10-K 1 a2017123110-k.htm 10-K Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________________________________________
Form 10-K
________________________________________________________________________________________
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                  to                 
Commission file number 001-36098
________________________________________________________________________________________
OCI Partners LP
(Exact name of registrant as specified in its charter)
________________________________________________________________________________________
Delaware
90-0936556
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
Mailing Address:
Physical Address:
P.O. Box 1647
Nederland, Texas 77627
5470 N. Twin City Highway
Nederland, Texas 77627
(Address of principal executive offices) (Zip Code)
(409) 723-1900
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
________________________________________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
¨
Accelerated filer
 
ý
Non-accelerated filer
 
¨  (Do not check if a smaller reporting company)
Smaller reporting company
 
¨
 
 
 
Emerging growth company
 
ý
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ý
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
The aggregate market value of common units held by non-affiliates as of June 30, 2017 was approximately $154.9 million.
As of March 5, 2018, the registrant had 86,997,590 common units outstanding.



DOCUMENTS INCORPORATED BY REFERENCE: None




TABLE OF CONTENTS
 
 
 
Page
 
 
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
 
 
 
 
 
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
 
 
 
 
 
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
 
 
 
 
 
ITEM 15.
ITEM 16.

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EXPLANATORY NOTE
As used in this report, the terms “the partnership,” “we,” “our,” “us” and similar terms refer to OCI Partners, LP, a Delaware limited partnership (“OCIP”), and its wholly-owned subsidiary OCI Beaumont, LLC, a Texas limited liability company (“OCIB”). References to “our general partner” refer to OCI GP LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of OCI USA Inc. References to “OCIP Holding” refer to OCIP Holding LLC, a Delaware limited liability company and an indirect 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.
FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “will,” “believe,” “expect,” “anticipate,” “intend,” “estimate” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our expected revenues, our future profitability, our expected capital expenditures (including for maintenance or expansion projects and environmental expenditures) and the impact of such expenditures on our performance, and the costs of operating as a publicly traded partnership. These statements involve known and unknown risks, uncertainties and other factors, including the factors described under Item 1A—“Risk Factors” in this Annual Report that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Such risks and uncertainties include, among other things:

our ability to make cash distributions on our common units;
the volatile nature of our business, our ability to remain profitable and the variable nature of our cash distributions;
planned and unplanned downtime (including in connection with maintenance turnarounds), shutdowns (either temporary or permanent) or restarts of existing methanol and ammonia facilities, including, without limitation, the timing and length of planned maintenance outages;
the ability of our general partner to modify or revoke our distribution policy at any time;
our ability to forecast our future financial condition or results of operations and our future revenues and expenses;
our reliance on a single facility for conducting our operations;
intense competition from other methanol and ammonia producers, including recent announcements by other producers, including other OCI affiliates, of their intentions to relocate, restart or construct methanol or ammonia plants in the Texas Gulf Coast region or elsewhere in the United States;
risks relating to our relationships with OCI or its affiliates, including competition from the 1.8 million metric ton methanol plant currently being constructed in Beaumont, Texas by Natgasoline LLC (“Natgasoline”), an entity in which OCI indirectly owns a 50% interest;
potential operating hazards from accidents, fire, severe weather, floods or other natural disasters;
our lack of contracts that provide for minimum commitments from our customers;
the cyclical nature of our business;
expected demand for methanol, ammonia and their derivatives;
expected methanol, ammonia and energy prices;
anticipated methanol and ammonia production rates at our plant;
our reliance on insurance policies that may not fully cover an accident or event that causes significant damage to our facility or causes extended business interruption;

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our reliance on natural gas delivered to us by our suppliers, including a subsidiary of Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”); Houston Pipe Line Company, LP (“Houston Pipe Line Company”), a subsidiary of Energy Transfer Partners, L.P.; and Enterprise Products Operating LLC (“Enterprise Products”), a subsidiary of Enterprise Products Partners L.P.;
expected levels, timing and availability of economically priced natural gas and other feedstock supplies to our plant;
expected operating costs, including natural gas and other feedstock costs and logistics costs;
expected new methanol or ammonia supply or restart of idled plant capacity and timing for start-up of new or idled production facilities;
our expected capital expenditures;
the impact of regulatory developments on the demand for our products;
global and regional economic activity (including industrial production levels);
the dependence of our operations on a few third-party suppliers, including providers of transportation services and equipment;
the risk associated with changes, or potential changes, in governmental policies affecting the agricultural industry;
the hazardous nature of our products, potential liability for accidents involving our products that cause interruption to our business, severe damage to property or injury to the environment and human health and potential increased costs relating to the transport of our products;
our potential inability to obtain or renew permits;
existing and proposed environmental laws and regulations, including those relating to climate change, alternative energy or fuel sources, and the end-use and application of our products;
new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities;
our lack of asset and geographic diversification;
our dependence on a limited number of significant customers;
our ability to comply with employee safety laws and regulations;
our potential inability to successfully implement our business strategies, including the completion of significant capital programs;
additional risks, compliance costs and liabilities from expansions or acquisitions;
our reliance on our senior management team;
the potential shortage of skilled labor or loss of key personnel;
our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;
restrictions in our debt agreements, including those on our ability to distribute cash or conduct our business;
potential increases in costs and distraction of management resulting from the requirements of being a publicly traded partnership;
exemptions we rely on in connection with New York Stock Exchange (“NYSE”) corporate governance requirements;
control of our general partner by OCI;

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the conflicts of interest faced by our senior management team, which manages both our business and the businesses of various affiliates of our general partner;
limitations on the fiduciary duties owed by our general partner to us and our limited partners under our partnership agreement;
the impact of regulations recently issued by the Internal Revenue Service (“IRS”) and the U.S. Department of the Treasury on our status as a partnership for U.S. federal income tax purposes; and
changes in our treatment as a partnership for U.S. federal income or state tax purposes.
You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs, forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

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PART I
 
ITEM 1.    BUSINESS
OVERVIEW
We are a Delaware limited partnership formed in February 2013 whose focus is on the production, marketing and distribution of methanol and anhydrous ammonia. Our production facility is strategically located on the U.S. Gulf Coast near Beaumont, Texas and commenced full operations during August 2012. Our facility has pipeline connections to adjacent customers, port access with dedicated methanol and ammonia import/export jetties, allowing us to ship both products along the Gulf Coast, and truck loading facilities for both methanol and ammonia.
We are currently one of the larger merchant methanol producers in the United States, with an annual methanol production design capacity of approximately 912,500 metric tons and an annual ammonia production design capacity of approximately 331,000 metric tons.
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. The primary use of methanol is to make other chemicals, with approximately 42% of global methanol demand being used to produce formaldehyde, acetic acid and a variety of other chemicals that form the foundation of a large number of chemical derivatives. These derivatives are used to produce a wide range of products, including adhesives for the lumber industry, plywood, particle board and laminates, resins to treat paper and plastic products, and also paint and varnish removers, solvents for the textile industry and polyester fibers for clothing and carpeting. Energy related applications consume approximately 29% of methanol demand. In recent years, there has been a strong demand for methanol in energy applications such as gasoline blending, biodiesel and as a feedstock in the production of dimethyl ether (“DME”), methyl tertiary-butyl ether (“MTBE”), particularly in China. Methanol blending in gasoline is currently not permitted in the United States. Methanol-to-olefins (“MTO”) consumes the remaining 29% of global methanol demand as the MTO segment in China has grown by approximately 44% from 2016 to 2017, causing China to become increasingly reliant on imported methanol. Ammonia, 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. 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 derivatives.
On December 6, 2016, OCIP received a proposal from OCI pursuant to which OCI would acquire the publicly held common units not already directly or indirectly owned by OCI in exchange for OCI shares at an exchange ratio of 0.5200 OCI shares for each common unit (the “Proposed Transaction”). On April 14, 2017, after negotiations with the conflicts committee of the board of directors of our general partner regarding the Proposed Transaction reached an impasse, OCI informed representatives of the conflicts committee that no acceptable definitive agreement regarding the Proposed Transaction could be reached and terminated negotiations with the conflicts committee regarding the Proposed Transaction.
On February 20, 2018, we announced that we had priced a proposed $455 million term loan B facility (the “New Term Loan”) and proposed $40 million revolving credit facility (the “New Revolving Credit Facility”). The proposed New Term Loan is expected to mature in 2025, and is expected to be priced at the London Interbank Offered Rate (“LIBOR”) plus 425 basis points. We intend to use the expected net proceeds of the New Term Loan to repay in full our Term Loan B Credit Facility and to repay in full outstanding intercompany loans from OCI. The commitments in respect of the New Term Loan and New Revolving Credit Facility and the terms and conditions thereof (including the applicable interest rates) remain subject to the execution of definitive documentation with respect to the New Term Loan and New Revolving Credit Facility. The closing of the New Term Loan and New Revolving Credit Facility is expected to occur in March 2018 and is subject to customary closing conditions. Assuming our New Term Loan closes with an expected pricing of LIBOR plus 425 basis points, we expect a reduction of approximately $10 million per year of interest and principal payments on our New Term Loan based on the LIBOR as of March 5, 2018.



4


Organizational Structure
The following diagram depicts our organizational structure as of March 5, 2018:ocipstructure18.jpg
(1)
Does not include 879,214 common units representing an approximately 1.01% limited partner interest owned by Nassef Sawiris, one of our directors and the chief executive officer of OCI.

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Our Facility
We purchase natural gas from third parties and process the natural gas into synthesis gas, which we then further process in the production of methanol and ammonia. We store and sell the processed methanol and ammonia to industrial and commercial customers for further processing or distribution.
Our integrated methanol and ammonia production facility is located on a 62-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 facility began ammonia production in December 2011 and began methanol production in July 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:
 
Annual Production Design
Capacity as of
December 31, 2017
 
Production during
the Year Ended
December 31, 2017
 
Product Storage
Capacity as of
December 31, 2017
Product
Metric
Tons/Day
 
Metric
Tons/Year (1)
 
Metric Tons
 
Metric Tons
Methanol
2,500

 
912,500

 
821,849

 
42,000
(2 tanks)
Ammonia
907

 
331,000

 
312,431

 
33,000
(2 tanks)
_______________________________
(1)
Assumes facility operates 365 days per year.

Our facility is located on the Texas Gulf Coast, which provides us access and connectivity to our existing and prospective customers and to natural gas feedstock supplies. Our facility is connected to established infrastructure and transportation facilities, including pipeline connections to adjacent customers, port access with dedicated methanol and ammonia export barge docks and state-of-the-art methanol and ammonia truck loading facilities, which have improved delivery options for our customers. We own a 15-acre tract of land adjacent to our facility that provides us access to an ammonia pipeline and the flexibility to install a methanol and ammonia railcar loading facility. In addition, we also own a 19-acre tract of land adjacent to our facility that may serve as the future location of our administrative offices.
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. Our facility is connected to natural gas pipelines owned by Kinder Morgan, Houston Pipe Line Company, Florida Gas Transmission and DCP Midstream Partners, LP. We are currently receiving our natural gas from Kinder Morgan and Houston Pipe Line Company though our direct pipeline connections with those companies, and from Enterprise Products through our direct pipeline connection with Florida Gas Transmission. 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 compared to overseas suppliers that are subject to significant transportation costs associated with transporting product to our markets.

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The following table indicates ownership of the pipelines connected to our facility. Although we transport methanol and ammonia to various customers, we do not have ownership of all the pipelines that we use.
Manufactured Product:
Pipeline
Product
Ownership
ExxonMobil/Arkema Pipeline
Methanol
OCI Partners LP
Methanex Methanol Company, LLC
Methanol
OCI Partners LP
Lucite/DuPont
Ammonia
OCI Partners LP
Feedstocks:
Pipeline
Product
Ownership
Kinder Morgan Pipeline
Natural Gas
Kinder Morgan
DCP Midstream Pipeline
Natural Gas
DCP Midstream
Florida Gas Transmission Natural Gas Pipeline
Natural Gas
Florida Gas Transmission Company
Houston Pipe Line Company LP
Natural Gas
Houston Pipe Line Company LP
Air Liquide Nitrogen Pipeline
Nitrogen
Air Liquide
Air Products Hydrogen Pipeline
Hydrogen
Air Products


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The following diagram illustrates key elements of our methanol and ammonia value chain:ocipindustry.jpg











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Our Methanol Production Unit
Our methanol production unit is a 912,500 metric ton per year unit that is comprised of Foster-Wheeler-designed twin steam methane reformers for synthesis gas production, two Lurgi-designed parallel low-pressure, water-cooled reactors and four distillation columns. Our methanol production unit contains two methanol storage tanks with a combined storage capacity of 42,000 metric tons. In addition, our methanol production unit has a crude methanol surge tank, refined receiver tank, storage tank scrubber and crude tank scrubber. During the year ended December 31, 2017, our methanol production unit produced approximately 821,849 metric tons of methanol. We expect our methanol production unit to undergo an approximately four to five-week turnaround once approximately every four years. We executed a turnaround as part of our debottlenecking project that was completed in April 2015. We expect the next turnaround to occur in 2019. Please see below for a simplified process flow diagram.methanolproductionprocess.jpg

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Our Ammonia Production Unit
Our ammonia production unit is a 331,000 metric ton per year unit. The Haldor-Topsøe-designed ammonia synthesis loop at our facility processes hydrogen produced by our methanol production process as the feedstock to produce ammonia. Our ammonia production unit also uses hydrogen we purchase from third parties to supplement the hydrogen produced by our methanol production process. Our ammonia production unit contains two refrigerated ammonia storage tanks with a combined storage capacity of 33,000 metric tons. During the year ended December 31, 2017, our ammonia production unit produced approximately 312,431 metric tons of ammonia. We expect our ammonia production unit to undergo an approximately three to four-week turnaround once approximately every four years coinciding with the turnaround of our methanol production unit. We executed a turnaround as part of our debottlenecking project that was completed in April 2015 and we expect the next turnaround to occur in 2019. Please see below for a simplified process flow diagram.ammoniaproductionprocess.jpg

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Our Debottlenecking Project
As a means of maximizing our production efficiencies and reducing our energy consumption, we executed a debottlenecking project on our production facility that included a maintenance turnaround and environmental upgrades. This project increased our maximum annual methanol production capacity by 25% to approximately 912,500 metric tons and our maximum annual ammonia production capacity by 25% to approximately 331,000 metric tons. Beginning in January 2015, we shut down our methanol and ammonia production units for 82 and 71 days, respectively, in order to complete the debottlenecking project. We began start-up of the ammonia production facility on April 9, 2015 and reached daily ammonia production design capacity of 907 metric tons on May 5, 2015. We began start-up of the methanol production facility on April 22, 2015 and reached daily methanol production design capacity of 2,500 metric tons on May 23, 2015. The total cost of the debottlenecking project (including costs associated with a turnaround and environmental upgrades) was approximately $384.0 million (excluding capitalized interest).
Our depreciation expense has increased from the additional assets placed into service from our debottlenecking project. In addition, due to the increase in our production capacity, our production volumes and cost of goods sold are greater in subsequent periods following the completion of the debottlenecking project than in prior periods. Thus, our results of operations for periods prior to and after the completion of our debottlenecking project may not be comparable.
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 110,000 to 120,000 MMBtu per day of natural gas, as of December 31, 2017. For the year ended December 31, 2017, natural gas feedstock costs represented approximately 59% of our cost of goods sold (exclusive of depreciation). Accordingly, our profitability depends in large part on the price of our natural gas feedstock. Please read Item 7A—“Quantitative and Qualitative Disclosure about Market Risk” included in this report for additional information.
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. Our facility is connected to natural gas pipelines owned by Kinder Morgan, Houston Pipe Line Company, Florida Gas Transmission and DCP Midstream Partners, LP. We are currently receiving our natural gas from Kinder Morgan and Houston Pipe Line Company though our direct pipeline connections with those companies, and from Enterprise Products through our direct pipeline connection with Florida Gas Transmission. 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.
We procure our hydrogen and nitrogen supply needs from Air Products LLC (“Air Products”) and Air Liquide Large Industries U.S. LP (“Air Liquide”), respectively. Our supply contract with Air Products provides for 31.0 MMscf per day of dedicated hydrogen and expires in 2021. The price we pay under the Air Products contract is linked to natural gas prices. Our supply contract with Air Liquide provides for up to 24.8 MMscf of dedicated nitrogen per day, expiring in 2024. The price we pay under our contract with Air Liquide is based on a combination of the cost of electric power, average gross hourly earnings and the latest value of the U.S. Bureau of Statistics Producer Price Index for Industrial Commodities.
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. For the years ended December 31, 2017 and 2016, we derived approximately 81% and 62%, respectively, of our revenues from the sale of our products to commercial traders for further processing or distribution and derived approximately 19% and 38%, respectively, of our revenues from the sale of our products to industrial users. In addition, we derive a portion of our revenues from uncontracted and contracted sales with our customers that have pricing terms based upon published spot prices. For the years ended December 31, 2017 and 2016, we derived approximately 10% and 11%, respectively, of our revenues from spot price-based sales of ammonia. For the years ended December 31, 2017 and 2016, we derived approximately 11% and 18%, respectively, of our revenues from spot price based sales of methanol.

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We currently are party to methanol sales contracts with several customers, including but not limited to Methanex Methanol Company, LLC (“Methanex”) and Southern Chemical Distribution, L.L.C. One of our customers is obligated to use best efforts to purchase a certain quantity of methanol from us each year, but generally our customers may determine not to purchase any more methanol from us at any time and may purchase methanol from other suppliers. Consistent with industry practice, our methanol sales contracts set our pricing terms to reflect a specified discount to a published monthly benchmark methanol price (Argus or Southern Chemical), and our methanol is sold on an Free on Board (“FOB”) basis when transported by barge, pipeline, and our methanol truck loading facility. For the year ended December 31, 2017, methanol sales contracts with Methanex and Southern Chemical Distribution, L.L.C., a subsidiary of Southern Chemical Corporation, accounted for approximately 40% and 14%, respectively, of our total revenues. For the year ended December 31, 2016, methanol sales contracts with Methanex and Koch Methanol LLC accounted for approximately 35% and 24%, respectively, of our total revenues.
We are party to ammonia sales contracts with several customers, including but not limited to Interoceanic Corporation (“IOC”) and Lucite International, Inc. Our customers have no minimum volume purchase obligations under these contracts, may determine not to purchase any more ammonia from us at any time and may purchase ammonia from other suppliers. Consistent with industry practice, these contracts set our pricing terms to reflect a specified discount to a published monthly benchmark ammonia price (CFR Tampa), and our ammonia is sold on an FOB basis when transported by barge, pipeline and our ammonia truck loading facility. For the years ended December 31, 2017 and 2016, ammonia sales contracts with IOC accounted for approximately 8% and 14%, respectively, of our total revenues.
During the year ended December 31, 2017, we delivered approximately 57% of our total sales by barge or vessel, 39% of our total sales by pipeline, and approximately 4% of our total sales through our ammonia and methanol truck loading facilities.
Quality Assurance
On December 20, 2016, we became ISO 9001 certified. ISO 9000 (which includes ISO 9001) is an international standard on quality assurance developed by the International Organization for Standardization. ISO 9001 certification indicates that a company has established and follows a rigorous set of requirements aimed at achieving customer satisfaction by preventing nonconformity in design, development, production, installation and servicing of products.
Competition
The industries in which we operate are highly competitive. Methanol and ammonia are global commodities, and we compete with a number of domestic and foreign producers of methanol and ammonia. In addition, a long period of low natural gas prices in the United States has made it economical for companies to upgrade existing plants and initiate construction of new methanol and nitrogen projects. For example, Methanex and the Celanese-Mitsui joint venture have brought their new methanol facilities online in the last three years and Natgasoline, in which OCI indirectly owns a 50% interest, is currently in the construction phase on its 1.8 million metric ton methanol facility in Beaumont, Texas, and has stated that it expects to commence operations in the second quarter of 2018. In addition, Yuhuang Chemical and several other developers have announced plans to construct methanol plants in the U.S. Gulf Coast region over the next few years, which, if constructed, would increase overall U.S. production capacity and the availability of methanol supply to our customers from competing sources. There have also been significant ammonia capacity additions in the U.S. Gulf Coast region, including CF Industries' Donaldsonville plant and Dyno Nobel's ammonia plant in Louisiana. In addition, BASF/Yara have announced that they expect to commission an ammonia plant in Freeport, Texas in 2018. However, over the past few years, several methanol and ammonia projects have been canceled or delayed as a result of higher capital expenditure estimates than originally anticipated, among other reasons.
While the methanol and ammonia industries are global in nature, we believe that our strategic location on the Texas Gulf Coast positions us as a key local supplier. Our proximity to customers and access to major infrastructure and transportation facilities, including pipeline connections to adjacent customers, port access with dedicated methanol and ammonia barge docks and state-of-the-art methanol and ammonia truck loading facilities provide us with a competitive advantage over other suppliers.
The majority of methanol consumed in the U.S. Gulf Coast is imported from Trinidad and Tobago or produced domestically. During 2017, methanol sourced from Trinidad and Tobago accounted for approximately 49% of total imported methanol in the United States. Producers in Trinidad and Tobago have been facing significant natural gas feedstock shortages, thereby reducing the supply of all natural gas-based products from Trinidad and Tobago the United States. Furthermore, we believe that transportation and port-handling costs for imported methanol provide us with a cost advantage over foreign producers.

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Similarly, the majority of ammonia consumed in our market is sourced overseas, particularly from Trinidad and Tobago, and is transported through the U.S. Gulf Coast. Our close proximity to our customers allows us to maintain a cost advantage over foreign producers that import ammonia into the U.S. Gulf Coast. During 2017, ammonia sourced from Trinidad and Tobago accounted for approximately 67% of total imported ammonia in the United States. Although ammonia sourced from Trinidad and Tobago historically enjoyed a competitive cost advantage, natural gas supply shortages and higher production costs in recent years have eroded this competitive advantage. Furthermore, we believe that transportation and port-handling costs for all imported ammonia provide us with a cost advantage over foreign producers.
Our major competitors in the methanol industry include Methanex, Mitsui, Mitsubishi and Southern Chemical Corporation and our major competitors in the ammonia industry include Koch Fertilizer, CF Industries and Nutrien (formerly Agrium and Potash Corporation of Saskatchewan Inc.). Based on 2017 data regarding total use of methanol and ammonia in the United States, we estimate that our production in 2017 represented approximately 14% and 2%, respectively, of total U.S. methanol and ammonia use.
Seasonality and Volatility
While most U.S. methanol is sold pursuant to long-term contracts based on market index pricing and fixed volumes, the market price of methanol can be volatile. Methanol is an internationally traded commodity chemical, and 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. Methanol prices have historically been cyclical and sensitive to overall production capacity relative to demand, the price of feedstock (primarily natural gas or coal), energy prices and general economic conditions.
The seasonality of the U.S. ammonia business largely tracks the seasonality of the fertilizer business in the United States because the substantial majority of all domestic ammonia consumption in the United States is for fertilizer use. The fertilizer business is seasonal, based upon the planting, growing and harvesting cycles. Inventories must be accumulated to allow for customer shipments during the spring and fall fertilizer application seasons, which require significant storage capacity. The accumulation of inventory to be available for seasonal sales requires fertilizer producers to maintain significant working capital. This seasonality generally results in higher fertilizer prices during peak periods, with prices normally reaching their highest point in the spring, decreasing in the summer, and increasing again in the fall. Fertilizer products are sold both on the spot market for immediate delivery and under product prepayment contracts for future delivery at fixed prices. The terms of the product prepayment contracts, including the percentage of the purchase price paid as a down payment, can vary from season to season. Variations in the proportion of product sold through forward sales and variations in the terms of the product prepayment contracts can increase the seasonal volatility of fertilizer producers’ cash flows and cause changes in the patterns of seasonal volatility from year to year. Nitrogen fertilizer prices can also be volatile as a result of a number of other factors, including weather patterns, field conditions, quantities of fertilizers imported to the United States, current and projected grain inventories and prices and fluctuations in natural gas prices. In addition, governmental policies may directly or indirectly influence the number of acres planted, the level of grain inventories, the mix of crops planted and crop prices, which would also affect nitrogen fertilizer prices.

13


Environmental Matters
Our business is subject to extensive and frequently changing federal, state and local, environmental, health and safety regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water and the storage, handling, use and transportation of our methanol and ammonia. These laws include the federal Clean Air Act (“CAA”), the federal Water Pollution Control Act (also known as the Clean Water Act, or the “CWA”), the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Toxic Substances Control Act and various other federal, state and local laws and regulations. These laws, their underlying regulatory requirements and the enforcement thereof impact us by imposing:
restrictions on operations or the need to install enhanced or additional controls;
the need to obtain and comply with permits and authorizations;
liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities and off-site waste disposal locations (if any); and
specifications for the products we market.
Our operations require numerous permits and authorizations. Failure to comply with these permits or environmental laws generally could result in substantial fines, penalties or other sanctions, court orders to install pollution-control equipment, permit revocations and facility shutdowns. In addition, environmental, health and safety laws may impose joint and several liability, without regard to fault, for cleanup costs on potentially responsible parties who have released or disposed of hazardous substances into the environment. We may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. Private parties, including the owners of properties adjacent to other facilities where our wastes are taken for disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The laws and regulations to which we are subject are complex, change frequently and have tended to become more stringent over time. The ultimate impact on our business of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws, such as the CAA, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could increase our capital, operating and compliance costs.
Our facility has experienced some level of regulatory scrutiny in the past, and we may be subject to further regulatory inspections, future requests for investigation or assertions of liability relating to environmental issues. In the future, we could incur material liabilities or costs related to environmental matters, and these environmental liabilities or costs (including fines or other sanctions) could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

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The principal environmental regulations and risks associated with our business are outlined below.
The Federal Clean Air Act. The CAA and its implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect us through the CAA’s permitting requirements and emission control requirements relating to specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases of certain substances. Some or all of the standards promulgated pursuant to the CAA, or any future promulgations of standards, may require the installation of controls or changes to our facility in order to comply. If new controls or changes to operations are needed, the costs could be significant. In addition, failure to comply with the requirements of the CAA and its implementing regulations could result in fines, penalties or other sanctions.
The regulation of air emissions under the CAA requires that we obtain various construction and operating permits, including Title V and Prevention of Significant Deterioration (“PSD”) air permits issued by the Texas Commission on Environmental Quality (the “TCEQ”). Requirements under these permits will cause us to incur capital expenditures for the installation of certain air pollution control devices at our operations. Various regulations specific to our operations have been implemented, such as National Emission Standard for Hazardous Air Pollutants, New Source Performance Standards and New Source Review. We have incurred, and expect to continue to incur, substantial capital expenditures to maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future, including in connection with the projects discussed below under “—Material Estimated Capital Expenditures for Environmental Matters” that are designed to comply with our emission limits and requirements of our Title V CAA permit.
Release Reporting. The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws, including the Emergency Planning and Community Right-to-Know Act. We occasionally experience minor releases of hazardous or extremely hazardous substances from our equipment. We report such releases to the U.S. Environmental Protection Agency (the “EPA”), TCEQ and other relevant state and local agencies as required by applicable laws and regulations. If we fail to properly report a release, or if the release violates the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third-party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability.
Clean Water Act. The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
Greenhouse Gas Emissions. Currently, legislative and regulatory measures to address greenhouse gas (“GHG”) emissions (including CO2, methane and nitrous oxides) are in various phases of discussion or implementation. At the federal legislative level, Congress has previously considered legislation requiring a mandatory reduction of GHG emissions. Although Congressional passage of such legislation does not appear likely at this time, 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.

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In the absence of congressional legislation curbing GHG emissions, the EPA is moving ahead administratively under its CAA authority. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs to inventory and report their GHG emissions to the EPA. In accordance with the rule, we monitor our GHG emissions from our facility and have reported the emissions to the EPA annually beginning in September 2011. On December 7, 2009, the EPA finalized its “endangerment finding” that GHG emissions, including CO2, pose a threat to human health and welfare. The finding allows the EPA to regulate GHG emissions as air pollutants under the CAA. In May 2010, the EPA finalized the “Greenhouse Gas Tailoring Rule,” which establishes new GHG emissions thresholds that determine when stationary sources, such as our facility, must obtain permits under the PSD and Title V programs of the CAA. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD or Title V permit requires a source to install best available control technology (“BACT”) for those regulated pollutants that are emitted in certain quantities. In June 2014, the U.S. Supreme Court invalidated that portion of the rule that would require facilities that only emitted GHG emissions (and not other regulated pollutants) in excess of specified thresholds to obtain PSD and Title V permits. Sources that emit other regulated pollutants in excess of specified thresholds that also trigger greenhouse gas emissions thresholds still must obtain a PSD permit for greenhouse gas emissions. Our debottlenecking project was a major modification for other pollutants, which required us to obtain a PSD permit for greenhouse gas emissions. We received our PSD permit from the EPA in August 2014. The TCEQ has since been authorized by the EPA to implement a greenhouse gas permitting program.
The implementation of additional 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 facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. Increased costs associated with compliance with any future legislation or regulation of GHG 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 our customers that utilize our products, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (“Paris Accord”). The Paris Accord entered into force in November 2016. The United States is one of over 70 countries that has ratified or otherwise indicated its intent to be bound by the agreement. To the extent the United States implements the Paris Accord in addition to the GHG regulations, it could have an adverse impact on our operations. However, on June 1, 2017, President Trump announced that the United States will withdraw from the Paris Accord and seek negotiations either to reenter the Paris Accord on different terms or to establish a new framework agreement. The Paris Accord provides for a four-year exit process, which would result in an effective exit date of November 2020. The United States' adherence to the exit process and/or the terms on which the United States may reenter the Paris Accord or a separately negotiated agreement are unclear at this time.
Environmental Remediation. Under CERCLA and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons can include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, retroactive and, under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. As is the case with all companies engaged in similar industries, depending on the underlying facts and circumstances, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of or released. We cannot assure you that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material.

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Government Assessments of Methanol. In September 2013, the EPA issued a final Toxicological Review of Methanol under its Integrated Risk Information System (“IRIS”). This review concluded that daily exposures to the human population (including sensitive subgroups) are “likely to be without an appreciable risk of deleterious effectives during a lifetime”. This review did not address carcinogenicity, however, and the EPA has no plans at this time to conduct a Health Hazard Assessment under IRIS for cancer effects. The European Chemicals Agency (“ECHA”) has recently adopted the report prepared by Poland in support of a proposal to restrict the sale of methanol to the general public and to limit its presence as an additive in consumer products. A decision on this proposal is currently pending before the European Commission, and action by the European Commission to restrict methanol sales and uses for certain markets and products could have a material adverse effect on our business. ECHA’s Committee for Risk Assessment declined to endorse a separate proposal from Italy and Holland to reclassify methanol as a Category 1B or Category 2 Reproductive Toxin on grounds of insufficient evidence, but it is possible that this proposal may be revisited in the future if new evidence becomes available.
Derivatives of Methanol-Formaldehyde. Methanol has many commercial uses, including as a building block to manufacture formaldehyde, among other chemicals. Formaldehyde is a component of resins used as wood adhesives and as a raw material for engineering plastics and a variety of other products, including elastomers, paints, building products, foams, polyurethane and automotive products. As discussed below, changes in environmental, health and safety laws, regulations or requirements relating to formaldehyde are being considered, and if adopted, could restrict formaldehyde uses and exposures, and as a result, could lead to a material adverse impact on our business by reducing the demand for methanol to manufacture formaldehyde.
Formaldehyde has been classified as a known human carcinogen by the International Agency for Research on Cancer and as a probable human carcinogen by the EPA. On July 7, 2010, President Obama signed the Formaldehyde Standards for Composite Wood Products Act into law. This legislation, which adds a Title VI to the Toxic Substances Control Act, establishes limits for formaldehyde emissions from composite wood products and requires the EPA to evaluate and establish limits for other types of wood products. In December 2016, the EPA finalized a regulation to implement this Act with two components: (1) formaldehyde emissions standards for hardwood plywood, medium-density fiberboard, particleboard, and finished goods containing these products that are sold, supplied, offered for sale, or manufactured (including imported) in the United States and (2) a third-party certification program to assure compliance by composite wood panel producers with the formaldehyde emissions limits established directly in the Act. This regulation was to become effective in December 2017, but the EPA has extended the compliance deadlines under the December 2016 rule to December 2018 and beyond. In addition, in December 2017, the EPA published a notice that it is withdrawing its direct final rule issued in October 2017 to update the voluntary consensus standards that were originally published in the December 2016 rule. The EPA had issued both a direct final rule and a proposed rule in October 2017. The EPA stated that, due to its receipt of adverse comments on the rule, it was required to withdraw the direct final rule and proceed with issuing a final rule only after it has considered all of the comments received. The comment period for submitting comments closed in November 2017.
A risk assessment process for formaldehyde has been underway in the European Union for the past several years and has resulted in classification of formaldehyde as a category 1B carcinogen (“known to have carcinogenic potential for humans”) and a category 2 mutagen (“suspected of being toxic for human reproduction”). No decision has yet been made whether this classification will result in restrictions required under Registration, Evaluation, Authorisation and Restriction of Chemicals (“REACH”), or in new classification, labeling and packing obligations; however, to support its decision-making, ECHA required an update by October 2017 of all Registrations for aqueous formaldehyde solutions containing methanol above 10% with information pertaining to various formaldehyde exposure scenarios, including from composite wood products.
Derivatives of Methanol—MTBE. Changes in environmental, health and safety laws, regulations or requirements could also impact methanol demand for the production of MTBE. 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, methanol is used in the United States to produce MTBE for export markets, where demand for MTBE has continued at strong levels. While we currently expect demand for methanol for use in MTBE production in the United States to remain steady or to decline slightly, it 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.

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Material Capital Expenditures for Environmental Matters. We incurred approximately $84.4 million in capital expenditures for the year ended December 31, 2015, relating to the installation of a SCR unit for nitrogen oxide control; the installation of a saturator column system to improve plant efficiency, decrease nitrogen oxide emissions and decrease wastewater treatment from distillation; and the installation of a new flare to decrease carbon monoxide emissions during start-ups and shutdowns of our facility. These capital expenditures assist us in complying with federal, state and local environmental, health and safety regulations. None of the capital expenditures incurred during the years ended December 31, 2016 and 2017, were related to environmental matters.
On December 20, 2016, we became ISO 14001 certified. ISO 14000 (which includes ISO 14001) is an international standard on environmental management developed by the International Organization for Standardization that was developed to help organizations manage the environmental impacts of their processes, products and services. ISO 14001 defines an approach to setting and achieving environmental objectives and targets, within a structured management framework.
Safety, Health and Security Matters
We are subject to a number of federal and state laws and regulations related to safety, including the Occupational Safety and Health Act (“OSHA”), and comparable state statutes, the purpose of which are to protect the health and safety of workers. We also are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process that involves a chemical at or above the specified thresholds or any process that involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. We also are subject to the EPA Chemical Accident Prevention Provisions, known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials, and the U.S. Coast Guard’s Maritime Security Standards for Facilities, which are designed to regulate the security of high-risk maritime facilities.
On March 1, 2016, we achieved Star status in OSHA's Voluntary Protection Program (“VPP”). OSHA’s VPP is a program in which companies voluntarily participate that recognizes facilities for their exemplary safety and health programs.
Employees
We are managed and operated by the board of directors and executive officers of OCI GP LLC, our general partner. Neither we nor our subsidiary have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by our general partner or its affiliates. Our general partner and its affiliates have approximately 114 employees performing services for our operations. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.
Insurance
Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We are currently insured under casualty, environmental, property and business interruption insurance policies. The property and business interruption insurance policies have a combined loss limit of $672.0 million which is placed in two layers. The primary layer has a loss limit of $392.0 million, with a deductible of $4.3 million for physical damage. The first excess layer of the property and business interruption insurance policy has a loss limit of $280.0 million for all risks coverage. Business interruption losses under the primary layer are subject to a time element 45-day equivalent deductible per occurrence.
Our primary property policy provides coverage on an all risk basis and contains a number of sub-limits, such as a full primary limit of $382.0 million for losses due to business interruptions caused by machinery breakdown and a limit of $382.0 million for damage caused by a named windstorm, with a $41.0 million deductible per occurrence and a stand-alone named windstorm policy with a $10.0 million deductible, which reduces the primary deductible of $41.0 million. Our general liability insurance policies have a combined loss limit of $11.0 million per occurrence and $12.0 million for an annual aggregate. We are fully exposed to all losses in excess of the applicable limits and sub-limits of our policies. We are also exposed to losses due to business interruptions caused by machinery breakdown of fewer than 45 days per occurrence and losses due to property damage that are less than $4.3 million per occurrence. Because Hurricane Harvey did not cause any significant losses to our equipment or facilities, lost profitability resulting from the operational interruption of Hurricane Harvey was outside the scope of our insurance coverage.


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With regard to environmental claims due to pollution, we currently have a policy limit of $25.0 million, and this policy has a deductible of $250,000. Our current construction floater policy contains a specific limit of $20.0 million for losses incurred during the construction of any equipment or facilities at our site. We continue to evaluate our policy limits and risk retentions as they relate to the overall cost and scope of our insurance program.

Financial Information about Geographical Areas
We have no international activities. For all periods included in this report, all of our revenue was derived from operations conducted in, and all of our assets were located in, the United States.
Available Information
Our website address is www.ocipartnerslp.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports are available free of charge through our website under “Investor and Media Relations,” as soon as reasonably practical after they are filed with or furnished to the SEC. In addition, our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the Charter of the Audit Committee and the Conflicts Committee of the Board of Directors of our general partner are available on our website. These guidelines, policies and charters are also available in print without charge to any unitholder requesting them. Materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The information contained on our website does not constitute part of this report.

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ITEM 1A.    RISK FACTORS
Set forth below are certain risk factors related to our business, our partnership structure and tax matters. Actual results could differ materially from those anticipated as a result of these and various other factors, including those set forth in our other periodic and current reports filed with the SEC from time to time. If any risks or uncertainties develop into an actual event, our business, financial condition, cash flow or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment. The risks described in this report are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, cash flow and ability to make cash distributions to our unitholders.
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 (exclusive of depreciation), including the cost of natural gas, our primary 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:
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;
the level of our capital expenditures;
our debt service requirements;
the level of our expenses that are incurred by our general partner and its affiliates on our behalf and reimbursed by us;
fluctuations in our working capital needs;
our ability to access capital markets;
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 does 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-listed factors.

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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 do 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, the amount of our quarterly cash distributions, if any, will be volatile and are expected to vary quarterly and annually. For example, we did not pay any quarterly cash distributions with respect to the quarters ended June 30, 2016, September 30, 2016, or December 31, 2016. Unlike most publicly traded partnerships, we do 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. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes. Please read “Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy.”
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.
Under our current cash distribution policy, we intend to 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. For example, we did not pay any quarterly cash distributions with respect to the quarters ended June 30, 2016, September 30, 2016, or December 31, 2016.
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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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 curtailment 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, fire, damage by severe weather, hurricanes, 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 facility; and
governmental limitations on the use of our products, either generally or specifically those manufactured at our plant.
During the quarter ended September 30, 2017, Hurricane Harvey caused extensive and costly damage across Southeast Texas. On August 25, 2017, in anticipation of Hurricane Harvey and in conjunction with our safety policies and procedures, we began reducing production volumes of ammonia and methanol. The ammonia and methanol production facilities were taken offline on August 28, 2017 and August 30, 2017, respectively, due to Hurricane Harvey making landfall and the lack of availability of raw materials from our suppliers, who were also impacted by Hurricane Harvey. We restarted the methanol production facility on September 3, 2017, but were not able to restart our ammonia production facility until September 13, 2017 due to inventory constraints and reduced marine traffic caused by the temporary closure of the Sabine—Neches waterway as a result of Hurricane Harvey.
During the year ended December 31, 2017, our methanol and ammonia production units were shut down for 34 days and 30 days, respectively, due to, among other things, a natural gas supply control issue, leaks in the Transfer Line Heat Exchangers (“TLX”), and Hurricane Harvey. During the year ended December 31, 2016, our ammonia and methanol production units were shut down for 8 days and 26 days, respectively, due to an underground cooling water line leakage, repairs to our methanol reformer, an electrical power outage caused by our electrical power provider and repairs to our steam turbine of the methanol syngas compressor. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Operational Factors—Facility Reliability.”
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 approximately every four years, which will typically last approximately four to five weeks for our methanol production unit and approximately three to four weeks for our ammonia production unit and cost approximately $24 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 executed a turnaround as part of our debottlenecking project which was completed in April 2015. We expect that the next turnaround will occur in 2019. 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 either 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.

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For example, in the quarter(s) preceding our planned downtime for major turnarounds, 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 or cost 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.
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 combined loss limit of $672.0 million which is placed in two layers. The primary layer has a loss limit of $392.0 million, with a deductible of $4.3 million for physical damage. The first excess layer of the property and business interruption insurance policy has a loss limit of $280.0 million for all risks coverage. Business interruption losses under the primary layer are subject to a time element 45-day equivalent deductible per occurrence.
Our primary property policy provides coverage on an all risk basis and contains a number of sub-limits, such as a full primary limit of $382.0 million for losses due to business interruptions caused by machinery breakdown and a limit of $382.0 million for damage caused by a named windstorm, with a $41.0 million deductible per occurrence and a stand-alone named windstorm policy with a $10.0 million deductible which reduces the primary deductible of $41.0 million. Our general liability insurance policies have a combined loss limit of $11.0 million per occurrence and $12.0 million for an annual aggregate. We are fully exposed to all losses in excess of the applicable limits and sub-limits of our policies. We are also exposed to losses due to business interruptions caused by machinery breakdown of fewer than 45 days per occurrence and losses due to property damage that are less than $4.3 million per occurrence. Because Hurricane Harvey did not cause any significant losses to our equipment or facilities, lost profitability resulting from the operational interruption of Hurricane Harvey was outside the scope of our insurance coverage.

With regard to environmental claims due to pollution, we currently have a policy limit of $25.0 million, and this policy has a deductible of $250,000. Our current construction floater policy contains a specific limit of $20.0 million for losses incurred during the construction of any equipment or facilities at our site. We continue to evaluate our policy limits and risk retentions as they relate to the overall cost and scope of our insurance program.


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None of our contracts 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.
None of our contracts provide for a minimum commitment from our customers. Although our contracts set pricing terms, they generally do not obligate the counterparty to purchase a specified minimum volume of methanol or ammonia from us. As such, many of 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 such 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 none of our contracts 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 and the Celanese-Mitsui joint venture have brought their new methanol facilities online in the last three years and Natgasoline, in which OCI indirectly owns a 50% interest, is currently in the construction phase on its 1.8 million metric ton methanol facility in Beaumont, Texas, and has stated that it expects to commence operations in the second quarter of 2018. In addition, Yuhuang Chemical and several other developers have announced plans to construct methanol plants in the U.S. Gulf Coast region over the next few years, which, if constructed, would increase overall U.S. production capacity and the availability of methanol supply to our customers from competing sources. 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.
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.

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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.
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.

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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 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. For example, Methanex and the Celanese-Mitsui joint venture have brought their new methanol facilities online in the last three years and Natgasoline, in which OCI indirectly owns a 50% interest, is currently in the construction phase on its 1.8 million metric ton methanol facility in Beaumont, Texas, and has stated that it expects to commence operations in the second quarter of 2018. In addition, Yuhuang Chemical and several other developers have announced plans to construct methanol plants in the U.S. Gulf Coast region over the next few years, which, if constructed, would increase overall U.S. production capacity and the availability of methanol supply to our customers from competing sources. There have also been significant ammonia capacity additions in the U.S. Gulf Coast region, including CF Industries' Donaldsonville plant and Dyno Nobel's ammonia plant in Louisiana. In addition, BASF/Yara have announced that they expect to commission an ammonia plant in Freeport, Texas in 2018. 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 profitability 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 New York Mercantile Exchange (“NYMEX”) pricing point, Henry Hub, spiking to near-record high prices in 2008 and approaching seventeen-year lows at the beginning of 2016. This is 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 three main suppliers, Kinder Morgan, Houston Pipe Line Company and Enterprise Products, through supply agreements that are based on market indices, making us susceptible to fluctuations in the price of natural gas. In addition, the price we pay for hydrogen depends on natural gas prices. Operating at full capacity, our methanol and ammonia production units together require approximately 110,000 to 120,000 MMBtu per day of natural gas, as of December 31, 2017. A hypothetical increase or decrease of $1.00 per MMBtu of natural gas would increase or decrease our annual cost of goods sold (exclusive of depreciation) by approximately $43.9 million to $47.5 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. All of these permits, licenses, approvals and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate 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 could 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.

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During 2015, we executed a debottlenecking project that increased the output from our methanol and ammonia production units. 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. However, 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.
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, 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 construction projects;
poor workmanship, labor disputes or work stoppages;
failure by subcontractors to comply with applicable laws and regulations;
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. If the actual cost to complete 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.

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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 MTBE. 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, methanol is used in the United States 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. 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 as a known human carcinogen by the International Agency for Research on Cancer and as a probable human carcinogen by the EPA. On July 7, 2010, President Obama signed the Formaldehyde Standards for Composite Wood Products Act into law, which establishes limits for formaldehyde emissions from composite wood products and requires the EPA to evaluate and establish limits for other types of wood products. In December 2016, the EPA finalized a regulation to implement this Act with two components: (1) formaldehyde emissions standards for hardwood plywood, medium-density fiberboard, particleboard, and finished goods containing these products that are sold, supplied, offered for sale, or manufactured (including imported) in the United States and (2) a third-party certification program to assure compliance by composite wood panel producers with the formaldehyde emissions limits established directly in the Act. This regulation was to become effective in December 2017, but the EPA has extended the compliance deadlines under the December 2016 rule to December 2018 and beyond. In addition, in December 2017, the EPA published a notice that it is withdrawing its direct final rule issued in October 2017 to update the voluntary consensus standards that were originally published in the December 2016 rule. The EPA had issued both a direct final rule and a proposed rule in October 2017. The EPA stated that, due to its receipt of adverse comments on the rule, it was required to withdraw the direct final rule and proceed with issuing a final rule only after it has considered all of the comments received. The comment period for submitting comments closed in November 2017. As of April 1, 2015, formaldehyde was reclassified in the European Union as a category 1B carcinogen and category 2 mutagen. No decision has yet been made, however, whether this reclassification will result in restrictions under the Regulation on Registration, Evaluation, Authorization and Restrictions of Chemicals in the European Union, including in particular whether formaldehyde should be designated as a Substance of Very High Concern Candidate. 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.
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, which 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 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 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 GHGs 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. In addition, in December 2013, bipartisan legislation was introduced in the U.S. Senate to eliminate the corn-ethanol blending requirement for refiners. 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 United States, 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 has proposed various related regulatory actions, including approving various new regulations that, among other things, require green completions of certain hydraulically fractured wells and reduce emissions of methane and volatile organic compounds from certain sources in the oil and gas sector. 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 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 ability to make cash distributions.

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Our operations are dependent on third parties and their pipelines to provide us with our natural gas, hydrogen and nitrogen feedstock. 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, Florida Gas Transmission, Houston Pipe Line Company, Enterprise Products, Air Products and 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, approximately 52% of our methanol and approximately 77% of our ammonia is transported by barge along the Gulf Coast, approximately 47% of our methanol and approximately 10% of our ammonia is transported directly to certain customers through their pipelines and approximately 1% of our methanol and approximately 13% of our ammonia is transported to certain customers through our truck loading facilities. We may experience risks associated with distribution of our products by barge, pipelines or truck. 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. In September 2017, we were unable to immediately restart our ammonia production facility due to the temporary closure of the Sabine-Neches waterway as a result of Hurricane Harvey. This resulted in storage constraints at our facility. A significant increase in fuel prices could increase the costs incurred by our customers who transport our products by truck, which could decrease the volume of methanol and ammonia transported through our truck loading facilities. Prolonged interruptions in the transport of our products by barge or pipeline, or a reduction in the volume of methanol and ammonia transported through our truck loading facilities, could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Our customers purchase our methanol and ammonia on an FOB basis at our facility and then arrange and pay to transport it to their final destinations by barge according to customary practice in our market. Methanol and ammonia are also distributed to certain 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, 2017, Methanex and Southern Chemical Distribution, L.L.C. accounted for approximately 40% and 14%, 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.
In 2017, we competed, and we have historically competed with certain of our customers, including Methanex, Koch and Southern Chemical Distribution, L.L.C. 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.
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.

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Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate 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 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 GHG 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 GHG emission reduction laws, although the specific requirements and timing of any such laws are uncertain at this time. 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 GHG emissions, the EPA is moving ahead administratively under its CAA authority. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs to inventory and report their GHG emissions to the EPA. In accordance with the rule, we have begun monitoring our GHG emissions from our facility and have reported the emissions to the EPA beginning in 2011. On December 7, 2009, the EPA finalized its “endangerment finding” that GHG emissions, including CO2, pose a threat to human health and welfare. The finding allows the EPA to regulate GHG emissions as air pollutants under the CAA. In May 2010, the EPA finalized the “Greenhouse Gas Tailoring Rule,” which establishes new GHG emissions thresholds that determine when certain large stationary sources, such as our facility, must obtain permits under the 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 GHG emissions. The TCEQ has since been authorized by the EPA to implement a greenhouse gas permitting program.
The implementation of the 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 GHG emissions program. Increased costs associated with compliance with any future legislation or regulation of GHG emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Further, in December 2015, over 190 countries, including the United States, reached an agreement on the Paris Accord to reduce global greenhouse gas emissions. The Paris Accord entered into force in November 2016. The United States is one of over 70 countries that has ratified or otherwise indicated its intent to be bound by the agreement. To the extent the United States implements the Paris Accord in addition to the GHG regulations, it could have an adverse impact on our operations. However, on June 1, 2017, President Trump announced that the United States will withdraw from the Paris Accord and seek negotiations either to reenter the Paris Accord on different terms or to establish a new framework agreement. The Paris Accord provides for a four-year exit process, which would result in an effective exit date of November 2020. The United States' adherence to the exit process and/or the terms on which the United States may reenter the Paris Accord or a separately negotiated agreement are unclear at this time.
In addition, climate change legislation and regulations may result in increased costs not only for our business but also for our customers that utilize our products, thereby potentially decreasing demand for our products. Decreased demand for our 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 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.

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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.
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;
we may not have sufficient flexibility to react to adverse changes in the economy, our business or the industries in which we operate;
to the extent that we are unable to refinance our debt at maturity on favorable terms, or at all, our ability to fund our operations and our ability to make cash distributions could be adversely affected; and
an event of default under our credit agreements (such as failure to maintain financial covenants) could cause our debt to be accelerated which could impair our ability to fund our operations and our ability to make cash distributions.
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. As of March 5, 2018, our current debt service requirements on an annualized basis are approximately $24 million per year of interest and principal payments on our Term Loan B Credit Facility, approximately $75,000 per year of interest and commitment fees on our Revolving Credit Facility, approximately $203,000 per year of interest and commitment fees on our Revolving Credit Facility—Related Party, and approximately $18 million per year of interest on our Term Loan Facility—Related Party. Assuming our New Term Loan closes with an expected pricing of LIBOR plus 425 basis points, we would incur approximately $33 million per year of interest and principal payments on our New Term Loan based on the LIBOR as of March 5, 2018. 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 expenditures, debt service requirements 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 the principal of 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.

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Restrictions in the agreements governing our current and future indebtedness contain or likely will contain significant limitations on our business operations, including our ability to pay distributions and other payments.
As of December 31, 2017, we had $447.8 million of debt outstanding, excluding an unamortized debt discount of approximately $3.9 million. We and OCIB 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.”
In addition, we are subject to covenants contained in our debt agreements and any agreement governing other future indebtedness that will, subject to certain exceptions, limit our ability and the ability of OCIB or any of our future subsidiaries to, among other things, incur additional indebtedness, create liens on assets, engage in mergers or consolidations, sell assets, pay dividends and distributions or repurchase our common units, make investments, loans or advances, prepay certain subordinated indebtedness, make certain acquisitions or enter into agreements with respect to our equity interests, and engage in certain transactions with affiliates. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.” 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.
To the extent our ability to borrow under our existing credit facilities is limited or restricted, our liquidity may be insufficient to meet the operational and financial needs of our business.
Our ability to finance our business and operations, and ultimately to pay distributions to our unitholders, is dependent on our access to adequate sources of liquidity. Our ability to borrow under our existing third-party credit facilities is subject to covenant restrictions under the agreements governing those facilities. Our ability to borrow under our intercompany credit facilities with OCI is dependent on OCI’s ability and willingness to loan money to us under those facilities. To the extent that OCI faces liquidity, capital, credit or other constraints at the time we initiate borrowings under our intercompany credit facilities, we may be unable to draw the full amount otherwise available to us under those facilities. If for any of these or other reasons our ability to borrow additional funds under our third-party or intercompany credit facilities is limited or restricted, our ability to finance our business and operations and to pay distributions to unitholders could be adversely affected. For a further discussion of our liquidity and capital resources, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Facilities.”
We may not be able to consummate our New Term Loan or New Revolving Credit Facility at the expected terms, or at all.

We have priced our proposed $455 million New Term Loan and proposed $40 million New Revolving Credit Facility. However, the commitments in respect of the New Term Loan and New Revolving Credit Facility and the terms and conditions thereof (including the applicable interest rates) remain subject to the execution of definitive documentation with respect to the New Term Loan and New Revolving Credit Facility. The closing of the New Term Loan and New Revolving Credit Facility is expected to occur in March 2018 and is subject to customary closing conditions. In the event that we are unable to consummate our New Term Loan or New Revolving Credit Facility at the expected terms, or at all, then our ability to repay our Term Loan B Credit Facility and outstanding intercompany loans from OCI would be adversely affected, which could have an adverse effect on our business and operations.

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.

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Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business.
We 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 incur significant legal, accounting and other expenses that we did not incur as a private company, including 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. 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 Jumpstart Our Business Startups Act of 2012 (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.
In connection with the filing of the Annual Report on Form 10-K for the year ended 2018, we will no longer be an emerging growth company under the JOBS Act. After we are no longer an emerging growth company, we expect to incur 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. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our results of operations and financial condition may be materially adversely affected. 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Sarbanes-Oxley.
Risks Inherent in an Investment in Us
Under our current cash distribution policy, we intend to distribute 100% of the cash available for distribution that we generate each quarter, which could limit our ability to grow and make acquisitions.
Under our current cash distribution policy, we intend to distribute 100% of the cash available for distribution that we generate each quarter to our unitholders. Please read Item 5—“Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” included in this report for additional information. As a result, our general partner will rely primarily upon external financing sources, including commercial bank or intercompany borrowings or issuances of debt or 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 we intend 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 partnership interests in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional partnership interests will decrease the amount we distribute on each outstanding common unit. There are no limitations in our partnership agreement on our ability to issue additional partnership interests, including partnership interests 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.

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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.
OCI indirectly owns a non-economic general partner interest and, together with its affiliates, currently owns an approximately 89.26% limited partner interest in us as of December 31, 2017 and indirectly owns and controls our general partner. Additionally, OCI USA, an indirect wholly-owned subsidiary of OCI, is the lender under the Term Loan Facility—Related Party, under which we had $200.0 million outstanding as of December 31, 2017. 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 certain sales decisions, 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;
as a lender under the Term Loan Facility—Related Party and Revolving Credit Facility—Related Party, OCI USA, may have interests that differ from holders of our common units;
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 ability to pay distributions may be limited in order to repay the Term Loan Facility—Related Party and the Revolving Credit Facility—Related Party;
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;
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.

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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. For example, Natgasoline, in which OCI indirectly owns a 50% interest, is constructing a methanol plant adjacent to our facility in Beaumont, Texas, and has stated that it expects to commence operations in the second quarter of 2018. This facility will compete directly or indirectly with our facility to one degree or another, and OCI has no obligation to offer, and we have no right to acquire, any interest in this facility. OCI may also acquire or construct additional facilities in the future that may compete with us.
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 as opposed to in its individual capacity, our general partner is required to make such 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 reliance on the provisions of our partnership agreement;
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 intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; 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. By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

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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 common 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 of March 5, 2018, approximately 88.25% of our common units are owned by OCIP Holding, LLC, an indirect, wholly-owned subsidiary of OCI USA, an indirect, wholly-owned subsidiary of OCI that owns and controls our general partner, and approximately 1% of our common units are owned by Nassef Sawiris, one of our directors and the chief executive officer of OCI. As a result, as of March 5, 2018, our general partner and its affiliates own approximately 89.26% of our outstanding common units. Due to the acquisition of 7,276,549 units on December 26, 2017 by OCIP Holding, LLC, our general partner and its affiliates would need to acquire 644,478 units to meet the 90% threshold. If our general partner exercises its call right, 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.
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 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 are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66 23% of all outstanding units voting together as a single class is required to remove our general partner. As of March 5, 2018, our general partner and its affiliates own 89.26% of the common units issued and outstanding.
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.

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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 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.
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.
We may issue additional partnership interests without unitholder approval, which would dilute common 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 partnership interests of equal or senior rank will have the following effects:
our common unitholders’ proportionate ownership interest in us will decrease;
the amount of cash distributions on each common unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of our common units may decline.

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OCIP Holding may sell common units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of December 31, 2017, OCIP Holding, an indirect, wholly-owned subsidiary of OCI, owns 76,774,139 common units, representing approximately 88.25% of our outstanding common units. We have agreed to provide OCIP Holding with certain registration rights under applicable securities laws. The sale of these common units in the public or private markets could have an adverse impact on the market for our common units and the price at which they trade.
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.
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 equity holders of companies that are subject to all of the corporate governance requirements of the NYSE.
Tax Risks
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 entity-level taxation, or if we were otherwise subjected to a material amount 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 U.S. 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 21%, 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. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Therefore, if we were treated as a corporation for U.S. federal income tax purposes, or otherwise subjected to a material amount of entity-level taxation, 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.

41


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 time. For example, members of Congress and the President have periodically considered substantive changes to the existing U.S. federal income tax laws that would affect the tax treatment of certain publicly traded partnerships, including the elimination of the partnership tax for 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 satisfy the requirements of the exception pursuant to which we are treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.
Pursuant to final Treasury Regulations issued by the IRS and the U.S. Department of the Treasury, income derived from the production and marketing of methanol does not constitute “qualifying income” following the expiration of a ten-year transition period.
On January 24, 2017, the IRS and the U.S. Department of the Treasury published final Treasury Regulations promulgated under the Internal Revenue Code of 1986, as amended (the “Code”) that provide guidance regarding whether income earned from certain activities will constitute qualifying income. Pursuant to these final Treasury Regulations, income earned from the production and marketing of methanol and synthesis gas does not constitute qualifying income. These Treasury Regulations apply to taxable years beginning on or after January 19, 2017. We previously received a private letter ruling from the IRS concluding that the income we earn from the production and marketing of methanol and synthesis gas does constitute qualifying income, and we may continue to rely on this private letter ruling and treat such income as qualifying income during a ten-year transition period ending on the last day of our taxable year ending on or after January 19, 2027. After the conclusion of this ten-year transition period, all or part of our businesses may become subject to federal income tax at the maximum corporate rate, which would have a material adverse effect on our distributable cash flow and our ability to make cash distributions to our unitholders. In addition, the market price of our common units may decline significantly following, or in anticipation of, the expiration of this transition period. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Potential Impact of Final IRS Regulations Regarding Qualifying Income” for a more detailed discussion of the final Treasury Regulations and their potential impact on us and our unitholders.
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.
We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his or her share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information we will take various accounting and reporting positions. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained in an audit of our federal income tax information returns. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of 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. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his or her return. Any audit of a unitholder’s return could result in adjustments not related to our returns, as well as those related to our returns.

42


If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we expect to elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might 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.
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.
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 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 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 have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations promulgated under 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.

43


We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
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 those common units could be fully taxable as ordinary income. 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.
As a result of investing in our common units, you may be 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 are likely 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 are likely 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 currently 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.
ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.
ITEM 2.    PROPERTIES
The location and general character of our methanol and ammonia production facility has been described under Item 1—“Business” and are incorporated herein by reference. Our facility is located on a 62-acre site that is part of a large chemical refining and industrial complex located six miles south of Beaumont, Texas, on the Neches River. We own the land, plant and processing equipment at our facility. We believe that the land, plant and processing equipment at our facility are adequate for our current operations.

44


ITEM 3.    LEGAL PROCEEDINGS
We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business. We also incorporate by reference into this Part I, Item 3 of this Report, the information regarding the lawsuits and proceedings described and referenced in note 10 — “Commitments, Contingencies and Legal Proceedings” to our Consolidated Financial Statements as set forth in Part II, Item 8 of this Annual Report. In accordance with accounting principles generally accepted in the United States of America (“GAAP”), we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect, individually or in the aggregate, on our business, financial condition or results of operations.
ITEM 4.    MINE SAFETY DISCLOSURES
Not Applicable.

45


PART II
 
ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common units began trading on the NYSE under the symbol “OCIP” on October 4, 2013. On February 26, 2018, the closing price for our common units was $9.15 per unit. The number of unitholders of record as of February 26, 2018 was 3. Based upon the securities position listings maintained for our common units by registered clearing agencies, we estimate the number of beneficial owners is 64. As of March 5, 2018, there were 86,997,590 common units outstanding.
The following table sets forth the range of high and low closing prices for our common units as reported by the NYSE:
Year Ended December 31, 2017
High
 
Low
Fourth Quarter, ended December 31, 2017
$
8.05

 
$
6.95

Third Quarter, ended September 30, 2017
$
9.00

 
$
7.95

Second Quarter, ended June 30, 2017
$
10.20

 
$
7.40

First Quarter, ended March 31, 2017
$
10.20

 
$
8.45

Year Ended December 31, 2016
High
 
Low
Fourth Quarter, ended December 31, 2016
$
8.40

 
$
4.95

Third Quarter, ended September 30, 2016
$
8.03

 
$
5.71

Second Quarter, ended June 30, 2016
$
8.10

 
$
6.25

First Quarter, ended March 31, 2016
$
7.76

 
$
6.13

Cash Distribution Policy
Under our current cash distribution policy, we intend 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. Cash available for distribution is generally equal to EBITDA reduced for cash needed for (i) debt service requirements, (ii) maintenance and expansion capital expenditures which is composed of (a) capital expenditures and (b) reserves for scheduled turnaround expenses, (iii) reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any, (iv) taxes and (v) rounding for distributions which reflects the positive or negative adjustment necessary to eliminate any fraction of a cent per unit on our declared cash distributions.
We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distributions or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. As such, 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. Cash available for distribution is not a recognized term under GAAP. Cash available for distribution should not be considered in isolation or as an alternative to net income or operating income, as a measure of operating performance. In addition, cash available for distribution is not presented as, and should not be considered an alternative to, cash flows from operations or as a measure of liquidity. Cash available for distribution as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure.






46


The following table provides a reconciliation of EBITDA and cash available for distribution to net income, the most directly comparable GAAP financial measure, for the period indicated:
 
Three Months Ended
December 31, 2017
 
(in millions)
Reconciliation of Net income to EBITDA
 
Net income
12.7

Adjustments:
 
Add:
 
Interest expense
5.8

Interest expense—related party
4.3

Income tax expense
0.2

Depreciation expense
15.3

EBITDA
38.3

Reconciliation of EBITDA to Cash available for distribution
 
EBITDA
38.3

Adjustments:
 
Add:
 
Loss on disposition of fixed assets
1.9

Less:
 
Debt service (1)
10.6

Maintenance capital expenditures
 
Capital expenditures
0.4

Reserves for future turnarounds
1.5

Reserves for future operating or capital needs
4.0

Taxes
0.2

Rounding for distributions

Cash available for distribution
23.5

Actual cash distributions declared
23.5

(1)
Debt service is defined as (i) cash interest paid on long-term debt and revolving credit facilities, plus (ii) mandatory quarterly repayments on the Term Loan B Credit Facility, plus (iii) a 0.5% commitment fee on the unused portion of the $40.0 million Revolving Credit Facility—Related Party, plus (iv) a 1.4% commitment fee on the unused portion of the $35.0 million Revolving Credit Facility, plus (v) any up-front fees, transactions costs, etc. related to indebtedness. Debt service excludes amortization of deferred financing costs.

Because our policy is 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. 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.

A summary of cash distributions paid to unitholders during the years ended December 31, 2017, 2016 and 2015 and has been included in note 13 — “Distributions” to our Consolidated Financial Statements as set forth in Part II, Item 8 of this Annual Report.

47


The terms of our Term B Credit Facility provide that distributions from us and OCIB are permitted so long as (1) no event of default shall have occurred and be continuing and (2) OCIB has been in compliance with the terms of the Term B Credit Facility, including its financial covenants on a pro forma basis for the most recently completed four fiscal quarters as of the date of such distribution. As of December 31, 2017, we are in compliance with all of these covenants. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.”
Long-Term Incentive Plan Information
See Item 12—“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under our long-term incentive plan (“LTIP”).
Issuer Purchases of Equity Securities
We did not repurchase any of our common units during the year ended December 31, 2017, and we do not have any announced or existing plans to repurchase any of our common units.

48


ITEM 6.    SELECTED FINANCIAL DATA
The following table includes selected summary financial data for the years ended December 31, 2017, 2016, 2015, 2014 and 2013. The selected financial information presented below under the caption “Statements of Operations Data” for the fiscal years ended December 31, 2017, 2016, 2015, 2014 and 2013 and the selected financial information presented below under the caption “Balance Sheet Data” as of December 31, 2017 and 2016 have been derived from our audited financial statements included elsewhere in this report. The data below should be read in conjunction with Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8—“Financial Statements and Supplementary Data.” The data below is in thousands, except for per unit data and product pricing.
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
STATEMENTS OF OPERATIONS DATA
 
 
 
 
 
 
 
 
 
Revenues
$
324,883

 
$
247,234

 
$
298,690

 
$
402,780

 
$
427,964

Revenues—related party
18,442

 
10,995

 
10,753

 

 

Total revenue
343,325

 
258,229

 
309,443

 
402,780

 
427,964

 
 
 
 
 
 
 
 
 
 
Cost of goods sold (exclusive of depreciation)
181,466

 
162,810

 
149,463

 
205,529

 
188,630

Cost of goods sold (exclusive of depreciation)—related party
17,384

 
16,259

 
16,353

 
13,266

 
2,324

Total cost of goods sold (exclusive of depreciation)
198,850

 
179,069

 
165,816

 
218,795

 
190,954

 
 
 
 
 
 
 
 
 
 
Selling, general and administrative
12,322

 
15,856

 
16,906

 
17,928

 
18,088

Selling, general and administrative—related party
3,476

 
4,160

 
4,326

 
4,428

 
8,686

Total selling, general and administrative expenses
15,798

 
20,016

 
21,232

 
22,356

 
26,774

 
 
 
 
 
 
 
 
 
 
Depreciation expense
61,045

 
61,441

 
49,663

 
23,105

 
22,229

Income (loss) from operations before interest expense, other income and income tax expense
67,632

 
(2,297
)
 
72,732

 
138,524

 
188,007

Interest expense
22,857

 
45,096

 
20,018

 
18,250

 
16,684

Interest expense—related party
17,339

 
1,777

 
203

 
203

 
14,038

Loss on extinguishment of debt

 

 

 

 
6,689

Other income (expense)
(2,082
)
 
(577
)
 
123

 
941

 
5,154

Income (loss) from operations before tax expense
25,354

 
(49,747
)
 
52,634

 
121,012

 
155,750

Income tax expense
875

 
806

 
613

 
1,564

 
1,399

Net income (loss)
$
24,479

 
$
(50,553
)
 
$
52,021

 
$
119,448

 
$
154,351

Net income subsequent to initial public offering (October 9, 2013 through December 31, 2013)
 
 
 
 
 
 
 
 
$
47,380

Net income (loss) per common unit—Basic and Diluted(1)
$
0.28

 
$
(0.58
)
 
$
0.61

 
$
1.48

 
$
0.59

Weighted-average units used to compute net income (loss) per common unit:
 
 
 
 
 
 
 
 
 
Basic and Diluted
86,997,590

 
86,997,590

 
85,970,912

 
80,918,531

 
79,656,250


49


 
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
BALANCE SHEET DATA
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
16,275

 
$
8,080

 
$
13,238

 
$
71,810

 
$
182,977

Total assets
624,104

 
663,742

 
733,610

 
664,317

 
604,380

Total liabilities
483,783

 
510,491

 
496,747

 
476,253

 
453,009

Total partners’ capital/member’s equity
140,321

 
153,251

 
236,863

 
188,064

 
151,371

OTHER FINANCIAL DATA
 
 
 
 
 
 
 
 
 
EBITDA(2)
$
126,595

 
$
58,567

 
$
122,518

 
$
162,570

 
$
215,390

Capital expenditures for property, plant and equipment
2,128

 
6,785

 
233,540

 
152,160

 
52,634

Total debt (excluding accrued interest)
443,885

 
465,228

 
450,193

 
381,557

 
394,876

KEY OPERATING DATA
 
 
 
 
 
 
 
 
 
Products sold (thousand tons):
 
 
 
 
 
 
 
 
 
Ammonia
318.9

 
325.1

 
234.2

 
252.2

 
259.2

Methanol—procured
10.9

 

 

 

 
3.6

Methanol—produced
810.9

 
818.7

 
644.8

 
614.2

 
652.0

Products pricing (average dollars per ton):
 
 
 
 
 
 
 
 
 
Ammonia
$
240

 
$
258

 
$
425

 
$
503

 
$
525

Methanol—procured
$
317

 
$

 
$

 
$

 
$
447

Methanol—produced
$
325

 
$
213

 
$
325

 
$
449

 
$
444

Production (thousand tons):
 
 
 
 
 
 
 
 
 
Ammonia
312.4

 
331.5

 
234.7

 
259.2

 
259.8

Methanol
822.0

 
823.0

 
652.3

 
617.0

 
642.8

Days in Operations:
 
 
 
 
 
 
 
 
 
Ammonia
335

 
358

 
269

 
338

 
344

Methanol
331

 
340

 
272

 
320

 
336

Capacity Utilization Rate(3):
 
 
 
 
 
 
 
 
 
Ammonia
94
%
 
100
%
 
89
%
 
98
%
 
98
%
Methanol
90
%
 
90
%
 
94
%
 
85
%
 
88
%
Price of Natural Gas(4):
$3.13
 
$2.57
 
$2.73
 
$4.52
 
$3.78
_____________________________________
(1)
The 2013 amounts represent basic and diluted earnings per unit for the period from October 9, 2013 (the closing of our initial public offering) through December 31, 2013. Please see note 1— “Description of Business” in the notes to consolidated financial statements included in this report for additional information.
(2)
EBITDA is defined as net income (loss) plus (i) interest expense and other financing costs, (ii) depreciation expense, (iii) income tax expense and (iv) net loss on extinguishment of debt. We present EBITDA because it is a material component in our calculation of cash available for distribution. 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:
(1)
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; and
(2)
our operating performance and return on invested capital compared to those of other publicly traded limited partnerships and other public companies, without regard to financing methods and capital structure.
(3)
Calculated by total production volumes for a production unit for a given period, divided by the production capacity of that production unit. The 2015 amounts exclude planned downtime associated with the debottlenecking project.

50


(4)
Average purchase price of natural gas ($ per MMBtu) which is the Houston Ship Channel price plus a delivery fee, for a given period.
EBITDA is a non-GAAP measure and should not be considered an alternative to net income (loss), operating income (loss), 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, since each company may define this term differently.
The table below reconciles EBITDA to net income (loss) for the periods ended December 31, 2017, 2016, 2015, 2014 and 2013 (dollars in thousands).
 
Years Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
Net income (loss)
$
24,479

 
$
(50,553
)
 
$
52,021

 
$
119,448

 
$
154,351

 
Add:
 
 
 
 
 
 
 
 
 
 
Interest expense
22,857

 
45,096

 
20,018

 
18,250

 
16,684

 
Interest expense—related party
17,339

 
1,777

 
203

 
203

 
14,038

 
Depreciation expense
61,045

 
61,441

 
49,663

 
23,105

 
22,229

 
Income tax expense
875

 
806

 
613

 
1,564

 
1,399

 
Loss on extinguishment of debt

 

 

 

 
6,689

 
EBITDA
$
126,595

 
$
58,567

 
$
122,518

 
$
162,570

 
$
215,390

 

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ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis of our financial condition, results of operations and cash flows in conjunction with our consolidated financial statements and the related notes presented in this report. This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in control of management. Factors that could cause or contribute to these differences include those discussed elsewhere in this report, particularly, but not limited to, those set forth in Item 1A—“Risk Factors” and under “Forward-Looking Statements.”
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 one of the larger merchant methanol producers in the United States, with an annual methanol production design capacity of approximately 912,500 metric tons and an annual ammonia production design capacity of approximately 331,000 metric tons.
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. The primary use of methanol is to make other chemicals, with approximately 42% of global methanol demand being used to produce formaldehyde, acetic acid and a variety of other chemicals that form the foundation of a large number of chemical derivatives. These derivatives are used to produce a wide range of products, including adhesives for the lumber industry, plywood, particle board and laminates, resins to treat paper and plastic products, and also paint and varnish removers, solvents for the textile industry and polyester fibers for clothing and carpeting. Energy-related applications consume approximately 29% of methanol demand. In recent years, there has been a strong demand for methanol in energy applications such as gasoline blending, biodiesel and as a feedstock in the production of DME, MTBE, particularly in China. Methanol blending in gasoline is currently not permitted in the United States. MTO consumes the remaining 29% of global methanol demand as the MTO segment in China has grown by approximately 44% from 2016 to 2017, causing China to become increasingly reliant on imported methanol. Ammonia, 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. 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 derivatives.
On December 6, 2016, OCIP received a proposal from OCI pursuant to which OCI would acquire the publicly held common units not already directly or indirectly owned by OCI in exchange for OCI shares at an exchange ratio of 0.5200 OCI shares for each common unit. On April 14, 2017, after negotiations with the conflicts committee of the board of directors of our general partner regarding the Proposed Transaction reached an impasse, OCI informed representatives of the conflicts committee that no acceptable definitive agreement regarding the Proposed Transaction could be reached and terminated negotiations with the conflicts committee regarding the Proposed Transaction.
On February 20, 2018, we announced that we had priced a proposed $455 million term loan B facility and proposed $40 million revolving credit facility. The proposed New Term Loan is expected to mature in 2025, and is expected to be priced at the LIBOR plus 425 basis points. We intend to use the expected net proceeds of the New Term Loan to repay in full our Term Loan B Credit Facility and to repay in full outstanding intercompany loans from OCI. The commitments in respect of the New Term Loan and New Revolving Credit Facility and the terms and conditions thereof (including the applicable interest rates) remain subject to the execution of definitive documentation with respect to the New Term Loan and New Revolving Credit Facility. The closing of the New Term Loan and New Revolving Credit Facility is expected to occur in March 2018 and is subject to customary closing conditions. Assuming our New Term Loan closes with an expected pricing of LIBOR plus 425 basis points, we expect a reduction of approximately $10 million per year of interest and principal payments on our New Term Loan based on the LIBOR as of March 5, 2018.




52


FACTORS AFFECTING COMPARABILITY OF FINANCIAL INFORMATION
Our historical results of operations for periods prior to the completion of our debottlenecking project are not comparable with our results of operations for the year ended December 31, 2017 or in the future for the reason discussed below.
Our Debottlenecking Project
As a means of maximizing our production efficiencies and reducing our energy consumption, we executed a debottlenecking project on our production facility that included a maintenance turnaround and environmental upgrades. This project increased our maximum annual methanol production capacity by 25% to approximately 912,500 metric tons and our maximum annual ammonia production capacity by 25% to approximately 331,000 metric tons. Beginning in January 2015, we shut down our methanol and ammonia production units for 82 and 71 days, respectively, in order to complete the debottlenecking project. We began start-up of the ammonia production facility on April 9, 2015 and reached daily ammonia production design capacity of 907 metric tons on May 5, 2015. We began start-up of the methanol production facility on April 22, 2015 and reached daily methanol production design capacity of 2,500 metric tons on May 23, 2015. The total cost of the debottlenecking project (including costs associated with a turnaround and environmental upgrades) was approximately $384.0 million (excluding capitalized interest).
Our depreciation expense has increased from the additional assets placed into service from our debottlenecking project. In addition, due to the increase in our production capacity, our production volumes and cost of goods sold are greater in subsequent periods following the completion of the debottlenecking project than in prior periods. Thus, our results of operations for periods prior to and after the completion of our debottlenecking project may not be comparable.
Key Industry and Operational 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. The primary use of methanol is to make other chemicals, with approximately 42% of global methanol demand being used to produce formaldehyde, acetic acid and a variety of other chemicals that form the foundation of a large number of chemical derivatives. These derivatives are used to produce a wide range of products, including adhesives for the lumber industry, 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.
Energy-related applications consume approximately 29% of global methanol demand. In recent years, there has been a strong demand for methanol in energy applications such as gasoline blending, biodiesel and as a feedstock in the production of DME and MTBE, particularly in China. Methanol blending in gasoline is currently not permitted in the United States, but 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. MTO consumes the remaining 29% of global methanol demand as the MTO segment in China has grown by approximately 44% from 2016 to 2017, causing China to become increasingly reliant on imported methanol.
Historically, demand for methanol in chemical derivatives has been closely correlated to levels of global economic activity, energy prices 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. Since methanol is used as the feedstock in the production of olefins, the polyolefin markets and its drivers, in particular packaging for food, are becoming more important. Methanol is predominately produced from natural gas, but is also produced from coal, particularly in China. Lower natural gas prices have resulted in an increase in methanol supply in the United States.

53


The methanol industry experienced a wave of global plant closures 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. However, a long period of low natural gas prices in the United States has made it economical for companies to upgrade existing plants and initiate construction of new methanol and nitrogen projects. For example, Methanex and the Celanese-Mitsui joint venture have brought their new methanol facilities online in the last three years and Natgasoline, in which OCI indirectly owns a 50% interest, is currently in the construction phase on its 1.8 million metric ton methanol facility in Beaumont, Texas, and has stated that it expects to commence operations in the second quarter of 2018. In addition, Yuhuang Chemical and several other developers have announced plans to construct methanol plants in the U.S. Gulf Coast region over the next few years, which, if constructed, would increase overall U.S. production capacity and the availability of methanol supply to our customers from competing sources. However, over the past few years, several methanol projects have been canceled or delayed as a result of higher capital expenditure estimates than originally anticipated, among other reasons. Nevertheless, it is expected that the U.S. will become self-sufficient in the next few years, eventually becoming a net exporter.
Ammonia. The fertilizer industry is the major end-user of ammonia, with approximately 77% used for the production of various fertilizers and approximately 3% used for direct application into the ground. Ammonia is also used to produce various industrial products including 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, which represents approximately 21% of the remaining global consumption of ammonia.
In the United States, there is a meaningful correlation between demand for nitrogen fertilizer products and crop prices. Demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on many factors, including crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted. 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.
The ammonia industry experienced a wave of global plant closures during 1998-2007 due to high natural gas prices. During this period, numerous U.S. ammonia facilities were shut down or relocated to other countries, resulting in the inability of current U.S. production capacity to meet current U.S. ammonia demand, which ultimately led to higher imports into the United States of ammonia and nitrogen fertilizers. More recently, the development of low-cost shale natural gas reserves in the United States has reduced the price of natural gas and has made it economical for companies to upgrade existing ammonia and nitrogen fertilizer plants and initiate construction of new ammonia and nitrogen projects. There have been significant capacity additions in the U.S. Gulf Coast region; including CF Industries' Donaldsonville plant and Dyno Nobel's ammonia plant in Louisiana. In addition, BASF/Yara have announced that they expect to commission an ammonia plant in Freeport, Texas in 2018. However, over the past few years, several ammonia projects have been canceled or delayed as a result of higher capital expenditure estimates than originally anticipated, among other reasons; therefore, we expect the U.S. will remain a net importer of ammonia.

54


Natural Gas Prices
Natural gas is the primary feedstock for our production of methanol and ammonia. Operating at full capacity, our methanol and ammonia production units together require approximately 110,000 to 120,000 MMBtu per day of natural gas, as of December 31, 2017. Accordingly, our profitability depends in large part on the cost of our natural gas feedstock, which approached seventeen-year lows at the beginning of 2016. 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 competitive position of methanol and ammonia producers outside of the United States where the natural gas price environment is generally higher.
For the year ended December 31, 2017, natural gas feedstock costs represented approximately 59% of our total cost of goods sold (exclusive of depreciation), as compared to 55% during the year ended December 31, 2016. Set forth below is a table showing amount paid for natural gas, the quantity purchased and the average cost per MMBtu, for the periods presented.
 
Amount spent on Natural Gas
Quantity Purchased
Average Cost per MMBtu
 
(in millions)
(in MMBtu)
$/MMBtu
Year-ended December 31,
 
 
 
2017
$116.4
37,238,062
$3.13
2016
$97.6
37,921,992
$2.57
2015
$81.7
29,959,223
$2.73
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. Our facility is connected to natural gas pipelines owned by Kinder Morgan, Houston Pipe Line Company, Florida Gas Transmission and DCP Midstream Partners, LP. We are currently receiving our natural gas from Kinder Morgan and Houston Pipe Line Company though our direct pipeline connections with those companies, and from Enterprise Products through our direct pipeline connection with Florida Gas Transmission. 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.
According to the Short-Term Energy Outlook published by the Energy Information Administration (the “EIA”) in February 2018, the Henry Hub natural gas spot price is expected to average $3.20 MMBtu during 2018 and $3.08 MMBtu in 2019. The EIA projects that U.S. total natural gas consumption will decrease by approximately 4% in 2018 and increase by approximately 2% in 2019. In 2019, the electric power and industrial sectors are the main drivers of consumption growth. During the same time period, U.S. natural gas production is expected to increase by approximately 9% in 2018 and 3% in 2019. 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.
Product Sales Contracts
We currently are party to methanol sales contracts with several customers, including but not limited to Methanex and Southern Chemical Distribution, L.L.C. One of our customers is obligated to use best efforts to purchase a certain quantity of methanol from us each year, but generally our customers may determine not to purchase any more methanol from us at any time and may purchase methanol from other suppliers. Consistent with industry practice, our methanol sales contracts set our pricing terms to reflect a specified discount to a published monthly benchmark methanol price (Argus or Southern Chemical), and our methanol is sold on an FOB basis when transported by barge, pipeline, and our methanol truck loading facility. For the year ended December 31, 2017, methanol sales contracts with Methanex and Southern Chemical Distribution, L.L.C accounted for approximately 40% and 14%, respectively, of our total revenues.

55


We are party to ammonia sales contracts with several customers, including but not limited to Interoceanic Corporation (“IOC”) and Lucite. Our customers have no minimum volume purchase obligations under these contracts, may determine not to purchase any more ammonia from us at any time and may purchase ammonia from other suppliers. Consistent with industry practice, these contracts set our pricing terms to reflect a specified discount to a published monthly benchmark ammonia price (CFR Tampa), and our ammonia is sold on an FOB basis when delivered by barge, pipeline, and our ammonia truck loading facility. For the year ended December 31, 2017, ammonia sales contracts with IOC accounted for approximately 8% of our total revenues.
During the year ended December 31, 2017, we delivered approximately 57% of our total sales by barge or vessel, 39% of our total sales by pipeline, and approximately 4% of our total sales through our methanol and ammonia truck loading facilities.
Facility Reliability
The amount of revenue we generate primarily depends on the sales and production volumes of methanol and ammonia. These volumes are primarily affected by the utilization rates of our production units, which is the total production volume for a production unit for a given period divided by the production capacity of that production unit. Production capacity is 907 metric tons per day for our ammonia production unit and 2,500 metric tons per day for our methanol production unit. Maintaining consistent, safe 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, which may result in lost margin opportunity, increased maintenance expense and a temporary decrease in working capital investment and related inventory position. As of December 31, 2017, we estimate for each day of unplanned downtime our lost opportunity cost to be approximately $500,000 to $600,000, per day. This estimate does not include the additional repair and maintenance costs associated with unplanned downtime.
We expect to perform maintenance turnarounds approximately every four years, which will typically last approximately four to five weeks for our methanol production unit and approximately three to four weeks for our ammonia production unit and cost approximately $24.0 million per turnaround. We will perform significant maintenance capital projects at our facility during a turnaround to minimize disruption to our operations and to maintain or improve reliability. We executed a turnaround as part of our debottlenecking project which was completed in April 2015. We expect that the next turnaround will occur in 2019.
Potential Impact of Final IRS Regulations Regarding Qualifying Income
In order to maintain our status as a partnership for U.S. federal income tax purposes, 90% or more of our gross income in each tax year must be “qualifying income” under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). If less than 90% of our gross income is qualifying income in any tax year, then we would be treated as a corporation for U.S. federal income tax purposes for such tax year and all subsequent tax years.
Prior to our initial public offering, we requested and received a favorable private letter ruling from the IRS to the effect that the income derived from processing and marketing gasoline, liquefied petroleum gas, methanol and synthesis gas produced through the processing of natural gas would constitute qualifying income.
On January 24, 2017, the IRS and the U.S. Department of the Treasury published final Treasury Regulations promulgated under the Code that provide guidance regarding whether income earned from certain activities will constitute qualifying income. Pursuant to these final Treasury Regulations, income earned from the production and marketing of methanol and synthesis gas does not constitute qualifying income. These Treasury Regulations apply to taxable years beginning on or after January 19, 2017. We may continue to rely on our private letter ruling from the IRS and treat income we earn from the production and marketing of methanol and synthesis gas as qualifying income during a ten-year transition period ending on the last day of our taxable year ending on or after January 19, 2027, which we generally expect to be December 31, 2027. This should allow us to maintain our treatment as a partnership for U.S. federal income tax purposes and to continue to execute our business strategy during the ten-year transition period.

56


How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our results of operations and profitability and include capacity utilization and EBITDA (as defined below). We view these metrics as important factors in evaluating our profitability and frequently review these measurements to analyze trends and make decisions.
Capacity Utilization
During the year ended December 31, 2017, our ammonia and methanol production units were in operation for 335 days and 331 days, respectively, as compared to 358 days and 340 days, respectively, during the year ended December 31, 2016. During the year ended December 31, 2017, our ammonia and methanol production units were shut down for 30 days and 34 days, respectively, due to, among other things, a natural gas supply control issue, leaks in the Transfer Line Heat Exchangers (“TLX”), and Hurricane Harvey. During the year ended December 31, 2016, our ammonia and methanol production units were shut down for 8 days and 26 days, respectively, due to an underground cooling water line leakage, repairs to our methanol reformer, an electrical power outage caused by our electrical power provider and repairs to our steam turbine of the syngas compressor.
We produced approximately 312,432 metric tons of ammonia and approximately 822,016 metric tons of methanol during the year ended December 31, 2017, representing capacity utilization rates of 94% and 90% for the ammonia and methanol production units, respectively, as compared to production of approximately 331,500 metric tons of ammonia and 823,000 metric tons of methanol during the year ended December 31, 2016, representing capacity utilization rates of 100% and 90% for the ammonia and methanol production units, respectively.
EBITDA
EBITDA is defined as net income (loss) plus (i) interest expense and other financing costs, (ii) depreciation expense, (iii) income tax expense and (iv) net loss on extinguishment of debt. 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 (loss), operating income (loss), 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.

57


RESULTS OF OPERATIONS
Comparison of the Results of Operations for the Years Ended December 31, 2017 and 2016:
Revenues
 
For the Years Ended
December 31,
 
2017
 
2016
 
(in thousands)
Total revenues
$
343,325

 
$
258,229

 
For the Year Ended
December 31, 2017
 
For the Year Ended
December 31, 2016
 
Metric Tons
 
Revenue
 
Metric Tons
 
Revenue
 
(in thousands)
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Ammonia
318.9

 
$
76,546

 
325.1

 
$
83,978

Methanol—Procured
10.9

 
3,438

 

 

Methanol—Produced
810.9

 
263,326

 
818.7

 
174,236

Other

 
15

 

 
15

Total
1,140.7

 
$
343,325

 
1,143.8

 
$
258,229

Our total revenues were approximately $343 million for the year ended December 31, 2017 compared to approximately $258 million for the year ended December 31, 2016. Our methanol revenues were approximately $267 million for the year ended December 31, 2017 compared to approximately $174 million for the year ended December 31, 2016, which is a 53% increase. The increase in methanol revenues is due to an increase in the average sales price per metric ton of methanol. Our ammonia revenues were approximately $77 million for the year ended December 31, 2017 compared to approximately $84 million for the year ended December 31, 2016, representing a 9% decrease. The decrease in ammonia revenues is due to a decrease in the average sales price per metric ton of ammonia, and lower ammonia sales volumes for the year ended December 31, 2017 compared to the year ended December 31, 2016.
We sold approximately 810,878 metric tons of produced methanol and approximately 10,857 metric tons of procured methanol during the year ended December 31, 2017 compared to approximately 818,700 metric tons of methanol during the year ended December 31, 2016. The average sales prices per metric ton of methanol sold during the year ended December 31, 2017 was $325 per metric ton compared to $213 per metric ton for the year ended December 31, 2016, representing an increase of 53%. During 2017, global supply disruptions caused by plant outages and production issues coupled with increases in global demand resulted in an increase in our average methanol sales price. Sales of methanol comprised approximately 78% of our total revenues for the year ended December 31, 2017 compared to 67% of our total revenues for the year ended December 31, 2016.
Set forth below is a table showing average methanol sales prices per metric ton, per quarter for the previous twelve fiscal quarters.
 
Average Methanol Sales Prices
 
2017
 
2016
 
2015
For the Three-Months Ended:
 
 
 
 
 
March 31
$
353

 
$
189

 
$
366

June 30
$
331

 
$
192

 
$
362

September 30
$
299

 
$
214

 
$
330

December 31
$
319

 
$
257

 
$
282


58


We sold approximately 318,889 metric tons of ammonia during the year ended December 31, 2017 compared to approximately 325,100 metric tons of ammonia during the year ended December 31, 2016, which represents a decrease of 2%. The average sales prices per metric ton of ammonia sold during the year ended December 31, 2017 was $240 per metric ton compared to $258 per metric ton for the year ended December 31, 2016, which represents a decrease of 7%. The price decrease is attributed to global supply and demand variations. Sales of ammonia comprised approximately 22% of our total revenues for the year ended December 31, 2017 compared to 33% of our total revenues for the year ended December 31, 2016.
Set forth below is a table showing average ammonia sales prices per metric ton, per quarter for the previous twelve fiscal quarters.
 
Average Ammonia Sales Prices
 
2017
 
2016
 
2015
For the Three-Months Ended:
 
 
 
 
 
March 31
$
247

 
$
295

 
$
509

June 30
$
291

 
$
301

 
$
447

September 30
$
185

 
$
235

 
$
418

December 31
$
246

 
$
199

 
$
378

Cost of Sales (exclusive of depreciation)
 
For the Year Ended
December 31, 2017
 
For the Year Ended
December 31, 2016
 
$ in thousands
 
% of Total
 
$ in thousands
 
% of Total
Natural Gas
$
116,423

 
58.5
%
 
$
97,616

 
54.5
%
Hydrogen
21,592

 
10.9
%
 
22,061

 
12.3
%
Nitrogen
7,403

 
3.7
%
 
10,194

 
5.7
%
Maintenance
16,001

 
8.0
%
 
17,520

 
9.8
%
Labor
16,273

 
8.2
%
 
16,064

 
9.0
%
Other
21,158

 
10.7
%
 
15,614

 
8.7
%
Total
$
198,850

 
100.0
%
 
$
179,069

 
100.0
%
Cost of goods sold (exclusive of depreciation) was approximately $199 million and 58% of revenue for the year ended December 31, 2017 compared to cost of goods sold (exclusive of depreciation) of approximately $179 million and 69% of revenues for the year ended December 31, 2016. This increase in cost of goods sold (exclusive of depreciation) for the year ended December 31, 2017 compared to the year ended December 31, 2016 was primarily due to an increase in natural gas prices. Our purchase price for natural gas increased from an average of $2.57 per MMBtu for the year ended December 31, 2016 to an average of $3.13 per MMBtu for the year ended December 31, 2017, an increase of 22%. The increase in cost of goods sold (exclusive of depreciation) was partially offset by a decrease in nitrogen feedstock costs of $3 million, due to an amendment of our nitrogen supply contract as part of an ongoing cost savings program initiated by management during the fourth quarter of 2016.
Set forth below is a table showing our purchase price for natural gas per MMBtu, per quarter for the previous twelve fiscal quarters.
 
Natural Gas Purchase Prices
 
2017
 
2016
 
2015
For the Three-Months Ended:
 
March 31
$
3.15

 
$
2.13

 
$
3.15

June 30
$
3.32

 
$
2.13

 
$
2.87

September 30
$
3.08

 
$
2.88

 
$
2.88

December 31
$
3.00

 
$
3.10

 
$
2.32


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The decrease in Total Cost of Goods Sold (exclusive of depreciation) as a percentage of revenues was due to the increase in Total Revenue. Our Total Revenues increased by 33% during the year ended December 31, 2017 as compared to the year ended December 31, 2016 due to the increase in average methanol sales prices, outpacing the increases in natural gas costs.
Depreciation Expense
Depreciation expense was approximately $61 million for the year ended December 31, 2017 compared to approximately $61 million for the year ended December 31, 2016.
Selling, General and Administrative Expense
Selling, general and administrative expenses were approximately $12 million for the year ended December 31, 2017 compared to approximately $16 million for the year ended December 31, 2016, which represents a decrease of 22%. The decrease in selling, general and administrative expenses was primarily due to a decrease in our insurance expense and property taxes.
Our selling, general and administrative expenses—related party were approximately $3 million for the year ended December 31, 2017 compared to approximately $4 million for the year ended December 31, 2016.
Interest Expense
Interest expense was approximately $23 million for the year ended December 31, 2017 compared to $45 million for the year ended December 31, 2016. During the year ended December 31, 2017, interest expense was lower than the comparable period as a result of the $200.0 million principal prepayment made on November 30, 2016 in which OCIB utilized the funds borrowed under the Term Loan Facility—Related Party to prepay $200.0 million of Term B Loans under the Term B Loan Credit Facility.
Interest expense—related party was approximately $17 million for the year ended December 31, 2017 compared to $2 million for the year ended December 31, 2016. During the year ended December 31, 2017, interest expense—related party was higher than the prior year as the result of $200.0 million in borrowings on November 30, 2016 under the Term Loan Facility—Related Party to prepay a portion of the Term Loan B Credit Facility. Interest expense—related party relates to interest expense and commitment fees on the unused portion of the Revolving Credit Facility—Related Party and interest expense on our Term Loan Facility—Related Party, both payable to OCI USA.


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Comparison of the Results of Operations for the Years Ended December 31, 2016 and 2015:
Revenues
 
For the Years Ended
December 31,
 
2016
 
2015
 
(in thousands)
Total revenues
$
258,229

 
$
309,443

 
For the Year Ended
December 31, 2016
 
For the Year Ended
December 31, 2015
 
Metric Tons
 
Revenue
 
Metric Tons
 
Revenue
 
(in thousands)
 
(in thousands)
Revenues:
 
 
 
 
 
 
 
Ammonia
325.1

 
$
83,978

 
234.2

 
$
99,443

Methanol
818.7

 
174,236

 
644.8

 
209,654

Other

 
15

 

 
346

Total
1,143.8

 
$
258,229

 
879.0

 
$
309,443

Our total revenues were approximately $258 million for the year ended December 31, 2016 compared to approximately $309 million for the year ended December 31, 2015. Our methanol revenues were approximately $174 million for the year ended December 31, 2016 compared to approximately $210 million for the year ended December 31, 2015, which is a 17% decrease. The decrease in methanol revenues is due to a decrease in the average sales price per metric ton of methanol, partially offset by higher methanol sales volumes. Our ammonia revenues were approximately $84 million for the year ended December 31, 2016 compared to approximately $99 million for the year ended December 31, 2015, representing a 16% decrease. The decrease in ammonia revenues is due to a decrease in the average sales price per metric ton of ammonia, partially offset by higher ammonia sales volumes for the year ended December 31, 2016 compared to the year ended December 31, 2015.
We sold approximately 818,700 metric tons of methanol during the year ended December 31, 2016 compared to approximately 644,800 metric tons of methanol during the year ended December 31, 2015, which represents an increase of 27%. The increase in methanol sales volumes was due to the corresponding increase in methanol production volumes, due to the production capacity additions from the debottlenecking project. In addition, during the year ended December 31, 2015, our methanol production unit was shut down for 82 days in order to complete the debottlenecking project. The average sales prices per metric ton of methanol sold during the year ended December 31, 2016 was $213 per metric ton compared to $325 per metric ton for the year ended December 31, 2015, representing a decrease of 34%. During 2016, increases in global supply, from the commissioning of new methanol capacity additions in North America and increases in global production utilization rates, outpaced demand growth leading to a decline in our average methanol sales price. Sales of methanol comprised approximately 67% of our total revenues for the year ended December 31, 2016 compared to 68% of our total revenues for the year ended December 31, 2015.
Set forth below is a table showing average methanol sales prices per metric ton, per quarter for the previous twelve fiscal quarters.
 
Average Methanol Sales Prices
 
2016
 
2015
 
2014
For the Three-Months Ended:
 
 
 
 
 
March 31
$
189

 
$
366

 
$
529

June 30
$
192

 
$
362

 
$
470

September 30
$
214

 
$
330

 
$
394

December 31
$
257

 
$
282

 
$
405


61


We sold approximately 325,100 metric tons of ammonia during the year ended December 31, 2016 compared to approximately 234,200 metric tons of ammonia during the year ended December 31, 2015, which represents an increase of 39%. The increase in ammonia sales volumes was due to the corresponding increase in ammonia production volumes, due to the production capacity additions from the debottlenecking project. In addition, during the year ended December 31, 2015, our ammonia production unit was shut down for 71 days in order to complete the debottlenecking project. The average sales prices per metric ton of ammonia sold during the year ended December 31, 2016 was $258 per metric ton compared to $425 per metric ton for the year ended December 31, 2015, which represents a decrease of 39%. The price decrease is attributed to global supply and demand variations. Prices have also been affected by additional nitrogen fertilizer production brought on line in North America during 2015 and 2016. Sales of ammonia comprised approximately 33% of our total revenues for the year ended December 31, 2016 compared to 32% of our total revenues for the year ended December 31, 2015.
Set forth below is a table showing average ammonia sales prices per metric ton, per quarter for the previous twelve fiscal quarters.
 
Average Ammonia Sales Prices
 
2016
 
2015
 
2014
For the Three-Months Ended:
 
 
 
 
 
March 31
$
295

 
$
509

 
$
408

June 30
$
301

 
$
447

 
$
511

September 30
$
235

 
$
418

 
$
508

December 31
$
199

 
$
378

 
$
568

Cost of Sales (exclusive of depreciation)
 
For the Year Ended
December 31, 2016
 
For the Year Ended
December 31, 2015
 
$ in thousands
 
% of Total
 
$ in thousands
 
% of Total
Natural Gas
$
97,616

 
54.5
%
 
$
81,710

 
49.3
%
Hydrogen
22,061

 
12.3
%
 
18,637

 
11.2
%
Nitrogen
10,194

 
5.7
%
 
7,743

 
4.7
%
Maintenance
17,520

 
9.8
%
 
22,952

 
13.8
%
Labor
16,064

 
9.0
%
 
18,795

 
11.3
%
Other
15,614

 
8.7
%
 
15,979

 
9.7
%
Total
$
179,069

 
100.0
%
 
$
165,816

 
100.0
%
Cost of goods sold (exclusive of depreciation) was approximately $179 million and 69% of revenue for the year ended December 31, 2016 compared to cost of goods sold (exclusive of depreciation) of approximately $166 million and 54% of revenues for the year ended December 31, 2015. This increase in cost of goods sold (exclusive of depreciation) for the year ended December 31, 2016 compared to the year ended December 31, 2015 was primarily due to an increase in our raw material consumption due to the increased production capacity from the execution of our debottlenecking project. Our purchase price for natural gas decreased from an average of $2.73 per MMBtu for the year ended December 31, 2015 to an average of $2.57 per MMBtu for the year ended December 31, 2016, a decrease of 6%.
Set forth below is a table showing our purchase price for natural gas per MMBtu, per quarter for the previous twelve fiscal quarters.
 
Natural Gas Purchase Prices
 
2016
 
2015
 
2014
For the Three-Months Ended:
 
March 31
$
2.13

 
$
3.15

 
$
5.07

June 30
$
2.13

 
$
2.87

 
$
4.66

September 30
$
2.88

 
$
2.88

 
$
4.28

December 31
$
3.10

 
$
2.32

 
$
4.07


62


Depreciation Expense
Depreciation expense was approximately $61 million for the year ended December 31, 2016 compared to approximately $50 million for the year ended December 31, 2015, which represents an increase of 24%. This increase was due to the assets placed in service during 2015 due to the completion of the debottlenecking project.
Selling, General and Administrative Expense
Selling, general and administrative expenses were approximately $16 million for the year ended December 31, 2016 compared to approximately $17 million for the year ended December 31, 2015, which represents a decrease of 6%. The decrease in selling, general and administrative expenses was primarily due to a decrease in our insurance expense and property taxes.
Our selling, general and administrative expenses—related party were approximately $4 million for the year ended December 31, 2016 compared to approximately $4 million for the year ended December 31, 2015.
Interest Expense
Interest expense was approximately $45 million for the year ended December 31, 2016 compared to $20 million for the year ended December 31, 2015. During the year ended December 31, 2016, interest expense was higher than the prior year as the result of amendments to our Term Loan B Credit Facility agreement and Revolving Credit Facility Agreement that resulted in higher interest rates. We capitalized $8.6 million of interest expense during the year ended December 31, 2016. No interest was capitalized during the year ended December 31, 2016. Capitalized interest costs are determined by applying a weighted average interest rate paid on borrowings to the average amount of accumulated capital expenditures in the period. This decrease in capitalized interest is due to the completion of the debottlenecking project.
Interest expense—related party was approximately $2 million for both the year ended December 31, 2016 compared to $203,000 for the year ended December 31, 2015. During the year ended December 31, 2016, interest expense—related party was higher than the prior year as the result of $200.0 million in borrowings on November 30, 2016 under the Term Loan Facility—Related Party to prepay a portion of the Term Loan B Credit Facility.
LIQUIDITY AND CAPITAL RESOURCES
Our principal liquidity requirements are to finance current operations, pay distributions to our partners, fund capital expenditures and service our debt. We believe that our current and expected sources of liquidity will be adequate to fund these operating needs and capital expenditures for the next 12 months. Our sources of liquidity include cash flow from operations, cash on hand, the Revolving Credit Facility and the Revolving Credit Facility—Related Party described below. However, our future capital expenditures and other cash requirements could be higher than we currently anticipate as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors outside our control.
Under our current cash distribution policy, we intend to distribute 100% of the cash available for distribution that we generate each quarter. Please read Item 5—“Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” included in this report for additional information.
Depending on the needs of our business, we may for time to time seek to issue additional common units, incur additional debt, modify the terms of our existing debt, or otherwise refinance our existing debt. There can be no assurance that we will be able to do any of the foregoing on terms acceptable to us or at all.
Credit Facilities
Described below are the credit facilities under which OCIB had available borrowing capacity as of December 31, 2017. Please read “Risk Factors—Risks Related to Our Business—To the extent our ability to borrow under our existing credit facilities is limited or restricted, our liquidity may be insufficient to meet the operational and financial needs of our business”, Item 8—“Financial Statements and Supplementary Data”, and note 6 and note 14 to the consolidated financial statements included in this report for additional information relating to OCIB’s credit facilities.

63


Term Loan B Credit Facility
On August 20, 2013, OCIB, as borrower, and OCI USA, as guarantor, entered into a senior secured term loan credit facility (as supplemented by a credit agreement joinder, dated as of October 18, 2013, under which the Partnership became a party to such credit facility as a guarantor, and as subsequently amended through and in effect as of December 31, 2017, the “Term Loan B Credit Facility”) with a syndicate of institutional lenders and investors and Bank of America, N.A., as administrative agent. As of December 31, 2017, the principal outstanding under the Term Loan B Credit Facility was $231.8 million. Interest on the Term Loan B Credit Facility accrues, at OCIB's option, at adjusted LIBOR plus 6.75% per annum or the alternate base rate (as each such term is defined in the Term Loan B Credit Facility), plus 5.75%.
Although we do not have any additional committed capacity from identified lenders or investors, as of December 31, 2017, we had capacity to incur another $50 million under the Term Loan B Credit Facility in the form of an additional incremental facility, subject to receiving commitments from lenders to provide such an additional amount. Furthermore, the Term Loan B Credit Facility contains customary covenants and conditions based on the maintenance of certain senior secured net leverage ratios and interest coverage ratios (see note 6 to the consolidated financial statements for a complete description). As a result of such covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs. In addition, to the extent that we are unable to refinance our debt at maturity on favorable terms, or at all, our ability to fund our operations and our ability to make cash distributions could be adversely affected. Upon the occurrence of certain events of default under the Term Loan B Credit Facility, OCIB’s obligations under the Term Loan B Credit Facility may be accelerated which could impair our ability to fund our operations and our ability to make cash distributions.
Revolving Credit Facility
On April 4, 2014, OCIB as borrower, the Partnership as a guarantor, Bank of America, N.A. as administrative agent and a syndicate of lenders entered into a revolving credit agreement (as subsequently amended through and in effect as of December 31, 2017, the “Revolving Credit Facility”), with an initial aggregate borrowing capacity of up to $40 million (less any amounts borrowed under the Revolving Credit Facility—Related Party (as defined below)), including a $20 million sublimit for letters of credit. The aggregate borrowing capacity of the Revolving Credit Facility was reduced by $2.5 million on the last day of each fiscal quarter commencing with the fiscal quarter ending June 30, 2017, leaving an aggregate borrowing capacity of $32.5 million as of December 31, 2017. The Revolving Credit Facility has a one-year term that expires on March 31, 2018 and may be extended for additional one-year periods subject to the consent of the lenders. As of December 31, 2017, outstanding principal amounts under the Revolving Credit Facility bear interest at OCIB’s option at either LIBOR plus a margin of 4.75% or a base rate plus a margin of 3.75%. OCIB pays a commitment fee of 1.40% per annum on the unused portion of the Revolving Credit Facility.
As of December 31, 2017, we had $16.5 million in additional committed capacity under the Revolving Credit Facility. The Revolving Credit Facility contains customary covenants and conditions based on the maintenance of certain senior secured net leverage ratios and interest coverage ratios (see note 6 to the consolidated financial statements for a more detailed description). As a result of such covenants, we will be limited in the manner in which we conduct our business and our ability to finance future operations or capital needs. In addition, to the extent that we are unable to refinance our debt at maturity on favorable terms, or at all, our ability to fund our operations and our ability to make cash distributions could be adversely affected. Upon the occurrence of certain events of default under the Revolving Credit Facility, OCIB’s obligations under the Revolving Credit Facility may be accelerated which could impair our ability to fund our operations and our ability to make cash distributions. As of December 31, 2017, OCIB had $16 million outstanding under the Revolving Credit Facility.
Revolving Credit Facility—Related Party
Our intercompany revolving credit facility with OCI USA (the “Revolving Credit Facility—Related Party”) has a borrowing capacity of $40 million and a maturity date of January 20, 2020. The amount that can be drawn under the Revolving Credit Facility—Related Party is limited by the Revolving Credit Facility to $40 million minus the amount of indebtedness outstanding under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility—Related Party bear interest at a rate equal to the sum of (i) the rate per annum applicable to the Revolving Credit Facility (as such rate may fluctuate from time to time in accordance with the terms of the agreement governing the Revolving Credit Facility), plus (ii) 0.25%. OCIB pays a commitment fee to OCI USA under the Revolving Credit Facility—Related Party on the undrawn available portion at a rate of 0.5% per annum, which is included as a component of interest expense—related party on the consolidated statements of operations. The Revolving Credit Facility—Related Party is subordinated to indebtedness under the Term Loan B Credit Facility and the Revolving Credit Facility. As of December 31, 2017, OCIB had no amounts outstanding under the Revolving Credit Facility—Related Party.


64


Term Loan Facility—Related Party
Our intercompany term loan facility with OCI USA (the “Term Loan Facility—Related Party”) has a borrowing capacity of $200 million and a maturity date of January 20, 2020. Borrowings under the Term Loan Facility—Related Party are subordinated to the Term B Loans under the Term Loan B Credit Facility and the Revolving Credit Facility. Borrowings under the Term Loan Facility—Related Party bear interest at a rate equal to the sum of (i) the rate per annum applicable to the Term B Loans (as such rate may fluctuate from time to time in accordance with the terms of the agreement governing the Term Loan B Credit Facility) plus (ii) 0.25%. Such interest is payable on or before the date that is two business days after each payment of interest under the Term Loan B Credit Facility either, at the election of OCIB, (i) in cash or (ii) in-kind (“PIK Interest”) on which date (in the case of PIK Interest) such accrued interest shall be added to the principal amount of the loan outstanding and accrue interest as set forth in the Term Loan Facility—Related Party. On November 30, 2016, OCIB borrowed $200 million under the Term Loan Facility—Related Party to prepay a portion of the Term Loan B Credit Facility. As of December 31, 2017, OCIB had $200 million outstanding under the Term Loan Facility—Related Party.
Proposed Refinancing Transactions
On February 20, 2018, we announced that we had priced a proposed $455 million term loan B facility (the “New Term Loan”) and proposed $40 million revolving credit facility (the “New Revolving Credit Facility”). The proposed New Term Loan is expected to mature in 2025, and is expected to be priced at the London Interbank Offered Rate (“LIBOR”) plus 425 basis points. We intend to use the expected net proceeds of the New Term Loan to repay in full our Term Loan B Credit Facility and to repay in full outstanding intercompany loans from OCI. The commitments in respect of the New Term Loan and New Revolving Credit Facility and the terms and conditions thereof (including the applicable interest rates) remain subject to the execution of definitive documentation with respect to the New Term Loan and New Revolving Credit Facility. The closing of the New Term Loan and New Revolving Credit Facility is expected to occur in March 2018 and is subject to customary closing conditions.  
Debt Ratings
On July 27, 2017, Standard & Poor's Global Ratings raised our corporate credit rating to “B-” from “CCC+”, raised its rating on the Term Loan B Credit Facility to “B+” from “B” and revised its outlook to stable from positive.
On February 13, 2018, Moody's Investors Service raised our corporate credit rating to “B1” from “B2”. On February 15, 2018, Standard & Poor's Global Ratings affirmed our corporate credit rating of “B-” and revised its outlook to positive from stable.
Our ability to obtain additional external financing and the related cost of borrowing may be affected by our debt ratings, which are periodically reviewed by the major credit rating agencies. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies.

65


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. Major maintenance capital expenditures that extend the life or improve the safety or efficiency of the asset are capitalized and amortized over the period of expected benefits. Routine maintenance costs are expensed as incurred. A turnaround is capitalized and amortized over a four year period, which is the time lapse between turnarounds. 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. Expansion capital expenditures are capitalized and amortized over the period of expected benefits.
For the year ended December 31, 2017 and 2016, we incurred approximately $1 million and $8 million, respectively, in maintenance capital expenditures related to our capital spares project and other budgeted maintenance capital projects. We expect to perform maintenance turnarounds approximately every four years, which will typically last approximately four to five weeks for our methanol production facility and approximately three to four weeks for our ammonia production facility and cost approximately $24 million per turnaround. We will 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 executed a turnaround as part of our debottlenecking project which was completed in April 2015. We expect the next turnaround to occur in 2019.
We did not have any expansion capital expenditures during the years ended December 31, 2017 and 2016.
Working Capital
Working capital is the amount by which total current assets exceed total current liabilities. Our working capital requirements have been, and we expect will continue to be, primarily driven by changes in accounts receivable and accounts payable. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, as well as the level of spending for capital expenditures and changes in the market prices of raw materials that we purchase in the normal course of business.
Working capital at December 31, 2017 was a surplus of $8 million, consisting of $65 million in total current assets and $57 million in total current liabilities. Working capital at December 31, 2016 was a deficit of $40 million, consisting of $42 million in total current assets and $82 million in total current liabilities. The reduction in the working capital deficit was primarily due to the use of operating cash flows to reduce our short-term indebtedness.

66


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.
The following table summarizes our consolidated statements of cash flows:
 
For the Year Ended
December 31,
 
2017
 
2016
 
(in thousands)
Net cash provided by (used in):
 
 
 
Operating activities
$
71,572

 
$
31,612

Investing activities
(2,101
)
 
(6,761
)
Financing activities
(61,276
)
 
(30,009
)
Net increase (decrease) in cash and cash equivalents
$
8,195

 
$
(5,158
)
Operating Activities
Net cash provided by operating activities for the year ended December 31, 2017 was $72 million. We had net income of $24 million for the year ended December 31, 2017. During this period, we recorded depreciation expense of $61 million and amortization of debt issuance costs of $2 million. Accounts receivable, which is approximately equal to one month of revenue, increased by $10 million during the year ended December 31, 2017. The increase in accounts receivable is due to an increase in realized methanol and ammonia sales prices in December 2017 as compared to December 2016. Third party sales increased to $33 million in December 2017 as compared to $22 million in December 2016. Accounts receivable—related party increased by $5 million due to sales to OCI Fertilizer Trade & Supply B.V. Inventories decreased by $2 million due to high sales volumes during December 2017 which caused a decrease in end of year methanol and ammonia inventory volumes. Accounts payable decreased by $5 million due to the use of operating cash flows to reduce our accounts payable balances.
Net cash provided by operating activities for the year ended December 31, 2016 was $32 million. We had a net loss of $51 million for the year ended December 31, 2016. During this period, we recorded depreciation expense of $61 million and amortization of debt issuance costs of $12 million. Accounts receivable, which is approximately equal to one month of revenue, decreased by $6 million during the year ended December 31, 2016. The decrease in accounts receivable is due to a decrease in the realized methanol and ammonia sales prices in December 2016 as compared to December 2015. Third party sales decreased to $22 million in December 2016 as compared to $29 million in December 2015. Accounts receivable—related party decreased by $4 million due to the expiration of our agreement with OCI Fertilizer Trade & Supply B.V. which expired in February 2016. Inventories increased by $2 million due to an increase in raw materials costs and an increase in end of year ammonia inventory volumes. Other non-current assets, other current assets and prepaid expenses decreased by $2 million due to a decrease in insurance policy premiums and the timing of the receipt and payment of our industrial property tax invoice. Other payables, accruals and current liabilities (excluding non-cash accruals of property, plant and equipment) decreased by $5 million due to the reduction of financed insurance policies premiums and the payment of a long-term incentive bonus paid to all non-executive employees in January 2016. Please read note 9 – “Retention Bonus Plan” to the consolidated financial statements included in this report for additional information. Accrued interest—related party increased by $2 million due to the $200 million of borrowing under the Term Loan Facility—Related Party that occurred on November 30, 2016. Please read note 6—“Debt” to the consolidated financial statements included in this report for additional information.

67


Investing Activities
Net cash used in investing activities was approximately $2 million and $7 million, respectively, for the years ended December 31, 2017 and 2016.
Financing Activities
Net cash used in financing activities was approximately $61 million for the year ended December 31, 2017. During the year ended December 31, 2017, we received $103 million in proceeds from the Revolving Credit Facility and subsequently repaid $87 million, leaving $16 million outstanding under the Revolving Credit Facility as of December 31, 2017. We received $5 million in proceeds from the Revolving Credit Facility—Related Party and subsequently repaid $40 million, leaving no amounts outstanding under the Revolving Credit Facility—Related Party as of December 31, 2017. We repaid borrowings of $4 million on the Term Loan B Credit Facility and paid cash distributions to unitholders of $37 million in the year ended December 31, 2017.
Net cash used in financing activities was approximately $30 million for the year ended December 31, 2016. During the year ended December 31, 2016, we received $70 million in proceeds from the Revolving Credit Facility and subsequently repaid $95 million, leaving no amounts outstanding under the Revolving Credit Facility as of December 31, 2016. We received $69 million in proceeds from the Revolving Credit Facility—Related Party and subsequently repaid borrowings of $34 million under the facility, leaving $35 million outstanding under the Revolving Credit Facility—Related Party as of December 31, 2016. We received $200 million in proceeds from the Term Loan Facility—Related Party and repaid borrowings of $204 million on the Term Loan B Credit Facility. We paid cash distributions to unitholders of $33 million and paid $2 million in deferred financing costs associated with Amendments No. 6 and No. 7 to the Term Loan B Credit Facility and Amendments No. 4 and 5 to the Revolving Credit Facility. Please read note 6—“Debt” to the consolidated financial statements included in this report for additional information.
CONTRACTUAL OBLIGATIONS
The following table lists our significant contractual obligations and their future payments at December 31, 2017:
Contractual Obligations
Total
 
Less than
1 Year
 
1-3
Years
 
3-5
Years
 
More than
5 Years
 
(in thousands)
Term Loan B Credit Facility—Principal Payments
$
231,825

 
$
4,480

 
$
227,345

 
$

 
$

Term Loan Facility—Related Party—Principal Payments
200,000

 

 
200,000

 

 

Revolving Credit Facility—Related Party—Principal Payments

 

 

 

 

Interest Payments on third party debt(1)
31,293

 
19,369

 
11,924

 

 

Interest Payments on related party debt
35,508

 
17,281

 
18,227

 

 

Hydrogen supply contract(2)
4,000

 
4,000

 

 

 

Natural gas supply contract(2)
11,053

 
11,053

 

 

 

Nitrogen supply contract(2)
37,538

 
5,775

 
17,325

 
14,438

 

Purchase commitments
15,559

 
15,559

 

 

 

Total
$
582,776

 
$
93,517

 
$
474,821

 
$
14,438

 
$

_____________________________________
(1)
Interest rate on floating rate debt is based on the rate of 6.75% plus adjusted LIBOR for the Term Loan B Credit Facility and 4.75% plus LIBOR for the Revolving Credit Facility.
(2)
Quantities of feedstock to be purchased are subject to change based on our current and expected production, market dynamics and market reports

OFF-BALANCE SHEET ARRANGEMENTS
We have no material off-balance sheet arrangements.

68


RECENTLY ISSUED ACCOUNTING STANDARDS
Refer to note 3 to the consolidated financial statements, “New Accounting Pronouncements,” to our Consolidated Financial Statements as set forth in Part II, Item 8 of this Annual Report.
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. Accuracy of estimates is based on the accuracy of information used. Described below are the most significant policies we apply in preparing our 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 financial statements included in Item 8 of this report.
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. 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 was no allowance for doubtful accounts and no bad debt write-offs during the years ended December 31, 2017 and 2016. We do not have any off-balance-sheet credit exposure related to our customers.
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 lives used in computing depreciation and amortization expense are based on estimates of the period over which the assets will be of economic benefit to us. Estimated lives are based on historical experience, manufacturers' or engineering estimates, valuation or appraisal estimates and future business plans. 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 review the depreciable lives assigned to our property, plant and equipment on a periodic basis, and change our estimates to reflect the results of those reviews.
The estimated useful lives of our assets are as follows:
Asset
Useful Lives,
in Years
Buildings
30

Machinery and equipment
4 - 15

Automotive equipment
5

Furniture and fixtures
5


69


Maintenance Activities. We incur maintenance costs on our facilities and equipment. Routine repair and maintenance costs are expensed as incurred. For the years ended December 31, 2017 and 2016, we expensed approximately $16 million and $18 million, respectively, of routine repair and maintenance costs. Major maintenance 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. Plant turnarounds are performed to help ensure the long-term reliability and safety of integrated plant machinery at our continuous process production facility.
Preceding a turnaround, facilities experience decreased efficiency in resource conversion to finished products. Replacement or overhaul of equipment and items such as compressors, turbines, pumps, motors, valves, piping and other parts that have an estimated useful life of at least four years, the internal assessment of production equipment, replacement of aged catalysts, and new installation/recalibration of measurement and control devices result in increased production output and/or improved plant efficiency after the turnaround. Turnaround activities are betterments that either extend equipment useful life, or increase the output and/or efficiency. As a result, we follow the deferral method of accounting for major maintenance costs; and thus, expenditures associated with the turnaround are capitalized as property, plant and equipment and amortized over a four year period, which is the time lapse between turnarounds. Should the estimated period between turnarounds change, we may be required to amortize the remaining cost of the turnaround over a shorter period, which would lead to higher depreciation and amortization costs. For the year ended December 31, 2017 and 2016, we capitalized approximately $1 million and $8 million, respectively, in maintenance capital expenditures related to our capital spares project and other budgeted maintenance capital projects.
We classify deferred maintenance cost as an investing activity under the caption “Purchase of property, plant, and equipment” in the Consolidated Statement of Cash Flows, since this cash outflow relates to expenditures related to long-lived productive assets. Repair, maintenance and related labor costs are expensed as incurred and are included in operating cash flows.
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, 2017 and 2016, we had no environmental remediation obligations.
Impairment of 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, 2017 and 2016 that indicated the carrying amount of an asset may not be recoverable.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk. We are exposed to interest rate risk related to our borrowings. As of December 31, 2017, interest on borrowings under the Term Loan B Credit Facility accrued, at OCIB’s option, at adjusted LIBOR plus 6.75% per annum or the alternate base rate plus 5.75%. Interest on borrowings under the Revolving Credit Facility accrued, at OCIB's option, at LIBOR plus 4.75% per annum or the alternative base rate plus 3.75%. Interest on borrowings under the Term Loan Facility—Related Party, will accrue at the rate equal to the sum of (a) the rate per annum applicable to the loans under the Term Loan B Credit Facility (as such rate may fluctuate from time to time in accordance with the terms of the agreement governing the Term Loan B Credit Facility), plus (b) 25 basis points. Interest on borrowings under the Revolving Credit Facility—Related Party, will accrue at the rate equal to the sum of (a) the rate per annum applicable to the loans under the Revolving Credit Facility (as such rate may fluctuate from time to time in accordance with the terms of the agreement governing the Revolving Credit Facility), plus (b) 25 basis points. Based upon the outstanding balances of our variable-interest rate debt at December 31, 2017, 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 $4.5 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. Operating at full capacity, our methanol and ammonia production units together require approximately 110,000 to 120,000 MMBtu per day of natural gas, as of December 31, 2017. We have supply agreements with Kinder Morgan, Enterprise Products and Houston Pipe Line to supply natural gas required for our production of methanol and ammonia. In addition, the price we pay for hydrogen depends on natural gas prices. As of December 31, 2017, 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 (exclusive of depreciation) of approximately $43.9 million to $47.5 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. As of December 31, 2017, 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 $45.6 million, based on an annual methanol volume of 912,500 metric tons. As of December 31, 2017, 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 $16.6 million, based on an annual ammonia volume of 331,000 metric tons.

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Unitholders
OCI Partners LP:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of OCI Partners LP and subsidiary (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Partnership's auditor since 2012.
Houston, Texas
March 5, 2018


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OCI PARTNERS LP
Consolidated Balance Sheets
December 31, 2017 and 2016
(Dollars in thousands, except per unit data)
 
 
2017
 
2016
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
16,275

 
$
8,080

Accounts receivable
32,032

 
22,170

Accounts receivable—related party
6,503

 
1,322

Inventories
6,041

 
7,543

Advances due from related parties
188