsor

     6   

Our Facility

     6   

Our Debottlenecking Project

     7   

Feedstock Supply

     7   

Customers and Contracts

     7   

Our Emerging Growth Company Status

     8   

Risk Factors

     8   

The Transactions

     9   

Organizational Structure After the Transactions

     11   

Management of OCI Partners LP

     12   

Principal Executive Offices and Internet Address

     12   

Summary of Conflicts of Interest and Duties

     12   

The Offering

     13   

Summary Historical and Pro Forma Financial and Operating Data

     18   

RISK FACTORS

     21   

Risks Related to Our Business

     21   

Risks Inherent in an Investment in Us

     40   

Tax Risks

     45   

USE OF PROCEEDS

     49   

CAPITALIZATION

     50   

DILUTION

     52   

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     54   

General

     54   

Unaudited Pro Forma Cash Available for Distribution

     56   

Unaudited Forecasted Cash Available for Distribution

     58   

Assumptions and Considerations

     61   

HOW WE MAKE CASH DISTRIBUTIONS

     66   

General

     66   

Common Units Eligible for Distributions

     66   

Method of Distributions

     66   

General Partner Interest

     66   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     67   

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

     70   

Overview

     70   

Key Industry Factors

     71   

Key Operational Factors

     72   

How We Evaluate Our Operations

     73   

Factors Affecting Comparability of Financial Information

     73   

Results of Operations

     75   

Liquidity and Capital Resources

     80   

Cash Flows

     82   

Contractual Obligations

     84   

Off-Balance Sheet Arrangements

     85   

Critical Accounting Policies

     85   

Recent Accounting Pronouncements

     87   

Quantitative and Qualitative Disclosures About Market Risk

     87   

 

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Page

 

INDUSTRY OVERVIEW

     88   

Overview

     88   

Natural Gas Feedstock

     89   

Methanol

     93   

Ammonia

     98   

BUSINESS

     102   

Overview

     102   

Our Competitive Strengths

     103   

Our Business Strategies

     105   

Our Sponsor

     106   

Our Facility

     107   

Our Growth Projects

     110   

Feedstock Supply

     111   

Our Production Process

     112   

Customers and Contracts

     113   

Competition

     114   

Seasonality and Volatility

     114   

Environmental Matters

     115   

Safety, Health and Security Matters

     119   

Employees

     120   

Properties

     120   

Insurance

     120   

Legal Proceedings

     120   

MANAGEMENT

     121   

Management of OCI Partners LP

     121   

Director Independence

     121   

Committees of the Board of Directors

     122   

Directors and Executive Officers of OCI GP LLC

     122   

Board Leadership Structure

     124   

Board Role in Risk Oversight

     124   

Reimbursement of Expenses

     124   

Executive Compensation

     124   

2013 Long-Term Incentive Plan

     126   

Compensation of Our Directors

     128   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     129   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     131   

Distributions and Payments to OCI and Its Affiliates

     131   

Our Agreements with OCI

     131   

Other Transactions with Related Parties

     133   

Indemnification Agreements

     134   

Procedures for Review, Approval and Ratification of Related Person Transactions

     134   

CONFLICTS OF INTEREST AND DUTIES

     135   

Conflicts of Interest

     135   

Duties of the General Partner

     140   

DESCRIPTION OF OUR COMMON UNITS

     144   

Our Common Units

     144   

Transfer Agent and Registrar

     144   

Transfer of Common Units

     144   

Listing

     145   

THE PARTNERSHIP AGREEMENT

     146   

Organization and Duration

     146   

Purpose

     146   

Capital Contributions

     146   

 

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Page

 

Voting Rights

     146   

Limited Liability

     148   

Issuance of Additional Securities

     149   

Amendment of Our Partnership Agreement

     149   

Merger, Consolidation, Conversion, Sale or other Disposition of Assets

     151   

Termination and Dissolution

     152   

Liquidation and Distribution of Proceeds

     152   

Withdrawal or Removal of Our General Partner

     152   

Transfer of General Partner Interest

     153   

Transfer of Ownership Interests in Our General Partner

     154   

Change of Management Provisions

     154   

Limited Call Right

     154   

Non-Citizen Assignees; Redemption

     155   

Non-Taxpaying Assignees; Redemption

     155   

Meetings; Voting

     155   

Status as Limited Partner

     156   

Indemnification

     156   

Reimbursement of Expenses

     157   

Books and Reports

     157   

Right to Inspect Our Books and Records

     157   

Registration Rights

     158   

Exclusive Forum

     158   

COMMON UNITS ELIGIBLE FOR FUTURE SALE

     159   

Rule 144

     159   

Our Partnership Agreement and Registration Rights

     159   

Lock-Up Agreements

     160   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     161   

Partnership Status

     162   

Limited Partner Status

     163   

Tax Consequences of Common Unit Ownership

     163   

Tax Treatment of Operations

     169   

Disposition of Common Units

     171   

Uniformity of Common Units

     173   

Tax-Exempt Organizations and Other Investors

     174   

Administrative Matters

     175   

Recent Legislative Developments

     178   

State, Local, Foreign and Other Tax Considerations

     178   

INVESTMENT IN OCI PARTNERS LP BY EMPLOYEE BENEFIT PLANS

     180   

UNDERWRITING

     182   

Commissions and Discounts

     182   

Option to Purchase Additional Common Units

     183   

No Sales of Similar Securities

     183   

New York Stock Exchange Listing

     183   

Price Stabilization, Short Positions and Penalty Bids

     184   

Electronic Distribution

     185   

Conflicts of Interest

     185   

Other Relationships

     185   

Directed Unit Program

     185   

Selling Restrictions

     185   

LEGAL MATTERS

     188   

EXPERTS

     188   

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     188   

FORWARD-LOOKING STATEMENTS

     189   

 

iii


Table of Contents
    

Page

 

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A: FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF OCI PARTNERS LP

     A-1   

APPENDIX B: GLOSSARY OF SELECTED TERMS

     B-1   

 

 

You should rely only on the information contained in this prospectus or in any free writing prospectus that we authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with additional, different or inconsistent information from that contained in this prospectus and any free writing prospectus. If anyone provides you with additional, 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 not assume that the information contained in this prospectus or in any free writing prospectus is accurate as of any date other than the date on the front cover of this prospectus or the date of such free writing prospectus. Our business, financial condition, results of operations and prospects may have changed since such date.

For investors outside the United States: We have not, and the underwriters have not, done anything that would permit this offering, or possession or distribution of this prospectus, in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of the common units and the distribution of this prospectus outside of the United States.

 

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Industry and Market Data

When we make statements in this prospectus about our position in the methanol industry, the ammonia industry, any sector of those industries or about our market share, we are making those statements based on our belief as to their accuracy. This belief is based on data regarding the methanol industry and the ammonia industry, including trends in such markets and our position and the position of our competitors within those industries, derived from a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers, trade and business organizations and publicly available information (including the reports and other information our competitors file with the U.S. Securities and Exchange Commission (“SEC”), which we did not participate in preparing and as to which we make no representation), as well as our good faith estimates, which have been derived from management’s knowledge and experience in the areas in which our business operates. Estimates of market size and relative positions in a market are difficult to develop and inherently uncertain. Accordingly, investors should not place undue weight on the industry and market share data presented in this prospectus.

In this prospectus, we rely on and refer to information regarding the methanol industry and the ammonia industry and future methanol and ammonia production and consumption from Jim Jordan and Associates, LP (“Jim Jordan”), with respect to the methanol industry, and Blue, Johnson & Associates, Inc. (“Blue Johnson”), with respect to the ammonia industry. Neither Jim Jordan nor Blue Johnson is affiliated with us. Each of Jim Jordan and Blue Johnson has consented to being named in this prospectus.

We do not have any knowledge that the market and industry data and forecasts provided to us from third party sources are inaccurate in any material respect. However, we have been advised that certain information provided to us from third party sources is derived from estimates or subjective judgments, and while such third party sources have assured us that they have taken reasonable care in the compilation of such information and believe it to be accurate and correct, data compilation is subject to limited audit and validation procedures. We believe that, notwithstanding such qualification by such third party sources, the market and industry data provided in this prospectus is accurate in all material respects.

Our estimates, in particular as they relate to market share and our general expectations, involve risks and uncertainties and are subject to change based on various factors, including those discussed under the section entitled “Risk Factors.”

 

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors” and the historical and unaudited pro forma condensed financial statements and related notes included elsewhere in this prospectus, before making a decision to invest in our common units. Unless otherwise indicated, the information 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) that the underwriters do not exercise their option to purchase additional common units, and, accordingly, that the             common units that could be purchased by the underwriters pursuant to such option will instead be issued to OCI USA Inc. at the expiration of the option period.

Unless the context otherwise requires, references in this prospectus to “our partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to the business and operations of OCI Beaumont LLC, a Texas limited liability company (“OCIB”) that OCI USA Inc. will contribute to OCI Partners LP in connection with this offering. When used in the present tense or future tense, those terms and “OCI Partners LP” refer to OCI Partners LP, a Delaware limited partnership, and its subsidiaries, including OCIB. References to “our general partner” refer to OCI GP LLC, a Delaware limited liability company and a wholly owned subsidiary of OCI USA Inc. References to “OCI” refer to OCI N.V., a Dutch public limited liability company, and its consolidated subsidiaries other than us, our subsidiaries and our general partner. References to “OCI USA” refer to OCI USA Inc., a Delaware corporation, which is an indirect wholly owned subsidiary of OCI. References to “OCI Fertilizer” refer to OCI Fertilizer International B.V., a Dutch private limited liability company, which is an indirect wholly owned subsidiary of OCI. The transactions being entered into in connection with this offering that are described beginning on page 9 of this prospectus are referred to herein as the “Transactions.” You should also read the “Glossary of Selected Terms” contained in Appendix B for definitions of some of the terms we use to describe our business and industry and other terms used in this prospectus.

OCI Partners LP

Overview

We are a Delaware limited partnership formed in February 2013 to own and operate a recently upgraded, integrated methanol and ammonia production facility that is strategically located on the Texas Gulf Coast near Beaumont. We are currently the largest merchant methanol producer in the United States with an annual methanol production capacity of approximately 730,000 metric tons and an annual ammonia production capacity of approximately 265,000 metric tons, and we are in the early stages of a debottlenecking project that will increase our annual methanol production capacity by 25% to approximately 912,500 metric tons and our annual ammonia production capacity by 15% to approximately 305,000 metric tons. Given our advantageous access and connectivity to customers and attractively priced natural gas feedstock supplies, we believe that we are one of the lowest-cost producers of methanol and ammonia in our markets and intend to capitalize on our competitive position to maximize our cash flow. We believe that the prospects for our methanol and ammonia business will remain positive for the foreseeable future because of growing U.S. and global demand for methanol and ammonia, our continued access to attractively priced natural gas feedstock, the United States’ current position as a net importer of both methanol and ammonia and our competitive position in our markets.

Both methanol and ammonia are global commodities that are essential building blocks for numerous end-use products. Methanol is a liquid petrochemical that is used in a variety of industrial and energy-related applications. Methanol is used in industrial applications to produce adhesives used in manufacturing wood products, such as plywood, particle board and laminates, resins to treat paper and plastic products, paint and varnish removers, solvents for the textile industry and polyester fibers for clothing and carpeting. Methanol is also used outside of the United States as a direct fuel for automobile engines, as a fuel blended with gasoline and

 

 

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as an octane booster in reformulated gasoline. In the United States, ammonia is primarily used as a feedstock to produce nitrogen fertilizers, such as urea and ammonium sulfate, and is also directly applied to soil as a fertilizer. In addition, ammonia is widely used in industrial applications, particularly in the Texas Gulf Coast market, including in the production of plastics, synthetic fibers, resins and numerous other chemical compounds.

Natural gas, methanol and ammonia commodity market dynamics have contributed favorably to our profitability in four ways. First, increased natural gas production from shale formations in the United States has increased domestic supplies of natural gas, resulting in a relatively low natural gas price environment. Second, robust and increasing domestic and global demand for both methanol and ammonia has led to historically high prices for those commodities. Third, domestic methanol and ammonia production capacity is currently constrained, as the higher domestic natural gas price environment during the period from 1998 through 2007 prompted U.S. producers to shut down or relocate U.S. production facilities, which has resulted in significantly more domestic demand for methanol and ammonia than can be satisfied with domestic production and substantial reliance on foreign imports to meet domestic demand for methanol and ammonia. Consequently, approximately 82% of U.S. methanol demand and approximately 39% of U.S. ammonia demand during 2012 was met by imports according to Jim Jordan and Blue Johnson, respectively. Fourth, we and other domestic methanol and ammonia producers have been able to satisfy a growing portion of domestic demand as foreign natural gas-based producers, particularly in Trinidad, are experiencing declining methanol and ammonia production due to decreased natural gas production and declining natural gas reserves. The favorable pricing environment for our products driven by robust demand, together with attractive natural gas feedstock prices, has enabled us to realize significant profit margins since our facility began operating at full capacity in the fourth quarter of 2012.

We expect the current commodity market dynamics for our products and natural gas feedstock to continue for the foreseeable future. In addition, according to Jim Jordan, annual U.S. demand for methanol is forecasted to increase from approximately 6.0 million metric tons in 2012 to approximately 7.1 million metric tons by 2016, representing a compound annual growth rate of approximately 4.2%, while annual domestic production of methanol is expected to increase from approximately 1.1 million metric tons to approximately 5.1 million metric tons over this same period. Moreover, according to Blue Johnson, annual U.S. demand for ammonia is forecasted to increase from approximately 16.5 million metric tons in 2012 to approximately 17.5 million metric tons in 2016, representing a compound annual growth rate of approximately 1.5%, while annual domestic production of ammonia is expected to increase from approximately 10.1 million metric tons to approximately 11.7 million metric tons over this same period, which is expected to result in an annual production deficit of approximately 5.8 million metric tons in 2016. In addition, recent increases in domestic natural gas production levels from shale formations have resulted in a significant increase in the supply of natural gas, leading to a lower natural gas price environment in the United States compared to other regions. We expect this trend of relatively low natural gas prices in the United States to continue for the foreseeable future as a result of ongoing investment in the development of shale formations and related midstream infrastructure.

We acquired our facility (which had been idled by the previous owners since 2004) in May 2011, commenced an upgrade that was completed in July 2012 and began operating our facility at full capacity in the fourth quarter of 2012. Our newly renovated facility began ammonia production in December 2011 and began methanol production in July 2012 (with no significant methanol production until August 2012), with revenues first generated from ammonia sales in the first quarter of 2012 and from methanol sales in the third quarter of 2012. For the three months ended March 31, 2013, our net income and EBITDA, on a pro forma basis, were approximately $56.5 million and $65.2 million, respectively. Subject to certain assumptions, we expect our net income and EBITDA to be approximately $167.3 million and $201.8 million, respectively, for the twelve months ending June 30, 2014. For a reconciliation of EBITDA to net income and the assumptions used in our forecast of our net income and EBITDA for the twelve months ending June 30, 2014, please read “Selected Historical and Pro Forma Financial and Operating Data” and “Our Cash Distribution Policy and Restrictions on Distribution—Unaudited Forecasted Cash Available for Distribution.”

 

 

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Our Competitive Strengths

Attractively Priced Natural Gas for Methanol and Ammonia Production. Given our ready access to abundant domestic natural gas supplies and our relatively low natural gas feedstock costs compared to our overseas competitors, including Trinidadian producers, we believe that we are one of the lowest-cost producers of methanol and ammonia in our markets. For the three months ended March 31, 2013, natural gas feedstock represented approximately 59.1% of our total cost of goods sold (or approximately 85.0% of our variable cost of goods sold). The emergence of a U.S. “shale gas advantage” has led to an increase in the domestic production of natural gas, resulting in attractive domestic natural gas feedstock prices. In addition, continued robust demand for methanol and ammonia globally has resulted in a favorable pricing environment for our products. Since our facility began operating at full capacity in the fourth quarter of 2012, we have been able to compete effectively with higher-cost foreign producers and realize significant profit margins.

Favorable Market Fundamentals with Growing Demand for Our Products. Due to growing demand and constrained domestic production capacity for our products, we expect the fundamentals for the production and sale of methanol and ammonia in the United States to remain favorable for the foreseeable future.

 

   

According to Jim Jordan, annual global demand for methanol is forecasted to increase from 62.6 million metric tons in 2012 to 81.2 million metric tons in 2016, representing a compound annual growth rate of approximately 6.7%. Annual U.S. demand for methanol is forecasted to increase from 6.0 million metric tons to 7.1 million metric tons over this same period, representing a compound annual growth rate of approximately 4.2%. Over this same period, the United States is expected to remain a net importer of methanol, as Jim Jordan forecasts that annual domestic methanol production will increase to only 5.1 million metric tons by the end of 2016. We expect prices for methanol to remain favorable for the foreseeable future as global prices for methanol are highly correlated to the prices set by higher-cost, coal-based methanol producers in China.

 

   

According to Blue Johnson, annual global demand for ammonia is forecasted to increase from 166.0 million metric tons in 2012 to 182.0 million metric tons in 2016, representing a compound annual growth rate of approximately 2.3%. Annual U.S. demand for ammonia is forecasted to increase from 16.5 million metric tons to 17.5 million metric tons over this same period, representing a compound annual growth rate of approximately 1.5%. Over this same period, the United States is expected to remain a net importer of ammonia, as Blue Johnson forecasts that imports will comprise approximately 6.4 million metric tons of U.S. consumption in 2016. In addition, Blue Johnson forecasts that ammonia prices in the United States will remain elevated for the foreseeable future as a result of growing agricultural demand and continued strong industrial demand, particularly in the Texas Gulf Coast region.

As a result of growing demand and constrained production capacity in the United States, we expect that domestic producers of methanol and ammonia will continue to displace a portion of imported supplies for the foreseeable future because of the higher feedstock and transportation costs associated with foreign supplies.

Strategic Location on the Texas Gulf Coast with Access to Port and Pipeline Facilities. We are strategically located on the Texas Gulf Coast, which provides us advantageous access and connectivity to our existing and prospective customers and attractively priced natural gas feedstock supplies. Our facility is connected to established infrastructure and transportation facilities, including pipeline connections to adjacent customers and port access with dedicated methanol and ammonia export barge docks. We also have the flexibility to add rail and truck loading facilities to improve delivery options for our customers. We have connections to one major interstate and three major intrastate natural gas pipelines that provide us access to significantly more natural gas supply than our facility requires and flexibility in sourcing our natural gas

 

 

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feedstock. Our facility is located in close proximity to many of our major customers, which allows us to deliver our products to those customers at competitive prices and realize greater margins than overseas suppliers that are subject to significant costs associated with transporting product to our markets. In addition, we have direct pipeline connections to certain of our methanol and ammonia customers, which provides us a competitive advantage in supplying their methanol and ammonia requirements.

Recently Upgraded Production Facility that Operates Efficiently and Maximizes Returns. We completed an upgrade on the methanol and ammonia production units at our facility in 2012. From January 1, 2013 through May 31, 2013, our methanol production unit and our ammonia production unit each operated at over a 95% utilization rate relative to its nameplate capacity. As a means of further optimizing our production efficiencies, we are in the early stages of a debottlenecking project on our production facility that is expected to be completed in the second half of 2014 and increase our annual methanol production capacity by approximately 25% and our annual ammonia production capacity by approximately 15%. For information on our debottlenecking project, please read “—Our Debottlenecking Project.”

Advantageous Relationship with Our Sponsor, OCI. We expect to benefit from OCI’s commercial, operational and technical expertise. OCI is a global nitrogen-based fertilizer producer and engineering and construction contractor based in the Netherlands, with projects and investments across Europe, the United States, South America, the Middle East, North Africa and Central Asia. We expect to benefit from OCI’s expertise in strategic development, as OCI’s management team has successfully executed over $25 billion in acquisitions, divestments and greenfield projects in 15 countries in the past eight years. In June 2013, we entered into a procurement and construction contract with Orascom E&C, Inc., an indirect wholly owned construction subsidiary of OCI, for our debottlenecking project. OCI Construction Group’s technical expertise and experience with large-scale infrastructure and industrial projects were critical to the recent upgrade of our facility that was completed in 2012 and will be essential to the cost-effective implementation of our debottlenecking project.

Experienced Management and Operational Team. We are managed by an experienced and dedicated team of executives with a long history in the chemical industry. Our senior operational team has an average of 30 years of experience in the chemical industry and significant experience operating facilities such as ours. In fact, a majority of our operating management team ran our facility for many years under prior ownership. Our management team was responsible for developing and executing the recent upgrade of our facility and will be integral in the execution of our debottlenecking project and any future expansion projects.

Our Business Strategies

Distribute 100% of Our Cash Available for Distribution each Quarter. Upon the completion of this offering, the board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution that we generate each quarter to unitholders of record on a pro rata basis. We do not intend to maintain excess distribution coverage or retain funds in order to maintain stable quarterly distributions or fund future distributions. Unlike many publicly traded partnerships, our general partner will have a non-economic general partner interest and will have no incentive distribution rights. Therefore, all of our cash distributions will be made to our unitholders, in contrast to other publicly traded partnerships, some of which distribute up to 50% of their quarterly cash distributions in excess of specified levels to their general partner. Our structure is designed to maximize distributions to our unitholders and to align OCI’s interests with those of our other unitholders. We expect our distribution yield to be             % (calculated by dividing our forecasted distribution for the twelve months ending June 30, 2014 of $            per common unit by $            (the midpoint of the price range set forth on the cover page of this prospectus)). Please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Forecasted Cash Available for Distribution.”

 

 

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Pursue Organic Growth Opportunities and Strategic Acquisitions. We will continue to evaluate methods of expanding our production capabilities and product offerings. We are in the early stages of a debottlenecking project that is designed to increase our annual methanol production capacity by approximately 182,500 metric tons, or approximately 25%, and increase our annual ammonia production capacity by approximately 40,000 metric tons, or approximately 15%. As part of the debottlenecking project, we additionally plan to complete a maintenance turnaround as well as various other upgrades to our facility. We expect that the debottlenecking project will be completed in the second half of 2014 and currently estimate the total cost of the project will be approximately $150 million (including costs associated with a maintenance turnaround and various other upgrades). We intend to fund a portion of the costs of our debottlenecking project and other budgeted capital projects incurred after the completion of this offering with a portion of the net proceeds from this offering. Please read “—Our Debottlenecking Project.”

We also intend to pursue strategic acquisitions that offer attractive synergies and maximize distributions to our unitholders, such as increasing our logistical capabilities by purchasing infrastructure at the industrial park in which our production facility is located. In addition, we intend to evaluate and pursue acquisition and development opportunities that will enhance our operating platform and increase our cash available for distribution.

Maintain High Utilization Rates. From January 1, 2013 through May 31, 2013, we operated at over a 95% utilization rate relative to the nameplate capacity of our methanol and ammonia production units, and we intend to maintain consistent and reliable operations at our facility, which are critical to our financial performance and results of operations. Efficient production of methanol and ammonia requires reliable and stable operations at our facility due to the high costs associated with planned and unplanned downtime. In addition, strict production schedules are essential in order to maximize utilization and productivity and to ensure a competitive cost position. We intend to continue implementing our rigorous maintenance program, which is executed by a skilled, experienced and well-trained workforce, at regular intervals. To continue to maintain our high utilization rates and minimize downtime at our facility, we plan to perform maintenance capital projects that require downtime during scheduled turnarounds. We believe that our diligent adherence to proactive maintenance programs and the experience of our workforce will minimize unplanned downtime and maintain our facility’s longevity and high utilization rates.

Continue Commitment to Health, Safety and the Environment. We are committed to maintaining a culture that makes health, safety and the environment a high priority. We have made significant investments in safety analysis and reporting technology and have established a track record of safe operations, with a total case incident rate (the average number of work-related injuries incurred by 100 workers during a one-year period) for both our employees and contractors of 0.13 for 2012 and 0.0 from January 1, 2013 through May 31, 2013. We also view personnel training as essential for accident prevention and successful operation of our facility and intend to continue our efforts in these areas. In addition, we are participating in Occupational Safety and Health Act (“OSHA”) Voluntary Protection Programs to become an OSHA Star site. We believe that our commitment to health, safety and the environment is critical to the success of our business.

Maintain a Conservative and Flexible Capital Structure. We are committed to maintaining a conservative capital structure with prudent leverage that affords us the financial flexibility to execute our business strategy. As of March 31, 2013, on a pro forma basis, after giving effect to the Transactions (including this offering), we would have had approximately $235.0 million of total indebtedness (excluding unamortized debt discount of $2.4 million) and approximately $             million of cash and cash equivalents, resulting in net leverage of $             million (or approximately $235.0 million of total indebtedness (excluding unamortized debt discount of $2.4 million) and approximately $            million of cash and cash equivalents, resulting in net leverage of $            million, if the underwriters exercise their option to purchase additional common units in full). We will retain a portion of net proceeds from this offering to pre-fund growth capital expenditures,

 

 

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including the anticipated remaining costs of our debottlenecking project (including a maintenance turnaround and various other upgrades).

Our Sponsor

OCI is a global nitrogen-based fertilizer producer and engineering and construction contractor based in the Netherlands, with projects and investments across Europe, the United States, South America, the Middle East, North Africa and Central Asia. The OCI Fertilizer Group owns and operates nitrogen fertilizer plants in the Netherlands, the United States, Egypt and Algeria and has an international distribution platform spanning from the Americas to Asia. The OCI Fertilizer Group ranks among the world’s largest nitrogen fertilizer producers by production capacity with annual production capacity of nearly 7.0 million metric tons.

The OCI Fertilizer Group’s latest greenfield project, the Iowa Fertilizer Company located near the Mississippi River in Wever, Iowa, is a $1.8 billion plant that is the first world scale natural gas-based fertilizer plant to be built in the United States in nearly 25 years. The plant is being constructed by Orascom E&C, Inc., an indirect wholly owned subsidiary of OCI, and is expected to produce approximately 2.0 million metric tons of nitrogen fertilizer annually following completion of construction in late 2015. In connection with financing the project, Iowa Fertilizer Company issued approximately $1.2 billion of tax-exempt bonds, representing one of the largest non-investment grade transactions ever sold in the U.S. tax-exempt bond market.

The OCI Construction Group provides international engineering and construction services primarily on infrastructure, industrial and high-end commercial projects in the United States, Europe, the Middle East, North Africa and Central Asia for public and private clients. According to the Engineering News Record, the OCI Construction Group consistently ranks among the world’s top global contractors.

OCI employs more than 75,000 people in 35 countries and is listed on the NYSE Euronext in Amsterdam under the symbol “OCI.” OCI’s market capitalization, as reported by Bloomberg, was approximately $5.9 billion as of June 6, 2013.

Our Facility

Our integrated methanol and ammonia production facility is located on a 28-acre site south of Beaumont, Texas on the Neches River. We acquired our facility (which had been idled by the previous owners since 2004) in May 2011, commenced an upgrade that was completed in July 2012 and began operating our facility at full capacity in the fourth quarter of 2012. Our newly renovated facility began ammonia production in December 2011 and began methanol production in July 2012 (with no significant methanol production until August 2012), with revenues first generated from ammonia sales in the first quarter of 2012 and from methanol sales in the third quarter of 2012.

The following table sets forth our facility’s production capacity and storage capacity:

 

Product

   Current Production Capacity      Production
during the
Three
Months
Ended
March 31,
2013
     Expected Production  Capacity
after Completion of
Debottlenecking Project
     Product Storage
Capacity

(Metric Tons)
 
     Metric
Tons/Day
     Metric
Tons/Year(1)
     Metric
Tons
     Metric
Tons/Day
     Metric
Tons/Year(1)
    

Methanol

     2,000         730,000         175,523         2,500         912,500         42,000 (2 tanks)   

Ammonia

     726         264,990         64,491         835         304,739         18,000 (1 tank)   

 

(1) 

Assumes facility operates 365 days per year.

 

 

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Our Debottlenecking Project

As a means of further optimizing our production efficiencies, we are in the early stages of a debottlenecking project on our production facility, including a maintenance turnaround and environmental upgrades, which we collectively refer to as our “debottlenecking project.” This project is expected to increase our annual methanol production capacity by approximately 182,500 metric tons, or approximately 25%, and increase our annual ammonia production capacity by approximately 40,000 metric tons, or approximately 15%. We expect the debottlenecking project to be completed in the second half of 2014 and currently estimate the total cost of the project to be approximately $150 million (including costs associated with a maintenance turnaround and environmental upgrades). We expect to shut down our facility for approximately 30 to 40 days in the second half of 2014 in order to complete our debottlenecking project. As of May 31, 2013, OCIB had incurred approximately $2.6 million in expenditures related to our debottlenecking project, including costs associated with engineering fees and down payments on equipment, and will fund any costs incurred through the completion of this offering. We intend to fund a portion of the costs of our debottlenecking project and other budgeted capital projects incurred after the completion of this offering with a portion of the net proceeds from this offering. Please read “Business—Our Growth Projects—Our Debottlenecking Project.”

Feedstock Supply

The primary feedstock that we use to produce methanol and ammonia is natural gas. Operating at full capacity, our methanol and ammonia production units together require approximately 84,000 MMBtu per day of natural gas. For the three months ended March 31, 2013, natural gas feedstock costs represented approximately 59.1% of our total cost of goods sold (or approximately 85.0% of our variable cost of goods sold). Accordingly, our profitability depends in large part on the price of our natural gas feedstock.

We have connections to one major interstate and three major intrastate natural gas pipelines that provide us flexibility in sourcing our natural gas supplies. We currently source natural gas from a subsidiary of DCP Midstream Partners, LP (“DCP Midstream”) and a subsidiary of Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”). In addition, we have recently connected our facility to a natural gas pipeline owned by Florida Gas Transmission Company, LLC (“Florida Gas Transmission”) and a natural gas pipeline owned by Houston Pipe Line Company LP (“Houston Pipe Line Company”). We believe that we have ready access to an abundant supply of natural gas for the foreseeable future due to our location and connectivity to major natural gas pipelines.

Customers and Contracts

We generate our revenues from the sale of methanol and ammonia manufactured at our facility. We sell our products, primarily under contract, to industrial users and commercial traders for further processing or distribution. In addition, we derive a portion of our revenues from uncontracted sales of methanol and ammonia. We are party to methanol sales contracts with a subsidiary of Methanex Corporation (“Methanex”), a subsidiary of Koch Industries, Inc. (“Koch”), a subsidiary of Exxon Mobil Corporation (“ExxonMobil”), Arkema Inc. (“Arkema”) and a subsidiary of Lucite International, Inc. (“Lucite”). Consistent with industry practice, these contracts set our pricing terms to reflect a specified discount to a published monthly benchmark methanol price (Jim Jordan or Southern Chemical), and our methanol is sold on a free on board (“FOB”) basis when delivered by barge. Currently, we deliver approximately 55% of our methanol sales by barge and approximately 45% of our methanol sales by pipeline.

We generally sell ammonia under monthly contracts with a subsidiary of Transammonia, Inc. (“Transammonia”), a subsidiary of Koch and a subsidiary of Rentech Nitrogen Partners, L.P. (“Rentech”). Consistent with industry practice, these contracts set our pricing terms to reflect a specified discount to a

 

 

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published monthly benchmark ammonia price (CFR Tampa). Although we have ammonia pipeline connections with certain of our customers, currently all of our ammonia is sold on an FOB basis and is transported by barge.

Our Emerging Growth Company Status

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (“JOBS Act”). As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

 

   

the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations;

 

   

exemption from the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

 

   

exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

 

   

exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

 

   

reduced disclosure about executive compensation arrangements.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenue, (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

We have elected to take advantage of all of the applicable JOBS Act provisions, except that we will elect to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards (this election is irrevocable). Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before investing in our common units. Please also read “Forward-Looking Statements.”

 

 

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The Transactions

OCI Partners LP was formed on February 7, 2013 by OCI USA to own, operate and grow our methanol and ammonia business. In connection with this offering, OCI USA, an indirect wholly owned subsidiary of OCI, will contribute all of its ownership interest in OCIB to OCI Partners LP. In this prospectus, we refer to the following transactions that have taken place or will take place in connection with this offering, collectively, as the “Transactions.”

The following transactions have already occurred prior to this offering:

 

   

On May 21, 2013, OCIB entered into a $360.0 million senior secured term loan credit facility with a group of lenders and Bank of America, N.A., as administrative agent. The term loan facility is comprised of two term loans in the amounts of $125.0 million (the “Term B-1 Loan”) and $235.0 million (the “Term B-2 Loan”), respectively;

 

   

OCIB used all $125.0 million of proceeds under the Term B-1 Loan to repay outstanding borrowings under its previous third-party credit facility;

 

   

OCIB used approximately $230.0 million of the proceeds from the Term B-2 Loan to finance a distribution to OCI USA and approximately $2.8 million of the proceeds from the Term B-2 Loan to pay for bank fees, accrued interest and legal fees associated with the term loan facility. The remaining proceeds from the Term B-2 Loan of approximately $2.2 million were recorded to cash; and

 

   

OCIB transferred an office lease to OCI USA.

Additionally, at or prior to the completion of this offering, the following transactions will occur:

 

   

OCIB will enter into a new $235.0 million senior secured term loan credit facility (the “Term Loan B”) with a syndicate of institutional lenders and investors, which Bank of America, N.A. will serve as administrative agent, to repay borrowings under the Term B-2 Loan;

 

   

OCIB will transfer all of its employees to OCI GP LLC;

 

   

OCIB will distribute to OCI USA all of OCIB’s cash, restricted cash and accounts receivable;

 

   

OCI USA will contribute the member interests it owns in OCIB to OCI Partners LP in exchange for                     common units;

 

   

OCI Partners LP will (i) pay offering expenses, estimated at approximately $             million, excluding the underwriting discount, (ii) pay a structuring fee of approximately $             million to Merrill Lynch, Pierce, Fenner & Smith Incorporated for the evaluation, analysis and structuring of OCI Partners LP in connection with this offering and (iii) make a capital contribution to OCIB of the remaining net proceeds from this offering, estimated to be approximately $             million (based on an assumed initial public offering price of $             per common unit, the midpoint of the price range set forth on the cover page of this prospectus);

 

   

OCIB will use the capital contribution from OCI Partners LP of the net proceeds from this offering referred to in the immediately preceding bullet as described in “Use of Proceeds;”

 

 

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OCIB will enter into a new $40.0 million, seven-year intercompany revolving credit facility with OCI Fertilizer as the lender;

 

   

OCI Partners LP’s partnership agreement and the limited liability company agreement of OCI GP LLC will be amended and restated to the extent necessary to reflect the transactions in the contribution agreement; and

 

   

OCI Partners LP will redeem the limited partner interest issued to OCI USA in connection with OCI Partners LP’s formation and will retire such limited partner interest in exchange for a payment of $1,000 to OCI USA.

The number of common units to be issued to OCI USA includes              common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters’ option to purchase additional common units would reduce the common units shown as issued to OCI USA by the number to be purchased by the underwriters in connection with such exercise. 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 pursuant to any exercise of the option will be issued to OCI USA at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us for general partnership purposes.

 

 

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Organizational Structure After the Transactions

After giving effect to the Transactions described above and assuming the underwriters’ option to purchase additional common units from us is not exercised, our common units will be held as follows:

 

Public common units

             

OCI common units

             
  

 

 

 

Total

     100
  

 

 

 

The following simplified diagram depicts our organizational structure after giving effect to the Transactions described above.

 

LOGO

 

 

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Management of OCI Partners LP

We are managed and operated by the board of directors and executive officers of OCI GP LLC, our general partner. OCI USA, an indirect wholly owned subsidiary of OCI, is the sole member of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with the listing standards of the New York Stock Exchange (“NYSE”). Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. For more information about the directors and executive officers of our general partner, please read “Management.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 5470 N. Twin City Highway, Nederland, Texas 77627, our mailing address is P.O. Box 1647, Nederland, Texas 77627 and our telephone number is (409) 723-1900. Our website is located at www.                        .com. We expect to make our periodic reports and other information filed with or furnished to the SEC available, 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 into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership. However, because our general partner is an indirect, wholly owned subsidiary of OCI, the officers and directors of our general partner and the officers and directors of OCI have a duty to manage the business of our general partner in a manner that is in the best interests of OCI. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including OCI, on the other hand. For a more detailed description of the conflicts of interest and duties of our general partner, please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

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. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including OCI, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—Duties of the General Partner” for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

 

 

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The Offering

 

Issuer

OCI Partners LP, a Delaware limited partnership.

 

Common Units Offered to the Public

            common units.

 

              common units if the underwriters exercise their option to purchase additional common units from us in full.

 

Common Units Outstanding after this Offering

            common units. If the underwriters do not exercise their option to purchase additional common units, in whole or in part, we will issue             additional common units to OCI USA at the expiration of the option period 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 such exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to such exercise of the option will be issued to OCI USA at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

 

  In addition, our general partner will own a non-economic general partner interest in us which will not entitle it to receive distributions.

 

Use of Proceeds

We estimate that the net proceeds to us from this offering, after deducting the estimated underwriting discount, structuring fees and the estimated offering expenses payable by us, will be approximately $            million (based on an assumed initial public offering price of $            per common unit, the midpoint of the price range set forth on the cover page of this prospectus). We intend to use the net proceeds from this offering as follows:

 

   

approximately $125.0 million to repay in full and terminate the Term B-1 Loan;

 

   

approximately $170.5 million to repay in full and terminate all of OCIB’s intercompany debt with OCI Fertilizer;

 

   

to pay a portion of the costs of our debottlenecking project and other budgeted capital projects incurred after the completion of this offering; and

 

   

the remainder, if any, for general partnership purposes, including working capital.

 

 

If the underwriters exercise their option to purchase up to             additional common units in full, the additional net proceeds would be approximately $            million, assuming an initial public offering price per common unit of $            (the midpoint of the price range set forth on the cover page of this prospectus). We will use the net

 

 

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proceeds from any exercise of the underwriters’ option to purchase additional common units for general partnership purposes.

 

  Affiliates of each of Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc. and Citigroup Global Markets Inc. are lenders under the Term B-1 Loan and, accordingly, may receive a portion of the distributions made to OCIB in connection with this offering. Please read “Underwriting—Other Relationships.”

 

Cash Distributions

Within 45 days after the end of each quarter, beginning with the first full quarter following the closing date of this offering, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date.

 

  Upon the completion of this offering, the board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution that we generate each quarter. If we have cash available for distribution, our first distribution will take place following the first full quarter after the completion of this offering and will include cash available for distribution with respect to the period beginning on the closing date of this offering and ending on the last day of the first full quarter ending after the completion of this offering. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that cash available for distribution for each quarter will generally equal the cash we generate during the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Other than the expansion capital expenditures we intend to fund with the net proceeds from this offering, we expect to finance substantially all of our growth externally, either with commercial bank borrowings or by debt issuances or additional issuances of equity.

 

 

Because our policy will be to distribute 100% of the cash available for distribution that we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low cash flow from operations, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our cash flow during such quarter. As a result, our cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of, among other things, variations in our operating performance and cash flows caused by fluctuations in the prices of our natural gas supply and the demand for and prices of

 

 

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methanol and ammonia. Such variations in the amount of our quarterly distributions may be significant. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly cash distributions over time. We may change our distribution policy at any time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

 

  Subject to certain assumptions and assuming the board of directors of our general partner declares distributions in accordance with our cash distribution policy, we expect that our cash available for distribution for the twelve months ending June 30, 2014 will be approximately $            million, or $            per common unit. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Forecasted Cash Available for Distribution.” Unanticipated events may occur that could materially adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, cash flows, need for reserves and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations, cash flows and financial condition. In addition, the board of directors of our general partner may be required to or elect to eliminate our distributions at any time during periods of reduced prices or demand for our products, among other reasons. Please read “Risk Factors.”

 

  For a calculation of our ability to make distributions to unitholders based on our pro forma results of operations for the year ended December 31, 2012 and the twelve months ended March 31, 2013, please read “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution.” Our pro forma cash available for distribution generated during the year ended December 31, 2012 and the twelve months ended March 31, 2013 would have been $67.0 million and $129.0 million, respectively. However, the pro forma cash available for distribution information for the year ended December 31, 2012 and the twelve months ended March 31, 2013 that we include in this prospectus do not necessarily reflect the actual cash that would have been available for distribution with respect to those periods.

 

Incentive Distribution Rights

None.

 

Subordinated Units

None.

 

Issuance of Additional Units

Our partnership agreement authorizes us to issue an unlimited number of additional units and rights to buy units for the consideration and on the terms and conditions determined by the board of directors of our general partner without the approval of our unitholders. Please read

 

 

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“The Partnership Agreement—Issuance of Additional Securities” and “Common Units Eligible for Future Sale.”

 

Limited Voting Rights

Our general partner manages us and our operations. 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 our general partner’s directors on an annual or other continuing basis. Our general partner may be removed by a vote of the holders of at least 66 2/3% of our outstanding common units, including any common units held by our general partner and its affiliates (including OCI USA), voting together as a single class. Upon the closing of this offering, our general partner and its affiliates will own an aggregate of approximately             % of our outstanding common units (or approximately             % if the underwriters exercise their option to purchase additional common units in full). Please read “The Partnership Agreement—Voting Rights.”

 

Limited Call Right

If at any time our general partner and its affiliates own more than 90% 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 public unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, then concurrently with such reduction, the ownership threshold to exercise the limited call right will be permanently reduced to 80%. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and exercising its limited call right. Please read “The Partnership Agreement—Limited Call Right.”

 

Estimated Ratio of Taxable Income to Distributions

We estimate that if you own the common units you purchase in this offering from the date of the completion of this offering through the record date for distributions for the period ending December 31, 2015 you will be allocated, on a cumulative basis, an amount of U.S. federal taxable income for that period that will be approximately             % of the cash distributed to you with respect to that period. Because of the nature of our business and the expected variability of our quarterly distributions, the ratio of our taxable income to distributions may vary significantly from one year to another. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Common Unit Ownership—Ratio of Taxable Income to Distributions.”

 

Material U.S. Federal Income Tax Consequences

For a discussion of material U.S. federal income tax consequences that may be relevant to prospective unitholders, please read “Material U.S. Federal Income Tax Consequences.”

 

 

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Exchange Listing

We intend to apply to list our common units on the NYSE under the symbol “OCIP.”

 

Risk Factors

Please read “Risk Factors” for a discussion of factors that you should carefully consider before deciding to invest in our common units.

Depending on market conditions at the time of pricing of this offering and other considerations, we may sell fewer or more common units than the number set forth on the cover page of this prospectus.

 

 

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Summary Historical and Pro Forma Financial and Operating Data

The summary historical financial information presented below under the caption “Statements of Operations Data” and “Cash Flows Data” for the years ended December 31, 2012 and 2011 and the summary historical financial information presented below under the caption “Balance Sheets Data” as of December 31, 2012 and 2011 have been derived from OCIB’s audited financial statements included elsewhere in this prospectus, which financial statements have been audited by KPMG LLP, an independent registered public accounting firm (“KPMG”).

The summary historical financial information presented below under the caption “Statements of Operations Data” and “Cash Flows Data” for the three months ended March 31, 2013 and 2012 and the summary financial data presented below under the caption “Balance Sheets Data” as of March 31, 2013 have been derived from OCIB’s unaudited financial statements included in this prospectus which, in the opinion of management, include all adjustments, consisting of only normal, recurring adjustments, necessary for the fair presentation of the results for the unaudited interim periods.

The summary unaudited pro forma condensed statements of operations data presented for the year ended December 31, 2012 and the three months ended March 31, 2013 assumes that the Transactions occurred as of January 1, 2012, and the unaudited pro forma condensed balance sheet data as of March 31, 2013 assumes that the Transactions occurred as of March 31, 2013. The summary unaudited pro forma condensed financial information is derived from our unaudited pro forma condensed financial statements included elsewhere in this prospectus. The pro forma condensed financial data is not comparable to our historical financial data. A more complete explanation of the pro forma condensed financial data can be found in our unaudited pro forma condensed financial statements and accompanying notes included elsewhere in this prospectus. Neither the pro forma condensed statements of operations data nor the pro forma condensed balance sheet data include estimates of the incremental costs of operating as a publicly traded limited partnership.

 

 

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For a detailed discussion of the summary historical financial information and operating data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and our audited and unaudited historical financial statements and our unaudited pro forma condensed financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

    Historical     Pro Forma  
(Dollars and metric tons in thousands)  

Year ended December 31,

   

Three months ended
March 31,

   

Year

ended
December 31,

   

Three
months
ended
March 31,

 
 

2011

   

2012

   

2012

   

2013

   

2012

   

2013

 
                (unaudited)     (unaudited)  

Statements of Operations Data:

           

Revenues(1)

  $ —        $ 224,629      $ 26,492      $ 112,161      $ 224,629      $ 112,161   

Cost of goods sold

    —          124,483        19,907        43,167        124,483        43,167   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross Profit

    —          100,146        6,585        68,994        100,146        68,994   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Expenses:

           

Depreciation expense

    —          11,355        966        5,512        11,355        5,512   

Selling, general and administrative

    236        14,980        3,479        8,098        15,000        3,750   

Income (loss) from operations before interest expense, other income and income tax expense

    (236     73,811        2,140        55,384        73,791        59,732   

Interest expense

    —          5,718        —          2,259        11,002        2,750   

Interest expense – related party

    —          6,469        —          4,411        200        50   

Other income

    523        202        159        9        202        9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

    287        61,826        2,299        48,723        62,791        56,941   

Income tax expense

    —          1,048        47        474        1,048        474   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 287      $ 60,778      $ 2,252      $ 48,249      $ 61,743      $ 56,467   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income per common unit (basic and diluted)

           

Common units outstanding (basic and diluted)

           

Cash Flows Data:

           

Net cash provided by (used in):

           

Operating activities

  $ (5,252   $ 74,657      $ (4,842   $ (15,824    

Investing activities

    (130,214     (193,965     (83,752     (6,481    

Financing activities

    136,500        159,982        91,000        —         

Balance Sheets Data (at period end):

           

Cash and cash equivalents

  $ 1,034      $ 41,708        $ 19,403        $ 159,618   

Total assets

    154,682        405,345          420,411          494,643   

Total liabilities

    150,395        340,280          307,097          243,277   

Member’s equity / partners’ capital

    4,287        65,065          113,314          251,366   

Other Financial Data:

           

EBITDA(2)

  $ (236   $ 85,166      $ 3,106      $ 60,896      $ 85,146      $ 65,244   

Capital expenditures for property, plant and equipment

    130,214        193,965        83,752        6,481       

Total debt (excluding accrued interest)

    132,500        295,482          295,482          232,650   

Key Operating Data:

           

Production (metric tons)

           

Methanol

    —          275.0        —          176.5       

Ammonia

    21.0        213.0        42.8        64.5       

 

 

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(1) Our ammonia production unit commenced production in December 2011, and our methanol production unit commenced production in July 2012. Although we began producing ammonia in December 2011, we did not sell the produced ammonia volumes until January 2012 in order to build inventories.
(2) EBITDA is defined as net income plus interest expense and other financing costs, depreciation and income tax expense, net of interest income.

EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:

 

   

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; and

 

   

our operating performance and return on invested capital compared to those of other publicly traded partnerships, without regard to financing methods and capital structure.

EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA may have material limitations as a performance measure because it excludes items that are necessary elements of our costs and operations. In addition, EBITDA presented by other companies may not be comparable to our presentation because each company may define that term differently.

 

     Historical      Pro Forma  
     Year ended
December 31,
     Three months ended
March 31,
     Year
ended
December

31,
     Three
months
ended
March 31,
 
(dollars in thousands)   

2011

   

2012

    

2012

   

2013

    

2012

    

2013

 
                  (unaudited)      (unaudited)  

Net income

   $ 287      $ 60,778       $ 2,252      $ 48,249       $ 61,743       $ 56,467   

Add:

               

Interest expense, net

     (523     5,516         (159     2,250         10,800         2,741   

Interest expense – related party

     —          6,469         —          4,411         200         50   

Depreciation expense

     —          11,355         966        5,512         11,355         5,512   

Income tax expense

     —          1,048         47        474         1,048         474   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

EBITDA

   $ (236   $ 85,166       $ 3,106      $ 60,896       $ 85,146       $ 65,244   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

 

 

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RISK FACTORS

You should carefully consider each of the following risks and all of the information set forth in this prospectus before deciding to invest in our common units. If any of the following risks and uncertainties develops into an actual event, our business, financial condition, cash flows or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment. Although many of our business risks are comparable to those faced by a corporation engaged in a similar business, limited partner interests are inherently different from the capital stock of a corporation and involve additional risks described below.

Risks Related to Our Business

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

We may not have sufficient cash available for distribution each quarter to enable us to pay any distributions to our common unitholders. The amount of cash we will be able to distribute on our common units principally depends on the amount of cash we generate from our operations, which is directly dependent upon the operating margins we generate. Our profit margins are significantly affected by the level of our cost of goods sold, including the cost of natural gas, our main feedstock, as well as the costs of hydrogen and nitrogen and other costs, the market-driven prices for methanol and ammonia we are able to charge our customers, seasonality, weather conditions, governmental regulation and global and domestic economic conditions and demand for methanol and ammonia, among other factors. In addition, our results of operations and our ability to pay distributions are affected by:

 

   

the level of capital expenditures we make;

 

   

our debt service requirements;

 

   

the amount of any reimbursement of expenses incurred by our general partner and its affiliates on our behalf;

 

   

fluctuations in our working capital needs;

 

   

our ability to access capital markets;

 

   

planned and unplanned maintenance at our facility, which may result in downtime and thus negatively impact our cash flows in the quarter in which such maintenance occurs;

 

   

fluctuations in interest rates;

 

   

the level of competition in our market and industry;

 

   

restrictions on distributions and on our ability to make working capital borrowings; and

 

   

the amount of cash reserves established by our general partner, including for turnarounds and related expenses.

Our partnership agreement will not require us to pay a minimum quarterly distribution. The amount of distributions that we pay, if any, and the decision to pay any distribution at all will be determined by the board of directors of our general partner. Our quarterly distributions, if any, will be subject to significant fluctuations based on the above factors.

 

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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 our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly cash distributions over time.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. We expect our business performance will be more volatile, and our cash flows will be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions will be volatile and are expected to vary quarterly and annually. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly cash distributions over time. The amount of our quarterly cash distributions will be directly dependent on the performance of our business, which is subject to volatility. Methanol prices have historically been, and are expected to continue to be, characterized by significant cyclicality. Additionally, ammonia and natural gas prices are volatile, and seasonal and global fluctuations in demand for nitrogen fertilizer products and other ammonia-based products could affect our revenues. Because our quarterly cash distributions will be subject to significant fluctuations directly related to the cash we generate after payment of our fixed and variable expenses and other cash reserves established by our general partner, future quarterly cash distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Given the volatile nature of our business, we expect that our unitholders will have direct exposure to fluctuations in the price of methanol and ammonia and the cost of natural gas.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

You should be aware that the amount of cash we have available for distribution depends primarily on our cash flow and not solely on our profitability, which may be affected by non-cash items. For example, we may have extraordinary capital expenditures and major maintenance expenses in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures.” As a result, we may make cash distributions during periods when we report losses and may not make cash distributions during periods when we report net income.

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

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute 100% of the cash available for distribution that we generate each quarter to unitholders of record on a pro rata basis. However, the board of directors may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

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

 

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For each of the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, we would not have generated sufficient cash available for distribution to have paid the per unit quarterly distribution that we project that we will be able to pay for the twelve months ending June 30, 2014.

We project that we will be able to pay aggregate quarterly distributions of $            per unit for the twelve months ending June 30, 2014. In order to pay these projected distributions, we must generate approximately $            million of cash available for distribution during the twelve months ending June 30, 2014. We have a limited operating history upon which to rely in evaluating whether we will have sufficient cash to allow us to pay quarterly distributions on our common units. We acquired our facility (which had been idled by the previous owners since 2004) in May 2011, commenced an upgrade that was completed in July 2012 and began operating our facility at full capacity in the fourth quarter of 2012. Our newly renovated facility began ammonia production in December 2011 and began methanol production in July 2012 (with no significant methanol production until August 2012), with revenues first generated from ammonia sales in the first quarter of 2012 and from methanol sales in the third quarter of 2012. We did not achieve maximum daily production rates at our current capacity until the fourth quarter of 2012, after an approximate 20-month start-up phase. For a description of the price assumptions upon which we have based our projected per unit quarterly distributions during the twelve months ending June 30, 2014, please read “Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations.”

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

Our forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Forecasted Cash Available for Distribution” includes our forecast of our results of operations and cash available for distribution for the twelve months ending June 30, 2014. The forecast has been prepared by our management team. Neither our independent registered public accounting firm nor any other independent accountants have examined, compiled or performed any procedures with respect to the forecast, nor have any of them expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for the forecast. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those discussed in this section, that could cause actual results to differ materially from those forecasted. If the forecasted results are not achieved, we would not be able to pay the forecasted distribution amounts, in which event the market price of our common units may decline materially. Our actual results may differ materially from the forecasted results presented in this prospectus. Investors should review the forecast of our results of operations for the twelve months ending June 30, 2014 together with the other information included elsewhere in this prospectus, including “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We have a limited operating history. As a result, you may have difficulty evaluating our ability to pay quarterly cash distributions to our unitholders or our ability to be successful in implementing our business strategy.

As a newly upgraded facility, the operating performance of our facility over the short-term and long-term is not yet proven. We have already encountered and will continue to encounter risks and difficulties frequently experienced by companies whose performance is dependent upon newly constructed or recently upgraded world-scale processing or manufacturing facilities, such as the risks described in this prospectus. We may not achieve the efficiencies and utilization rates we expect from our newly upgraded facility.

We acquired our facility (which had been idled by the previous owners since 2004) in May 2011, commenced an upgrade that was completed in July 2012 and began operating our facility at full capacity in the fourth quarter of 2012. Our newly renovated facility began ammonia production in December 2011 and began

 

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methanol production in July 2012 (with no significant methanol production until August 2012), with revenues first generated from ammonia sales in the first quarter of 2012 and from methanol sales in the third quarter of 2012. We did not achieve maximum daily production rates at our current capacity until the fourth quarter of 2012, after an approximate 20-month start-up phase. During this period, we experienced unplanned downtime. For example, in the third quarter of 2012, our facility experienced approximately four weeks of unplanned downtime as we took our facility offline to resolve certain start-up issues and to complete other capital and maintenance projects.

Because of our limited operating history and performance record, it is difficult for you to evaluate our business and results of operations to date and to assess our future prospects. Further, our historical financial statements present a period of limited operations and therefore do not provide a meaningful basis for you to evaluate our operations or our ability to achieve our business strategy. We may be less successful than a seasoned company in achieving a consistent operating level at our facility capable of generating cash flows from our operations sufficient to regularly pay a quarterly cash distribution or to pay any quarterly cash distribution to our unitholders. We may also be less successful in implementing our business strategy than a seasoned company with a longer operating history. Finally, we may be less equipped to identify and address operating risks and hazards in the conduct of our business than those companies whose major facilities have longer operating histories.

Our management has no experience in managing our business as a U.S. publicly traded partnership.

Our executive management team and internal accounting staff have no experience in managing our business and reporting as a U.S. publicly traded partnership. As a result, we may not be able to anticipate or respond to material changes or other events in our business as effectively as if our executive management team and accounting staff had such experience. Furthermore, growth projects may place significant strain on our management resources, thereby limiting our ability to execute our business strategy.

Our facility faces operating hazards and interruptions, including unscheduled maintenance or downtime. We could face significant reductions in revenues and increases in expenses to the extent these hazards or interruptions cause a material decline in production and are not fully covered by our existing insurance coverage. Insurance companies that currently insure companies in our industry may cease to do so, may change the coverage provided or may substantially increase premiums in the future.

Our operations, located at a single location, are subject to significant operating hazards and interruptions. Any significant curtailing of production at our facility or individual units within our facility could result in materially lower levels of revenues and cash flow and materially increased expenses for the duration of any downtime and materially adversely impact our results of operations, financial condition and ability to make cash distributions. Operations at our facility could be curtailed or partially or completely shut down, temporarily or permanently, as the result of a number of circumstances, most of which are not within our control, such as:

 

   

unscheduled maintenance or catastrophic events such as a major accident or fire, damage by severe weather, flooding or other natural disaster;

 

   

labor difficulties that result in a work stoppage or slowdown;

 

   

environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at our facility;

 

   

increasingly stringent environmental regulations;

 

   

a disruption in the supply of natural gas to our plant; and

 

   

governmental limitations on the use of our products, either generally or specifically those manufactured at our plant.

 

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The magnitude of the effect on us of any downtime will depend on the length of the downtime and the extent our operations are affected by the downtime. We expect to perform maintenance turnarounds every three to four years, which will typically last from 20 to 40 days and cost approximately $10 million to $15 million per turnaround. Such turnarounds may have a material impact on our cash flows and ability to make cash distributions in the quarter or quarters in which they occur. We plan to undertake a turnaround as part of our debottlenecking project that is expected to be completed in the second half of 2014, which will result in approximately 30 to 40 days of downtime at our facility. Scheduled and unscheduled maintenance or downtime could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions during the period of time that any of our units is not operating. During downtime, we will be required to fulfill certain of our customer contracts with product purchased from third parties at spot prices and we may incur losses in connection with those sales. In addition, a major accident, fire, flood or other event could damage our facility or the environment and the surrounding community or result in injuries or loss of life.

For example, in the quarter(s) preceding our planned downtime for major turnarounds as described elsewhere in this prospectus, the board of directors of our general partner may elect to reserve amounts to fund (i) the capital costs associated with our major turnarounds, (ii) all or a portion of the revenues projected to be forgone as a result of the loss of production during the downtime associated with a turnaround or (iii) both. Based upon the decision(s) made by the board of directors of our general partner, the cash available for distribution in the quarter(s) preceding such a planned maintenance event in which the reserves are withheld may be adversely impacted. Conversely, additional amounts may be required to be reserved from cash available for distribution generated in a quarter subsequent to such a planned maintenance event should the scope of the actual work performed during such period be materially different than that planned.

If we experience significant property damage, business interruption, environmental claims or other liabilities, our business could be materially adversely affected to the extent the damages or claims exceed the amount of valid and collectible insurance available to us. We are currently insured under casualty, environmental, property and business interruption insurance policies. These policies contain exclusions and conditions that could have a materially adverse impact on our ability to receive indemnification thereunder, as well as customary sub-limits for particular types of losses. Please read “Business—Insurance.”

We are not fully insured against all risks related to our business and, if an accident or event occurs that is not fully insured, it could materially adversely affect our business.

A major accident, fire, flood or other event could damage our facility or the environment and the surrounding community or result in injuries or loss of life. If we experience significant property damage, business interruption, environmental claims or other liabilities, our business could be materially adversely affected to the extent the damages or claims exceed the amount of valid and collectible insurance available to us. We are currently insured under casualty, environmental, property and business interruption insurance policies. The property and business interruption insurance policies have a €400.0 million limit, with a €0.5 million deductible for physical damage (€1.0 million for property damage from a major machinery breakdown), a €2.3 million deductible for business interruption and a 30-day waiting period before losses resulting from business interruptions are recoverable. The policies also contain exclusions and conditions that could have a materially adverse impact on our ability to receive indemnification thereunder, as well as customary sub-limits for particular types of losses. For example, the current property policy contains a specific sub-limit of €100.0 million for damage caused by flooding and €100.0 million for damage caused by named windstorm. We are fully exposed to all losses in excess of the applicable limits and sub-limits and for losses due to business interruptions caused by machinery breakdown of fewer than 30 days, and there is a limit of €4.0 million for losses due to such business interruption incurred after the expiration of the 30-day waiting period. With regard to environmental claims due to accidental pollution, we currently have a policy limit of €100.0 million under the general liability insurance policy in place, and this policy has a deductible of €125,000. The occurrence of any operating risk not covered by our insurance could have a material adverse effect on our business, financial condition, results of operations and ability to pay distributions to our unitholders. Market factors, including but not limited to catastrophic perils that

 

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impact our industry, significant changes in the investment returns of insurance companies, insurance company solvency trends and industry loss ratios and loss trends, can negatively impact the future cost and availability of insurance. There can be no assurance that we will be able to buy and maintain insurance in the future with adequate limits, reasonable pricing terms and conditions.

We do not have contracts that provide for a minimum commitment from our customers. The prices we receive for our products are determined by reference to pricing indices and thus could be subject to significant variations.

We do not have contracts that provide for a minimum commitment from our customers. Although our contracts set pricing terms, they do not obligate the counterparty to purchase a specified minimum volume of methanol or ammonia from us. As such, our customers could source their methanol or ammonia supply elsewhere and cease buying our products at any time and for any reason, and we will have no recourse in the event a customer decides not to purchase our products. If customers representing a significant amount of our revenues elect not to purchase the methanol and ammonia we produce, it could materially adversely affect our results of operations, financial condition and ability to make cash distributions.

Methanol and ammonia are global commodities, with little or no product differentiation, and customers make their purchasing decisions principally on the basis of delivered price and availability of the product. As a result, the prevailing market sales prices for methanol and ammonia are subject to volatile, cyclical and seasonal changes in respect to relatively small changes in demand. Since we have no contracts that provide for a minimum commitment from our customers and the prices at which we sell our products are determined by reference to specific pricing indices that change in response to changes in prevailing market conditions, the revenue we receive for the sales of our products will be subject to significant variations from period to period in response to changes in prevailing market prices for methanol and ammonia, which variations will result in changes in our cash available for distribution and distributions per common unit.

The methanol industry is subject to commodity price volatility and supply and demand uncertainty, which could potentially affect our operating and financial results, and expose our unitholders to substantial volatility in our quarterly cash distributions and material reductions in the trading price of our common units.

The methanol industry has historically been characterized by cycles of oversupply caused by either excess supply or reduced demand, resulting in lower prices and idling of capacity, followed by periods of shortage and rising prices as demand exceeds supply until increased prices lead to new plant investment or the restart of idled capacity. The methanol industry has historically operated significantly below stated capacity on a consistent basis, even in periods of high methanol prices, due primarily to shutdowns for planned and unplanned repairs and maintenance, temporary closures of marginal production facilities, as well as shortages of feedstock and other production inputs.

The methanol business is a highly competitive commodity industry, and prices are affected by supply and demand fundamentals and global energy prices. Methanol prices have historically been, and are expected to continue to be, characterized by significant cyclicality. New methanol plants are expected to be built in the United States, and this will increase overall production capacity. For example, Methanex, LyondellBasell Industries N.V. (“LyondellBasell”) and Celanese Corporation (“Celanese”) have each announced plans to relocate, restart or construct methanol plants in the U.S. Gulf Coast region over the next few years, which will increase overall U.S. production capacity and the availability of methanol supply to our customers from competing sources. Please read “Business—Competition.” Additional methanol supply can also become available in the future by restarting idle methanol plants, carrying out major expansions of existing plants or debottlenecking existing plants to increase their production capacity. Historically, higher-cost plants have been shut down or idled when methanol prices are low, but there can be no assurance that this practice will occur in the future or that such plants will remain idle. Relatively low prices for natural gas have led to reduced idling at the current time. In addition, Jim Jordan projects that by 2017 increased methanol production capacity in the United States could exceed domestic demand. This increased supply could lead to downward pressure on methanol prices.

 

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Demand for methanol largely depends upon levels of global industrial production, changes in general economic conditions and energy prices. We are not able to predict future methanol supply and demand balances, market conditions, global economic activity, methanol prices or energy prices, all of which are affected by numerous factors beyond our control. Since methanol constitutes a significant portion of the products we produce and market, a decline in the price of methanol would have an adverse impact on our financial condition, cash flows and results of operations, which could result in significant volatility or material reductions in the price of our common units or an inability to make quarterly cash distributions on our common units.

The ammonia business is, and ammonia prices are, cyclical and highly volatile and have experienced substantial downturns. Cycles in demand and seasonal fluctuations in pricing could potentially affect our operating and financial results, and expose our unitholders to substantial volatility in our quarterly cash distributions and material reductions in the trading price of our common units.

Ammonia is a commodity, and demand for and prices of ammonia can be highly volatile. In particular, our ammonia business is exposed to fluctuations in the demand for nitrogen fertilizer from the agricultural industry. These fluctuations historically have had and could in the future have significant effects on prices across all ammonia-based products and, in turn, our financial condition, cash flows and results of operations, which could result in significant volatility or material reductions in the price of our common units or an inability to make quarterly cash distributions on our common units.

The ammonia industry is generally seasonal. Farmers tend to apply nitrogen fertilizer during two short application periods, one in the spring and the other in the fall. The strongest demand for nitrogen fertilizers typically occurs during the planting season. In contrast, we and other ammonia producers generally produce our products throughout the year. As a result, ammonia producers generally build inventories during the low demand periods of the year in order to ensure timely product availability during the peak sales seasons. The seasonality of nitrogen fertilizer demand results in ammonia producers’ sales volumes being highest during the North American spring season and their working capital requirements typically being highest just prior to the start of the spring season. The degree of seasonality of the ammonia industry can change significantly from year to year due to conditions in the agricultural industry and other factors. As a consequence of this seasonality, we expect that our distributions will be volatile and will vary quarterly and annually.

If seasonal demand exceeds the projections on which we base our production, we will not have enough product and our customers may acquire ammonia from our competitors, which will negatively impact our profitability. If seasonal demand is less than we expect, we will be left with excess inventory and higher working capital and liquidity requirements associated with the liquidation or storage of such inventory. Additionally, because our inventory storage capacity is not significant, during periods of peak demand we may be required to acquire ammonia at spot prices in order to fulfill our supply obligations to customers. The prices at which we purchase ammonia for sale to our customers may negatively impact our profitability.

The pricing and demand for nitrogen fertilizer products is also dependent on demand for crop nutrients by the global agricultural industry. The agricultural products business can be affected by a number of factors. The most important of these factors, for U.S. markets, are:

 

   

weather patterns and field conditions (particularly during periods of traditionally high nitrogen fertilizer consumption);

 

   

quantities of nitrogen fertilizers imported to and exported from North America;

 

   

current and projected grain inventories and prices, which are heavily influenced by U.S. exports and world-wide grain markets; and

 

   

U.S. governmental policies, including farm and biofuel policies, which may directly or indirectly influence the number of acres planted, the level of grain inventories, the mix of crops planted or crop prices.

 

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International market conditions may also significantly influence our operating results. The international market for nitrogen fertilizers is influenced by such factors as the relative value of the U.S. dollar and its impact upon the cost of importing nitrogen fertilizers, foreign agricultural policies, the existence of, or changes in, import or foreign currency exchange barriers in certain foreign markets, changes in the hard currency demands of certain countries and other regulatory policies of foreign governments, as well as the laws and policies of the United States affecting foreign trade and investment.

Since ammonia constitutes a significant portion of the products we produce and market, a decline in the price of or demand for nitrogen fertilizers would have a material adverse effect on our business, cash flow and ability to make distributions.

Methanol and ammonia are global commodities, and we face intense competition from other producers.

Our business is subject to intense price competition from both U.S. and foreign sources, including competitors operating in Trinidad with respect to methanol and in the Persian Gulf, the Asia-Pacific region, the Caribbean, Russia and the Ukraine with respect to ammonia. Both methanol and ammonia are global commodities, with little or no product differentiation, and customers make their purchasing decisions principally on the basis of delivered price and availability of the product. We compete with a number of domestic and foreign producers, including state-owned and government-subsidized entities. Most significantly, producers in Trinidad have historically been the largest suppliers of methanol to the United States. These companies have significant experience and expertise in production, transportation, marketing and sales of methanol in the United States. Some competitors have greater total resources and are less dependent on earnings from methanol or ammonia sales, which makes them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. In addition, Methanex, LyondellBasell and Celanese have each announced plans to relocate, restart or construct methanol plants in the U.S. Gulf Coast region over the next few years, which would compete directly with our facility. If we are unable to provide customers with a reliable supply of methanol or ammonia at competitive prices, we may lose market share to our competitors, which could have an adverse impact on our results of operations, financial condition and ability to make cash distributions.

Our gross profit is vulnerable to fluctuations in the cost of natural gas, our primary feedstock.

Our profitability is significantly dependent on the cost of our natural gas feedstock, and a significant increase in the price of natural gas would adversely affect our ability to operate our facility on a profitable basis. In recent history, the price of natural gas has been very volatile, with prices at the NYMEX pricing point, Henry Hub, spiking to near-record high prices in 2008 and dropping to near-record low prices in 2012. This was due to various supply and demand factors, including the increasing overall demand for natural gas from industrial users, which is affected, in part, by the general conditions of the U.S. and global economies, and other factors. We currently procure our natural gas through two main suppliers, Kinder Morgan and DCP Midstream, through supply agreements that are based on spot pricing, making us susceptible to fluctuations in the price of natural gas. A hypothetical increase or decrease of $1.00 per MMBtu of natural gas would increase or decrease our annual cost of goods sold by approximately $32.6 million. A material increase in natural gas prices could materially and adversely affect our results of operations, financial condition and ability to make cash distributions.

Our facility operates under a number of federal and state permits, licenses and approvals, and failure to comply with or obtain necessary permits, licenses and approvals may result in unanticipated costs or liabilities, which could reduce our profitability.

Our facility operates under a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. Our facility is also required to comply with prescriptive limits and meet performance standards specific to chemical facilities as well as to general manufacturing facilities. All of these permits, licenses, approvals and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate

 

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compliance with the underlying permit, license, approval or standard. Incomplete documentation of compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, due to the nature of our manufacturing processes, there may be times when we are unable to meet the standards and terms and conditions of these permits and licenses due to operational upsets or malfunctions, which may lead to violations or enforcement from regulatory agencies that could potentially result in operating restrictions. This would have a direct material adverse effect on our ability to operate our facilities and accordingly our results of operations, financial condition and ability to make cash distributions.

We hold numerous environmental and other governmental permits and approvals authorizing operations at our plant. We are currently operating our facility under a Title V permit issued by the Texas Commission on Environmental Quality (the “TCEQ”) that limits certain operations to three years from the date of startup. We have applied for an amendment to our existing permit, including an application to EPA for review of greenhouse gas (“GHG”) emissions under best available control technology (“BACT”). A denial of or delay in issuing, renewing or amending a material permit could have an adverse impact on our results of operations, financial condition and ability to make cash distributions because of an inability to operate our facilities in accordance with our business plan.

We plan to undertake a debottlenecking project in the second half of 2014 that we expect will increase output from our methanol and ammonia production units. Our debottlenecking project and any other expansion of our operations is also predicated upon securing the necessary environmental or other permits or approvals, including necessary amendments to current permits to account for increased output. We have applied for a greenhouse gas permit from the U.S. Environmental Protection Agency (the “EPA”) in connection with our debottlenecking project in 2014. In some cases, such permits must be issued prior to the commencement of the project. We have begun pre-construction and other activities associated with our debottlenecking project that do not require a permit. A decision by a government agency to deny or delay issuing a new or renewed material permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations or our ability to commence and complete our debottlenecking or other expansion projects.

Our expansion of existing assets and construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations, financial condition and ability to make cash distributions.

In order to optimize our existing asset base, we intend to evaluate and capitalize on organic opportunities for expansion projects in order to increase revenue. The expansion of production capacity (such as our debottlenecking project), or the construction of new assets, involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. These risks include:

 

   

changes to plans and specifications;

 

   

engineering problems, including defective plans and specifications;

 

   

shortages of, and price increases in, energy, raw materials and skilled and unskilled labor;

 

   

inflation in key supply markets;

 

   

changes in laws and regulations, or in the interpretations and enforcement of laws and regulations, applicable to constructions projects;

 

   

poor workmanship, labor disputes or work stoppages;

 

   

failure by subcontractors to comply with applicable laws and regulations;

 

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injuries sustained by workers or patrons on the job site;

 

   

disputes with and defaults by contractors and subcontractors;

 

   

claims asserted against us for construction defects, personal injury or property damage;

 

   

environmental issues;

 

   

health and safety incidents and site accidents;

 

   

weather interferences or delays;

 

   

fires and other natural disasters; and

 

   

other unanticipated circumstances or cost increases.

If we undertake any expansion projects, they may not be completed on schedule or at all or at the budgeted cost. We plan to use a portion of the net proceeds from this offering to fund a portion of the costs of our debottlenecking project (including costs associated with a maintenance turnaround and various environmental upgrades) and other budgeted capital projects incurred after the completion of this offering. If the actual cost to complete the debottlenecking project and other budgeted capital projects is greater than the budgeted cost, we would be required to use our cash flow from operations or seek additional sources of financing to complete those projects. We may not have sufficient cash flow from operations, or additional sources of financing may not be available on commercially reasonable terms or at all. Using cash flow from operations or incurring debt to fund our expansion projects (and paying the interest related to such incremental debt) could adversely impact our ability to make cash distributions. If our expansion projects take longer than their contemplated schedules, then our facility could experience prolonged downtime, which could adversely affect our results of operations, financial condition and ability to make cash distributions.

Future demand for methanol for MTBE production may be adversely affected by regulatory developments.

Changes in environmental, health and safety laws, regulations or requirements could impact methanol demand for the production of methyl tertiary butyl ether (“MTBE”). In 2012, methanol demand for the production of MTBE, a source of octane and an oxygenate for gasoline, represented approximately 13% of global methanol demand. Several years ago, environmental concerns and legislative action related to gasoline leaking into water supplies from underground gasoline storage tanks in the United States resulted in the phase-out of MTBE as a gasoline additive in the United States. However, approximately 0.7 million metric tons of methanol was used in the United States in 2012 to produce MTBE for export markets, where demand for MTBE has continued at strong levels. Demand for methanol for use in MTBE production in the United States could decline materially if export demand is impacted by governmental legislation or policy changes. The EPA is currently reviewing the human health effects of MTBE, including its potential carcinogenicity. The European Union issued a final risk assessment report on MTBE in 2002 that permitted the continued use of MTBE, although several risk reduction measures relating to the storage and handling of fuels were recommended. Governmental efforts in recent years in some countries, primarily in the European Union and Latin America, to promote biofuels and alternative fuels through legislation or tax policy are also putting competitive pressures on the use of MTBE in gasoline in these countries. Declines in demand for methanol for use in MTBE production could have an adverse impact on our results of operations, financial condition and ability to make cash distributions.

Future demand for methanol may be adversely affected by regulatory developments.

Some of our customers use methanol that we supply to manufacture formaldehyde, among other chemicals. Formaldehyde currently represents the largest single demand use for methanol in the United States.

 

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Formaldehyde, a component of resins used as wood adhesives and as a raw material for engineered plastics and a variety of other products, including elastomers, paints, building products, foams, polyurethane and automotive products, has been classified by the EPA as a likely carcinogen. Changes in environmental, health and safety laws, regulations or requirements relating to formaldehyde could impact methanol demand, which could indirectly have a material adverse effect on our business. In 2011, the National Toxicological Program of the U.S. Department of Health and Human Services (the “NTP”) issued its 12th Report on Carcinogens (“RoC”) which lists formaldehyde as “known to be a human carcinogen.” In December 2011, Congress directed NTP to refer its report on formaldehyde to the National Academy of Sciences (“NAS”) for further review, but the current RoC could have an adverse effect on our customers regardless of the outcome from the NAS review. In addition, the EPA is considering regulatory options for setting limits on formaldehyde emissions from composite wood products that use formaldehyde based adhesives. In 2010, the U.S. Formaldehyde Standards for Composite Wood Products Act became effective required the EPA to promulgate regulations implementing the Act by January 1, 2013. However, the EPA has yet to propose these regulations, although they are expected to be promulgated sometime in 2013. It is also possible that additional regulatory requirements could be proposed or adopted that would affect our formaldehyde-producing customers. In addition, the EPA is evaluating non-cancer risks associated with exposure to methanol. As a result of these present and possible future regulatory initiatives, we cannot assure you that the demand for our methanol for use in formaldehyde production, and our results of operations, will not be materially and adversely affected. Please read “Business—Environmental Matters” for further information.

Any limitations on the use of nitrogen fertilizer for agricultural purposes could have a material adverse effect on the market for ammonia and on our results of operations, financial condition and ability to make cash distributions.

Conditions in the U.S. agricultural industry may significantly impact our operating results. State and federal governmental regulations and policies, including farm and biofuel subsidies and commodity support programs, as well as the prices of fertilizer products, may also directly or indirectly influence the number of acres planted, the mix of crops planted and the use of ammonia for particular agricultural applications. Developments in crop technology, such as nitrogen fixation, which is the conversion of atmospheric nitrogen into compounds that plants can assimilate, could also reduce the use of chemical fertilizers and adversely affect the demand for nitrogen fertilizer and thus affect general demand for and pricing of ammonia. Unfavorable industry conditions and new technological developments could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

In addition, future federal or state environmental laws and regulations, or new interpretations of existing laws or regulations, could limit our ability to market and sell our products to end users. From time to time, various state legislatures have considered limitations on the use and application of chemical fertilizers due to concerns about the impact of these products on the environment. In addition, a number of states have adopted or proposed numeric nutrient water quality criteria that could result in decreased demand for fertilizer products in those states. For instance, in Florida, the EPA and the Florida Department of Environmental Protection (“FDEP”) have issued rules regarding excess nitrogen and phosphorus in waterbodies, as these nutrients have been linked to algae blooms. In response to a consent decree, the EPA has finalized a rule for inland waters in Florida that FDEP had not included in its rulemaking, but the EPA has proposed to stay the effectiveness of this rule until November 15, 2013. The EPA’s rule may require farmers to implement best management practices, including the reduction of fertilizer use, to reduce the impact of fertilizer on water quality. Any such laws, regulations or interpretations could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

 

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A major factor underlying the current high level of demand for nitrogen-based fertilizer products is the expanding production of ethanol. A decrease in ethanol production, an increase in ethanol imports or a shift away from corn as a principal raw material used to produce ethanol could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

A major factor underlying the current high level of demand for nitrogen-based fertilizer products is the expanding production of ethanol in the United States and the expanded use of corn in ethanol production. Ethanol production in the United States is highly dependent upon numerous federal and state laws and regulations, and is made significantly more competitive by various federal and state incentives, mandated production of ethanol pursuant to federal renewable fuel standards, and permitted increases in ethanol percentages in gasoline blends, such as E15, a gasoline blend containing 15% ethanol. However, a number of factors, including a continuing “food versus fuel” debate and studies showing that expanded ethanol production may increase the level of greenhouse gases in the environment, have resulted in calls to reduce subsidies for ethanol, allow increased ethanol imports and adopt temporary waivers of the current renewable fuel standard levels, any of which could have an adverse effect on corn-based ethanol production, planted corn acreage and fertilizer demand. Therefore, ethanol incentive programs may not be renewed, or if renewed, they may be renewed on terms significantly less favorable to ethanol producers than current incentive programs. For example, on December 31, 2011, Congress allowed both the 45 cents per gallon ethanol tax credit and the 54 cents per gallon ethanol import tariff to expire. Similarly, the EPA’s waivers partially approving the use of E15 could be revised, rescinded or delayed. These actions could have a material adverse effect on ethanol production in the U.S., which could reduce the demand for ammonia for use as a nitrogen fertilizer. If such reduced demand for nitrogen fertilizer in the United States were significant and prolonged, it could adversely affect the prices we receive on sales of our ammonia products to industrial customers, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Furthermore, most ethanol is currently produced from corn and other raw grains, such as milo or sorghum, especially in the Midwest. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste and energy crops (plants grown for use to make biofuels or directly exploited for their energy content). If an efficient method of producing ethanol from cellulose-based biomass is developed, the demand for corn may decrease significantly, which could reduce demand for nitrogen fertilizer products and have a material adverse effect on the prices we receive on sales of our ammonia products and our results of operations, financial condition and ability to make cash distributions.

Evolving environmental laws and regulations on hydraulic fracturing could have an indirect effect on our financial performance.

Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations, and is primarily presently regulated by state agencies. However, Congress has in the past and may in the future consider legislation to regulate hydraulic fracturing by federal agencies. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing, and are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on oil and/or natural gas drilling activities. The EPA is also moving forward with various related regulatory actions, including approving, on April 17, 2012, new regulations requiring, among other matters, “green completions” of hydraulically-fractured wells by 2015. We do not believe these new regulations will have a direct effect on our operations, but because oil and/or natural gas production using hydraulic fracturing is growing rapidly in the United States, if new or more stringent federal, state or local legal restrictions relating to such drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and an increase in the price of natural gas. An increase in the price of natural gas could adversely affect our gross margins. In addition, a significant and sustained increase in domestic natural gas prices could make it more attractive for international

 

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producers of methanol and ammonia to import their products into the United States, which competition could adversely affect our results of operations, financial condition and our ability to make cash distributions.

Our operations are dependent on third parties and their pipelines to provide us with our natural gas, hydrogen and nitrogen feedstocks. A deterioration in the financial condition of a third-party supplier, the inability of a third-party supplier to perform in accordance with its contractual obligations or the unavailability of a supplier’s pipeline could have a material adverse effect on our results of operations, financial condition and our ability to make cash distributions.

Our operations depend in large part on the performance of third-party suppliers, including Kinder Morgan, DCP Midstream, Florida Gas Transmission, Houston Pipeline Company, Air Products LLC (“Air Products”) and Air Liquide Large Industries U.S. LP (“Air Liquide”) for the supply of natural gas, hydrogen and nitrogen. Our ability to obtain natural gas and other inputs necessary for the production of methanol and ammonia is dependent upon the availability of these third parties’ pipeline systems interconnected to our facility. Because we do not own these pipelines, their continuing operation is not within our control. These pipelines may become unavailable for a number of reasons, including testing, maintenance, capacity constraints, accidents, government regulation, weather-related events or other third party actions. If third-party pipelines become partially or completely unavailable, our ability to operate could be restricted and the transportation costs of our feedstock supply could increase, thereby reducing our profitability. In addition, should any of our third-party suppliers fail to perform in accordance with existing contractual arrangements, our operations could be forced to halt. Alternative sources of supply could be difficult to obtain. Any downtime associated with our operations, even for a limited period, could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Delays, interruptions or other limitations in the transportation of the products we produce could affect our operations.

Transportation logistics play an important role in allowing us to supply products to our customers. Any significant delays, interruptions or other limitations on the ability to transport our products could negatively affect our operations. Currently, all of our ammonia and approximately 55% of our methanol is transported by barge along the Gulf Coast. A significant portion of our methanol production is transported directly to certain of our customers through their pipelines. We may experience risks associated with distribution of our products by barge or pipelines. Delays and interruptions may be caused by weather-related events, including hurricanes, that would prevent the operation of barges for transport of our methanol and ammonia. Transport by pipeline may be interrupted because of accidents, earthquakes, hurricanes, governmental regulation, terrorism or other third party actions. Prolonged interruptions in the transport of our products by barge or pipeline could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Our customers purchase our ammonia and, in certain circumstances, our methanol on an FOB delivered basis at our facility and then arrange and pay to transport them to their final destinations by barge according to customary practice in our market. Methanol is also distributed to certain of our customers through pipelines connected directly to their facilities. However, in the future, our customers’ transportation needs and preferences may change and our customers may no longer be willing or able to transport purchased product from our facility or accept our product through their pipelines. In the event that our competitors are able to transport their products more efficiently or cost effectively than we do or work with our customers to develop direct pipelines to those customers, those customers may reduce or cease purchases of our products. If this were to occur, we could be forced to make a substantial investment in transportation capabilities to meet our customers’ delivery needs, and this would be expensive and time consuming. We may not be able to obtain transportation capabilities on a timely basis or at all, and our inability to provide transportation for products could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

 

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We currently derive substantially all of our revenues from a limited number of customers, and the loss of any of these customers without replacement on comparable terms would affect our results of operations, financial condition and ability to make cash distributions.

We derive, and believe that we will continue to derive, substantially all of our revenues from a limited number of customers. For the year ended December 31, 2012, Transammonia, Koch, Methanex and Arkema accounted for approximately 50.6%, 12.0%, 11.2% and 9.8%, respectively, of our total revenues. For the three months ended March 31, 2013, Methanex, Koch, Rentech and Transammonia accounted for approximately 35.5%, 21.3%, 17.9% and 15.1%, respectively, of our total revenues. Our customers, at any time, may decide to purchase fewer metric tons of methanol or ammonia from us. If our customers decide to purchase fewer metric tons of methanol or ammonia or at lower prices, and we are unable to find replacement counterparties on terms as favorable as our current arrangements, our results of operations, financial condition and ability to make cash distributions may be materially adversely affected.

We compete with certain of our customers which may result in conflicts of interest between us and those customers.

We compete with certain of our customers, including Methanex, Koch, Transammonia and Rentech. As competitors, our customers may take actions that would not be in our best interest. These customers may determine that it is strategically advantageous for them to reduce purchases of our product. In addition, they may sell our product to our other customers in an effort to reduce our market share. Any of these actions by our customers could have an adverse effect on our results of operations, financial condition and ability to make cash distributions.

All of our operations are located at a single facility in Texas, which makes us vulnerable to risks associated with operating in one geographic area.

The geographic concentration of our production facility in the Texas Gulf Coast means that we may be disproportionately exposed to disruptions in our operations if the region experiences severe weather, transportation capacity constraints, constraints on the availability of required equipment, facilities, personnel or services, significant governmental regulation or natural disasters. Although we maintain insurance coverage to cover a portion of these types of risks, there are potential risks associated with our operations not covered by insurance. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. Downtime or other delays or interruptions to our operations from any of such factors could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Anhydrous ammonia is extremely hazardous. Any liability for accidents involving anhydrous ammonia that cause severe damage to property or injury to the environment and human health could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. In addition, the costs of transporting anhydrous ammonia could increase significantly in the future.

We manufacture, process, store, handle, distribute and transport anhydrous ammonia, which is extremely hazardous. Major accidents or releases involving anhydrous ammonia could cause severe damage or injury to property, the environment and human health, as well as a possible disruption of supplies and markets. Such an event could result in civil lawsuits, fines, penalties and regulatory enforcement proceedings, all of which could lead to significant liabilities. Any damage to persons, equipment or property or other disruption of our ability to produce or distribute our products could result in a significant decrease in operating revenues and significant additional cost to replace or repair and insure our assets, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

 

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In addition, we may incur significant losses or costs relating to the operation of barges used for the purpose of transporting our anhydrous ammonia. Due to the dangerous and potentially toxic nature of the cargo, a barge accident may result in fires, explosions and pollution. These circumstances may result in sudden, severe damage or injury to property, the environment and human health. In the event of pollution, we may be held responsible even if we are not at fault and complied with the laws and regulations in effect at the time of the accident. Litigation arising from accidents involving anhydrous ammonia may result in our being named as a defendant in lawsuits asserting claims for large amounts of damages, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.

Our operations are subject to a variety of federal, state and local environmental laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal and remediation of solid and hazardous waste and materials. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations or facility shutdowns.

In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. These expenditures or costs for environmental compliance could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Our business is subject to accidental spills, discharges or other releases of hazardous substances into the environment. Past or future spills related to our facility or transportation of products or hazardous substances from our facility may give rise to liability (including strict liability, or liability without fault, and potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) for past or future spills without regard to fault or whether our actions were in compliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated with the facility we currently own and operate, facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or by-products containing hazardous substances for treatment, storage or disposal. The potential penalties and cleanup costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

In addition, we may incur liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facility. We may also face liability for personal injury, property damage, natural resource damage or for cleanup costs for the alleged migration of contamination or other hazardous substances from our facility to adjacent and other nearby properties.

We may incur future costs relating to the off-site disposal of hazardous wastes. Companies that dispose of, or arrange for the transportation or disposal of, hazardous substances at off-site locations may be held jointly and severally liable for the costs of investigation and remediation of contamination at those off-site locations, regardless of fault. We could become involved in litigation or other proceedings involving off-site waste disposal and the damages or costs in any such proceedings could be material.

 

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Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of discussion or implementation. At the federal legislative level, Congress could adopt some form of federal mandatory greenhouse gas emission reduction laws, although the specific requirements and timing of any such laws are uncertain at this time. In June 2009, the U.S. House of Representatives passed a bill that would create a nationwide cap-and-trade program designed to regulate emissions of carbon dioxide, methane and other greenhouse gases. A similar bill was introduced in the U.S. Senate, but was not voted upon. Congressional passage of such legislation does not appear likely at this time, though it could be adopted at a future date. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.

In the absence of congressional legislation curbing greenhouse gas emissions, the EPA is moving ahead administratively under its federal Clean Air Act (“CAA”) authority. In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring our greenhouse gas emissions from our facility and will report the emissions to the EPA beginning in 2011. On December 7, 2009, the EPA finalized its “endangerment finding” that greenhouse gas emissions, including CO2, pose a threat to human health and welfare. The finding allows the EPA to regulate greenhouse gas emissions as air pollutants under the CAA. In May 2010, the EPA finalized the “Greenhouse Gas Tailoring Rule,” which establishes new greenhouse gas emissions thresholds that determine when stationary sources, such as our facility, must obtain permits under the Prevention of Significant Deterioration (“PSD”) and Title V programs of the CAA. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, such as our debottlenecking project, the facility would need to evaluate and install BACT for its greenhouse gas emissions. Phase-in permit requirements commenced for the largest stationary sources in 2011. Several of the EPA’s greenhouse gas rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

On May 21, 2013, the Texas Legislature passed H.B. 788 which is intended to streamline GHG permitting in Texas by directing TCEQ to promulgate rules to be approved by EPA that would replace EPA permitting of GHGs in Texas with TCEQ permitting. The bill was sent to the Governor on May 22, 2013. Depending on how and when TCEQ implements this legislation, TCEQ could impose additional requirements on our operations that could increase our operating costs.

The implementation of EPA regulations and/or the passage of federal or state climate change legislation will likely result in increased costs to (i) operate and maintain our facility, (ii) install new emission controls on our facility and (iii) administer and manage any greenhouse gas emissions program. Increased costs associated with compliance with any future legislation or regulation of greenhouse gas emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

In addition, climate change legislation and regulations may result in increased costs not only for our business but also for agricultural producers that utilize our fertilizer products, thereby potentially decreasing demand for our fertilizer products. Decreased demand for our fertilizer products may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

New regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities could result in higher operating costs.

The costs of complying with regulations relating to the transportation of hazardous chemicals and security associated with our facility may have a material adverse effect on our results of operations, financial

 

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condition and ability to make cash distributions. Targets such as chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. The chemical industry has responded to the issues that arose in response to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terrorist attacks could lead to even stronger, more costly initiatives. Simultaneously, local, state and federal governments have begun a regulatory process that could lead to new regulations impacting the security of chemical plant locations and the transportation of hazardous chemicals. Our business could be materially adversely affected by the cost of complying with new regulations.

We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Our facility is subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions if we are subjected to significant fines or compliance costs.

A shortage of skilled labor, together with rising labor costs, could adversely affect our results of operations, financial condition and ability to make cash distributions.

Efficient production of methanol and ammonia using modern techniques and equipment requires skilled employees. To the extent that the services of our key technical personnel become unavailable to us for any reason, we would be required to hire other personnel. We may not be able to locate or employ such qualified personnel on acceptable terms or at all. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. If we are unable to find qualified employees, or if the cost to find qualified employees increases materially, our results of operations, financial condition and ability to make cash distributions could be adversely affected.

Our indebtedness could adversely affect our financial condition or make us more vulnerable to adverse economic conditions.

Our level of indebtedness could have significant effects on our business, financial condition, results of operations and cash flows and, therefore, important consequences to your investment in our securities, such as:

 

   

we may be limited in our ability to obtain additional financing to fund our working capital needs, capital expenditures and debt service requirements or our other operational needs;

 

   

we may be limited in our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our debt;

 

   

we may be at a competitive disadvantage compared to competitors with less leverage since we may be less capable of responding to adverse economic and industry conditions; and

 

   

we may not have sufficient flexibility to react to adverse changes in the economy, our business or the industries in which we operate.

 

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Our ability to service our indebtedness will depend on our ability to generate cash in the future.

Our ability to make payments on our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to general economic and market conditions and financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash to fund our working capital requirements, capital expenditure, debt service and other liquidity needs, which could result in our inability to comply with financial and other covenants contained in our debt agreements, our being unable to repay or pay interest on our indebtedness, and our inability to fund our other liquidity needs. If we are unable to service our debt obligations, fund our other liquidity needs and maintain compliance with our financial and other covenants, we could be forced to curtail our operations, our creditors could accelerate our indebtedness and exercise other remedies and we could be required to pursue one or more alternative strategies, such as selling assets or refinancing or restructuring our indebtedness. However, we cannot assure you that any such alternatives would be feasible or prove adequate.

Restrictions in the agreements governing our current and future indebtedness contain or will contain significant limitations on our business operations, including our ability to pay distributions and other payments.

As of March 31, 2013, on a pro forma basis after giving effect to this offering, the use of the estimated proceeds hereof and the other transactions described under “Prospectus Summary—The Transactions,” we would have had $235.0 million of debt outstanding, excluding unamortized debt discount of $2.4 million. We and our subsidiary may incur significant additional indebtedness in the future. Our ability to pay distributions to our unitholders will be subject to covenant restrictions under the agreements governing our indebtedness. We expect that our ability to make distributions to our unitholders will depend, in part, on our ability to satisfy applicable covenants as well as the absence of a default or event of default under the agreements governing our indebtedness. If we were unable to comply with any such covenant restrictions in any quarter, our ability to pay distributions to unitholders would be curtailed.

In addition, we will be subject to covenants contained in our debt agreements and any agreement governing other future indebtedness that will, subject to significant exceptions, limit our ability and the ability of OCIB or any of our future subsidiaries to, among other things, incur, assume or permit to exist additional indebtedness, guarantees and other contingent obligations, incur liens, make negative pledges, pay dividends or other distributions, make payments to our subsidiaries, make certain loans and investments, consolidate, merge or sell all or substantially all of our assets. Any failure to comply with these covenants could result in a default under our debt agreements. Upon a default, unless waived, our lenders would have all remedies available to a secured lender and could elect to terminate their commitments, cease making further loans, cause their loans to become due and payable in full, institute foreclosure proceedings against us or our assets and force us and our subsidiaries into bankruptcy or liquidation.

We are a holding company and depend upon our operating subsidiary, OCIB, for our cash flows.

We are a holding company. All of our operations are conducted and all of our assets are owned by OCIB, our wholly owned subsidiary and our sole direct or indirect subsidiary. Consequently, our cash flow and our ability to meet our obligations or to make cash distributions in the future will depend upon the cash flow of OCIB and the payment of funds by OCIB to us in the form of distributions or otherwise. The ability of OCIB to make any payments to us will depend on its earnings, the terms of its indebtedness, including the terms of any debt agreements, and legal restrictions. In particular, future debt agreements entered into by OCIB may impose significant limitations on the ability of OCIB to make distributions to us and consequently our ability to make distributions to our unitholders. Please read “—We may not have sufficient cash available for distribution to pay any quarterly distribution on our common units.” For the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, our annual distribution would have been $            per unit and

 

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$            per unit, respectively, significantly less than the $            per unit distribution we project that we will be able to pay for the twelve months ending June 30, 2014.

We will incur increased costs as a result of being a publicly traded partnership, including costs related to compliance with Section 404 of Sarbanes-Oxley.

As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur as a private company. We will incur costs associated with our public company reporting requirements. We also anticipate that we will incur costs associated with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), as well as rules implemented by the SEC and the Financial Industry Regulatory Authority (“FINRA”). We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, particularly after we are no longer an emerging growth company under the JOBS Act. We also expect these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on the board of directors of our general partner or as executive officers.

We will remain an emerging growth company under the JOBS Act for up to five years. After we are no longer an emerging growth company, we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not emerging growth companies, including Section 404 of the Sarbanes-Oxley Act. In order to comply with the requirements of Section 404 of Sarbanes-Oxley, we will need to implement new financial systems and procedures. We cannot assure you that we will be able to implement appropriate procedures on a timely basis. Failure to implement such procedures could have an adverse effect on our ability to satisfy applicable obligations under the Exchange Act and Sarbanes-Oxley. For the year ended December 31, 2011, we identified deficiencies constituting a “material weakness” in our internal control over financial reporting. Specifically, we determined that we did not have adequate internal resources to establish an effective and efficient financial statement reporting process to be in compliance with generally accepted accounting principles. During 2012, we hired additional accounting personnel with appropriate levels of training and experience to remediate the material weakness. As of December 31, 2012, we had not identified any deficiencies constituting a “material weakness” in our internal control over financial reporting. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our results of operations, financial condition and ability to make cash distributions could be materially adversely affected.

As a publicly traded partnership we qualify for, and are relying on, certain exemptions from the NYSE’s corporate governance requirements. Accordingly, holders of our common units will not have the same protections afforded to equity holders of companies subject to such corporate governance requirements.

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE’s corporate governance requirements, including:

 

   

the requirement that a majority of the board of directors of our general partner consist of independent directors;

 

   

the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and

 

   

the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

 

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As a result of these exemptions, our general partner’s board of directors will not be comprised of a majority of independent directors. Our general partner’s board of directors does not currently intend to establish a nominating/corporate governance committee or a compensation committee. Accordingly, unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE. Please read “Management.”

Risks Inherent in an Investment in Us

The board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution that we generate each quarter, which could limit our ability to grow and make acquisitions.

The board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution that we generate each quarter to our unitholders, beginning with the quarter ending             , 2013. As a result, our general partner 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. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because the board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution that we generate each quarter, 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 will decrease the amount we distribute on each outstanding unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the cash available for distribution that we have to distribute to our unitholders.

Our general partner and its affiliates, including OCI, 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 that of our unitholders. Additionally, we have no control over the business decisions and operations of OCI, and OCI is under no obligation to adopt a business strategy that favors us.

Following the completion of this offering, OCI will indirectly own a non-economic general partner interest and a             % limited partner interest in us (or             % if the underwriters’ option to purchase additional common units is exercised in full) and will indirectly own and control our general partner. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owner, OCI. Conflicts of interest may arise between OCI and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including OCI, over the interests of our common unitholders. These conflicts include, among others, the following situations:

 

   

neither our partnership agreement nor any other agreement requires OCI to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by OCI to increase or decrease production, shut down or reconfigure our plant, pursue and grow particular markets, or undertake acquisition opportunities for itself. OCI’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of OCI;

 

   

OCI may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

 

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

 

   

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

 

   

our general partner will determine the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness, issuances of additional partnership interests and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is available for distribution to our common unitholders;

 

   

our general partner will determine which costs incurred by it are reimbursable by us;

 

   

our general partner may cause us to borrow funds in order to permit the payment of cash distributions;

 

   

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;

 

   

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

 

   

our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than a specified percentage of our common units (please read “The Partnership Agreement—Limited Call Right”);

 

   

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our commercial agreements with OCI; and

 

   

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

Under 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, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Duties.”

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 whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such

 

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determination, or take or decline to take such other action, in good faith and 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;

 

   

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

 

   

provides that 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 criminal; and

 

   

provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above. Please read “Description of Our Common Units—Transfer of Common Units.”

Common units are subject to our general partner’s limited call right.

If at any time our general partner and its affiliates own more than 90% 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 public unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, then concurrently with such reduction in percentage ownership, the ownership threshold to exercise the limited call right will be permanently reduced to 80%. As a result, you may be required to sell your common units at an undesirable time or at a price that is less than the market price on the date of purchase and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and then exercising its limited call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. Please read “The Partnership Agreement—Limited Call Right.”

Unitholders have very limited voting rights and, even if they are dissatisfied, they cannot remove our general partner without its consent.

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

 

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business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the member of our general partner, which is an indirect, wholly owned subsidiary of OCI. 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 our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of the offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. At closing, our general partner and its affiliates will own             % of the common units (or            % if the underwriters’ option to purchase additional common units is exercised in full).

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision 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 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.

Unitholders may have liability to repay distributions.

In the event that: (1) we make distributions to our unitholders when our nonrecourse liabilities exceed the sum of (a) the fair market value of our assets not subject to recourse liability and (b) the excess of the fair market value of our assets subject to recourse liability over such liability, or a distribution causes such a result, and (2) a unitholder knows at the time of the distribution of such circumstances, such unitholder will be liable for a period of three years from the time of the impermissible distribution to repay the distribution under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”).

Likewise, upon the winding up of the partnership, in the event that (1) we do not distribute assets in the following order: (a) to creditors in satisfaction of their liabilities; (b) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (c) to partners for the return of their contribution; and finally (d) to the partners in the proportions in which the partners share in distributions and (2) a unitholder knows at the time of such circumstances, then such unitholder will be liable for a period of three years from the impermissible distribution to repay the distribution under Section 17-807 of the Delaware Act.

A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known by the purchaser at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

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

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of OCI to transfer its membership interest in our general partner to a third

 

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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 choices.

There is no existing market for our common units, and we do not know if one will develop to provide you with adequate liquidity. If our unit price fluctuates after this offering, you could lose a significant part of your investment.

Prior to this offering, there has not been a public market for our common units. If an active trading market does not develop, you may have difficulty selling any of our common units that you buy. The initial public offering price for the common units will be determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our common units at prices equal to or greater than the price paid by you in this offering.

In addition, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies like us. These broad market and industry factors may materially reduce the market price of our common units, regardless of our operating performance.

Our unitholders who fail to furnish certain information requested by our general partner or who our general partner, upon receipt of such information, determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.

Our general partner may require each limited partner to furnish information about such limited partner’s nationality, citizenship or related status. If a limited partner fails to furnish information about such limited partner’s nationality, citizenship or other related status within a reasonable period after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as an ineligible holder. An ineligible holder does not have the right to direct the voting of such holder’s common units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is an ineligible holder. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

We may issue additional units without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

our unitholders’ proportionate ownership interest in us will decrease;

 

   

the amount of cash distributions on each unit may decrease;

 

   

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 our common units may decline.

 

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OCI USA 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.

Upon the completion of this offering, OCI USA, an indirect wholly owned subsidiary of OCI, will own              common units, representing approximately             % of our outstanding common units (or approximately             % of our outstanding common units if the underwriters exercise their option to purchase additional common units in full). Additionally, we have agreed to provide OCI USA with certain registration rights under applicable securities laws. Please read “Common Units Eligible for Future Sale.” The sale of these units 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.

Tax Risks

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

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

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. 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 U.S. 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 U.S. federal income tax purposes, we would pay U.S. 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, gain, loss, deduction 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 U.S. federal income tax purposes, there would be a 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.

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 any such taxes may substantially reduce the cash available for distribution to you.

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.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any

 

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time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. Please read “Material U.S. Federal Income Tax Consequences—Partnership Status.” We are unable to predict whether any of these changes or other proposals will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the U.S. 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 because the costs will reduce our cash available for distribution.

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 that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to him, which may require the payment of U.S. federal income taxes and, in some cases, state and local income taxes on his share of our taxable income, even if he 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.

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

If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its 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, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material U.S. 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 our 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

 

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all of our income allocated to organizations that are exempt from U.S. 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 our 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 promulgated under the Internal Revenue Code of 1986 (the “Code”), referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Common Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We will prorate our items of income, gain, loss and deduction, for U.S. federal income tax purposes, between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common 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 federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common 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 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 will adopt. 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. Latham & Watkins LLP 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 U.S. 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 effect 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 U.S. 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 effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for U.S. 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 common unitholder as to

 

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those common units could be fully taxable as ordinary income. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; 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.

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 the Partnership for U.S. federal income tax purposes.

We will be considered to have technically terminated as a partnership for U.S. 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 common unit 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 fiscal year ending December 31, 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 federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced publicly traded partnership technical termination relief 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 U.S. 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 U.S. federal income taxes, 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 control 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 initially expect to conduct business in Texas. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units. Please consult your tax advisor.

 

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USE OF PROCEEDS

We estimate that the net proceeds to us from this offering, after deducting the estimated underwriting discount, structuring fees and the estimated offering expenses payable by us, will be approximately $              million (based on an assumed initial public offering price of $             per common unit, the midpoint of the price range set forth on the cover page of this prospectus). We intend to use the net proceeds from this offering as follows:

 

   

approximately $125.0 million to repay in full and terminate the Term B-1 Loan;

 

   

approximately $170.5 million to repay in full and terminate all of OCIB’s intercompany debt with OCI Fertilizer;

 

   

to pay a portion of the costs of our debottlenecking project and other budgeted capital projects incurred after the completion of this offering; and

 

   

the remainder, if any, for general partnership purposes, including working capital.

Borrowings under the Term B-1 Loan bear interest at a variable rate based upon either LIBOR plus 4.0% per annum or the lenders’ alternative base rate plus 3.0% per annum. Borrowings under OCIB’s intercompany debt with OCI Fertilizer bear interest at LIBOR plus 9.25%. As of May 31, 2013, OCIB had $125.0 million outstanding under the Term B-1 Loan and the applicable interest rate was 5.0% per annum. As of May 31, 2013, OCIB had $170.5 million outstanding under its intercompany debt with OCI Fertilizer and the applicable interest rate was 9.45% per annum. The Term B-1 Loan matures on the earlier of the consummation of the Transactions and December 31, 2013. As of March 31, 2013, OCIB had approximately $140.0 million of intercompany debt with OCI Fertilizer maturing on August 1, 2014 and approximately $30.5 million maturing on December 31, 2014.

OCIB used the proceeds from the Term B-1 Loan to repay outstanding borrowings under its previous third-party credit facility. OCIB used the proceeds from its intercompany debt with OCI Fertilizer to fund the upgrade on our facility, to satisfy working capital requirements and for general corporate purposes. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.”

Affiliates of certain of the underwriters participating in this offering are lenders under the Term B-1 Loan and may receive a portion of the net proceeds from this offering through the repayment of indebtedness under the Term B-1 Loan. Please read “Underwriting.”

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 such exercise will be issued to the public and the remainder of the              additional common units, if any, will be issued to OCI USA. Any such common units issued to OCI USA will be issued for no additional consideration. If the underwriters exercise in full their option to purchase additional common units from us, we expect to receive net proceeds of approximately $            million, after deducting the estimated underwriting discount and structuring fees. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us for general partnership purposes.

A $1.00 increase (or decrease) in the assumed initial public offering price of $             per common unit would increase (decrease) the net proceeds to us from this offering by $            , assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and assuming the underwriters do not exercise their option to purchase additional common units, and after deducting the estimated underwriting discount, structuring fees and the estimated offering expenses payable by us. The actual initial public offering price is subject to market conditions and negotiations between us and the underwriters.

Depending on market conditions at the time of pricing of this offering and other considerations, we may sell fewer or more common units than the number set forth on the cover page of this prospectus.

 

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CAPITALIZATION

The following table sets forth the combined cash and cash equivalents and capitalization as of March 31, 2013 of:

 

   

OCIB on a historical basis; and

 

   

OCI Partners LP on a pro forma basis to reflect the issuance of our common units in this offering (based on an assumed initial public offering price of $             per common unit, the midpoint of the price range set forth on the cover page of this prospectus), the other transactions described under “Prospectus Summary—The Transactions” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

The table assumes that the underwriters do not exercise their option to purchase additional common units. 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 pursuant to any exercise of the option will be issued to OCI USA at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us for general partnership purposes.

This table is derived from, should be read together with and is qualified in its entirety by reference to OCIB’s unaudited historical interim financial statements and the accompanying notes and our unaudited pro forma condensed financial statements and accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus Summary—The Transactions,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of March 31, 2013  
     OCIB
Historical
     OCI Partners LP
Pro Forma
 
     (Unaudited)
(In Thousands)
 

Cash and cash equivalents

   $ 19,403       $                
  

 

 

    

 

 

 

Long-term debt, including current maturities:

     

Intercompany debt(1)

   $ 170,482       $  —     

Previous credit agreement(1)

     125,000         —     

Term B-1 Loan(1)

     —           —     

Term B-2 Loan(1)

     —           —     

Term Loan B(2)

     —        

Intercompany revolving credit facility (2)

     —           —     

Member’s equity / partners’ capital:

     

Member’s equity

     113,314         —     

Capital held by public:

     

Common units (none issued and outstanding actual;              issued and outstanding pro forma)

     —        

Capital held by OCI and its affiliates:

     

Common units (none issued and outstanding actual;              issued and outstanding pro forma)

     —        
  

 

 

    

 

 

 

Total member’s equity/partners’ capital

     113,314      
  

 

 

    

 

 

 

Total capitalization

   $ 408,796       $                
  

 

 

    

 

 

 

 

(1)

As of May 31, 2013, OCIB had approximately $170.5 million outstanding under its intercompany debt with OCI Fertilizer, no outstanding borrowings under its previous credit agreement, $125.0 million outstanding

 

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  under the Term B-1 Loan and $235.0 million outstanding under the Term B-2 Loan. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.”
(2) We expect that OCIB will enter into a new $235.0 million Term Loan B to replace borrowings under the Term B-2 Loan. We also expect that OCIB will enter into a new $40.0 million intercompany revolving credit facility with OCI Fertilizer. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.”

 

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DILUTION

Purchasers of common units offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per unit. Our net tangible book value as of March 31, 2013 was approximately $            million. Our pro forma net tangible book value as of March 31, 2013, after giving effect to the Transactions but prior to giving effect to the issuance and sale of common units to purchasers in this offering, would have been approximately $            million, or approximately $            per unit. Pro forma net tangible book value per unit before the completion of this offering represents the amount of our pro forma tangible assets less our pro forma total liabilities, divided by the pro forma number of common units issued to OCI and its affiliates (assuming that the              common units that could be purchased by the underwriters pursuant to their option to purchase additional common units will be instead issued to OCI USA at the expiration of the option period for no consideration).

Dilution in net tangible book value per unit represents the difference between the amount per unit paid by purchasers of our common units in this offering and the pro forma net tangible book value per unit immediately after this offering. After giving effect to the sale of              common units in this offering 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 after deducting the estimated underwriting discount, structuring fees and estimated offering expenses payable by us, our pro forma net tangible book value as of March 31, 2013 would have been approximately $            million, or approximately $            per unit. This represents an immediate increase in net tangible book value of $            per unit to OCI and its affiliates and an immediate pro forma dilution of $            per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:

 

Assumed initial public offering price per unit

      $                

Pro forma net tangible book value per unit before this offering(1)

   $                   

Increase in net tangible book value per unit attributable to purchasers in this offering and the use of proceeds

   $                   

Less: Pro forma net tangible book value per unit after this offering(2)

      $                
     

 

 

 

Immediate dilution in net tangible book value per unit to purchasers in this offering(3)

      $                
     

 

 

 

 

(1) Determined by dividing the net tangible book value of our tangible assets less total liabilities by the number of common units issued to OCI USA, an indirect wholly owned subsidiary of OCI.
(2) Determined by dividing our pro forma net tangible book value, after giving effect to the application of the net proceeds from this offering, by the total number of common units to be outstanding after this offering.
(3) A $1.00 increase (decrease) in the assumed initial public offering price of $            per unit (the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) our pro forma net tangible book value by $            , the pro forma net tangible book value per unit by $            and the dilution per unit to new investors by $            , assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and the underwriters do not exercise their option to purchase additional common units, and after deducting the estimated underwriting discount, structuring fees and estimated offering expenses payable by us. Depending on market conditions at the time of pricing of this offering and other considerations, we may sell fewer or more common units than the number set forth on the cover page of this prospectus.

The following table sets forth the number of common units that we will issue and the total consideration contributed to us by OCI and its affiliates in respect of their common units and by the purchasers of common units in this offering upon the completion of the Transactions contemplated by this prospectus:

 

     Common Units     Total Consideration  
    

Number

  

Percent

   

Amount

    

Percent

 

OCI and its affiliates(1)

                       $                                  

New investors(2)

                       $                                  

Total(3)

                       $                                  

 

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(1) The net assets contributed by OCI and its affiliates were recorded at historical cost in accordance with GAAP.
(2) Reflects the net proceeds from this offering after deducting the estimated underwriting discount, structuring fees and estimated offering expenses payable by us.
(3) A $1.00 increase (decrease) in the assumed initial public offering price of $            per unit (the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) total consideration paid by new investors and total consideration paid by all unitholders by $            million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same, and after deducting the estimated underwriting discount, structuring fees and estimated offering expenses payable by us.

If the underwriters exercise their option to purchase             common units in full, then the pro forma increase per unit attributable to new investors would be $            , the net tangible book value per unit after this offering would be $            and the dilution per unit to new investors would be $            . In addition, new investors would purchase              common units, or approximately     % of units outstanding, and the total consideration contributed to us by new investors would increase to $             million, or     % of the total consideration contributed (based on an assumed initial public offering price of $             per unit, the midpoint of the price range set forth on the cover page of this prospectus).

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy and restrictions on distributions in conjunction with the specific assumptions upon which our cash distribution policy is based. Please read “—Assumptions and Considerations” below. For additional information regarding our historical and our pro forma operating results, you should refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited historical financial statements, our unaudited historical financial statements and our unaudited pro forma condensed financial statements included elsewhere in this prospectus. In addition, you should read “Risk Factors” and “Forward-Looking Statements” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

General

Our Cash Distribution Policy

Upon the completion of this offering, the board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution that we generate each quarter. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. If we have cash available for distribution, our first distribution will take place following the first full quarter after the completion of this offering and will include cash available for distribution with respect to the period beginning on the closing date of this offering and ending on the last day of the first full quarter ending after the completion of this offering. We expect that cash available for distribution for each quarter will generally equal the cash we generate during the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. We intend to fund a portion of the costs of our debottlenecking project and other budgeted capital projects incurred after the completion of this offering with a portion of the net proceeds from this offering. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Other than the expansion capital expenditures we intend to fund with the net proceeds from this offering, we expect to finance substantially all of our growth externally, either with commercial bank borrowings or by debt issuances or additional issuances of equity.

Because our policy will be to distribute 100% of cash available for distribution each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low cash flow from operations, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our operating cash flow during each quarter. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of, among other things, variations in our operating performance and variations in our cash flow caused by fluctuations in the price of natural gas, methanol and ammonia as well as our working capital requirements, planned and unplanned downtime and capital expenditures and our margins from selling our products. Please read “Business—Customers and Contracts,” “Business—Feedstock Supply” and “Business—Seasonality and Volatility.” These variations may be significant. The board of directors of our general partner may change our cash distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions to our unitholders on a quarterly or other basis.

 

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

There is no guarantee that unitholders will receive cash distributions from us. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including:

 

   

Our unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. Our policy will be to distribute to our unitholders each quarter 100% of the cash available for distribution we generate each quarter, as determined quarterly by the board of directors of our general partner, but it may change this policy at any time.

 

   

Our business performance is expected to be more volatile, and our cash flows are expected to be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our cash distributions will be volatile and are expected to vary quarterly and annually.

 

   

Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly cash distributions over time. Furthermore, none of our limited partner interests, including those indirectly held by OCI, will be subordinate in right of distribution payments to the common units sold in this offering.

 

   

The amount of cash available for distribution, the distributions we pay under our cash distribution policy and the decision to make any distribution will be determined by the board of directors of our general partner. Our partnership agreement will not provide for any minimum quarterly distributions. Prior to making any distributions on our units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. In connection with this offering, we, our general partner and OCI (or its affiliate) will enter into an omnibus agreement pursuant to which OCI (or its affiliate) will agree to provide us with labor and operational services related to operating our facility and we will reimburse OCI (or its affiliate) for the provision of such services. Under the terms of the omnibus agreement, OCI (or its affiliate) will agree to provide us with selling, general and administrative services, and we will pay to OCI (or its affiliate) a fixed annual fee of $15.0 million for the provision of such services, which amount excludes approximately $4.0 million of estimated incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash to pay distributions to our unitholders.

 

   

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

 

   

We expect that our cash distribution policy will be subject to restrictions on distributions under our debt agreements. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.” Should we be unable to satisfy these restrictions, we would be prohibited from making cash distributions to you.

 

   

We may lack sufficient cash to make distributions to our unitholders due to a number of factors that would adversely affect us, including, but not limited to, decreases in revenues or increases in operating expenses, principal and interest payments on debt, working capital requirements, capital expenditures, disruptions in the operations at our facility or anticipated cash needs. Please read “Risk Factors” for information regarding these factors.

 

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We have a limited operating history upon which to rely in evaluating whether we will have sufficient cash to allow us to pay distributions on our common units. While we believe, based on our financial forecast and related assumptions, that we should have sufficient cash to enable us to pay the forecasted aggregate distribution on all of our common units for the twelve months ending June 30, 2014, we may be unable to pay the forecasted distribution or any amount on our common units.

 

   

We intend to pay our distributions on or about the fifteenth day of each February, May, August and November to holders of record on or about the last day of each prior month. If we have cash available for distribution, our first distribution will take place following the first full quarter after the completion of this offering and will include cash available for distribution with respect to the period beginning on the closing date of this offering and ending on the last day of the first full quarter ending after the completion of this offering.

In the sections that follow, we present the following two tables:

 

   

“OCI Partners LP Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012 and the Twelve Months Ended March 31, 2013,” in which we present our estimate of the amount of pro forma cash available for distribution we would have had for the year ended December 31, 2012 and the twelve months ended March 31, 2013 had the Transactions described under “Prospectus Summary—The Transactions” been completed on January 1, 2012, in each case, based on our unaudited pro forma condensed financial statements included elsewhere in this prospectus. Please read “Unaudited Pro Forma Condensed Financial Statements” beginning on page F-2 of this prospectus; and

 

   

“OCI Partners LP Unaudited Forecasted Cash Available for Distribution for the Twelve Months Ending June 30, 2014,” in which we present our unaudited forecast of cash available for distribution for the twelve months ending June 30, 2014.

We do not, as a matter of course, make or intend to make public projections as to our future revenues, earnings or other results. However, our management has prepared the prospective financial information set forth under “—Unaudited Forecasted Cash Available for Distribution” below to supplement our historical and unaudited pro forma condensed financial statements included elsewhere in this prospectus. To management’s knowledge and belief, the accompanying prospective financial information was prepared on a reasonable basis, reflects the best currently available estimates and judgments and presents our expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being indicative of future results, and, therefore, readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. The forecast included in this prospectus has been prepared by, and is the responsibility of, our management. KPMG has not examined, compiled or performed any procedures with respect to the forecast, and, accordingly, KPMG does not express an opinion or any other form of assurance with respect thereto. The KPMG report included in this prospectus relates to our historical financial information. The KPMG report does not extend to the forecast and should not be read to do so. Please read “Risk Factors” and “Forward-Looking Statements.”

Unaudited Pro Forma Cash Available for Distribution

Our pro forma cash available for distribution generated during the year ended December 31, 2012 and the twelve months ended March 31, 2013 would have been approximately $67.0 million and $129.0 million, respectively. Based on our initial cash distribution policy, this amount would have resulted in an aggregate annual distribution equal to $             per unit and $             per unit for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively.

 

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The pro forma cash available for distribution calculations set forth below take into account the assumption that incremental general and administrative expenses related to being a publicly traded partnership were paid during the applicable periods in which they are included. The incremental general and administrative expenses reflect our estimate of the incremental expenses that we expect to incur as a publicly traded partnership, including expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing our common units on the NYSE, independent auditor fees, legal fees, investor relations costs, registrar and transfer agent fees, directors and officers insurance and director compensation. We estimate that our incremental general and administrative expenses will be approximately $4.0 million per year; however, actual amounts could differ from this estimate and such differences could be material. The estimated incremental general and administrative expenses are reflected in our pro forma cash available for distribution but are not reflected in our unaudited pro forma condensed financial statements included elsewhere in this prospectus.

The unaudited pro forma condensed financial statements, from which pro forma cash available for distribution is derived, do not purport to present our results of operations had the Transactions contemplated below actually been completed as of the date indicated below. Furthermore, cash available for distribution is a cash concept, while our unaudited pro forma condensed financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the Transactions contemplated below in earlier periods.

The following table illustrates, on a pro forma basis for the year ended December 31, 2012 and the twelve months ended March 31, 2013, the amount of cash that would have been available for distribution to our unitholders, assuming that the Transactions (as defined under “Prospectus Summary—The Transactions”) had occurred, in each case, on January 1, 2012:

OCI Partners LP

Unaudited Pro Forma Cash Available for Distribution

for the

Year Ended December 31, 2012 and the Twelve Months Ended March 31, 2013

 

    

Pro Forma
Year Ended
December 31, 2012

    

Pro Forma
Twelve Months
Ended

March 31, 2013

 
    

(unaudited)

(in millions, except per unit data)

 

Net income

   $ 61.7       $ 119.0   

Add:

     

Interest expense and other financing costs(1)

     11.0         11.2   

Depreciation expense

     11.4         15.9   

Income tax expense(2)

     1.0         1.5   
  

 

 

    

 

 

 

EBITDA(3)

   $ 85.1       $ 147.6   

Subtract:

     

Net debt service costs(4)

     13.1         13.1   

Income tax expense(2)

     1.0         1.5   

Estimated incremental general and administrative expenses(5)

     4.0         4.0   
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 67.0       $ 129.0   
  

 

 

    

 

 

 

Aggregate annual distributions per unit

   $         $     

Number of common units

     

Other Information

     

Expansion capital expenditures(6)

     194.0         116.7   

 

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(1) Interest expense and other financing costs represent the interest expense and fees (including amortization of debt issuance costs), net of interest income, related to our borrowings. Our pro forma interest expense is based on (i) a 4.5% interest rate on the new Term Loan B, (ii) amortization of deferred financing costs and (iii) a 0.5% commitment fee on the unused portion of the new $40.0 million intercompany revolving credit facility with OCI Fertilizer. We have assumed that OCIB did not incur any borrowings under the intercompany revolving credit facility.
(2) Income tax expense relates to Texas margin taxes.
(3) For a definition of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data.”
(4) Net debt service cost is defined as cash interest expense plus annual required principal payments of approximately $2.4 million (1% of the outstanding balance under the new Term Loan B) plus a 0.5% commitment fee on the unused portion of the new $40.0 million intercompany revolving credit facility, and excludes amortization of deferred financing costs.
(5) Reflects an adjustment for estimated incremental general and administrative expense we expect that we will incur as a publicly traded partnership, including expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing our common units on the NYSE, independent auditor fees, legal fees, investor relations costs, registrar and transfer agent fees, directors and officers insurance and director compensation.
(6) Expansion capital expenditures during these periods related to the upgrade of our facility and were funded with borrowings under credit facilities or intercompany debt.

Unaudited Forecasted Cash Available for Distribution

Subject to certain assumptions and assuming the board of directors of our general partner declares distributions in accordance with our cash distribution policy, we expect that our cash available for distribution for the twelve months ending June 30, 2014 will be approximately $183.9 million, or $            per unit. In “—Assumptions and Considerations” below, we discuss the material assumptions underlying our forecast of cash available for distribution for the twelve months ending June 30, 2014. The forecasted cash available for distribution discussed below should not be viewed as management’s projection of the actual cash available for distribution that we will generate during the twelve months ending June 30, 2014. We can give you no assurance that our assumptions will be realized or that we will generate any cash available for distribution during the twelve-month forecast period or otherwise, in which event we will not be able to pay cash distributions on our common units.

We do not, as a matter of course, make or intend to make public projections as to our future revenues, earnings or other results. However, our management has prepared the prospective financial information set forth below in the table entitled “OCI Partners LP Unaudited Forecasted Cash Available for Distribution for the Twelve Months Ending June 30, 2014” to present our expectations regarding our ability to generate $183.9 million of cash available for distribution for the twelve months ending June 30, 2014. 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 the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments and presents, to the best of management’s knowledge and belief, our expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being indicative of future results, and, therefore, readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.

Although our management considers the assumptions and estimates underlying the prospective financial information reasonable as of the date of its preparation, such assumptions and estimates are inherently uncertain and are subject to a wide variety of risks and uncertainties, including significant business, economic and

 

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competitive risks and uncertainties described under the headings “Risk Factors” and “Forward-Looking Statements” elsewhere in this prospectus, that could cause our actual results to differ materially from those contained in the prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that our actual results will not differ materially from those presented in the prospective financial information. Irrespective, investors in our common units should not regard inclusion of the prospective financial information in this prospectus as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to our financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the forecasted distributions on all of our outstanding common units for the twelve months ending June 30, 2014 should not be regarded as a representation by us, the underwriters or any other person that we will generate such amount of cash available for distribution or make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate forecasted cash available for distribution for the twelve months ending June 30, 2014. The assumptions that we believe are relevant to particular line items in the table below are explained in “—Assumptions and Considerations.”

The forecast included in this prospectus has been prepared by, and is the responsibility of, our management. KPMG has not examined, compiled or performed any procedures with respect to the forecast, and, accordingly, KPMG does not express an opinion or any other form of assurance with respect thereto. The KPMG report included in this prospectus relates to our historical financial information. The KPMG report does not extend to the forecast and should not be read to do so.

 

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OCI Partners LP

Unaudited Forecasted Cash Available for Distribution

for the Twelve Months Ending June 30, 2014

The following table illustrates the amount of cash that we estimate we will generate for each calendar quarter in the twelve months ending June 30, 2014 that would be available for distribution to our unitholders. All of the amounts in the table below are estimates.

 

     Three Months Ending      Twelve
Months
Ending
 
    

September

30, 2013

    

December

31, 2013

    

March
31, 2014

    

June
30, 2014

    

June
30, 2014

 
     (in millions)  

Revenues

   $ 100.5       $ 100.5       $ 99.3       $ 100.9       $ 401.2   

Cost of goods sold

     45.4         45.4         44.6         45.0         180.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Gross profit

     55.1         55.1         54.7         55.9         220.8   

Depreciation expense

     5.4         5.5         5.5         5.6         22.0   

Selling, general and administrative expenses(1)

     4.8         4.8         4.7         4.7         19.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Income (loss) from operations before interest and tax expense

     44.9         44.8         44.5         45.6         179.8   

Net interest expense

     2.7         2.6         2.6         2.6         10.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Income before tax expense

     42.2         42.2         41.9         43.0         169.3   

Income tax expense

     0.5         0.5         0.5         0.5         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income

   $ 41.7       $ 41.7       $ 41.4       $ 42.5       $ 167.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Adjustments to reconcile net income to EBITDA:

              

Add (subtract):

              

Net interest expense and other financing costs(2)

     2.7         2.6         2.6         2.6         10.5   

Depreciation expense

     5.4         5.5         5.5         5.6         22.0   

Income tax expense

     0.5         0.5         0.5         0.5         2.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA(3)

   $ 50.3       $ 50.3       $ 50.0       $ 51.2       $ 201.8   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Adjustments to reconcile EBITDA to cash available for distribution:

              

Subtract:

              

Net debt service costs(4)

     3.2         3.2         3.2         3.2         12.8   

Income tax expense(5)

     0.5         0.5         0.5         0.5         2.0   

Expansion capital expenditures(6)

     15.3         14.3         32.7         31.2         93.5   

Maintenance capital expenditures

     0.5         0.8         0.9         0.9         3.1   

Add:

              

Net proceeds from this offering to fund expansion capital expenditures

     15.3         14.3         32.7         31.2         93.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Cash Available for Distribution

   $ 46.1       $ 45.8       $ 45.4       $ 46.6       $ 183.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Aggregate annual distributions per unit

               $               

Number of common units

              

 

(1) Selling, general and administrative expenses includes an adjustment of $4.0 million for estimated incremental general and administrative expense we expect that we will incur as a publicly traded partnership, including expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing our common units on the NYSE, independent auditor fees, legal fees, investor relations costs, registrar and transfer agent fees, directors and officers insurance and director compensation.

 

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(2) Net interest expense and other financing costs represent the interest expense and fees (including amortization of debt issuance costs), net of interest income and amounts capitalized, related to our borrowings. Forecasted interest expense is based on (i) a 4.5% interest rate on the new Term Loan B, (ii) amortization of deferred financing costs and (iii) a 0.5% commitment fee on the unused portion of the new $40.0 million intercompany revolving credit facility. We have assumed that OCIB did not incur any borrowings under the intercompany revolving credit facility.
(3) For a definition of the non-GAAP financial measure of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data.”
(4) Net debt service cost is defined as cash interest expense plus annual required principal payments of $2.4 million (1% of the outstanding balance under the new Term Loan B) plus a 0.5% commitment fee on the unused portion of the new $40.0 million intercompany revolving credit facility, and excludes amortization of deferred financing costs.
(5) Income tax expense relates to Texas margin taxes.
(6) Expansion capital expenditures primarily relate to costs expected to be incurred after the completion of this offering for our debottlenecking project and other budgeted capital projects that will be funded with a portion of the net proceeds from this offering.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending June 30, 2014, we estimate that we would generate EBITDA and cash available for distribution in an amount sufficient to allow us to distribute an aggregate of $183.9 million, or $             per unit on all of our outstanding common units, for the twelve months ending June 30, 2014. If we have cash available for distribution, our first distribution will take place following the first full quarter after the completion of this offering and will include cash available for distribution with respect to the period beginning on the closing date of this offering and ending on the last day of the first full quarter ending after the completion of this offering.

Basis of Presentation

The accompanying financial forecast and summary of significant forecast assumptions of OCI Partners LP present the forecasted results of operations of OCI Partners LP for the twelve months ending June 30, 2014, assuming that the Transactions (as defined under “Prospectus Summary—The Transactions”) had occurred at the beginning of such period.

Summary of Significant Forecast Assumptions

Our Operating Days. For the twelve months ending June 30, 2014, we estimate that we will have 345 operating days for both our methanol and ammonia production units. During the year ended December 31, 2012, our methanol and ammonia production units were in operation for 138 days and 340 days, respectively. Our newly renovated facility began ammonia production in December 2011 and began methanol production in July 2012 (with no significant methanol production until August 2012). We did not achieve maximum daily production rates at our current capacity until the fourth quarter of 2012, after an approximate 20-month start-up phase. During the fourth quarter of 2012, the last quarter of our start-up phase, our methanol and ammonia production units were in operation for 78 days and 88 days, respectively. Following the conclusion of our start-up phase, during the period from January 1, 2013 through May 31, 2013, our methanol and ammonia production units were in operation for 151 days (no downtime) and 142 days, respectively.

Revenues. We estimate revenues based on a forecast of future methanol and ammonia netback prices (assuming that purchasers will pay shipping costs), multiplied by the number of metric tons we estimate we will sell during the forecast period.

 

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Based on these assumptions, we estimate our revenues for the twelve months ending June 30, 2014 will be approximately $401.2 million. Our revenues for the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, were approximately $224.6 million and $310.3 million, respectively. We estimate that we will sell 672,522 metric tons of methanol during the forecast period at an average netback price of $377 per ton, for revenues of approximately $253.7 million. We sold 252,230 metric tons of methanol at an average netback price of $380 per ton for revenues of approximately $95.7 million for the year ended December 31, 2012. We sold 411,790 metric tons of methanol at an average netback price of $391 per ton for revenues of approximately $161.1 million for the twelve months ended March 31, 2013 on a pro forma basis. We expect that sales volumes for methanol during the forecast period will be higher than for the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, primarily as a result of continued robust demand for methanol throughout the forecast period and increased operating days due to our methanol production unit operating at maximum daily production rates for the full period. The average netback price estimate for methanol during the forecast period was determined by management based on price estimates by our marketing group and data received from industry consultants, including Jim Jordan.

We estimate that we will sell 255,228 metric tons of ammonia during the forecast period at an average netback price of $578 per ton, for revenues of approximately $147.5 million. We generally sell ammonia under month-to-month contracts. Ammonia sales are generally priced at a fixed absolute discount to the CFR Tampa index during the month of delivery. Historically, ammonia prices have been seasonal, as the primary driver of demand for ammonia is fertilizer use, which typically results in ammonia prices rising during the fertilizer application seasons. Over the past two years, this trend has not been evident in our markets, with prices remaining strong throughout the year. We sold 221,820 metric tons of ammonia at an average netback price of $581 per ton for revenues of approximately $129.0 million for the year ended December 31, 2012. We sold 241,170 metric tons of ammonia at an average netback price of $619 per ton for revenues of approximately $149.0 million for the twelve months ended March 31, 2013, on a pro forma basis. We expect that sales volumes for ammonia during the forecast period will be higher than for the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, primarily due to continued robust demand for ammonia throughout the forecast period and increased operating days due to our ammonia production unit operating at maximum daily production rates for the full period. The average netback price estimate for ammonia during the forecast period was determined by management based on price estimates generated by our marketing group and data received from industry consultants in the fertilizer industry, including Blue Johnson.

Holding all other variables constant, we expect that a $50.00 change in the forecasted price per ton of methanol would change our forecasted cash available for distribution by approximately $33.6 million for the twelve months ending June 30, 2014. For the first three months of 2013, the average realized price of methanol was $406 per ton. Holding all other variables constant, we estimate that a $50.00 change in the forecasted price per ton of ammonia would change our forecasted cash available for distribution by approximately $12.8 million for the twelve months ending June 30, 2014. For the first three months of 2013, the average realized price of ammonia was $641 per ton.

Cost of Goods Sold. Our cost of goods sold consists of costs related to the production of methanol and ammonia. Raw material purchases, such as natural gas and hydrogen, represent the largest component of our total cost of goods sold. For the three months ended March 31, 2013, natural gas feedstock costs represented approximately 59.1% of our total cost of goods sold (or approximately 85.0% of our variable cost of goods sold). Our remaining cost of goods sold typically consists of purchases of hydrogen and nitrogen feedstock, as well as monthly fixed charges related to labor, maintenance and utilities expenditures. Based on our forecasted revenues, as well as the other assumptions discussed below, we estimate that our total cost of goods sold for the twelve months ending June 30, 2014 will be approximately $180.4 million. Our total cost of goods sold for the year ended December 31, 2012 was $124.5 million. Our total cost of goods sold for the twelve months ended March 31, 2013 was approximately $147.7 million, on a pro forma basis. We expect our total cost of goods sold for the forecast period to be higher than for the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, due to our facility operating at maximum daily production rates for the full period.

 

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Prior to the start-up of our methanol production unit in July 2012, we purchased and sold methanol to meet sales commitments to our customers and to take advantage of opportunities that we identified in the market. Such purchases of procured methanol were included in our total cost of goods sold. We did not purchase any methanol after the start-up of our methanol production unit through May 31, 2013, and we have assumed that we will not engage in methanol trading activities during the forecast period.

We estimate that our total natural gas expense for the twelve months ending June 30, 2014 will be approximately $123.6 million assuming consumption of 29.1 million MMBtu of natural gas and an average price of $4.25 per MMBtu during the forecast period. Our total natural gas costs included in cost of goods sold for the year ended December 31, 2012 was $28.6 million based on consumption of 9.4 million MMBtu at an average natural gas price of $3.05 per MMBtu, compared to $2.75 per MMBtu Henry Hub natural gas prices over this same period. Our total natural gas costs included in cost of goods sold for the twelve months ended March 31, 2013, on a pro forma basis, was approximately $54.1 million based on consumption of 17.3 MMBtu at an average natural gas price of $3.13 per MMBtu, compared to $3.00 per MMBtu Henry Hub natural gas prices over this same period. Holding all other variables constant, we estimate that a $1.00 change per MMBtu in the forecasted price of natural gas (and the resulting effect on our hydrogen price formula) would change our forecasted cash available for distribution by approximately $32.6 million for the twelve months ending June 30, 2014.

The hydrogen needed for our ammonia production is primarily supplied from our methanol production process. However, we also purchase additional hydrogen from nearby suppliers to maximize our ammonia utilization rate. Based on our forecasted operational assumptions, we estimate that our hydrogen expense for the twelve months ending June 30, 2014 will be approximately $25.7 million for 9.0 MMscf purchased from nearby suppliers. Our total hydrogen costs included in cost of goods sold for the year ended December 31, 2012 were approximately $36.3 million for 11.5 MMscf, and $28.9 million for 9.4 MMscf for the twelve months ended March 31, 2013, on a pro forma basis.

We estimate that our nitrogen costs for ammonia production for the twelve months ending June 30, 2014 will be approximately $3.8 million, assuming consumption of 6.3 MMscf for the production of 255,228 metric tons of ammonia. Our total nitrogen costs included in cost of goods sold for the year ended December 31, 2012 were $3.4 million for 5.4 MMscf. For the twelve months ended March 31, 2013, on a pro forma basis, our nitrogen costs included in cost of goods sold included $4.1 million for 5.8 MMscf. We estimate that our labor and operational maintenance costs for the twelve months ending June 30, 2014 will be approximately $18.0 million. Our total labor and maintenance costs included in cost of goods sold for the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, were $15.5 million and $19.1 million, respectively. In connection with this offering, we, our general partner and OCI (or its affiliate) will enter into an omnibus agreement pursuant to which OCI (or its affiliate) will agree to provide us with labor and operational services related to operating our facility and we will reimburse OCI (or its affiliate) for the provision of such services. Please read “Certain Relationships and Related Party Transactions—Our Agreements with OCI—Omnibus Agreement.”

Depreciation Expense. We estimate that depreciation for the forecast period will be approximately $22.0 million compared to $11.4 million for the year ended December 31, 2012 and $15.9 million for the twelve months ended March 31, 2013, on a pro forma basis.

Selling, General and Administrative Expenses. Selling, general and administrative expenses consist primarily of direct and allocated compensation, legal, treasury, accounting, marketing and human resources expenses and expenses related to maintaining our corporate offices in Nederland, Texas. Incremental general and administrative expenses will consist of all incremental expenses attributable to our administration as a publicly traded partnership. Incremental general and administrative expenses include, but are not limited to, expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing our common units on the NYSE, independent auditor fees, legal fees, investor

 

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relations costs, registrar and transfer agent fees, directors and officers insurance and director compensation. We estimate that we will incur a total of $4.0 million in incremental general and administrative expenses for the twelve months ending June 30, 2014. We estimate that our selling, general and administrative expenses will be approximately $19.0 million for the twelve months ending June 30, 2014. Selling, general and administrative expense for the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, were approximately $15.0 million for both periods.

Under the terms of the omnibus agreement, OCI (or its affiliate) will agree to provide us with selling, general and administrative services, and we will pay to OCI (or its affiliate) a fixed annual fee of $15.0 million for the provision of such services, which amount excludes approximately $4.0 million of estimated incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership. Please read “Certain Relationships and Related Party Transactions—Our Agreements with OCI—Omnibus Agreement.”

Net Interest Expense and Net Debt Service Costs. Net interest expense and net debt service costs includes interest expense, interest income and other financing costs. As part of the Transactions, we intend to repay in full and retire the Term B-1 Loan and all of OCIB’s approximate $170.5 million of intercompany debt with OCI Fertilizer and related fees and expenses. Please read “Use of Proceeds.” We expect to have a new $235.0 million Term Loan B recorded on our balance sheet as of the completion of this offering excluding unamortized debt discount. We expect the new Term Loan B will bear an interest rate of 4.5%, with a term of 6.5 years. Principal payments on the loan will be paid at 1% of the initial outstanding principal balance of the new Term Loan B per year until maturity and the remaining principal balance will be payable in 2020. We do not expect to incur any additional indebtedness during the forecast period. We estimate that net interest expense for the forecast period will be approximately $10.5 million, compared to $11.0 million for the year ended December 31, 2012 and $11.2 million for the twelve months ended March 31, 2013, on a pro forma basis. We estimate that net debt service costs for the forecast period will be approximately $12.8 million compared to $13.1 million for both the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis. Net interest expense includes amortization of deferred financing costs, which have been excluded from net debt service costs. Net debt service costs also include the required annual principal payment of $2.4 million (1% of the initial outstanding principal balance of the new Term Loan B) which is excluded from net interest expense.

Income Taxes. As a limited partnership, we estimate that we will pay no federal income tax during the forecast period. We estimate that we will pay approximately $2.0 million in Texas margin tax during the forecast period, which is included in income tax expense.

Expansion Capital Expenditures. Expansion capital expenditures are incurred for capital improvements that we expect will increase our production capacity, operating income or asset base over the long term. We are in the early stages of a debottlenecking project on our production facility that is expected to increase our annual methanol production capacity by approximately 182,500 metric tons, or approximately 25%, and increase our annual ammonia production capacity by approximately 40,000 metric tons, or approximately 15%. We expect that the debottlenecking project will be completed in the second half of 2014 and currently estimate the total cost of the project will be approximately $150 million (including costs associated with a turnaround and environmental upgrades). The forecast period does not include revenue from any increase in production resulting from the debottlenecking project. We estimate that we will incur a total of $93.5 million in expansion capital expenditures for the twelve months ending June 30, 2014, including expenditures of $68.5 million related to our debottlenecking project. The remaining $25.0 million of expansion capital expenditures will be spent on various other budgeted capital projects to help improve our operational efficiency and expand our customer accessibility. We will retain a portion of the net proceeds from this offering to fund any of these expenditures incurred after the completion of this offering. Our expansion capital expenditures during the year ended December 31, 2012 and for the twelve months ended March 31, 2013 related to the upgrade of our facility, which was funded by debt borrowings under credit facilities and intercompany debt.

 

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Maintenance Capital Expenditures. Maintenance capital expenditures are capital expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain, including over the long term, our production capacity, operating income or asset base, or to comply with environmental, health, safety or other regulations. Maintenance capital expenditures that are required to comply with regulations may also improve the output, efficiency or reliability of our facility. We estimate that we will incur a total of $3.1 million in maintenance capital expenditures for the twelve months ending June 30, 2014.

Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending June 30, 2014 is based on the following assumptions related to regulatory, industry and economic factors:

 

   

no material nonperformance or credit-related defaults by suppliers, customers or vendors;

 

   

no new regulation or interpretation of existing regulations that, in either case, would be materially adverse to our business;

 

   

no material accidents, weather-related incidents, floods, unscheduled turnarounds or other downtime or similar unanticipated events;

 

   

no material adverse change in the markets in which we operate resulting from substantially higher natural gas or electricity prices or reduced demand for our products;

 

   

no material decreases in the prices we receive for our products; and

 

   

no material changes in domestic or global agricultural markets or overall domestic or global economic conditions.

Actual regulatory, industry and economic conditions may differ materially from those anticipated in this section as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors” and “Forward-Looking Statements.”

 

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HOW WE MAKE CASH DISTRIBUTIONS

General

Upon the completion of this offering, the board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution that we generate each quarter to unitholders of record on a pro rata basis. Within 45 days after the end of each quarter, beginning with the first full quarter following the closing date of this offering, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date.

Common Units Eligible for Distributions

Upon the completion of this offering, we will have             common units outstanding. Each common unit will be allocated a portion of our income, gain, loss, deduction and credit on a pro-rata basis, and each common unit will be entitled to receive distributions (including upon liquidation) in the same manner as each other common unit.

Method of Distributions

We intend to make cash distributions pursuant to our general partner’s determination of the amount of cash available for distribution for the applicable quarter, which we will then distribute to our unitholders, pro rata; provided, however, that we may change this policy at any time and our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank as to distributions. Our partnership agreement permits us to borrow to make distributions, but we are not required, and do not intend, to borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on our common units in any quarter. We do not have a legal obligation to pay distributions, and the amount of distributions paid under our cash distribution policy and the decision to make any distribution is determined by the board of directors of our general partner. We expect that the agreements governing our indebtedness will restrict our ability to make cash distributions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities” for a discussion of provisions contained in the agreements governing our debt agreements that restrict our ability to make cash distributions.

General Partner Interest

Upon the completion of this offering, our general partner will own a non-economic general partner interest in us and, therefore, will not be entitled to receive cash distributions. However, OCI USA, an indirect wholly owned subsidiary of OCI that owns all of the outstanding member interests in our general partner, will own              common units upon the completion of this offering and may acquire additional common units and other equity interests in the future and will be entitled to receive pro rata distributions therefrom.

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The selected historical financial information presented below under the caption “Statements of Operations Data” and “Cash Flows Data” for the years ended December 31, 2012 and 2011 and the selected historical financial information presented below under the caption “Balance Sheets Data” as of December 31, 2012 and 2011 have been derived from OCIB’s audited financial statements included elsewhere in this prospectus, which financial statements have been audited by KPMG LLP, an independent registered public accounting firm.

The selected historical financial information presented below under the caption “Statements of Operations Data” and “Cash Flows Data” for the three months ended March 31, 2013 and 2012 and the selected financial data presented below under the caption “Balance Sheets Data” as of March 31, 2013 have been derived from OCIB’s unaudited financial statements included in this prospectus which, in the opinion of management, include all adjustments, consisting of only normal, recurring adjustments, necessary for the fair presentation of the results for the unaudited interim periods.

The selected unaudited pro forma condensed statements of operations data presented for the year ended December 31, 2012 and the three months ended March 31, 2013 assumes that the Transactions occurred as of January 1, 2012, and the unaudited pro forma condensed balance sheet data as of March 31, 2013 assumes that the Transactions occurred as of March 31, 2013. The selected unaudited pro forma condensed financial information is derived from our unaudited pro forma condensed financial statements included elsewhere in this prospectus. The pro forma condensed financial data is not comparable to our historical financial data. A more complete explanation of the pro forma condensed financial data can be found in our unaudited pro forma condensed financial statements and accompanying notes included elsewhere in this prospectus. Neither the pro forma condensed statements of operations data nor the pro forma condensed balance sheet data include estimates of the incremental costs of operating as a publicly traded limited partnership.

 

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For a detailed discussion of the selected historical financial information and operating data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and our audited and unaudited historical financial statements and our unaudited pro forma condensed financial statements included elsewhere in this prospectus. Among other things, the historical and unaudited pro forma condensed financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

    Historical     Pro Forma  
    Year ended December 31,     Three months ended
March 31,
    Year
ended
December  31,
    Three
months
ended
March 31,
 
  2011     2012     2012     2013     2012     2013  
(dollars and metric tons in thousands)               (unaudited)     (unaudited)  

Statements of Operations Data:

           

Revenues(1)

  $ —        $ 224,629      $ 26,492      $ 112,161      $ 224,629      $ 112,161   

Cost of goods sold

    —          124,483        19,907        43,167        124,483        43,167   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross Profit

    —          100,146        6,585        68,994        100,146        68,994   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Expenses:

           

Depreciation expense

    —          11,355        966        5,512        11,355        5,512   

Selling, general and administrative

    236        14,980        3,479        8,098        15,000        3,750   

Income (loss) from operations before interest expense, other income and income tax expense

    (236     73,811        2,140        55,384        73,791        59,732   

Interest expense

    —          5,718        —          2,259        11,002        2,750   

Interest expense – related party

    —          6,469        —          4,411        200        50   

Other income

    523        202        159        9        202        9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

    287        61,826        2,299        48,723        62,791        56,941   

Income tax expense

    —          1,048        47        474        1,048        474   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 287      $ 60,778      $ 2,252      $ 48,249      $ 61,743      $ 56,467   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income per common unit (basic and diluted)

           

Common units outstanding (basic and diluted)

           

Cash Flows Data:

           

Net cash provided by (used in):

           

Operating activities

  $ (5,252   $ 74,657      $ (4,842   $ (15,824    

Investing activities

    (130,214     (193,965     (83,752     (6,481    

Financing activities

    136,500        159,982        91,000        —         

Balance Sheets Data (at period end):

           

Cash and cash equivalents

  $ 1,034      $ 41,708        $ 19,403        $ 159,618   

Total assets

    154,682        405,345          420,411          494,643   

Total liabilities

    150,395        340,280          307,097          243,277   

Member’s equity / partners’ capital

    4,287        65,065          113,314          251,366   

Other Financial Data:

           

EBITDA(2)

  $ (236   $ 85,166      $ 3,106      $ 60,896      $ 85,146      $ 65,244   

Capital expenditures for property, plant and equipment

    130,214        193,965        83,752        6,481       

Total debt (excluding accrued interest)

    132,500        295,482          295,482          232,650   

Key Operating Data:

           

Production (metric tons)

           

Methanol

    —          275.0        —          176.5       

Ammonia

    21.0        213.0        42.8        64.5       

 

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(1) Our ammonia production unit commenced production in December 2011, and our methanol production unit commenced production in July 2012. Although we began producing ammonia in December 2011, we did not sell the produced ammonia volumes until January 2012 in order to build inventories.
(2) EBITDA is defined as net income plus interest expense and other financing costs, depreciation and income tax expense, net of interest income.

EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:

 

   

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; and

 

   

our operating performance and return on invested capital compared to those of other publicly traded partnerships, without regard to financing methods and capital structure.

EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA may have material limitations as a performance measure because it excludes items that are necessary elements of our costs and operations. In addition, EBITDA presented by other companies may not be comparable to our presentation because each company may define that term differently.

 

     Historical      Pro Forma  
     Year ended
December 31,
     Three months
ended March 31,
     Year ended
December 31,
     Three
months
ended
March 31,
 
  

2011

   

2012

    

2012

   

2013

    

2012

    

2013

 
(dollars in thousands)                 (unaudited)      (unaudited)  

Net income

   $ 287      $ 60,778       $ 2,252      $ 48,249       $ 61,743       $ 56,467   

Add:

               

Interest expense, net

     (523     5,516         (159     2,250         10,800         2,741   

Interest expense – related party

     —          6,469         —          4,411         200         50   

Depreciation expense

     —          11,355         966        5,512         11,355         5,512   

Income tax expense

     —          1,048         47        474         1,048         474   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

EBITDA

   $ (236   $ 85,166       $ 3,106      $ 60,896       $ 85,146       $ 65,244   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the historical financial statements and notes included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the sections entitled “Risk Factors” and “Forward-Looking Statements” and elsewhere in this prospectus.

Overview

We are a Delaware limited partnership formed in February 2013 to own and operate a recently upgraded, integrated methanol and ammonia production facility that is strategically located on the Texas Gulf Coast near Beaumont. We are currently the largest merchant methanol producer in the United States with an annual methanol production capacity of approximately 730,000 metric tons and an annual ammonia production capacity of approximately 265,000 metric tons, and we are in the early stages of a debottlenecking project that will increase our annual methanol production capacity by 25% to approximately 912,500 metric tons and our annual ammonia production capacity by 15% to approximately 305,000 metric tons. Given our advantageous access and connectivity to customers and attractively priced natural gas feedstock supplies, we believe that we are one of the lowest-cost producers of methanol and ammonia in our markets and intend to capitalize on our competitive position to maximize our cash flow. We believe that the prospects for our methanol and ammonia business will remain positive for the foreseeable future because of growing U.S. and global demand for methanol and ammonia, our continued access to attractively priced natural gas feedstock, the United States’ current position as a net importer of both methanol and ammonia and our competitive position in our markets.

Both methanol and ammonia are global commodities that are essential building blocks for numerous end-use products. Methanol is a liquid petrochemical that is used in a variety of industrial and energy-related applications. Methanol is used in industrial applications to produce adhesives used in manufacturing wood products, such as plywood, particle board and laminates, resins to treat paper and plastic products, paint and varnish removers, solvents for the textile industry and polyester fibers for clothing and carpeting. Methanol is also used outside of the United States as a direct fuel for automobile engines, as a fuel blended with gasoline and as an octane booster in reformulated gasoline. In the United States, ammonia is primarily used as a feedstock to produce nitrogen fertilizers, such as urea and ammonium sulfate, and is also directly applied to soil as a fertilizer. In addition, ammonia is widely used in industrial applications, particularly in the Texas Gulf Coast market, including in the production of plastics, synthetic fibers, resins and numerous other chemical compounds.

We acquired our facility (which had been idled by the previous owners since 2004) in May 2011, commenced an upgrade that was completed in July 2012 and began operating our facility at full capacity in the fourth quarter of 2012. Our newly renovated facility began ammonia production in December 2011 and began methanol production in July 2012 (with no significant methanol production until August 2012), with revenues first generated from ammonia sales in the first quarter of 2012 and from methanol sales in the third quarter of 2012. For the three months ended March 31, 2013, our net income and EBITDA, on a pro forma basis, were approximately $56.5 million and $65.2 million, respectively. For the year ended December 31, 2012, our net income and EBITDA were approximately $60.8 million and $85.2 million, respectively. Subject to certain assumptions, we expect our net income and EBITDA to be approximately $167.3 million and $201.8 million, respectively, for the twelve months ending June 30, 2014. For a reconciliation of EBITDA to net income and the assumptions used in our forecast of our net income and EBITDA for the twelve months ending June 30, 2014, please read “Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data” and “Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Forecasted Cash Available for Distribution.”

 

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Key Industry Factors

Supply and Demand

Revenues and cash flow from operations are significantly affected by methanol and ammonia prices. The price at which we ultimately sell our methanol and ammonia depends on numerous factors, including the global supply and demand for methanol and ammonia.

Methanol. Historically, demand for methanol in chemical derivatives has been closely correlated to levels of global economic activity and industrial production. Because methanol derivatives are used extensively in the building industry, demand for these derivatives rises and falls with building and construction cycles, as well as the level of production of wood products, housing starts, refurbishments and related customer spending. Demand for methanol is also affected by automobile production, durable goods production, industrial investment and environmental and health trends. Lower natural gas prices and improving economic conditions have recently resulted in an increase in methanol supply in the United States, with domestic annual production capacity expected to be 6.2 million metric tons by the end of 2016.

Ammonia. Approximately 95% of global ammonia production is utilized for downstream products, including nitrogen fertilizers. In the United States, there is a meaningful correlation between demand for nitrogen fertilizer products and crop prices. High crop prices incentivize farmers to increase fertilizer application in order to maximize crop yields. Thus, high crop prices tend to buoy fertilizer demand, resulting in higher demand for ammonia. Since 1970, the number of ammonia producers in North America and the Caribbean has declined from 63 to 20, largely driven by market consolidation through mergers and acquisitions. This market consolidation has resulted in a marketplace characterized by a disciplined and rational supplier base.

Natural Gas Prices

The primary feedstock that we use to produce methanol and ammonia is natural gas. Operating at full capacity, our methanol and ammonia production units together require approximately 84,000 MMBtu per day of natural gas. For the three months ended March 31, 2013, natural gas feedstock costs represented approximately 59.1% of our total cost of goods sold (or approximately 85.0% of our variable cost of goods sold). Accordingly, our profitability depends in large part on the price of our natural gas feedstock. In recent years, increased natural gas production from shale formations in the United States has increased domestic supplies of natural gas, resulting in a relatively low natural gas price environment. As a result, the competitive position of U.S. methanol and ammonia producers has been positively impacted relative to the methanol and ammonia competitive position of producers outside of the United States where the natural gas price environment is generally higher.

We have connections to one major interstate and three major intrastate natural gas pipelines that provide us access to significantly more natural gas supply than our facility requires and flexibility in sourcing our natural gas feedstock. We currently source natural gas from DCP Midstream and Kinder Morgan. In addition, we have recently connected our facility to a natural gas pipeline owned by Florida Gas Transmission and a natural gas pipeline owned by Houston Pipe Line Company. We believe that we have ready access to an abundant supply of natural gas for the foreseeable future due to our location and connectivity to major natural gas pipelines.

During the year ended December 31, 2012, we spent approximately $28.6 million on natural gas feedstock supplies, which equalled an average cost per MMBtu of approximately $2.95. We completed the refurbishment of our natural gas reformer and the upgrade of our methanol production unit in July 2012. Prior to the successful completion of our upgrade, we used hydrogen as our primary feedstock and spent an insignificant amount on natural gas feedstock. Since the completion of our upgrade, natural gas has been our primary feedstock. During the three months ended March 31, 2013, we spent approximately $25.5 million on natural gas feedstock supplies, which equalled an average cost per MMBtu of approximately $3.45.

 

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Key Operational Factors

Product Sales Contracts

We are party to methanol sales contracts with Methanex, Koch, ExxonMobil, Arkema and Lucite. Consistent with industry practice, these contracts set our pricing terms to reflect a specified discount to a published monthly benchmark methanol price (Jim Jordan or Southern Chemical), and our methanol is sold on an FOB basis when transported by barge. Our customers have no minimum volume purchase obligations under these contracts and may determine not to purchase any more methanol from us at any time. The payment terms under our methanol sales contacts are net 25-30 days. For the year ended December 31, 2012, Methanex, Koch and Arkema accounted for approximately 11.2%, 12.0% and 9.8%, respectively, of our total revenues. For the three months ended March 31, 2013, Methanex and Koch accounted for approximately 35.5% and 21.3%, respectively, of our total revenues.

We generally sell ammonia under monthly contracts. Consistent with industry practice, these contracts set our pricing terms to reflect a specified discount to a published monthly benchmark ammonia price (CFR Tampa). Our customers have no minimum volume purchase obligations under these contracts. The payment terms under our ammonia sales contacts are net 30 days. Although we have ammonia pipeline connections with certain of our customers, currently all of our ammonia is sold on an FOB basis and is transported by barge. For the year ended December 31, 2012, Transammonia accounted for approximately 50.6% of our total revenues. For the three months ended March 31, 2013, Transammonia and Rentech accounted for approximately 15.1% and 17.9%, respectively, of our total revenues.

Facility Reliability

Consistent, safe and reliable operations at our facility are critical to our financial performance and results of operations. Unplanned downtime at our facility may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, including facility turnarounds, is mitigated through a diligent planning process that takes into account the existing margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. We acquired our facility (which had been idled by the previous owners since 2004) in May 2011, commenced an upgrade that was completed in July 2012 and began operating our facility at full capacity in the fourth quarter of 2012. Our newly renovated facility began ammonia production in December 2011 and began methanol production in July 2012 (with no significant methanol production until August 2012), with revenues first generated from ammonia sales in the first quarter of 2012 and from methanol sales in the third quarter of 2012. During the fourth quarter of 2012, the last quarter of our start-up phase, our methanol and ammonia production units were in operation for 78 days and 88 days, respectively. Following the conclusion of our start-up phase, during the period from January 1, 2013 through May 31, 2013, our methanol and ammonia production units were in operation for 151 days (no downtime) and 142 days, respectively.

We expect to perform maintenance turnarounds every three to four years, which will typically last from 20 to 40 days and cost approximately $10 million to $15 million per turnaround. We will attempt to perform significant maintenance capital projects at our facility during a turnaround to minimize disruption to our operations. We will capitalize the costs related to these projects as property, plant and equipment and will classify the amounts as maintenance capital expenditures. We plan to undertake a turnaround as part of our debottlenecking project that is expected to be completed in the second half of 2014, which will result in approximately 30 to 40 days of downtime at our facility. We expect that the next turnaround after the completion of the debottlenecking project will occur in 2018.

 

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How We Evaluate Our Operations

We generate our revenues from the sale of methanol and ammonia manufactured at our facility. We sell our products, primarily under contract, to industrial and commercial customers for further processing or distribution. In addition, we derive a portion of our revenues from uncontracted sales of methanol and ammonia. We use the following metrics to evaluate our operating performance.

Utilization

As an industrial chemicals manufacturer, the primary criterion that we use when evaluating our performance is the utilization rates of our production units, which is the total production volumes for a production unit for a given period divided by the nameplate capacity of that production unit. Maintaining consistent and reliable operations at our facility are critical to our financial performance and results of operations. Efficient production of methanol and ammonia requires reliable and stable operations at our facility due to the high costs associated with planned and unplanned downtime.

EBITDA

EBITDA is defined as net income plus interest expense and other financing costs, depreciation and income tax expense, net of interest income. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:

 

   

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; and

 

   

our operating performance and return on invested capital compared to those of other publicly traded partnerships, without regard to financing methods and capital structure.

EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA may have material limitations as a performance measure because it excludes items that are necessary elements of our costs and operations. In addition, EBITDA presented by other companies may not be comparable to our presentation because each company may define EBITDA differently.

Cost of Goods Sold

Our cost of goods sold consists of costs related to the production of methanol and ammonia. Raw material purchases, such as natural gas and hydrogen, represent the largest component of our total cost of goods sold. For the three months ended March 31, 2013, natural gas feedstock costs represented approximately 59.1% of our total cost of goods sold (or approximately 85.0% of our variable cost of goods sold). Our remaining cost of goods sold typically consists of purchases of hydrogen and nitrogen feedstock, as well as monthly fixed charges related to labor, maintenance and utilities expenditures. During the periods presented, our facility’s start-up costs also contributed to higher cost of goods sold. Accordingly, the cost of goods sold presented below is not reflective of our facility’s expected run-rate cost of goods sold in the future.

Factors Affecting Comparability of Financial Information

Our historical results of operations for the periods presented may not be comparable between those periods or to our results of operations in the future for the reasons discussed below.

Start-Up of Our Facility

We did not achieve maximum daily production rates at our current capacity until the fourth quarter of 2012, after an approximate 20-month start-up phase. We acquired our facility (which had been idled by the

 

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previous owners since 2004) in May 2011, commenced an upgrade that was completed in July 2012 and began operating our facility at full capacity in the fourth quarter of 2012. Our newly renovated facility began ammonia production in December 2011 and began methanol production in July 2012 (with no significant methanol production until August 2012), with revenues first generated from ammonia sales in the first quarter of 2012 and from methanol sales in the third quarter of 2012. As a result of our limited history of operations due to an extended start-up phase, our results of operations and our operating cash flows presented below for the three months ended March 31, 2012 and for the years ended December 31, 2011 and 2012 do not reflect full utilization of our facility and are not indicative of our expected results of operations and operating cash flows for periods subsequent to the completion of this offering.

Our results of operations for the three months ended March 31, 2013 reflect 86 days and 90 days of operations at our ammonia and methanol production units, respectively, compared to 76 days and no days of operations at our ammonia and methanol production units, respectively, for the three months ended March 31, 2012. We produced approximately 64,500 metric tons of ammonia and approximately 175,500 metric tons of methanol during the three months ended March 31, 2013, representing utilization rates in excess of 100.0% (relative to nameplate capacity) for our ammonia and methanol production units for the operating days during the period, as compared to production of approximately 42,800 metric tons of ammonia and no methanol during the three months ended March 31, 2012, representing a utilization rate of 77.5% for the ammonia production unit for the operating days during the period.

Our results of operations for the year ended December 31, 2012 reflect 340 days and 138 days of operations at our ammonia and methanol production units, respectively, compared to 16 days and no days of operations at our ammonia and methanol production units, respectively, for the year ended December 31, 2011. We produced approximately 215,300 metric tons of ammonia and approximately 221,700 metric tons of methanol during the year ended December 31, 2012, representing utilization rates of 87.2% and 87.4% for the operating days during the period for our ammonia and methanol production units, respectively. In addition, prior to the start-up of our methanol production unit, we purchased and sold methanol to meet sales commitments to our customers and to take advantage of opportunities that we identified in the market. We did not purchase any methanol after the start-up of our methanol production unit through May 31, 2013.

Debt Agreements and Interest Expense

On May 21, 2013, OCIB entered into a $360.0 million senior secured term loan credit facility with a group of lenders and Bank of America, N.A., as administrative agent. The term loan facility is comprised of the $125.0 million Term B-1 Loan and the $235.0 million Term B-2 Loan. We intend to use a portion of the net proceeds from this offering to repay the Term B-1 Loan in full. The Term B-1 Loan matures on the earlier of the consummation of the Transactions and December 31, 2013. The Term B-2 Loan matures on the earliest of (i) December 31, 2013, (ii) the consummation of the Transactions or (iii) the incurrence of the new Term Loan B. Interest on the Term B-1 Loan accrues, at OCIB’s option, at adjusted LIBOR plus 4.0% per annum or the alternate base rate plus 3.0%. Interest on the Term B-2 Loan accrues, at OCIB’s option, at adjusted LIBOR plus 3.5% per annum or the alternate base rate plus 2.5%. The proceeds from the Term B-1 Loan were used to refinance all existing third-party debt. OCIB used approximately $230.0 million of the proceeds from the Term B-2 Loan to finance a distribution to OCI USA and approximately $2.8 million of the proceeds from the Term B-2 Loan to pay for bank fees, accrued interest and legal fees associated with the term loan facility. The remaining proceeds of approximately $2.2 million from the Term B-2 Loan were recorded to cash. Related-party debt outstanding at December 31, 2012 accrued interest at LIBOR plus 9.25%, while the third-party debt accrued interest at LIBOR plus 4.25%. As a result, our results of operations for periods prior to and after the completion of this offering may not be comparable. Please read “—Liquidity and Capital Resources—Credit Facilities.”

Publicly Traded Partnership Expenses

After the completion of this offering, we expect that our general and administrative expenses will increase due to the costs of operating as a publicly traded partnership, including expenses associated with SEC

 

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reporting requirements, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing our common units on the NYSE, independent auditor fees, legal fees, investor relations costs, registrar and transfer agent fees, directors and officers insurance and director compensation. We estimate that this incremental general and administrative expense will be approximately $4.0 million per year, excluding the costs associated with this offering. Our financial statements following this offering will reflect the impact of this incremental expense, which will affect the comparability of our post-offering results with our financial statements from periods prior to the completion of this offering. Our unaudited pro forma condensed financial statements, however, do not reflect this incremental general and administrative expense.

Our Debottlenecking Project

As discussed in “Business—Our Growth Projects—Our Debottlenecking Project,” we intend to expand our existing methanol and ammonia production capacity. To the extent that we proceed with and complete our debottlenecking project, we expect to incur significant costs and expenses for the construction and development of the project. We expect that the debottlenecking project will be completed in the second half of 2014 and currently estimate the total cost of the project will be approximately $150 million (including costs associated with a turnaround and environmental upgrades). We expect that we will shut down our facility for approximately 30 to 40 days in the second half of 2014 in order to complete our debottlenecking project (including completion of the associated turnaround and environmental upgrades). As of May 31, 2013, we had incurred approximately $2.6 million in expenditures related to our debottlenecking project, including costs associated with engineering fees and down payments on equipment. We intend to fund a portion of the costs of our debottlenecking project and other budgeted capital projects incurred after the completion of this offering with a portion of the net proceeds from this offering. We expect our depreciation expense will increase from the additional assets placed into service from our debottlenecking project. To the extent that we successfully complete our debottlenecking project, we expect that our production, revenues and costs of goods sold will be greater in subsequent periods than in prior periods. As a result, our results of operations for periods prior to, during and after the completion of our debottlenecking project may not be comparable.

Results of Operations

The period-to-period comparisons of our results of operations have been prepared using the historical periods included in our financial statements. The following discussion should be read in conjunction with the financial statements and the related notes included elsewhere in this prospectus.

Comparison of the Three Months Ended March 31, 2013 and 2012

 

     Three Months Ended March 31,  
    

2013

    

2012

 
     (in thousands)  

Revenues:

     

Ammonia

   $ 37,348       $ 16,919   

Methanol

     74,813         9,573   
  

 

 

    

 

 

 

Total revenues

     112,161         26,492   

Cost of goods sold

     43,167         19,907   
  

 

 

    

 

 

 

Gross profit

   $ 68,994       $ 6,585   

 

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Three Months Ended
March 31, 2013

    

Three Months Ended
March 31, 2012

 
     Metric Tons      Revenue      Metric Tons      Revenue  
     (in thousands)      (in thousands)  

Product Shipments:

           

Ammonia

     57.8       $ 37,348         38.4       $ 16,919   

Methanol – Procured

     —           —           23.3         9,573   

Methanol – Produced

     182.8         74,813         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     240.6       $ 112,161         61.7       $ 26,492   

Revenues

Our total revenues were approximately $112.2 million for the three months ended March 31, 2013 compared to approximately $26.5 million for the three months ended March 31, 2012. Our methanol revenues were approximately $74.8 million for the three months ended March 31, 2013 compared to approximately $9.6 million for the three months ended March 31, 2012. This increase was due to start-up downtime associated with our methanol production unit during 2012, which commenced methanol production in July 2012, ramped up production during the third and fourth quarters of 2012 and achieved maximum daily production rates at our current capacity in the fourth quarter of 2012. Prior to the start-up of our methanol production unit, we purchased and sold methanol to meet sales commitments to our customers and to take advantage of opportunities that we identified in the market. We did not purchase any methanol after the start-up of our methanol production unit through May 31, 2013. Our ammonia revenues were approximately $37.3 million for the three months ended March 31, 2013 compared to approximately $16.9 million for the three months ended March 31, 2012. This increase was due to continuing upgrades at our ammonia production unit during 2012. Although our ammonia production began in December 2011, we did not achieve maximum daily production rates of ammonia at our current capacity until August 2012.

We sold approximately 182,800 metric tons of produced methanol and no procured methanol during the three months ended March 31, 2013 compared to no produced methanol and approximately 23,300 metric tons of procured methanol during the three months ended March 31, 2012. The average sales prices per metric ton during the three months ended March 31, 2013 was $409 per metric ton for methanol compared to $411 per metric ton for methanol for the three months ended March 31, 2012. This represents a decrease of 0.5% for methanol compared to the average sales price per metric ton for methanol during the three months ended March 31, 2012. Sales of methanol comprised approximately 66.7% of our total revenues for the three months ended March 31, 2013 compared to 36.1% of our total revenues for the three months ended March 31, 2012

We sold approximately 57,800 metric tons of ammonia during the three months ended March 31, 2013 compared to approximately 38,400 metric tons of ammonia during the three months ended March 31, 2012. The average sales prices per metric ton during the three months ended March 31, 2013 was $646 per metric ton for ammonia compared to $441 per metric ton for ammonia for the three months ended March 31, 2012. This represents an increase of 46.5% for ammonia compared to the average sales price per metric ton for ammonia during the three months ended March 31, 2012. This increase in the sales price for ammonia was due to increases in the market price for ammonia. Sales of ammonia comprised approximately 33.3% of our total revenues for the three months ended March 31, 2013 compared to 63.9% of our total revenues for the three months ended March 31, 2012.

Cost of Goods Sold

Cost of goods sold was approximately $43.2 million for the three months ended March 31, 2013 compared to approximately $19.9 million for the three months ended March 31, 2012. The increase in cost of goods sold for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 was primarily due to our commencing methanol production in July 2012 and to higher ammonia sales volume for the three months ended March 31, 2013. Our methanol production unit began methanol production in July 2012 (with no significant

 

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methanol production until August 2012). Prior to the start-up of our methanol production unit, we purchased and sold methanol to meet sales commitments to our customers and to take advantage of opportunities that we identified in the market. We did not purchase any methanol after the start-up of our methanol production unit through May 31, 2013 and we do not intend to engage in methanol trading activities in the future. Methanol production was 182,800 metric tons for the three months ended March 31, 2013. Ammonia sales increased from 38,400 metric tons for the three months ended March 31, 2012 to 57,800 metric tons for the three months ended March 31, 2013. In addition, our purchase price for natural gas increased from an average of $3.23 per MMBtu for the three month period ended March 31, 2012 to an average of $3.45 per MMBtu for the three month period ended March 31, 2013.

Natural gas costs comprised approximately 59.1% of our total cost of goods sold (or approximately 85.0% of our variable cost of goods sold) for the three months ended March 31, 2013. Prior to the completion of the refurbishment of our natural gas reformer and the upgrade of our methanol production unit in July 2012, we used hydrogen as our primary feedstock for the production of ammonia. Upon the completion of our facility upgrades, hydrogen use has been reduced to normal operating levels. Hydrogen costs comprised approximately 5.1% of our cost of goods sold for the three months ended March 31, 2013 compared to approximately 48.7% of our cost of goods sold for the three months ended March 31, 2012. Nitrogen costs comprised approximately 2.8% of our cost of goods sold for the three months ended March 31, 2013 compared to approximately 2.8% of our cost of goods sold for the three months ended March 31, 2012. Procured methanol comprised approximately 45.1% of our cost of goods sold for the three months ended March 31, 2012. We did not purchase methanol for sale during the three months ended March 31, 2013. In addition, fixed manufacturing costs of approximately $2.4 million per month were recorded as costs of goods sold for the three months ended March 31, 2013, as compared to approximately $250,000 per month for the three months ended March 31, 2012. This increase in fixed manufacturing costs relates to the completion of the upgrade of our methanol production unit in July 2012, the increase in production levels and labor costs in 2012 and the corresponding increase in other related fixed manufacturing costs. Labor costs comprised approximately 4.8% of our cost of goods sold for the three months ended March 31, 2013 compared to approximately 2.5% of our cost of goods sold for the three months ended March 31, 2012. Maintenance costs comprised approximately 5.1% of our cost of goods sold for the three months ended March 31, 2013 compared to approximately 0.9% of our cost of goods sold for the three months ended March 31, 2012.

Depreciation Expense

Depreciation expense was approximately $5.5 million for the three months ended March 31, 2013 compared to approximately $1.0 million for the three months ended March 31, 2012. This increase was primarily due to depreciation expense associated with our methanol production unit that was placed into service in July 2012.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were approximately $8.1 million for the three months ended March 31, 2013 compared to approximately $3.5 million for the three months ended March 31, 2012. This increase was primarily due to additional insurance expense related to our upgraded facility, an increase in administrative and personnel expenses due to the addition of employees during the periods after March 31, 2012 and non-recurring corporate costs of $4.1 million in the aggregate related to a management fee paid to OCI and a consulting contract that has since been terminated. In connection with this offering, we, our general partner and OCI (or its affiliate) will enter into an omnibus agreement pursuant to which OCI (or its affiliate) will agree to provide us with selling, general and administrative services, and we will pay to OCI (or its affiliate) a fixed annual fee of $15.0 million for the provision of such services, which amount excludes approximately $4.0 million of estimated incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership. Please read “Certain Relationships and Related Party Transactions—Our Agreements with OCI—Omnibus Agreement.”

 

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After the completion of this offering, we expect that our general and administrative expenses will increase due to the costs of operating as a publicly traded partnership, including expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing our common units on the NYSE, independent auditor fees, legal fees, investor relations costs, registrar and transfer agent fees, directors and officers insurance and director compensation. We estimate that this incremental general and administrative expense will be approximately $4.0 million per year, excluding the costs associated with this offering.

Interest Expense

Interest expense and interest expense–related party were approximately $2.3 million and $4.4 million, respectively, for the three months ended March 31, 2013 compared to no interest expense or interest expense–related party for the three months ended March 31, 2012. Interest expense–related party relates to interest on OCIB’s intercompany debt owed to OCI Fertilizer that bears interest at LIBOR plus 9.25%. This increase was primarily due to increased borrowings to facilitate the upgrade of our facility.

Other Income

Other income was approximately $9,000 for the three months ended March 31, 2013 compared to approximately $0.2 million for the three months ended March 31, 2012. This decrease was primarily due to investment income realized during the three months ended March 31, 2012, as well as changes in foreign currency gains and losses. No interest bearing investments were held during the three months ended March 31, 2013.

Comparison of the Years Ended December 31, 2012 and 2011

 

     Year Ended December 31,  
    

2012

    

2011

 
     (in thousands)  

Revenues:

     

Ammonia

   $ 128,954       $ —     

Methanol

     95,675         —     
  

 

 

    

 

 

 

Total revenues

     224,629         —     

Cost of goods sold

     124,483         —     
  

 

 

    

 

 

 

Gross profit

   $ 100,146       $ —     

 

     Year Ended December 31,
2012
     Year Ended
December 31, 2011
 
     Metric Tons      Revenue      Metric Tons      Revenue  
     (in thousands)      (in thousands)  

Product Shipments:

           

Ammonia

     221.8       $ 128,954         —         $ —     

Methanol – Procured

     51.2         20,382         —           —     

Methanol – Produced

     201.0         75,293         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     474.0       $ 224,629         —         $ —     

Revenues

Our total revenues were approximately $224.6 million for the year ended December 31, 2012 compared to no revenues for the year ended December 31, 2011. Our ammonia production unit commenced production in December 2011, and our methanol production unit commenced production in July 2012. Although we began producing ammonia in December 2011, we did not sell the produced ammonia volumes until January 2012 in order to build inventories, resulting in all ammonia produced in 2011 being included in our 2012 revenues. Revenues from sales of methanol and ammonia comprised approximately $95.7 million (42.7%) and $129.0 million (57.3%), respectively, of our total revenues for the year ended December 31, 2012.

 

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We sold approximately 201,000 metric tons of produced methanol and approximately 51,200 metric tons of procured methanol during the year ended December 31, 2012. The average sales prices per metric ton during the year ended December 31, 2012 was $375 per metric ton for produced methanol and $401 per metric ton for procured methanol, as compared to no sales in 2011. Our methanol production unit commenced production in July 2012 (with no significant methanol production until August 2012) and ramped up production during the third and fourth quarters of 2012. Prior to the start-up of our methanol production unit, we purchased and sold methanol to meet sales commitments to our customers and to take advantage of opportunities that we identified in the market. We did not purchase any methanol after the start-up of our methanol production unit through May 31, 2013.

We sold approximately 221,800 metric tons of ammonia during the year ended December 31, 2012. The average sales prices per metric ton during the year ended December 31, 2012 was $581 per metric ton for ammonia, as compared to no sales in 2011.

Cost of Goods Sold

Cost of goods sold was approximately $124.5 million for the year ended December 31, 2012 compared to no costs of goods sold for the year ended December 31, 2011. Our ammonia production unit commenced production in December 2011 and our methanol production unit commenced production in July 2012 (with no significant methanol production until August 2012). Although we began producing ammonia in December 2011, we did not sell the produced ammonia volumes until January 2012 in order to build inventories. As there were no ammonia or methanol revenues recorded for the year ended December 31, 2011, no costs of goods sold were recorded in the period. Prior to the completion of the refurbishment of our natural gas reformer and the upgrade of our methanol production unit in July 2012, we used hydrogen as our primary feedstock for the production of ammonia. Consequently, hydrogen costs comprised approximately 29.2% of our total cost of goods sold for the year ended December 31, 2012. Upon the completion of our facility upgrades, hydrogen use has been reduced to normal operating levels. Natural gas accounted for approximately 24.9% of our total cost of goods sold for the year ended December 31, 2012. Nitrogen costs accounted for approximately 2.7% of our total cost of goods sold for the year ended December 31, 2012. Procured methanol comprised approximately 17.7% of our total costs of goods sold for the year ended December 31, 2012. Prior to the start-up of our methanol production unit, we purchased and sold methanol to meet sales commitments to our customers and to take advantage of opportunities that we identified in the market. We did not purchase any methanol after the start-up of our methanol production unit through May 31, 2013.

In addition, fixed manufacturing costs, primarily relating to labor and maintenance, of approximately $1.5 million per month were recorded as costs of goods sold for the year ended December 31, 2012. Labor costs comprised approximately 6.2% of our total cost of goods sold for the year ended December 31, 2012. Maintenance costs comprised approximately 6.2% of our total cost of goods sold for the year ended December 31, 2012.

For the year ended December 31, 2012, our cost of goods sold was impacted by high procurement costs for the hydrogen required by our ammonia production unit. When our facility became fully operational in July 2012, we began obtaining the hydrogen necessary to produce ammonia as a by-product of our methanol production process. However, until our methanol production unit became operational in July 2012, we acquired hydrogen from the local market. In addition, one-time start-up costs related to the commissioning and ramp-up of methanol production capacity at our facility required higher natural gas usage per ton.

Depreciation Expense

Depreciation expense was approximately $11.4 million for the year ended December 31, 2012 compared to no depreciation expense for the year ended December 31, 2011. This increase was primarily due to our methanol production unit being placed into service in July 2012 and our ammonia production unit being in

 

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service for the full year ended December 31, 2012. As of December 31, 2011, our production units were still undergoing upgrades and not ready for their intended use. Accordingly, no depreciation expense was recorded for the year ended December 31, 2011.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were approximately $15.0 million for the year ended December 31, 2012 compared to approximately $0.2 million for the year ended December 31, 2011. This increase was primarily due to additional insurance expense related to our upgraded facility, an increase in administrative and personnel expenses due to the addition of employees during 2012 and additional corporate costs.

Interest Expense

Interest expense and interest expense–related party were approximately $5.7 million and $6.5 million, respectively, for the year ended December 31, 2012 compared to no interest expense for the year ended December 31, 2011. Our policy is to capitalize interest costs incurred during the construction of major projects. Because our facility was undergoing an upgrade during the year ended December 31, 2011 and we had no revenues during that period, we capitalized $3.5 million of interest incurred and recorded no interest expense for the year ended December 31, 2011. The increase in interest incurred for the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due to increased borrowings to facilitate the upgrade of our facility.

Other Income

Other income was approximately $0.2 million for the year ended December 31, 2012 compared to approximately $0.5 million for the year ended December 31, 2011. This decrease was primarily due to a reduction in investment income caused by a reduction in interest bearing cash equivalents held during the year ended December 31, 2012 as compared to those held during the year ended December 31, 2011. This reduction in interest bearing assets was due to the funds being required to complete the upgrade of our facility.

Liquidity and Capital Resources

For the year ended December 31, 2012 and the three months ended March 31, 2013, we funded our operations and construction primarily from intercompany loans from OCI Fertilizer, third party loans and operating cash flow.

Our principal uses of cash are expected to be for our operations, distributions, capital expenditures and funding our debt service obligations. We believe that our cash from operations and the net proceeds from this offering will be adequate to fund our commercial commitments and planned capital expenditures for the next twelve months.

Distributions

Upon the completion of this offering, the board of directors of our general partner will adopt a policy to distribute 100% of the cash available for distribution we generate each quarter to our unitholders, which could materially impact our liquidity and limit our ability to grow and make acquisitions. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. As a result of our cash distribution policy, our liquidity will be significantly impacted, and other than the expansion capital expenditures we intend to fund with the net proceeds from this offering, we expect to finance substantially all of our growth externally, either with commercial bank borrowings or by debt issuances or additional issuances of equity. However, our partnership agreement does not require us to pay cash distributions on a quarterly or other basis, and we may change our cash distribution policy at any time and from time to time. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

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Intercompany Debt

As of March 31, 2013, we had approximately $170.5 million of intercompany debt with OCI Fertilizer, an indirect wholly owned subsidiary of OCI, which we incurred to fund the upgrade of our facility that was completed in July 2012, satisfy working capital requirements and for general corporate purposes. Please read “Certain Relationships and Related Party Transactions—Other Transactions with Related Parties—Intercompany Debt.” We intend to repay all outstanding intercompany debt owed to OCI Fertilizer with a portion of the net proceeds from this offering. Please read “Use of Proceeds.” Please also see “—Credit Facilities—Intercompany Revolving Credit Facility.”

Credit Facilities

Existing Term Loan Facility. On May 21, 2013, OCIB entered into a $360.0 million senior secured term loan credit facility with a group of lenders and Bank of America, N.A., as administrative agent. The term loan facility is comprised of a $125.0 million Term B-1 Loan and a $235.0 million Term B-1 Loan, respectively. Borrowings under the term loan facility are unconditionally guaranteed by OCI USA. The Term B-1 Loan matures on the earlier of the consummation of the Transactions and December 31, 2013. We intend to use a portion of the net proceeds from this offering to repay the $125.0 million Term B-1 Loan in full and to pay related fees and expenses. Please read “Use of Proceeds.” The Term B-2 Loan matures on the earliest of (i) December 31, 2013, (ii) the consummation of the Transactions or (iii) the incurrence of the new Term Loan B described below. Borrowings under the term loan facility are secured by a first priority lien on substantially all of OCIB’s assets and a pledge by OCI USA of its ownership interest in OCIB. Interest on the Term B-1 Loan accrues, at OCIB’s option, at adjusted LIBOR plus 4.0% per annum or the alternate base rate plus 3.0%. Interest on the Term B-2 Loan accrues, at OCIB’s option, at adjusted LIBOR plus 3.5% per annum or the alternate base rate plus 2.5%. The agreement governing the term loan facility contains customary covenants and conditions. In addition, the agreement governing the term loan facility requires that OCIB not permit aggregate capital expenditures to exceed $70.0 million and that OCIB maintain a minimum trailing three-month EBITDA of $45.0 million. Upon the occurrence of certain events of default, OCIB’s obligations under the term loan facility may be accelerated.

New Term Loan Facility. In June 2013, we expect that OCIB will enter into a new $235.0 million senior secured term loan credit facility with a syndicate of lenders and Bank of America, N.A., as administrative agent, to replace borrowings under OCIB’s existing term loan facility that will be outstanding after the completion of this offering. We expect that the new term loan facility will be comprised of a new $235.0 million Term Loan B. Borrowings under the term loan facility will be unconditionally guaranteed by OCI USA. We expect that the new Term Loan B will mature 6.5 years after the incurrence of the term loan. We expect that the term loan facility will be subject to certain mandatory prepayment obligations upon the disposition of certain assets and the incurrence of certain indebtedness. We expect that borrowings under the term loan facility will be secured by a first priority lien on substantially all of OCIB’s assets and a pledge by OCI USA of its ownership interest in OCIB. We expect that interest on the new Term Loan B will accrue, at OCIB’s option, at adjusted LIBOR plus             % per annum or the alternate base rate plus             %. We expect that the agreement governing the term loan facility will contain customary covenants and conditions. Upon the occurrence of certain events of default, OCIB’s obligations under the term loan facility may be accelerated.

Intercompany Revolving Credit Facility. At the closing of the offering, OCIB will enter into a new $40.0 million, seven-year intercompany revolving credit facility with OCI Fertilizer as the lender. We expect that interest on borrowings under the intercompany revolving credit facility will accrue at a rate equal to the Term Loan B interest rate. OCIB will pay a commitment fee to OCI Fertilizer on the unused portion of the intercompany revolving credit facility of 0.5% annually. The intercompany revolving credit facility will be subordinated to indebtedness under the new Term Loan B.

 

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Capital Expenditures

We divide our capital expenditures into two categories: maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are capital expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing or the construction or development of new capital assets) made to maintain, including over the long term, our production capacity, operating income or asset base (including capital expenditures relating to turnarounds), or to comply with environmental, health, safety or other regulations. Maintenance capital expenditures that are required to comply with regulations may also improve the output, efficiency or reliability of our facility. Expansion capital expenditures are capital expenditures incurred for acquisitions or capital improvements that we expect will increase our production capacity, operating income or asset base over the long term.

During the years ended December 31, 2011 and 2012, all equipment at our facility was tested, inspected and upgraded. All capital expenditures incurred during the period from our acquisition of the facility until it reached full production capacity in the fourth quarter of 2012 were recorded as expansion capital expenditures. We have not recorded any maintenance capital expenditures for the three months ended March 31, 2013, or for the years ended December 31, 2011 and 2012. We expect to perform maintenance turnarounds every three to four years, which will typically last from 20 to 40 days and cost approximately $10 million to $15 million per turnaround. We will attempt to perform significant maintenance capital projects at our facility during a turnaround to minimize disruption to our operations. We will capitalize the costs related to these projects as property, plant and equipment and will classify the amounts as maintenance capital expenditures. We plan to undertake a turnaround as part of our debottlenecking project that is expected to be completed in the second half of 2014, which will result in approximately 30 to 40 days of downtime at our facility. We expect that the next turnaround after the completion of the debottlenecking project will occur in 2018. Our expansion capital expenditures totalled approximately $6.5 million, $194.0 million and $130.2 million for the three months ended March 31, 2013 and the years ended December 31, 2012 and 2011, respectively.

Our expansion capital expenditures are expected to be approximately $55.6 million and $142.5 million for the years ending December 31, 2013 and 2014, respectively, for expenditures related to our debottlenecking project and other budgeted capital projects. As discussed in “Business—Our Growth Projects,” we expect to incur a total of approximately $150 million in expansion capital expenditures for our debottlenecking project (including costs associated with a turnaround and environmental upgrades). As of May 31, 2013, we had incurred approximately $2.6 million in expenditures related to our debottlenecking project, including costs associated with engineering fees and down payments on equipment. We intend to fund a portion of the costs of our debottlenecking project and other budgeted capital projects incurred after the completion of this offering with a portion of the net proceeds from this offering.

Our estimated capital expenditures are subject to change due to unanticipated increases in the cost, scope and completion time for our capital projects. For example, we may experience increases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our facility. Our future capital expenditures will be determined by the board of directors of our general partner.

Cash Flows

Our profits, operating cash flows and cash available for distribution are subject to changes in the prices of our products and natural gas, which is our primary feedstock. Our products and feedstocks are commodities and, as such, their prices can be volatile in response to numerous factors outside of our control.

 

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As a result of our limited history of operations due to an extended start-up phase associated with the upgrade of our facility, our operating cash flows presented below for the three months ended March 31, 2012 and for the years ended December 31, 2011 and 2012 do not reflect full utilization of our facility and are not indicative of our expected operating cash flows for periods subsequent to the completion of this offering.

Net cash from (used in) operating activities, investing activities and financing activities for the three months ended March 31, 2012 and 2013 and for the years ended December 31, 2011 and 2012 were as follows:

 

     Year Ended
December 31,
    Three Months
Ended

March 31,
 
     2011     2012     2012     2013  
     (in thousands)  

Net cash used provided by (used in):

    

Operating activities

   $ (5.3   $ 74.7      $ (4.8   $ (15.8

Investing activities

     (130.2     (194.0     (83.8     (6.5

Financing activities

     136.5        160.0        91.0        —     

Three Months Ended March 31, 2013 Compared to Year Ended March 31, 2012

Operating Activities. Net cash used in operating activities for the three months ended March 31, 2013 was approximately $15.8 million. We had net income of $48.2 million for the three months ended March 31, 2013. During this period, we recorded depreciation expense of $5.5 million and amortization of debt issuance costs of $0.8 million. Accounts receivable increased by $27.4 million during the three months ended March 31, 2013 as our facility reached full production capacity on both our methanol and ammonia production units. Prepaid interest (related party) increased by $10.4 million, while accrued interest (related party) decreased by $20.2 million during the three months ended March 31, 2013, due to the payment of interest on long-term debt owed to OCI USA. Accounts payable (excluding non-cash accruals of property, plant and equipment), accounts payable (related party) and other payables and accruals decreased by $6.5 million, $1.3 million and $3.4 million, respectively. This net decrease in accounts payable of $11.2 million was due to our improved liquidity position and the settlement of 2012 corporate allocations in the first quarter of 2013.

Net cash used in operating activities for the three months ended March 31, 2012 was approximately $4.8 million. We had net income of $2.3 million for the three months ended March 31, 2012. During this period, we recorded depreciation expense of $1.0 million. Accounts receivable increased by $8.2 million during the three months ended March 31, 2012 due to the start-up of the ammonia production unit and the initial sales activity during the period then ended. Inventories increased by $5.9 million during the three months ended March 31, 2012 due to completion of upgrades at our ammonia production unit and the ramp-up of our production of ammonia during the period then ended. Accounts payable (excluding non-cash accruals of property, plant and equipment) increased by $5.8 million due to the upgrade of our facility and purchases of additional feedstock as our ammonia production began.

Investing Activities. Net cash used in investing activities was approximately $6.5 million and $83.8 million, respectively, for the three months ended March 31, 2013 and 2012. The decrease in purchases of property, plant and equipment of $77.3 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 was primarily due to the completion of upgrades at our ammonia production unit in December 2011 and the completion of upgrades at our methanol production unit in July 2012.

Financing Activities. There was no net cash provided by or used in financing activities for the three months ended March 31, 2013 compared to net cash provided by financing activities of $91.0 million for the three months ended March 31, 2012. During the three months ended March 31, 2012, we received contributions of $91.0 million from OCI USA.

 

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Operating Activities. Net cash provided by operating activities for the year ended December 31, 2012 was approximately $74.7 million. We had net income of $60.8 million for the year ended December 31, 2012. During this period, we recorded depreciation expense of $11.4 million and amortization of debt issuance costs of $2.0 million. Accounts receivable increased by $28.1 million during the year ended December 31, 2012, due to increased shipments of our products. Accounts payable (excluding non-cash accruals of property, plant and equipment), accounts payable (related party) and other payables and accruals increased by $9.7 million, $3.8 million and $7.7 million, respectively. This net increase in accounts payable of $21.2 million was due to an increase in purchases of feedstock as a result of increased production volumes and an increase in corporate allocations.

Net cash used in operating activities for the year ended December 31, 2011 was approximately $5.3 million. We had net income of $0.3 million for the year ended December 31, 2011. We had no accounts receivable during the year ended December 31, 2011. Inventories increased by $4.9 million during the year ended December 31, 2011 due to the ammonia production unit commencing production in December 2011 and the build-up of inventory until our first shipment in January 2012.

Investing Activities. Net cash used in investing activities was approximately $194.0 million and $130.2 million, respectively, for the years ended December 31, 2012 and 2011 related to the upgrade of our facility.

Financing Activities. Net cash provided by financing activities was approximately $160.0 million for the year ended December 31, 2012 compared to net cash provided by financing activities of $136.5 million for the year ended December 31, 2011. During the year ended December 31, 2012, we borrowed approximately $257.5 million of debt, repaid approximately $94.5 million of outstanding borrowings and incurred approximately $3.0 million in debt issuance costs. During the year ended December 31, 2011, we borrowed approximately $132.5 million of debt and received $4.0 million in contributions from OCI USA.

Contractual Obligations

The following table lists our significant contractual obligations and their future payments at March 31, 2013:

 

Contractual Obligations

   Total      Less than
1  Year
     1-3
Years
     3-5
Years
     More
than 5
Years
 
     (in thousands)  

Credit facility(1)

   $ 125,000       $ 125,000       $       $       $   

Intercompany debt (2)

     170,482                 170,482                   

Interest payments on debt

     43,693         21,107         22,586                   

Hydrogen supply contract

     4,384         4,384                           

Natural gas supply contract

     10,786         10,786                           

Purchase commitments

     15,659         15,659                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 370,004       $ 176,936       $ 193,068       $       $   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Proceeds from borrowings under the Term B-1 Loan were used to pay in full and retire this credit facility in May 2013. Please read “—Liquidity and Capital Resources—Credit Facilities.” We intend to use a portion of the net proceeds from this offering to repay the $125.0 million Term B-1 Loan in full and to pay related fees and expenses. Please read “Use of Proceeds.”

 

(2) We intend to use a portion of the net proceeds from this offering to repay the $170.5 million intercompany loan with OCI Fertilizer in full. Please read “Use of Proceeds.”

 

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The following table lists our significant contractual obligations and their future payments on a pro forma basis at March 31, 2013:

 

Contractual Obligations (Pro Forma)

   Total      Less than
1  Year
     1-3
Years
     3-5
Years
     More than
5 Years
 
     (in thousands)  

Term Loan B(1)

   $ 235,000       $ 1,763       $ 4,700       $ 4,700       $ 223,837   

Interest payments on debt(1)

     68,737         7,931         21,150         21,150         18,506   

Hydrogen supply contract

     4,384         4,384                           

Natural gas supply contract

     10,786         10,786                           

Purchase commitments

     15,729         15,729                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 334,636       $ 40,593       $ 25,850       $ 25,850       $ 242,343   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) We intend to use a portion of the net proceeds from this offering to pay in full the $125.0 million Term B-1 Loan and the intercompany debt with OCI Fertilizer. Please read “Use of Proceeds.” We intend to draw $235 million under the new Term Loan B, with annual principal repayments of 1% of the original principal balance, an assumed annual interest rate of 4.5%, and a maturity of 6.5 years to pay in full and retire the Term B-2 Loan.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates based on the accuracy of the information utilized and subsequent events. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. Our accounting policies are described in the notes to our audited financial statements included elsewhere in this prospectus.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the amounts of revenues and expenses reported for the period then ended.

Trade Accounts Receivable. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We maintain a customer specific allowance for doubtful accounts for estimated losses inherent in our accounts receivable portfolio. In establishing the required allowance, management considers customers’ financial condition, the amount of receivables in dispute, the current receivables aging and current payment patterns. We review our allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectability. All other balances are reviewed on a pooled basis for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no bad debt write-offs during the years ended December 31, 2012 and 2011. We do not have any off-balance-sheet credit exposure related to our customers.

 

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Property, Plant and Equipment. Property, plant and equipment are stated at cost. Depreciation on plant and equipment is calculated on the straight-line method over the estimated useful lives of the assets. The estimated useful life of machinery, equipment and buildings is 15 years, while the estimated useful lives of furniture, office equipment and vehicles are 5 years. Our policy is to exclude depreciation expense from cost of goods sold. We estimate initial useful lives based on experience and current technology. These estimates may be extended through sustaining capital programs. Factors affecting the fair value of our assets may also affect the estimated useful lives of our assets and these factors can change. Therefore, we periodically review the estimated remaining lives of our facilities and other significant assets and adjust our depreciation rates prospectively where appropriate.

Major Maintenance Activities. We incur maintenance costs on our major equipment. Repair and maintenance costs are expensed as incurred. Major capital expenditures that extend the life, increase the capacity or improve the safety or efficiency of the asset are capitalized and amortized over the period of expected benefits.

Commitments and Contingencies. Liabilities for loss contingencies, including environmental remediation costs not within the scope of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (ASC) Topic 410, Asset Retirement and Environmental Obligations, arising from claims, assessments, litigation, fines and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of expected future expenditures for environment remediation obligations are not discounted to their present value. We regularly assess the likelihood of material adverse judgments or outcomes as well as potential ranges or probability of losses. We determine the amount of accruals required, if any, for contingencies after carefully analyzing each individual matter. Actual costs incurred in future periods may vary from the estimates, given the inherent uncertainties in evaluating environmental exposures. As of December 31, 2012 and 2011, we had no environmental remediation obligations.

Long-Lived Assets. Long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The carrying amount of a long-lived asset group is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset group. If circumstances require a long-lived asset or asset group be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary. Assessing the potential impairment of long-lived assets involves estimates that require significant management judgment, and include inherent uncertainties that are often interdependent and do not change in isolation. Factors that management must estimate include, among others, industry and market conditions, the economic life of the asset, sales volume and prices, inflation, raw materials costs, cost of capital, and capital spending. No events or changes in circumstances occurred during the years ended December 31, 2012 and 2011 that indicated the carrying amount of an asset may not be recoverable.

Asset Retirement Obligation. We recognize the fair value of the liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, we will capitalize the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. The liability is accreted to its present value each period, while the capitalized cost is depreciated over the useful life of the related asset. We recognize asset retirement obligations in the period in which we have an existing legal obligation, and the amount of the liability can be reasonably estimated. We utilize internal engineering experts as well as third-party consultants to assist management in

 

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determining the costs of retiring certain of our long-term operating assets. Assumptions and estimates reflect our historical experience and our best judgments regarding future expenditures. The assumed costs are inflated based on an estimated inflation factor and discounted based on a credit-adjusted risk-free rate. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, or written or oral contracts, including obligations arising under the doctrine of promissory estoppel. We own the land, assets and facilities related to our business; however, management does not believe that we have any legal and/or constructive obligations for asset retirement obligations as of December 31, 2012 and 2011.

Recent Accounting Pronouncements

Future Adoption of Accounting Standards. The following new accounting pronouncements have been issued, but have not yet been adopted as of December 31, 2012:

In December 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11). This newly issued accounting standard requires an entity to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions executed under a master netting or similar arrangement and was issued to enable users of financial statements to understand the effects or potential effects of those arrangements on its financial position. This ASU is required to be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013. As this accounting standard only requires enhanced disclosure, the adoption of this standard is not expected to have a material impact on our financial position or results of operations.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk. We are exposed to interest rate risk related to our borrowings under our existing term loan facility. As of May 31, 2013, borrowings under the Term B-1 Loan bear interest at LIBOR plus 4.0% per annum or the alternate base rate plus 2.5%, and borrowings under the Term B-2 Loan bear interest at LIBOR plus 3.5% per annum or the alternate base rate plus 2.5%. Please read “—Liquidity and Capital Resources—Credit Facilities.” Based upon the outstanding balances of our variable-interest rate debt at March 31, 2013, and assuming interest rates are above the applicable minimum, a hypothetical increase or decrease of 100 basis points would result in an increase or decrease to our annual interest expense of approximately $3.6 million.

Commodity Price Risk. We are exposed to significant market risk due to potential changes in prices for methanol, ammonia and natural gas. Natural gas is the primary raw material used in the production of the methanol and ammonia manufactured at our facility. We have supply agreements with Kinder Morgan and DCP Midstream to supply natural gas required for our production of methanol and ammonia. Please read “Business—Feedstock Supply.” A hypothetical increase or decrease of $1.00 per MMBtu of natural gas would result in an increase or decrease to our annual cost of goods sold of approximately $32.6 million.

In the normal course of business, we produce methanol and ammonia throughout the year to supply the needs of our customers. Our inventory is subject to market risk due to fluctuations in the price of methanol and ammonia, changes in demand, natural gas feedstock costs and other factors. Methanol prices have historically been, and are expected to continue to be, characterized by significant cyclicality. A hypothetical increase or decrease of $50 per ton in the price of methanol would result in an increase or decrease to our annual revenue of approximately $33.6 million. A hypothetical increase or decrease of $50 per ton in the price of ammonia would result in an increase or decrease to our annual revenue of approximately $12.8 million.

 

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INDUSTRY OVERVIEW

Unless otherwise indicated, the information set forth in this “Industry Overview,” including all statistical data and related forecasts regarding (i) the methanol industry, is derived from information provided by Jim Jordan and Associates, LP, referred to herein as Jim Jordan, and (ii) the ammonia industry, is derived from information provided by Blue Johnson & Associates, Inc., referred to herein as Blue Johnson, and is included in this prospectus in reliance upon the authority of Jim Jordan and Blue Johnson as experts on the methanol industry and the ammonia industry, respectively. The information under the caption “—Natural Gas Feedstock” is not part of the information included upon the authority of Jim Jordan and Blue Johnson. The information presented under the caption “—Natural Gas Feedstock” has been derived by us from various sources noted herein. We believe that the information provided is reliable, but we have not independently verified the information provided nor have we ascertained any underlying assumptions relied upon therein. While we are not aware of any misstatements regarding the methanol and ammonia industry data presented herein, estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed under the heading “Risk Factors.”

Overview

Methanol

Methanol, a global commodity, is a liquid petrochemical utilized in a variety of industrial and energy-related applications. It is predominantly produced from natural gas, but is also produced from coal, particularly in China. In 2012, global methanol production was approximately 62.6 million metric tons, with 41.7% of 2012 global production originating in China and 9.7% originating in Trinidad. Significantly, Trinidad was the largest exporter of methanol to the United States in 2012. Methanol demand is largely driven by global economic activity, and as a result of improving economic conditions, demand has increased since 2009. Global demand is currently expected to increase to approximately 81.2 million metric tons by 2016, representing a compound annual growth rate of 6.7% between 2012 and 2016. In 2012, U.S. consumption and production of methanol totalled 6.0 million metric tons and 1.1 million metric tons, respectively, resulting in the majority of U.S. demand being met by imports. In 2016, U.S. consumption of methanol is projected to increase to approximately 7.1 million metric tons, with production expected to increase to 5.1 million metric tons, resulting in a continued dependency on imports to satisfy U.S. demand for methanol. Global methanol prices are strongly correlated to feedstock prices in China, where the primary feedstock is coal, as well as global demand for end products that utilize methanol as a feedstock.

The methanol industry experienced a wave of global plant closures totalling more than 10.5 million metric tons of annual production between 1998-2007 due to high natural gas prices as well as generally weaker demand for chemicals. During this period, numerous U.S. methanol facilities were shut down or relocated to other countries resulting in the inability of current U.S. production capacity to meet current U.S. methanol demand.

The primary use of methanol is to make other chemicals, with approximately 29.9% of global methanol demand in 2012 being converted to formaldehyde, which is then used for a host of other industrial applications. Methanol is also used to produce adhesives for the lumber industry, such as plywood, particle board and laminates, for resins to treat paper and plastic products, and also in paint and varnish removers, solvents for the textile industry and polyester fibers for clothing and carpeting. Outside of the United States, methanol is used as a direct fuel for automobile engines, as a fuel blended with gasoline and as an octane booster in reformulated gasoline.

Ammonia

Ammonia, a global commodity, produced in anhydrous form (containing no water) from the reaction of nitrogen and hydrogen, constitutes the base feedstock for nearly all of the world‘s nitrogen chemical production.

 

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In 2012, global production of ammonia was approximately 166.0 million metric tons. In 2011, annual global production of ammonia was approximately 163.0 million metric tons, with approximately 30.8% of 2011 global production originating in China, 25.6% originating in the rest of Asia and Australia, 14.3% originating in the former Soviet Union and 3.5% originating in Trinidad. Significantly, Trinidad was the largest exporter of ammonia to the United States in 2012. In 2012, U.S. consumption and production of ammonia totalled 16.5 million metric tons and 10.1 million metric tons, respectively. In 2016, U.S. agricultural and industrial consumption of ammonia is projected to increase to approximately 17.5 million metric tons, with production expected to increase to 11.7 million metric tons, resulting in a continued dependency on imports to satisfy U.S. demand for ammonia.

Since 1970, the number of ammonia producers in North America and the Caribbean has declined from 63 to 20, with the top five producers currently accounting for 70% of total ammonia production capacity. Plant closures, as well as some market consolidation through mergers and acquisitions were the result of an increasingly competitive supply environment. Similar consolidation has also occurred elsewhere in the world, particularly in Europe, and is still occurring today on a global scale. Given the current supply deficit in the United States of approximately 6.4 million metric tons of annual production, imports, largely from Trinidad, are projected to meet this demand through at least 2016. Over 95% of global ammonia output is used as a feedstock to produce other chemical forms of nitrogen, such as fertilizers (urea, ammonium nitrate, ammonium sulfates, phosphates); blasting/mining compounds (ammonium nitrate); fibers and plastics (acrylonitrile, caprolactam and other nylon intermediates, isocyanates and other urethane intermediates, amino resins); and NOx emission reducing agents (ammonia, urea), among others, with 3% to 4% being directly applied to the soil for agricultural purposes.

Natural Gas Feedstock

The U.S. Natural Gas Advantage

The primary feedstock for global methanol and ammonia production is natural gas, accounting for 76% and 68%, respectively, of the average volumes produced. In recent years, improved production techniques and drilling technologies in the United States have resulted in an increased supply of U.S. natural gas that is projected to continue for the foreseeable future. This abundance of U.S. natural gas has resulted in attractive domestic natural gas prices, often substantially below natural gas prices in other global markets, such as Europe, Japan and Northeast Asia.

 

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As indicated by the Energy Information Administration (“EIA”) forecasts shown in the diagram below, as the depletion of conventional onshore and offshore U.S. natural gas resources continues, natural gas from unconventional resource plays, such as shale formations and coalbeds, is forecasted to continue to gain market share from conventional and often higher-cost sources of natural gas. In fact, the EIA estimates that natural gas production from the major shale formations will provide the majority of the growth in domestically produced natural gas supply for the foreseeable future, increasing to approximately 50% in 2040 as compared with 34% in 2011. According to the EIA, shale gas will be the largest contributor to natural gas production growth, while production from tight sands, coalbed methane deposits and offshore waters is expected to remain stable.

U.S. Natural Gas Production by Source, 1990 – 2040

 

LOGO

Source: EIA, Annual Energy Outlook 2013 (January 2013).

According to the EIA, total annual U.S. natural gas consumption is expected to grow from approximately 24.4 Tcf in 2011 to approximately 29.5 Tcf in 2040, or 0.7% per year on average. However, during the same time period, U.S. natural gas production is expected to increase from approximately 23.1 Tcf to approximately 33.2 Tcf, or 1.5% per year on average. The United States consumed more natural gas than it produced in 2011, with net imports of almost 2.0 Tcf. However, U.S. natural gas production is expected to exceed U.S. natural gas consumption by 2019, which is expected to spur the growth of net U.S. natural gas exports to approximately 3.6 Tcf in 2040.

 

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Total U.S. Natural Gas Production and Consumption, 1990 – 2040

 

LOGO

Source: EIA, Annual Energy Outlook 2013 (January 2013).

As a result of the previously described fundamentals for natural gas in the United States, the EIA expects natural gas prices to remain relatively low for the foreseeable future. More specifically, in the EIA 2013 Annual Energy Outlook published in January 2013, the EIA expects Henry Hub average natural gas prices to remain below $4.00 per MMBtu until 2019 and thereafter to remain below $6.00 per MMBtu until 2034. As natural gas is the feedstock for the majority of global methanol and ammonia production, having a low cost natural gas feedstock is a significant competitive advantage for U.S. producers like us.

Annual Average Henry Hub Spot Natural Gas Prices, 1990 – 2040

 

LOGO

Source: EIA, Annual Energy Outlook 2013 (January 2013).

The natural gas advantage currently enjoyed by the United States is highlighted by a comparis