UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2012

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 No. 001-35334

RENTECH NITROGEN PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	45-2714747
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
10877 Wilshire Boulevard, Suite 600 Los Angeles, California	90024
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (310) 571-9800

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  x.    No  ¨.

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  x.

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  x    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  x    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.    x

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 29, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $412.5 million (based upon the closing price of the common units on June 29, 2012, as reported by the New York Stock Exchange).

As of February 28, 2013, the registrant had 38,839,033 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

TABLE OF CONTENTS

	Page
PART I
ITEM 1. Business		4
ITEM 1A. Risk Factors		20
ITEM 1B. Unresolved Staff Comments		47
ITEM 2. Properties		47
ITEM 3. Legal Proceedings		47
ITEM 4. Mine Safety Disclosures		47
PART II
ITEM 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units		48
ITEM 6. Selected Financial Data		50
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		54
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk		79
ITEM 8. Financial Statements and Supplementary Data		81
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		112
ITEM 9A. Controls and Procedures		112
ITEM 9B. Other Information		112
PART III
ITEM 10. Directors, Executive Officers and Corporate Governance		113
ITEM 11. Executive Compensation		118
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		152
ITEM 13. Certain Relationships and Related Transactions, and Director Independence		155
ITEM 14. Principal Accounting Fees and Services		158
PART IV
ITEM 15. Exhibits and Financial Statement Schedules		159
Signatures		164

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FORWARD-LOOKING STATEMENTS

Certain statements and information included in this Annual Report on Form 10-K, or this report, and other reports or materials that we have filed or will file with the Securities and Exchange Commission, or the SEC, (as well as information included in oral statements or other written statements made or to be made by us or our management), contain or may contain “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 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 our operating costs. These statements involve known and unknown risks, uncertainties and other factors, 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. Factors that could affect our results include the risk factors detailed in Part I—Item 1A “Risk Factors” and from time to time in our periodic reports and registration statements filed with the SEC. 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.

References in this report to “the Partnership,” “RNP,” “we,” “our,” “us” and like terms refer to Rentech Nitrogen Partners, L.P. and our subsidiaries, unless the context otherwise requires or where otherwise indicated. References in this report to “Rentech” refer to Rentech, Inc. and its subsidiaries other than us, unless the context otherwise requires or where otherwise indicated. References to “RDC” refer to Rentech Development Corporation, which is a wholly owned subsidiary of Rentech, references to “RNHI” refer to Rentech Nitrogen Holdings, Inc., which is a wholly owned subsidiary of RDC, and references to “Rentech Nitrogen GP” and “our general partner” refer to Rentech Nitrogen GP, LLC, which is our general partner and a wholly owned subsidiary of RNHI. References to “our operating companies” refer to Rentech Nitrogen, LLC, or RNLLC, which was formerly known as Rentech Energy Midwest Corporation, or REMC, and Rentech Nitrogen Pasadena, LLC, or RNPLLC, which was formerly known as Agrifos Fertilizer, LLC.

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PART I

ITEM 1. BUSINESS

Change in Fiscal Year End

On February 1, 2012, the board of directors of our general partner approved a change in our fiscal year end from September 30 to December 31. The fiscal periods presented in this report include the calendar years ended December 31, 2012 and 2011, the three months ended December 31, 2011 and 2010 and the fiscal years ended September 30, 2011, 2010, 2009 and 2008.

Overview

We are a Delaware limited partnership formed in July 2011 by Rentech, a publicly traded entity on the NYSE MKT under the symbol “RTK,” to own, operate and expand our fertilizer business. We own and operate two fertilizer facilities: our East Dubuque Facility and our Pasadena Facility. Our East Dubuque Facility is located in East Dubuque, Illinois, and has been in operation since 1965. We produce primarily ammonia and urea ammonium nitrate solution, or UAN, at our East Dubuque Facility, using natural gas as the facility’s primary feedstock. Our Pasadena Facility, which we acquired in November 2012, is located in Pasadena, Texas, and has been in operation since the 1940s. In 2011, our Pasadena Facility was retrofitted to produce ammonium sulfate. We produce ammonium sulfate, ammonium thiosulfate and sulfuric acid at our Pasadena Facility, using ammonia and sulfur as the facility’s primary feedstocks.

Our East Dubuque Facility is located in the center of the Mid Corn Belt, the largest market in the United States for direct application of nitrogen fertilizer products. The Mid Corn Belt includes the States of Illinois, Indiana, Iowa, Missouri, Nebraska and Ohio. The States of Illinois and Iowa have been the top two corn producing states in the United States for the last 20 years according to the United States Department of Agriculture, or USDA. We consider the market for our East Dubuque Facility to be comprised of the States of Illinois, Iowa and Wisconsin.

Our East Dubuque Facility’s core market consists of the area located within an estimated 200-mile radius of the facility. In most instances, our customers take delivery of our nitrogen products at our East Dubuque Facility and then arrange and pay to transport them to their final destinations by truck. To the extent our products are picked up at our East Dubuque Facility, we do not incur any shipping costs, in contrast to nitrogen fertilizer producers located outside of the facility’s core market that must incur transportation and storage costs to transport their products to, and sell their products in, our market. In addition, our East Dubuque Facility does not maintain a fleet of trucks and, unlike some of our major competitors, our East Dubuque Facility does not maintain a fleet of rail cars because the facility’s customers generally are located close to the facility and prefer to be responsible for transportation. Having no need to maintain a fleet of trucks or rail cars lowers the East Dubuque Facility’s fixed costs. The combination of the East Dubuque Facility’s proximity to its customers and our storage capacity at the facility also allows for better timing of the pick-up and application of the facility’s products, as nitrogen fertilizer product shipments from more distant locations have a greater risk of missing the short periods of favorable weather conditions during which the application of nitrogen fertilizer may occur.

The Pasadena Facility is the largest producer of synthetic ammonium sulfate and the third largest overall producer of ammonium sulfate in North America. We believe that our ammonium sulfate has several characteristics that distinguish it from competing products. In general, the ammonium sulfate that is available for sale in our industry is a byproduct of other processes and does not have certain characteristics valued by customers. Our ammonium sulfate is sized to the specifications preferred by customers and may more easily be blended with other fertilizer products. We also believe that our ammonium sulfate has a longer shelf-life, is more stable and is more easily transported and stored than many other competing products.

Our Pasadena Facility is located on the Houston Ship Channel with access to transportation at favorable prices. The facility has two deep-water docks and access to the Mississippi waterway system and key international waterways. The facility is also connected to key domestic railways which permit the efficient, cost-effective distribution of its products west of the Mississippi River. Our Pasadena Facility’s distributors purchase our products at our facility and then arrange and pay to transport them to their final destinations by truck, rail car or vessel. Our Pasadena Facility’s products are sold primarily through distributors to customers in the U.S. and in Brazil, and are applied to many types of crops including soybeans, potatoes, cotton, canola, alfalfa, corn and wheat. We believe that the diversification of the geographic markets and applications for this facility’s products should improve the stability of our overall results. Ammonium sulfate prices and margins generally have been less volatile than the prices and margins for the products of the East Dubuque Facility.

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The Pasadena Facility purchases ammonia as a feedstock at contractual prices based on the monthly Tampa Index market, while the East Dubuque Facility sells ammonia at prevailing prices in the Mid Corn Belt, which are typically significantly higher than Tampa ammonia prices.

The Agrifos Acquisition

On November 1, 2012, we completed our acquisition of 100% of the membership interests of Agrifos LLC, or Agrifos, from Agrifos Holdings Inc., or the Seller, pursuant to a Membership Interest Purchase Agreement, or the Purchase Agreement. Upon the closing of this transaction, or the Agrifos Acquisition, Agrifos became our wholly-owned subsidiary and its name changed to Rentech Nitrogen Pasadena Holdings, LLC. Rentech Nitrogen Pasadena Holdings, LLC owns all of the member interests in RNPLLC, which owns and operates the Pasadena Facility. At closing, we paid consideration of approximately $136.0 million in cash, less estimated working capital adjustments, and 538,793 common units valued at approximately $20.0 million, which reduced Rentech’s ownership interest in RNP from 60.8% to 59.9%. Among other terms, the Seller is required to indemnify us for a period of six years after the closing for certain environmental matters relating to the Pasadena Facility, which indemnification obligations are subject to important limitations including a deductible and an overall cap. We deposited with an escrow agent in several escrow accounts a portion of the initial consideration consisting of an aggregate of $7.25 million in cash, and 323,276 common units, representing a value of $12.0 million, which amounts may be used to satisfy certain indemnity claims upon the occurrence of certain events. In addition to the consideration paid at closing, the Seller may be entitled to receive additional earn-out consideration, payable in common units or cash at our option based on the amount by which the two-year Adjusted EBITDA, as defined in the Purchase Agreement, of the Pasadena Facility exceeds certain Adjusted EBITDA thresholds. Depending on the two-year Adjusted EBITDA amounts, such additional earn-out consideration may vary from zero to a maximum of $50.0 million. Any earn-out consideration would be paid after April 30, 2015 and the completion of the relevant calculations in either common units or cash at our option.

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Organizational Structure

The following diagram depicts our organizational structure as of February 28, 2013 (all percentage ownership interests are 100% unless otherwise noted):

Business

Our East Dubuque Facility

Our East Dubuque Facility is located on approximately 210 acres in the northwest corner of Illinois on a 140-foot bluff above the Upper Mississippi River. Our East Dubuque Facility produces ammonia, UAN, liquid and granular urea, nitric acid and food-grade carbon dioxide, or CO₂, using natural gas as its primary feedstock. Our East Dubuque Facility operates continuously, except for planned shutdowns for maintenance and efficiency improvements, and unplanned shutdowns. Our East Dubuque Facility can optimize its product mix according to changes in demand and pricing for its various products. Some of these products are final products sold to customers, and others, including ammonia, are both final products and feedstocks for final products, such as UAN, nitric acid, liquid urea, granular urea and CO₂.

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The following table sets forth our East Dubuque Facility’s current rated production capacity for the listed products in tons per day and tons per year, and its product storage capacity.

Product	Approximate Production Capacity				Product Storage Capacity
	Tons /Day		Tons  /Year(1)
Ammonia		830		302,950	40,000 tons (2 tanks); 15,000 tons(2)
UAN		1,100		401,500	80,000 tons (2 tanks)
Urea (liquid)		460		167,900	Limited capacity is not a factor
Urea (granular)		140		51,100	12,000 granular ton warehouse
Nitric acid		380		138,700	Limited capacity is not a factor
CO2		350		127,750	1,900 tons

(1) Production capacity for the year is based on daily rated production capacity times 365 days. The number of actual operating days will vary from year to year.

(2) Represents 15,000 tons of space at the terminal of Agrium U.S.A., Inc., or Agrium, in Niota, Illinois where we have the right to store ammonia pursuant to our distribution agreement with Agrium. Our right to store ammonia at this terminal expires on June 30, 2016, but automatically renews for successive one year periods, unless we deliver a termination notice to Agrium with respect to such storage rights at least three months prior to an automatic renewal. Notwithstanding the foregoing, our right to use the storage space immediately terminates if the distribution agreement terminates in accordance with its terms. See “—Marketing and Distribution.”

The following table sets forth the amount of products produced by, and shipped from, the East Dubuque Facility for the calendar years ended December 31, 2012 and 2011, the three months ended December 31, 2011 and 2010, and the fiscal years ended September 30, 2011 and 2010:

	For the Calendar Years Ended December 31,				For the Three Months Ended December 31,				For the Fiscal Years Ended September 30,
	2012		2011		2011		2010		2011		2010
	(in thousands of tons)
Products Produced
Ammonia		293		261		63		75		273		267
UAN		301		294		68		86		312		287
Urea (liquid)		139		130		30		37		137		128
Urea (granular)		23		16		4		6		18		17
Nitric acid		122		118		27		35		126		111
CO2		76		92		16		34		109		107
Products Shipped
Ammonia		149		135		55		44		125		153
UAN		291		301		65		79		315		294
Urea (liquid)		13		12		3		3		12		11
Urea (granular)		22		17		4		4		17		21
Nitric acid		14		15		3		3		15		11
CO2		76		92		15		34		110		107

Expansion Projects

Our urea expansion project and diesel exhaust fluid, or DEF, build-out project at the East Dubuque Facility were completed in 2012 at a combined cost of approximately $6.3 million. The urea expansion project increased our urea production capacity by approximately 15%, or 60 tons per day. The DEF build-out project enables us to produce and sell DEF from urea produced at the East Dubuque Facility. DEF is a higher grade of liquid urea. We have entered into a long-term exclusive agreement to sell the DEF produced at the East Dubuque Facility.

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We are continually evaluating or pursuing opportunities to increase our profitability by expanding the East Dubuque Facility’s production capabilities and product offerings, including the following expansion projects:

• Ammonia Production and Storage Capacity Expansion Project. In 2011, we commenced construction of a project that is designed to increase ammonia production at the East Dubuque Facility to approximately 1,020 tons per day or 372,000 tons annually for sale or upgrade to additional products, and to increase our ammonia storage capacity by approximately 20,000 tons. Construction of this project is expected to be completed during the planned downtime for the 2013 turnaround at the facility scheduled for the fourth quarter of 2013. We estimate that the total project cost will be approximately $100 million. We have entered into a new credit agreement (referred to as the new 2012 credit agreement), which provides for a $300.0 million senior secured credit facility, including a $110.0 million capital expenditures facility, or the new capex facility, that is being used to fund this project. We believe that the remaining capacity under the new capex facility will be adequate to complete this project. For a more complete discussion of the new 2012 credit agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources of Liquidity—Credit Agreements.”

• Nitric Acid Project. In the third quarter of 2013, we intend to commence construction of a debottlenecking project that is designed to increase nitric acid production at our East Dubuque Facility by approximately 1,200 tons annually, without consuming additional feedstock. Moreover, this project is expected to reduce the amount of anhydrous ammonia required for nitric acid production by about 350 tons annually. We expect to complete this project during the first quarter of 2014 at a cost of approximately $2.0 million, with approximately $1.6 million expected to be expended in 2013.

Products

Our East Dubuque Facility’s product sales are heavily weighted toward sales of ammonia and UAN, which together made up 80% or more of our East Dubuque Facility’s total revenues for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and each of the fiscal years ended September 30, 2011 and 2010. A majority of our East Dubuque Facility’s products are sold through our distribution agreement with Agrium as described below under “—Marketing and Distribution,” with the exception of CO₂, which we sell directly to customers in the food and beverage market at negotiated contract prices. Although ammonia and UAN may be used interchangeably in some cases, each has its own characteristics, and customer product preferences vary according to the crop planted, soil and weather conditions, regional farming practices, relative prices and the cost and availability of appropriate storage, transportation, handling and application equipment, each of which vary among these two products. During the calendar year ended December 31, 2012, the three months ended December 31, 2011 and each of the fiscal years ended September 30, 2011 and 2010, we sold more than 90% of our East Dubuque Facility’s nitrogen products to customers for agricultural application, with the remaining portion being sold to customers for industrial uses.

Ammonia. Our East Dubuque Facility produces ammonia, the simplest form of nitrogen fertilizer and the feedstock for the production of other nitrogen fertilizers. The ammonia processing unit at our East Dubuque Facility has a current rated capacity of approximately 830 tons per day, which is expected to increase to approximately 1,020 tons per day following completion of our ammonia production capacity expansion project at the East Dubuque Facility. Our East Dubuque Facility’s ammonia product storage consists of two 20,000 ton tanks, to which, in the first quarter of 2014, we expect to add an additional 20,000 ton tank following completion of our ammonia storage capacity expansion project at the East Dubuque Facility, and 15,000 tons of leased storage in Niota, Illinois. Ammonia is used in the production of all other products produced by our East Dubuque Facility, except CO₂.

UAN. UAN is a liquid fertilizer that has a slight ammonia odor and, unlike ammonia, it does not need to be refrigerated or pressurized when transported or stored. Our East Dubuque Facility has two UAN storage tanks with a combined capacity of 80,000 tons.

Urea. Our East Dubuque Facility’s urea solution is sold in its liquid state, processed into granular urea through the facility’s urea granulation plant to create dry granular urea (46% nitrogen concentration) or upgraded into DEF or UAN. We assess market demand for each of these four end products and allocate our East Dubuque Facility’s produced urea solution as appropriate. We sell liquid urea, including DEF, primarily to industrial customers in the power, ethanol and diesel emissions markets. DEF is a urea-based chemical reactant that is intended to reduce nitrogen oxide emissions in the exhaust systems of certain diesel engines of trucks and off-road farm and construction equipment. Although we believe there is high demand for our granular urea in agricultural markets, we sell granular urea primarily to customers in specialty urea markets where the spherical and consistent size of the granules resulting from our “curtain granulation” technology generally command a premium price. Our East Dubuque Facility has a 12,000 ton capacity bulk warehouse that can be used for dry bulk granular urea storage.

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Nitric Acid. Our East Dubuque Facility produces nitric acid through two separate nitric acid plants at the facility. Nitric acid is either sold to third parties or used within the facility for the production of ammonium nitrate solution, as an intermediate from which UAN is produced. We believe that our East Dubuque Facility currently has sufficient storage capacity available for the nitric acid produced at the facility.

Carbon Dioxide. CO₂ is a gaseous product that is co-manufactured with ammonia, with approximately 1.1 tons of CO₂ produced per ton of ammonia produced. Our East Dubuque Facility utilizes CO₂ in its urea production and has developed a market for CO₂ through conversion to a purified food grade liquid CO₂. Our East Dubuque Facility has storage capacity for approximately 1,900 tons of CO₂. We have multiple CO₂ sales agreements that allow for regular shipment of CO₂ throughout the year, and our current storage capacity is sufficient to support our CO₂ delivery commitments.

Marketing and Distribution

In 2006, we entered into a distribution agreement with Agrium under which a majority of our East Dubuque Facility’s products, including ammonia and UAN, are sold. Pursuant to the distribution agreement, Agrium is obligated to use its commercially reasonable efforts to promote the sale of, and to solicit and secure orders from its customers for, nitrogen fertilizer products comprising ammonia, liquid and granular urea, UAN and nitric acid. Under the distribution agreement, Agrium bears the credit risk on products sold through Agrium pursuant to the agreement. The distribution agreement has a term that ends in April 2016, but automatically renews for subsequent one-year periods, unless either party delivers a termination notice to the other party at least three months prior to an automatic renewal.

During the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, we sold 80% or more of the nitrogen fertilizer products produced at our East Dubuque Facility through Agrium pursuant to the distribution agreement, and sold the remaining amounts directly to customers. Our management pre-approves price, quantity and other terms for each sale through Agrium, and we pay Agrium a commission for its services. Our rights under the distribution agreement include the right to store specified amounts of our ammonia for a monthly fee at Agrium’s ammonia terminal in Niota, Illinois, which serves as another location where ammonia produced at our East Dubuque Facility is sold. Our right to store ammonia at Agrium’s terminal expires on June 30, 2016, but automatically renews for successive one year periods, unless we deliver a termination notice to Agrium with respect to such storage rights at least three months prior to an automatic renewal. Notwithstanding the foregoing, our right to use the storage space immediately terminates if the distribution agreement terminates in accordance with its terms. Outside of the distribution agreement, we also sell our East Dubuque Facility’s nitrogen products and CO₂ directly to our customers.

Under the distribution agreement, we pay commissions to Agrium not to exceed $5 million during each contract year on applicable gross sales during the first 10 years of the agreement. The commission rate was 2% during the first year of the agreement and increased by 1% on each anniversary date of the agreement up to the current rate of 5%, which is the maximum allowable rate under the distribution agreement during the first 10 years of the agreement. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, the effective commission rate associated with sales under the distribution agreement was 2.7%, 2.6%, 4.3% and 4.2%, respectively.

Transportation

In most instances, our East Dubuque Facility’s customers take delivery of nitrogen products on a freight on board, or FOB, basis at the facility, and then arrange and pay to transport the products to their final destinations by truck. Similarly, under the distribution agreement, neither we nor Agrium is responsible for transportation, and customers that purchase our East Dubuque Facility’s products through Agrium also take delivery of such products FOB at the facility. When products are purchased FOB at the facility, the customer is responsible for all costs for and bears all risks associated with the transportation of products from the facility.

In certain instances, customers take delivery of products on a FOB destination basis. In these circumstances, we are responsible for the associated transportation costs. In order to accommodate barge and rail deliveries, we own and operate a barge dock on the Mississippi River, and a rail spur that connects to the Burlington Northern Santa Fe Railway, or Burlington Northern, and the Canadian National Railway Company or its predecessors have provided rail service to our East Dubuque Facility since 1966. We also ship products by barge to our leased storage facility in Niota, Illinois, which provides another distribution point from which our customers may pick up our East Dubuque Facility’s products by truck.

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We believe that having the option to transport our East Dubuque Facility’s nitrogen products by barge or rail provides us with the flexibility to sell the facility’s products to locations that cannot be economically delivered by truck. However, transportation by truck generally is not subject to many of the risks and costs associated with transportation by barge or rail. Barge transportation from the Gulf Coast frequently is constrained by unpredictable conditions and limited equipment and storage infrastructure on the Mississippi River. Lock closures on the Upper Mississippi River can be caused by a variety of conditions, including inclement weather or surface conditions, and can unexpectedly delay barge transportation. In addition, in the United States, there are only two towing companies that transport ammonia by barge and only 32 active barges available for ammonia transport, and we believe those barges are fully utilized for transport of the current levels of ammonia produced in the U.S. Ammonia storage sites and terminals served by barge on the Mississippi River are controlled primarily by CF Industries Holdings, Inc., or CF Industries, Koch Industries, Inc., or Koch, and Agrium. Because ownership of storage sites and terminals is limited to these competitors, other competitors who rely on barge transportation could encounter storage limitations associated with the seasonal Mississippi River closure that occurs annually from mid-November to early March. Railroads also charge premium prices to ship certain toxic inhalation hazard, or TIH, chemicals, including ammonia, due in part to additional liability insurance costs incurred by the railroads. We believe that railroads are taking other actions, such as requiring indemnification from their customers for liabilities relating to TIH chemicals, to shift the risks they face from shipping TIH chemicals to their customers, which may make transportation of ammonia by rail less economically feasible.

Customers

We sell a majority of our East Dubuque Facility’s nitrogen products to customers located in the facility’s core market. We sold over 90% of our East Dubuque Facility’s nitrogen products to customers for agricultural uses during the calendar year ended December 31, 2012, the three months ended December 31, 2011 and each of the fiscal years ended September 30, 2011 and 2010. Given the nature of our business, and consistent with industry practice, we generally do not have long-term minimum sales contracts for fertilizer products with any of our customers.

In the aggregate, our East Dubuque Facility’s top five ammonia customers represented approximately 54%, 54%, 46% and 52%, respectively, of the facility’s ammonia sales for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, and our East Dubuque Facility’s top five UAN customers represented approximately 38%, 53%, 50% and 60%, respectively, of the facility’s UAN sales for these periods. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, approximately 2%, 1%, 3% and 7%, respectively, of our East Dubuque Facility’s total product sales were to Agrium as a direct customer (rather than a distributor) and approximately 9%, 7%, 15% and 11%, respectively, of our East Dubuque Facility’s total product sales were to Crop Production Services, Inc., or CPS, a controlled affiliate of Agrium.

Seasonality and Volatility

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 requires significant storage capacity. The accumulation of inventory to be available for seasonal sales requires us to maintain significant working capital. This seasonality generally results in higher fertilizer prices during peak fertilizer application periods, with prices normally reaching their highest point in the spring, decreasing in the summer, and increasing again in the fall. Our East Dubuque Facility 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 contracts and variations in the terms of the product prepayment contracts can increase the seasonal volatility of our cash flows and cause changes in the patterns of seasonal volatility from year-to-year. The cash from product prepayment contracts is included in our operating cash flow in the quarter in which the cash is received, while revenue related to product prepayment contracts is recognized when products are picked-up or delivered and the customer takes title. As a result, the cash received from product prepayment contracts increases our operating cash flow in the quarter in which the cash is received, but may effectively reduce our operating cash flow in a subsequent quarter if the cash was received in a quarter prior to the one in which the revenue is recorded. See Part II—Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk.”

Another seasonal factor affecting our industry is the effect of weather-related conditions on the ability to transport products by barge on the Upper Mississippi River. During portions of the winter, the Upper Mississippi River cannot be used for transport due to lock closures, which could preclude the transportation of nitrogen products by barge during this period and may increase transportation costs. However, only approximately 5.6% and 1.7% of the ammonia and UAN tonnage from our East Dubuque Facility, respectively, that we sold during the calendar year ended December 31, 2012, 2.3% and 0.0% of the ammonia and UAN tonnage from our East Dubuque Facility, respectively, that we sold during the three months ended December 31, 2011, 4.4% and 3.7% of the ammonia and UAN tonnage from our East Dubuque Facility, respectively, that we sold during the fiscal year ended September 30, 2011, and 15.4% and 19.1% of the ammonia and UAN tonnage from our East Dubuque Facility, respectively, that we sold during the fiscal year ended September 30, 2010 were transported from our facility by barge.

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The following table shows total tons of our East Dubuque Facility’s products shipped for each quarter presented below:

	For the Calendar Year Ended December 31,		For the Three Months Ended December 31,		For the Fiscal Years Ended September 30,
	2012		2011		2011		2010
	(in thousands of tons)
Ammonia
Quarter ended March 31		30				20		22
Quarter ended June 30		40				43		51
Quarter ended September 30		31				18		35
Quarter ended December 31		48		55		44		45
UAN
Quarter ended March 31		34				30		25
Quarter ended June 30		92				129		112
Quarter ended September 30		110				77		100
Quarter ended December 31		55		65		79		57
Other Nitrogen Products
Quarter ended March 31		13				12		14
Quarter ended June 30		13				15		12
Quarter ended September 30		14				7		10
Quarter ended December 31		9		10		10		7
CO2
Quarter ended March 31		15				27		24
Quarter ended June 30		15				26		32
Quarter ended September 30		25				23		36
Quarter ended December 31		21		15		34		15
Total Tons Shipped		565		145		594		597

We typically ship the highest volume of tons from our East Dubuque Facility during the spring planting season, which occurs during the quarter ending June 30 of each year, and the next highest volume of tons after the fall harvest during the quarter ending December 31 of each year. However, as reflected in the table above, the seasonal patterns may change substantially from year-to-year due to various circumstances, including timing of or changes in the weather. These seasonal increases and decreases in demand also can cause fluctuations in sales prices. In more mild winter seasons with warmer weather, early planting may shift significant ammonia sales into the quarter ending March 31.

Raw Materials

The principal raw material used to produce nitrogen fertilizer products at our East Dubuque Facility is natural gas. We historically have purchased natural gas in the spot market, through the use of forward purchase contracts, or a combination of both. We use forward purchase contracts to lock in pricing for a portion of our East Dubuque Facility’s natural gas requirements. These forward purchase contracts are generally either fixed-price or index-priced, short term in nature and for a fixed supply quantity. Our policy is to purchase natural gas under fixed-price forward contracts to produce the products that have been sold under product prepayment contracts for later delivery, effectively fixing a substantial portion of the gross margin on pre-sold product. We are able to purchase natural gas at competitive prices due to our East Dubuque Facility’s connection to the Northern Natural Gas interstate pipeline system which is within one mile of the facility. The pipeline is connected to Nicor Inc.’s distribution system at the Chicago Citygate receipt point from which natural gas is transported to the facility. Though we do not purchase natural gas for the purpose of resale, we occasionally sell natural gas when contracted quantities received exceed production requirements and storage capacities. The location of our East Dubuque Facility’s receipt point has allowed us to obtain relatively favorable natural gas prices for our excess natural gas using the Chicago Citygate price point created by the stable residential demand for the commodity in the city of Chicago, Illinois. Natural gas purchased and used in production at our East Dubuque Facility was approximately 10.6 million MMBtus (or million British thermal units), 2.3 million MMBtus, 10.3 million MMBtus and 9.9 million MMBtus in the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, respectively.

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Changes in the levels of natural gas prices and market prices of nitrogen-based products can materially affect our financial position and results of operations. Natural gas prices in the United States have experienced significant fluctuations over the last several years, increasing substantially in 2008 and subsequently declining to the current lower levels. The price changes have been driven by changes in the demand for natural gas from industrial users, which is affected, in part, by the general conditions of the United States economy, and other factors. Several recent discoveries of large natural gas deposits in North America, combined with advances in technology for natural gas production also have caused large increases in the estimates of available natural gas reserves and production in the United States, contributing to significant reductions in the market price of natural gas. One major factor in the recent decrease in natural gas prices has been the use of technologies, including hydraulic fracturing and horizontal drilling, that have substantially increased the amount of natural gas produced in the United States. Hydraulic fracturing is the process of fracturing the underground formation with water, sand and chemicals under high pressure to recover natural gas from coalbeds and shale gas formations that otherwise may have been inaccessible. Horizontal drilling involves drilling a well from the surface to a subsurface location and then proceeding horizontally, which typically exposes significantly more reservoir rock to the well bore and thus results in greater potential natural gas recovery than traditional vertical drilling. Seasonal fluctuations in natural gas prices exist within each year resulting from various supply and demand factors, including, but not limited to, the severity of winter weather and its effect on consumer and industrial demand for heating, the severity of summer weather and its effect on industrial demand by utilities for electrical generation, and hurricane activity in the Gulf of Mexico.

Competition

Our East Dubuque Facility competes with a number of domestic and foreign producers of nitrogen fertilizer products, many of which are larger than we are and have significantly greater financial and other resources than we do. We believe that customers for nitrogen fertilizer products make purchasing decisions principally on the delivered price and availability of the product at the critical application times. Our East Dubuque Facility’s proximity to its customers provides us with a competitive advantage over producers located further away from those customers. The nitrogen fertilizer facilities closest to our East Dubuque Facility are located in Fort Dodge, Creston and Port Neal, Iowa, approximately 190 miles, 275 miles and 300 miles, respectively, from our East Dubuque Facility, and in Lima, Ohio, approximately 350 miles to the east of our East Dubuque Facility. Our East Dubuque Facility’s physical location in the center of the Mid Corn Belt provides the facility with a transportation cost advantage, compared to other producers who must ship their products over greater distances to our East Dubuque Facility’s market area. The combination of our East Dubuque Facility’s proximity to its customers and our storage capacity at the facility allows customers to better time the pick-up and application of our products, as deliveries from more distant locations have a greater risk of missing the short periods of favorable weather conditions during which the application of nitrogen fertilizer and planting may occur. However, other producers of nitrogen fertilizer products are contemplating the construction of new nitrogen fertilizer facilities in North America, including in the Mid Corn Belt. For example, Orascom Construction Industries Company, or OCI, an Egyptian producer of fertilizer products, announced that in November 2012 it broke ground on construction of a facility in our core market that is designed to produce between 1.5 to 2.0 million metric tons per year of ammonia, urea, UAN and diesel exhaust fluid by mid-2015. If a new nitrogen fertilizer facility is completed in our East Dubuque Facility’s core market, it could benefit from the same competitive advantage associated with the location of our East Dubuque Facility. The completion of such a facility could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions to our unitholders.

We plan to continue to operate our East Dubuque Facility with natural gas as its primary feedstock. Competitors may have access to cheaper natural gas or other feedstocks that could provide them with a cost advantage. Depending on its magnitude, the amount of this cost advantage could offset the savings we may experience on transportation and storage costs as a result of our East Dubuque Facility’s location. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, our East Dubuque Facility’s average prices for natural gas in cost of sales were $3.59 per MMBtu, $4.75 per MMBtu, $4.66 per MMBtu and $4.79 per MMBtu, respectively.

Our Pasadena Facility

Our Pasadena Facility is located on approximately 500 acres in Texas on the Houston Ship Channel. In early 2011 prior to our ownership, the Pasadena Facility ceased production of phosphate fertilizers, which included diammonium phosphate, or DAP, and monoammonium phosphate, or MAP. Major capital and maintenance projects were undertaken at the Pasadena Facility, including decommissioning certain phosphate production assets, and converting a portion of its assets to the production of ammonium sulfate fertilizer. Ammonium sulfate is now the primary product of the Pasadena Facility. Following the conversion, the Pasadena Facility continues to produce sulfuric acid and ammonium thiosulfate.

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Our Pasadena Facility is the largest producer of synthetic ammonium sulfate and the third largest overall producer of ammonium sulfate in North America. We believe that our ammonium sulfate has several benefits that distinguish it from competing products. In general, the ammonium sulfate that is available for sale in our industry is a byproduct of other processes and does not have certain characteristics valued by customers. Our ammonium sulfate is sized to the specifications preferred by customers and may more easily be blended with other fertilizer products. We also believe that our ammonium sulfate has a longer shelf-life, is more stable and is more easily transported and stored than many other competing products.

The following table sets forth our Pasadena Facility’s current rated production capacity for the listed products in tons per day and tons per year, and our product storage capacity.

Product	Approximate Production Capacity				Product Storage Capacity
	Tons /Day		Tons  /Year(1)
Ammonium sulfate		1,750		577,500		60,000 tons
Sulfuric acid		1,750		638,750		27,000 tons
Ammonium thiosulfate		165		60,225		14,000 tons

(1) Ammonium sulfate production capacity for the year is based on daily rated production capacity times 330 days given regular required cleanings of the granulator. Sulfuric acid and ammonium thiosulfate production capacities for the year are based on daily rated production capacity times 365 days. The number of actual operating days will vary from year to year.

The following table sets forth the amount of products produced by, and shipped from, our Pasadena Facility for the period beginning November 1, 2012 (the closing date of the Agrifos Acquisition) through December 31, 2012 (in thousands of tons):

Products Produced
Ammonium sulfate	88
Sulfuric acid	69
Ammonium thiosulfate	9
Products Shipped
Ammonium sulfate	115
Sulfuric acid	27
Ammonium thiosulfate	—

Expansion Projects

We are continually evaluating or pursuing opportunities to increase our profitability by expanding our Pasadena Facility’s production capabilities and product offerings, including with the following expansion projects:

• Ammonium Sulfate Debottlenecking and Production Capacity Project. We have commenced a debottlenecking project at our Pasadena Facility. As part of this project, we expect to make process improvements to the facility during a 14-day planned outage of the ammonium sulfate plant at the facility in November 2013, and to complete upgrades to certain material handling equipment at the facility in the first quarter of 2014. Following the November 2013 work, we expect that the ammonium sulfate production capacity at our Pasadena Facility will increase by approximately 20%, from 1,750 tons per day to 2,100 tons per day. The upgrades to the material handling equipment to be completed in early 2014 are expected to ensure that the additional production can be reliably stored and loaded for distribution. We expect this project could cost approximately $6.0 million to complete.

• Power Generation Project. We have commenced plans and engineering for an electrical power generation project at our Pasadena Facility. As part of this project, we intend to install a steam turbine/generator set that would use excess steam produced from the sulfuric acid plant at the facility to produce electrical power. We expect that a portion of the power will be used in our Pasadena Facility, reducing electricity expenses, and the remaining power will be sold in the deregulated Texas power market, creating an additional revenue stream. If we obtain the necessary financing to complete this project on schedule and it is approved by the board of directors of our general partner, we expect that this project will be completed in the fall of 2014 at a cost of approximately $30.0 million.

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We intend to finance substantially all of the costs of these expansion projects using borrowings under the new 2012 credit agreement. In addition to the new capex facility, the new 2012 credit agreement provides for a $35.0 million incremental term loan facility, or the accordion facility. The accordion facility allows us, at any time on or before October 31, 2014, to borrow additional funds under the terms of the new 2012 credit agreement from any of the lenders, if such lenders agree to lend such amount. Proceeds from the accordion facility must be used for development projects at the Pasadena Facility as described above. If the lenders do not agree to lend amounts under the accordion facility to us, we would need to seek alternative sources of funding for the expansion projects. Depending on conditions in the capital markets, we also may seek external funding, among other things, to finance a portion of the costs of these expansion projects, including financing from the issuance of common units or debt securities. However, there is no assurance that these sources of capital would be available to us.

Products

Our Pasadena Facility’s products are applied to many types of crops including soybeans, potatoes, cotton, canola, alfalfa, corn and wheat. Our Pasadena Facility’s product sales are heavily weighted toward sales of ammonium sulfate, which made up approximately 92% of our Pasadena Facility’s total revenues for the calendar year ended December 31, 2012. Our Pasadena Facility’s products are sold primarily through distribution agreements as described below under “—Marketing and Distribution.”

Ammonium Sulfate. Ammonium sulfate is a solid dual-nutrient fertilizer produced by combining ammonia and sulfuric acid. Ammonium sulfate is the form of sulfur most available as a nutrient for crops. Our Pasadena Facility produces ammonium sulfate that is sized to the specifications of other nitrogen, phosphate and potash fertilizer products which results in less segregation in blended products. The ammonium sulfate plant at our Pasadena Facility has a current rated capacity of approximately 1,750 tons per day, which is expected to increase to approximately 2,100 tons per day following completion of our ammonium sulfate debottlenecking and production capacity project at our Pasadena Facility. Our Pasadena Facility has storage capacity for 60,000 tons of ammonium sulfate. In addition, we have an arrangement with Interoceanic Corporation, or IOC that permits us to store 32,000 tons of ammonium sulfate at IOC-controlled terminals, which are located near end customers of our Pasadena Facility’s ammonium sulfate.

Sulfuric Acid. Our Pasadena Facility produces sulfuric acid primarily for the production of ammonium sulfate. The majority of the sulfuric acid sold by the Pasadena Facility is sold through a distributor to industrial consumers. Our Pasadena Facility has storage capacity for 27,000 tons of sulfuric acid.

Ammonium Thiosulfate. Ammonium thiosulfate is a liquid fertilizer. Ammonium thiosulfate typically is combined with UAN to help increase the efficiency of nitrogen in crops. Our Pasadena Facility has storage capacity for 14,000 tons of ammonium thiosulfate.

Marketing and Distribution

We sell substantially all of our Pasadena Facility’s products through marketing and distribution agreements that automatically renew for successive one year periods. Pursuant to an exclusive marketing agreement we have entered into with IOC, IOC has the exclusive right and obligation to market and sell all of our Pasadena Facility’s granular ammonium sulfate in certain specified jurisdictions. Under the marketing agreement, IOC is required to use commercially reasonable efforts to market the product to obtain the most advantageous price. We compensate IOC for transportation and storage costs relating to the granular ammonium sulfate it markets through the pricing structure under the marketing agreement. The marketing agreement has a term that ends in February 2014, but automatically renews for subsequent one-year periods (unless either party delivers a termination notice to the other party at least 180 days prior to an automatic renewal). The marketing agreement may be terminated prior to its stated term for specified causes. During the period beginning November 1, 2012 through December 31, 2012, the marketing agreement with IOC accounted for 100% of our Pasadena Facility’s ammonium sulfate revenues. In addition, we have an arrangement with IOC that permits us to store 32,000 tons of ammonium sulfate at IOC-controlled terminals, which are located near end customers. This arrangement currently is not governed by a written contract.

Transportation

Our Pasadena Facility is located on the Houston Ship Channel with access to transportation at favorable prices by barge, truck or rail. The facility has two deep-water docks and access to the Mississippi waterway system and international waterways. The docks at the facility are suitable for loading and unloading bulk or liquid barges with payloads of up to 35,000 tons. The facility is also connected to key domestic railways which permit the efficient, cost-effective distribution of its products west of the Mississippi River. We believe this provides a significant cost advantage relative to producers located on the East Coast that are forced to switch railways when shipping product to this region. Our location on the Houston Ship Channel allows our distributors or us to use low cost barge and vessel when selling products and purchasing feedstocks.

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Customers

We sell substantially all of the products from our Pasadena Facility to IOC and our other distributors, and we do not have direct contact with our distributors’ customers. Our distributors sell a majority of our Pasadena Facility’s products to customers located west of the Mississippi River. Through our distributors, we sold all of our Pasadena Facility’s nitrogen products to customers for agricultural uses during the calendar year ended December 31, 2012. Given the nature of our business, and consistent with industry practice, we generally do not have long-term minimum sales contracts for fertilizer products with any of our customers exceeding one year.

Seasonality and Volatility

The ammonium sulfate and ammonium thiosulfate business is seasonal, based upon planting, growing and harvesting cycles. 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. While we experience seasonality in our domestic sales of ammonium sulfate and ammonium thiosulfate, our sales internationally offset a portion of this seasonal impact in our total revenues. Further, we adjust the sales prices of these products seasonally in order to facilitate distribution of the products throughout the year. We operate the ammonium sulfate plant at our Pasadena Facility throughout the year to the extent that there is available on-site storage capacity for this product. We have 60,000 tons of storage capacity for ammonium sulfate at the facility, and an arrangement with IOC that permits us to store 32,000 tons of ammonium sulfate at IOC-controlled terminals. We manage the storage capacity by distributing the product through IOC to customers in both domestic and offshore markets throughout the year. If storage capacity becomes insufficient, we would be forced to cease production of the product until such capacity becomes available. Our Pasadena Facility’s fertilizer products are sold both on the spot market for immediate delivery and, to a much lesser extent, under product prepayment contracts for future delivery at fixed prices. The amount of products we sell under product prepayment contracts is highly variable. As of December 31, 2012, there were approximately 6,300 tons of ammonium sulfate sold under product prepayment contracts. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk.”

The majority of sulfuric acid our Pasadena Facility sells to its distributor is placed with industrial consumers. Demand generally is constant during the year since sales of industrial products, such as sulfuric acid, are generally not impacted by seasons and weather. We typically ship sulfuric acid from our Pasadena Facility each month of the year with the majority of the product sold under annual contracts.

Raw Materials

The principal raw materials used to produce nitrogen fertilizer products at our Pasadena Facility are ammonia and sulfur. Since January 2013, we have purchased ammonia for use at the facility from OCI Beaumont, LLC, or OCI Beaumont. OCI Beaumont operates an ammonia and methanol production facility on the Neches River in Nederland, Texas just outside of Beaumont, Texas. Ammonia pricing is based on a published Tampa, Florida market index. The Tampa index is commonly used in annual contracts for both the agricultural and industrial sectors, and is based on the most recent major industry transactions in the Tampa market. Pricing considerations for ammonia incorporate international supply-demand, ocean freight and production factors. An 1,800 short ton ammonia barge delivers ammonia from Beaumont, Texas to our Pasadena Facility, pursuant to a long term lease we have entered into with Port Arthur Towing Company. Ammonia purchased and used in production at our Pasadena Facility was approximately 23,000 tons in the two-month period ended December 31, 2012.

We obtain sulfur for our Pasadena Facility primarily by truck from local refineries in the Houston area and, to a lesser extent, by rail car. Major suppliers of sulfur to our Pasadena Facility include refiners, such as Phillips 66 Company, Shell Oil Products U.S. and Valero Energy Corporation. Our contracts with these refiners generally have a term of one year. Once pricing for the first quarter of a year is negotiated, the price then fluctuates up or down each subsequent quarter based on changes to a Tampa index that is set on a quarterly basis through negotiations between large industry producers and consumers. Sulfur purchased and used in production at our Pasadena Facility was approximately 26,000 tons in the two-month period ended December 31, 2012.

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Competition

Our Pasadena Facility competes with a number of domestic and foreign producers of nitrogen fertilizer products, many of which are larger than we are and have significantly greater financial and other resources than we do. We believe that customers who purchase the product make purchasing decisions based, in part, on the product’s size and shelf life. The majority of ammonium sulfate produced in North America and globally is generated as a byproduct of another process. Our ammonium sulfate (which we refer to as synthetic ammonium sulfate) is made specifically for fertilizer and is sized to the specifications preferred by customers and is more easily blended with other fertilizer products. We also believe that our ammonium sulfate has a longer shelf-life, is more stable and is more easily transported and stored than many other competing products. Honeywell International Inc., the largest producer of ammonium sulfate in the United States is located in Hopewell, Virginia, approximately 1,350 miles from our Pasadena Facility. BASF AG, the second largest producer of ammonium sulfate, is located in Freeport, Texas, approximately 60 miles away from our Pasadena Facility. Our Pasadena Facility has access to transportation at favorable prices, such as low cost barge and vessel. We believe that our close proximity to sources of our primary feedstocks and access to low-cost transportation enables the facility to offer competitive pricing to customers adjacent to and west of the Mississippi River.

We also face competition from numerous regional producers of sulfuric acid, including E. I. du Pont de Nemours and Company, or DuPont, located in El Paso and La Porte, Texas and Burnside, Louisiana, Rhodia Inc. located in Baytown and Houston, Texas and Chemtrade Logistics Inc., located in Beaumont, Texas.

Environmental Matters

Our business is subject to extensive and frequently changing federal, state and local, environmental, health and safety regulations governing a wide range of matters, including the emission of air pollutants, the release of hazardous substances into the environment, the treatment and discharge of waste water and the storage, handling, use and transportation of our fertilizer products, raw materials, and other substances that are part of our operations. These laws include the Clean Air Act, or the CAA, the federal Water Pollution Control Act, or the Clean Water Act, the Resource Conservation and Recovery Act, or RCRA, the Comprehensive Environmental Response, Compensation and Liability Act, or 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 (if any) and off-site waste disposal locations; and

• specifications for the products we market.

These laws significantly affect our operating activities as well as the level of our operating costs and capital expenditures. Failure to comply with environmental laws, including the permits issued to us thereunder, generally could result in substantial fines, penalties or other sanctions, court orders to install pollution-control equipment, permit revocations and facility shutdowns. During the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, we made $0.3 million, $0.5 million, $5.6 million and $1.3 million, respectively, of environmental, health and safety-related capital expenditures at the East Dubuque Facility. During the calendar years ended December 31, 2012, 2011 and 2010, we (or the Seller) made $1.0 million, $0.6 million and $1.3 million, respectively, of environmental, health and safety-related capital expenditures at the Pasadena Facility.

Our operations require numerous permits and authorizations. A decision by a governmental regulator to revoke or substantially modify an existing permit or authorization could have a material adverse effect on our ability to continue operations at the impacted facility. Expansion of our operations is predicated upon obtaining the necessary environmental permits and authorizations. 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.

In addition, environmental, health and safety laws may impose joint and several liability, without regard to fault, for cleanup of a contaminated site on current owners and operators of the site, former owners and operators of the site at the time of the disposal of the hazardous substances, any person who arranges for the transportation, disposal or treatment of the hazardous substances, and the transporters who select the disposal and treatment facilities, regardless of the care exercised by such persons. 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 damages. 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 or results of operations.

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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 result in increased capital, operating and compliance costs.

Our facilities have 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.

Certain environmental regulations and risks associated with our business are outlined below. We strive to maintain compliance with these regulations; however, they are complex and varied, and our operations are heavily regulated, and we may, from time to time, fall out of compliance. As examples, the Pasadena Facility may not comply with wastewater and stormwater discharge requirements and solid and hazardous waste requirements, and the US Environmental Protection Agency, or EPA, issued in December 2011 a consent agreement and final order, or CAFO, concerning hazardous waste management and air emissions at the Pasadena Facility which imposed civil penalties of $1.8 million plus interest. Pursuant to this CAFO, penalties of approximately $0.7 million were paid prior to the closing of the Agrifos Acquisition, we were obligated to pay penalties of approximately $0.4 million in December 2012, and we are obligated to pay penalties of approximately $0.7 million by December 2013.

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, impose permitting 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. Standards promulgated pursuant to the CAA may require that we install controls at or make other changes to our facilities. 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 substantial fines, civil or criminal penalties, or other sanctions.

The regulation of air emissions under the CAA requires that we obtain various construction and operating permits, including Title V air permits and incur capital expenditures for the installation of certain air pollution control devices at our facilities. Measures have been taken to comply with various regulations specific to our operations, 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. As one example, we are confirming whether certain emissions at our Pasadena facility are in compliance with applicable emission limits, and we are currently conducting testing to assess if any action will be required. As another example, we have one project that is designed to achieve compliance with the emissions limits and other requirements applicable to our East Dubuque Facility. In July 2011, we began operating what we believe is the first tertiary N2O catalytic converter in the United States on one of our nitric acid plants at our East Dubuque Facility. This converter is designed to convert approximately 90%, and for the year ended December 31, 2012 converted on average approximately 92% of the N2O generated in our production of nitric acid into nitrogen and oxygen at that one plant. For the year ended December 31, 2012, the converter reduced N2O emissions at our East Dubuque Facility by approximately 330 tons. This converter also monitors and records its effect on reducing N2O emissions and we are awarded corresponding emission reduction credits for the reduction. If we do not need the credits, we can list the credits on an active registry, such as the Climate Registry maintained by the Climate Action Reserve, and sell the credits for a profit. We have entered into a five-year agreement to supply emission reduction credits with sales totaling approximately $0.1 million during the calendar year ended December 31, 2012.

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 releases of hazardous or extremely hazardous substances from our operations or properties. We report such releases to the EPA, the IEPA, the Texas Commission on Environmental Quality, and other relevant federal, 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.

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Clean Water Act. The Clean Water Act 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 waters of the United States. 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 Clean Water Act 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 Clean Water Act 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 Clean Water Act and analogous state laws and regulations.

GHG Emissions. Currently, various legislative and regulatory measures to address greenhouse gas, or 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 imminent 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 or impose a carbon fee.

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 facilities and began reporting 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 facilities, must obtain permits under the Prevention of Significant Deterioration, or 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 permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Greenhouse Gas Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Greenhouse Gas Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. The ongoing ammonia capacity expansion project at our East Dubuque Facility did not trigger the need to install BACT because actual construction commenced prior to July 1, 2011 and is not considered a major modification with respect to criteria pollutants. However, a future major modification to one of our facilities may require us to satisfy BACT requirements and potentially require us to meet other CAA requirements applicable to GHG emissions. The EPA’s endangerment finding, the Greenhouse Gas Tailoring Rule and certain other GHG emission rules have been challenged and will likely be subject to extensive litigation. In addition, a number of Congressional bills were introduced in 2010 and 2011 to overturn the endangerment finding and bar the EPA from regulating GHG emissions, or at least to defer such action by the EPA under the CAA, although President Obama has announced his intention to veto any such bills if passed.

In addition to federal regulations, a number of states have adopted regional GHG initiatives to reduce CO₂ and other GHG emissions. In 2007, a group of Midwest states formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control GHG emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and it is not known if or when any such laws or regulations will be implemented in Illinois.

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 agricultural producers that utilize our fertilizer products, thereby potentially decreasing demand for our nitrogen fertilizer products. Decreased demand for our fertilizer products may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

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Management of Hazardous Substances and Contamination. Under CERCLA and related state laws, certain persons may be liable at sites where or from release or threatened release of hazardous substances has occurred or is threatened. 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. RCRA regulates the generation, treatment, storage, handling, transportation and disposal of solid waste and requires states to develop programs to ensure the safe disposal of solid waste. Under RCRA, persons may be liable at sites where the past or present storage, handling, treatment, transportation, or disposal of any solid or hazardous waste may present an imminent and substantial endangerment to health or the environment. These persons can include the current owner or operator of property where disposal occurred, any persons who owned or operated the property when the disposal occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under RCRA is strict 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. For a discussion of hazardous substances management at the Pasadena Facility, see the risk factor captioned “There are phosphogypsum stacks located at the Pasadena Facility that will require closure. In the event we become financially obligated for the costs of closure, this would have a material adverse effect on our business, cash flow and ability to make cash distributions to our unitholders.” For a discussion of releases at the Pasadena Facility, see the risk factor captioned “Soil and groundwater at the Pasadena Facility is pervasively contaminated, and we may incur costs to investigate and remediate known or suspected contamination at the Pasadena Facility. We may also face legal actions or sanctions or incur costs related to contamination or noncompliance with environmental laws at the facility.”

Underground Injection Operations. Underground injection operations are subject to the Safe Drinking Water Act, or SWDA, as well as analogous state laws and regulations. Under the SWDA, the EPA established the underground injection control or UIC program, which includes requirements for permitting, testing, monitoring, record keeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. ExxonMobil Corporation (a former owner of the Pasadena Facility), or ExxonMobil, operates injection wells located at or surrounded by our Pasadena Facility for the disposal of wastewater related to the phosphogypsum stacks. State regulations require that a permit be obtained from the applicable regulatory agencies to operate underground injection wells. Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of ExxonMobil’s UIC permit, which could adversely impact the closure of the phosphogypsum stacks.

Environmental Insurance. We have a premises pollution liability insurance policy which covers third party bodily injury and property damages claims, remediation costs and associated legal defense expenses for pollution conditions at or migrating from our facilities and the transportation risks associated with moving waste from our facilities to offsite locations for unloading or depositing waste. The policy also covers business interruptions and non-owned disposal sites. Our policy is subject to a limit and self-insured retention and contains other terms, exclusions, conditions and limitations that could apply to a particular pollution condition claim, including the closure post closure of the gypsum stacks (the responsibility of ExxonMobil) and we cannot guarantee that a claim will be adequately insured for all potential damages.

Safety, Health and Security Matters

We are subject to a number of federal and state laws and regulations related to safety, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purpose of which are to protect the health and safety of workers. Various OSHA standards may apply to our operations, including standards concerning notices of hazards, safety in excavation and demolition work, the handling of asbestos and asbestos-containing materials and worker training and emergency response programs. 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 have an internal safety, health and security program designed to monitor and enforce compliance with worker safety requirements, and we routinely review and consider improvements in our programs. We also are subject to 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 United States Coast Guard’s Maritime Security Standards for Facilities, which are designed to regulate the security of high-risk maritime facilities. We believe that we are in material compliance with all applicable laws and regulations related to worker health and safety. Notwithstanding these preventative measures, we cannot guarantee that serious accidents will not occur in the future.

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Employees

As of December 31, 2012, we had 92 non-unionized and salaried employees, and 146 unionized employees. We have collective bargaining agreements in place covering unionized employees at our East Dubuque Facility and Pasadena Facility. The agreement for the East Dubuque Facility is effective until October 17, 2016. There are two agreements for the Pasadena Facility. One agreement expires on March 28, 2013 and the other, which covers nine employees, expires on April 30, 2013. We have not experienced work stoppages in the recent past.

Financial Information

We operate in two business segments. All of our properties are located in the United States and all of the related revenues are derived from purchasers located in the United States. Our financial information is included in Part II—Item 8 “Financial Statements and Supplementary Data.”

Properties

We operate our East Dubuque Facility on an approximately 210 acre site in East Dubuque, Illinois adjacent to the Mississippi River. We own the land, buildings, several special purpose structures, equipment, storage tanks and specialized truck, rail and river barge loading facilities, and hold easements for the roadways, wells, the rail track and the barge dock. We also have the right to store 15,000 tons of ammonia at Agrium’s terminal in Niota, Illinois. See “—Our East Dubuque Facility—Marketing and Distribution.”

We operate our Pasadena Facility on an approximately 85 acre site in Pasadena, Texas located on the Houston Ship Channel which includes 2,700 linear feet of water frontage and two deep-water docks. The property also includes approximately 415 acres of unused land which contains phosphogypsum stacks. In addition, we have an arrangement with IOC that permits us to store 32,000 tons of ammonium sulfate at IOC-controlled terminals, which are located near end customers of our Pasadena Facility’s ammonium sulfate. This arrangement currently is not governed by a written contract. See “—Our Pasadena Facility—Marketing and Distribution.”

Available Information

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 as soon as reasonably practical after they are filed or furnished to the SEC, at the “Investor Relations” portion of our website, www.rentechnitrogen.com. 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, and other information regarding us that we file electronically with the SEC. The information contained on our website does not constitute part of this report.

ITEM 1A — RISK FACTORS

Set forth below are certain risk factors related to our business. 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 develops into an actual event, our business, financial condition, cash flow or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment. Although many of our business risks are comparable to those faced by a corporation engaged in a similar business, limited partner interests are inherently different from the capital stock of a corporation and involve additional risks described below.

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Risks Related to Our Business

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

We may not have sufficient cash available for distribution each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount of cash we will be able to distribute on our common units principally depends on the amount of cash flow we generate from our operations, which is directly dependent upon the operating margins we generate, which have been volatile historically, and cash collections under product prepayment contracts for our products. Our operating margins are significantly affected by the price and availability of natural gas, market-driven product prices we are able to charge our customers and our production costs, as well as seasonality, weather conditions, governmental regulation, unplanned maintenance or shutdowns at our facilities and global and domestic demand for nitrogen fertilizer products, among other factors. In addition:

• Our partnership agreement does not provide for any minimum quarterly distribution and our quarterly distributions, if any, will be subject to significant fluctuations directly related to the cash flow we generate after payment of our expenses due to the nature of our business.

• The amount of distributions we make, if any, and the decision to make any distribution at all is 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 Rentech to the detriment of our common unitholders.

• Our new 2012 credit agreement limits, and any credit facility or other debt instruments we enter into in the future may limit, the distributions that we can make. Our new 2012 credit agreement contains, and any future credit facility or debt instruments we enter into may contain, financial tests and covenants that we must satisfy prior to making distributions. Any failure to comply with these tests and covenants could result in the applicable lenders prohibiting distributions by us.

• The amount of cash available to pay any quarterly distribution to our unitholders depends primarily on our cash flow, and not solely on our profitability, which is affected by non-cash items that may be large relative to our reported net income. As a result, we may make distributions during periods when we record losses and may not make distributions during periods when we record net income.

• The actual amount of cash available for distribution will depend on numerous factors, some of which are beyond our control, including the availability and price of natural gas, ammonia and sulfur, our operating costs, global and domestic demand for nitrogen fertilizer products, fluctuations in our capital expenditures and working capital needs, our product pre-sale and cash collection cycle and the amount of fees and expenses we incur.

• Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or Delaware Act, we are prohibited from making a distribution to our limited partners if the distribution would cause our liabilities to exceed the fair value of our assets.

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 limited partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase 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 seasonal and volatile, and our cash flow will be less stable, than the business performance and cash flow of most publicly traded limited partnerships. As a result, our quarterly cash distributions will be volatile and are expected to vary quarterly and annually. Unlike most publicly traded limited partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The amount of our quarterly cash distributions will be directly dependent on the performance of our business, which has been volatile historically for reasons including volatile nitrogen fertilizer and natural gas prices, unplanned outages, seasonal and global fluctuations in demand for nitrogen fertilizer products and the timing of our product pre-sale and cash collections. Because our quarterly distributions will be subject to significant fluctuations directly related to the cash flow we generate after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Given the seasonal nature of our business, we expect that our unitholders will have direct exposure to fluctuations in the margins we realize on sales of nitrogen fertilizers and other products that we produce. In addition, we frequently make product sales pursuant to product prepayment contracts, whereby we receive cash in respect of product to be picked up by or delivered to a customer at a later date, but do not record revenue in respect of such sales until product is picked up or delivered. The cash received from product prepayments increases our operating cash flow in the quarter in which the cash is received, but may effectively reduce our operating cash flow in a subsequent quarter if the cash was received in a quarter prior to the one in which the revenue is recorded.

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We may modify or revoke our cash distribution policy at any time at our discretion. Our partnership agreement does not require us to make any distributions at all.

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

Our operations may become unprofitable and may require substantial working capital financing.

In recent years, we have generated positive income from operations and positive cash flow from operations. However, in the past, we sustained losses and negative cash flow from operations. Our profits and cash flow are subject to changes in the prices for our products and our main inputs, natural gas, ammonia and sulfur, which are commodities, and, as such, the prices can be volatile in response to numerous factors outside of our control. Our profits depend on maintaining high rates of production of our products, and interruptions in operations at our facilities could materially adversely affect our profitability. If we are not able to operate our facilities at a profit or if we are not able to retain cash or access a sufficient amount of financing for working capital, our business, financial condition, cash flow, results of operations and ability to pay cash distributions could be materially adversely affected, which could adversely affect the trading price of our common units.

The nitrogen fertilizer business and nitrogen fertilizer prices are seasonal, cyclical and highly volatile and have experienced substantial and sudden downturns in the past. Currently, nitrogen fertilizer demand and prices are at relative high points and could decrease significantly in the future. Cycles in demand and pricing could potentially expose us to significant fluctuations in our operating and financial results, and expose you to substantial volatility in our quarterly distributions and material reductions in the trading price of our common units.

We are exposed to fluctuations in nitrogen fertilizer demand and prices in the agricultural industry. These fluctuations historically have had, and could in the future have, significant effects on prices across all nitrogen fertilizer products and, in turn, our financial condition, cash flow and results of operations, which could result in significant volatility or material reductions in the price of our common units or an inability to pay cash distributions to our unitholders.

Nitrogen fertilizer products are commodities, the prices of which can be highly volatile. The price of nitrogen fertilizer products depends on a number of factors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, the prices of natural gas, ammonia, sulfur and other raw materials, the prices of other commodities such as corn, soybeans, potatoes, cotton, canola, alfalfa and wheat, and weather conditions, all of which have a greater relevance because of the seasonal nature of fertilizer application. If seasonal demand exceeds the projections on which we base production, our customers may acquire nitrogen fertilizer products from our competitors, and our profitability will be negatively impacted. If seasonal demand is less than we expect, we will be left with excess inventory that will have to be stored or liquidated, which could adversely affect our operating margins and our ability to pay cash distributions. Demand for nitrogen fertilizer products is dependent on demand for crop nutrients by the global agricultural industry. Nitrogen fertilizer products are currently in high demand, driven by a growing world population, changes in dietary habits and an expanded production of corn. Supply is affected by available capacity and operating rates of nitrogen producers, raw material costs, government policies and global trade. A significant or prolonged decrease in nitrogen fertilizer prices would have a material adverse effect on our business, cash flow and ability to make cash distributions to our unitholders. Further, the margins on the sale of ammonium sulfate fertilizer products are currently lower than the margins on our other main nitrogen fertilizer products. If our costs to produce ammonium sulfate fertilizer products increase and the prices at which we sell these products do not correspondingly increase, our profits from the sale of these products may decrease and we may suffer losses on these sales. A significant or prolonged decrease in profits (or increase in losses) on the sale of our ammonium sulfate fertilizer products would have a material adverse effect on our business, cash flow and ability to make cash distributions to our unitholders.

Any decline in United States agricultural production or crop prices or limitations on the use of nitrogen fertilizer for agricultural purposes could have a material adverse effect on the market for nitrogen fertilizer, and on our results of operations, financial condition and ability to make cash distributions.

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Conditions in the United States agricultural industry significantly impact our operating results. This is particularly the case in the production of corn, which is a major driver of the demand for nitrogen fertilizer products in the United States. The United States agricultural industry in general, and the production and prices of corn in particular, can be affected by a number of factors, including weather patterns and soil conditions, current and projected grain inventories and prices, domestic and international supply of and demand for United States agricultural products and United States and foreign policies regarding trade in agricultural products. Prices for these agricultural products can decrease suddenly and significantly. For example, in June 2011, an unexpectedly large corn crop estimate resulted in an approximately 20% decrease in corn prices from their peak levels earlier in the month, the largest monthly decrease since June 2009.

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 fertilizers for particular agricultural applications. Developments in crop technology, such as nitrogen fixation, 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. In addition, 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. The adoption or enforcement of such regulations could adversely affect the demand for and prices of nitrogen fertilizers, which could adversely affect our results of operations, cash flows and ability to make cash distributions to our unitholders.

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

A major factor underlying the current level of demand for corn and the use of nitrogen fertilizer products is the current production level of ethanol in the United States. Ethanol production in the United States is dependent in part upon a myriad of federal and state incentives. Such 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. Studies showing that expanded ethanol production may increase the level of GHGs in the environment, or other factors, may reduce political support for ethanol production. For example, the Volumetric Ethanol Excise Tax Credit, or VEETC, provided for a 45 cents per gallon tax credit to blenders and refiners for gasoline that has been blended with ethanol. On December 31, 2011, the VEETC expired. We cannot guarantee that any other ethanol-related subsidy will be implemented in its place. Furthermore, the current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass. If another ethanol-related subsidy is not implemented, or if an efficient method of producing ethanol from cellulose-based biomass is developed and commercially deployed at scale, the demand for corn may decrease significantly. Any reduction in the demand for corn and, in turn, for nitrogen fertilizer products could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions to our unitholders.

Nitrogen fertilizer products are global commodities. Any decrease in the price of nitrogen fertilizer products from foreign countries could harm us.

Fertilizers 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. In recent years, the price of nitrogen fertilizer in the United States has been substantially driven by pricing in the global fertilizer market and favorable prices for natural gas in the United States as compared to those in foreign countries. If foreign natural gas prices become lower than natural gas prices in the United States, competition from foreign businesses will likely increase and this could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions to our unitholders.

We face intense competition from other nitrogen fertilizer producers.

We have a number of competitors in the United States and in other countries, including state-owned and government-subsidized entities. Our East Dubuque Facility’s principal competitors include domestic and foreign fertilizer producers, major grain companies and independent distributors and brokers, including Koch Industries, Inc., CF Industries Holdings, Inc., Agrium, Gavilon, LLC, CHS Inc., Transammonia, Inc., OCI and Helm Fertilizer Corp., and our Pasadena Facility’s principal competitors include domestic and foreign fertilizer producers and independent distributors and brokers, including BASF AG, Honeywell International Inc., Agrium Inc., Royal DSM N.V., Dakota Gasification Company and Martin Midstream Partners L.P.

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Some competitors have greater total resources, or better name recognition, and are less dependent on earnings from fertilizer sales, which make them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. For example, certain of our East Dubuque Facility’s nitrogen fertilizer competitors have announced that they currently have expansions planned or underway to increase production capacity of their nitrogen fertilizer products. Furthermore, there are a few dormant nitrogen production facilities located outside of the East Dubuque Facility’s core market that are scheduled to resume operations in the near future. We may face additional competition due to the expansion of facilities that are currently operating and the reopening of currently dormant facilities. Also, other producers of nitrogen fertilizer products are contemplating the construction of new nitrogen fertilizer facilities in North America, including in the Mid Corn Belt. For example, OCI, an Egyptian producer of fertilizer products, announced that in November 2012 it broke ground on construction of a facility in our core market that is designed to produce between 1.5 to 2.0 million metric tons per year of ammonia, urea, UAN and diesel exhaust fluid by mid-2015. If a new nitrogen fertilizer facility is completed in the East Dubuque Facility’s core market, it could benefit from the same competitive advantage associated with the location of the facility. As a result, the completion of such a facility could have a material adverse effect on our business, cash flow and ability to make cash distributions to our unitholders.

In addition, competitors utilizing different corporate structures may be better able to withstand lower cash flow than we can as a limited partnership. Our competitive position could suffer to the extent that we are not able to adapt our product mix to meet the needs of our customers or expand our own resources either through investments in new or existing operations or through acquisitions, joint ventures or partnerships. An inability to compete successfully could result in the loss of customers, which could adversely affect our sales and profitability, and our ability to make cash distributions to our unitholders. In addition, as a result of increased pricing pressures caused by competition, we may in the future experience reductions in our profit margins on sales, or may be unable to pass future input price increases on to our customers, which would reduce our cash flows and the cash available for distribution to our unitholders.

Our business is seasonal, which may result in our carrying significant amounts of inventory and seasonal variations in working capital. Our inability to predict future seasonal nitrogen fertilizer demand accurately may result in excess inventory or product shortages.

Our business is highly seasonal. Historically, most of the annual deliveries of the products from our East Dubuque Facility have occurred during the quarters ending June 30 and December 31 of each year due to the condensed nature of the spring planting season and the fall harvest in the East Dubuque Facility’s market. Farmers in that market tend to apply nitrogen fertilizer during two short application periods, one in the spring and the other in the fall. Since interim period operating results reflect the seasonal nature of our business, they are not indicative of results expected for the full fiscal year. In addition, results for comparable quarters can vary significantly from one year to the next due primarily to weather-related shifts in planting schedules and purchase patterns of our customers. We expect to incur substantial expenditures for fixed costs throughout the year and substantial expenditures for inventory in advance of the spring planting season and fall harvest season in our East Dubuque Facility’s market as we build inventories during these low demand periods. Seasonality also relates to the limited windows of opportunity that nitrogen fertilizer customers have to complete required tasks at each stage of crop cultivation. Should events such as adverse weather or production or transportation interruptions occur during these seasonal windows, we would face the possibility of reduced revenue without the opportunity to recover until the following season. In addition, an adverse weather pattern affecting one of our markets could have a material adverse effect on the demand for our products and our revenues, and we may not have sufficient geographic diversity in our customer base to mitigate such effects. Because of the seasonality of agriculture, we also expect to face the risk of significant inventory carrying costs should our customers’ activities be curtailed during their normal seasons. The seasonality can negatively impact accounts receivable collections and increase bad debts. In addition, variations in the proportion of product sold through forward sales and variances in the terms and timing of product prepayment contracts can affect working capital requirements and increase the seasonal and year-to-year volatility of our cash flow and cash available for distribution to our unitholders.

If seasonal demand exceeds our projections, we will not have enough product and our customers may acquire products from our competitors, which would 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.

The degree of seasonality of our business can change significantly from year to year due to conditions in the agricultural industry and other factors. As a consequence of our seasonality, we expect that our distributions will be volatile and will vary quarterly and annually.

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Any operational disruption at our facilities as a result of equipment failure, an accident, adverse weather, a natural disaster or another interruption could result in a reduction of sales volumes and could cause us to incur substantial expenditures. A prolonged disruption could materially affect the cash flow we expect from our facilities, or lead to a default under our new 2012 credit agreement.

The equipment at our facilities could fail and could be difficult to replace. Our facilities may be subject to significant interruption if it were to experience a major accident or equipment failure, including accidents or equipment failures caused during expansion projects, or if they were damaged by severe weather or natural disaster. Significant shutdowns at our facilities could significantly reduce the amount of product available for sale, which could reduce or eliminate profits and cash flow from our operations. Repairs to our facilities in such circumstances could be expensive, and could be so extensive that our facilities could not economically be placed back into service. It has become increasingly difficult to obtain replacement parts for equipment and the unavailability of replacement parts could impede our ability to make repairs to our facilities when needed. We currently maintain property insurance, including business interruption insurance, but we may not have sufficient coverage, or may be unable in the future to obtain sufficient coverage at reasonable costs. A prolonged disruption at our facilities could materially affect the cash flow we expect from our facilities, or lead to a default under our new 2012 credit agreement. In addition, operations at our facilities are subject to hazards inherent in chemical processing. Some of those hazards may cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. As a result, operational disruptions at our facilities could materially adversely impact our business, financial condition, results of operations and cash flow.

The market for natural gas has been volatile. Natural gas prices are currently at a relative low point. If prices for natural gas increase significantly, we may not be able to economically operate our East Dubuque Facility.

The operation of our East Dubuque Facility with natural gas as the primary feedstock exposes us to market risk due to increases in natural gas prices, particularly if the price of natural gas in the United States were to become higher than the price of natural gas outside the United States. During 2008, natural gas prices spiked to near-record high prices. This was due to various supply and demand factors, including the increasing overall demand for natural gas from industrial users, which is affected, in part, by the general conditions of the United States and global economies, and other factors. The profitability of operating our East Dubuque Facility is significantly dependent on the cost of natural gas, and our East Dubuque Facility has operated in the past, and may operate in the future, at a net loss. Since we expect to purchase a substantial portion of our natural gas for use in our East Dubuque Facility on the spot market we remain susceptible to fluctuations in the price of natural gas. We also expect to use short-term, fixed supply, fixed price forward purchase contracts to lock in pricing for a portion of our natural gas requirements. Our ability to enter into forward purchase contracts is dependent upon our creditworthiness and, in the event of a deterioration in our credit, counterparties could refuse to enter into forward purchase contracts on acceptable terms. If we are unable to enter into forward purchase contracts for the supply of natural gas, we would need to purchase natural gas on the spot market, which would impair our ability to hedge our exposure to risk from fluctuations in natural gas prices. Moreover, forward purchase contracts may not protect us from increases in natural gas prices. A hypothetical increase of $0.10 per MMBtu of natural gas would increase our cost to produce one ton of ammonia by approximately $3.50. Higher than anticipated costs for the catalyst and other materials used at our East Dubuque Facility could also adversely affect operating results. These increased costs could materially and adversely affect our results of operations, financial condition and ability to make cash distributions.

The markets for ammonia and sulfur have been volatile. If prices for either ammonia or sulfur increase significantly, we may not be able to economically operate our Pasadena Facility.

The operation of our Pasadena Facility with ammonia and sulfur as its primary feedstocks also exposes us to market risk due to increases in ammonia or sulfur prices. Since we expect to purchase a substantial portion of our ammonia and sulfur for use in our Pasadena Facility on the spot market we remain susceptible to fluctuations in the respective prices of ammonia and sulfur. The margins on the sale of ammonium sulfate fertilizer products are relatively low. If our costs to produce ammonium sulfate fertilizer products increase and the prices at which we sell these products do not correspondingly increase, our profits from the sale of these products may decrease and we may suffer losses on these sales. A hypothetical increase of $10.00 per ton of ammonia would increase the cost to produce one ton of ammonium sulfate by approximately $2.50. A hypothetical increase of $10.00 per ton of sulfur would also increase the cost to produce one ton of ammonium sulfate by approximately $2.50.

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An increase in natural gas prices could impact our relative competitive position when compared to other foreign and domestic nitrogen fertilizer producers.

We rely on natural gas as our East Dubuque Facility’s primary feedstock, and the cost of natural gas is a large component of the total production cost for that facility’s nitrogen fertilizer. The dramatic increase in nitrogen fertilizer prices in recent years was not the direct result of an increase in natural gas prices, but rather the result of increased demand for nitrogen-based fertilizers due to historically low stocks of global grains and a surge in the prices of corn and wheat, the primary crops in the Mid Corn Belt region. This increase in demand for nitrogen fertilizers has created an environment in which nitrogen fertilizer prices have diverged from their traditional correlation with natural gas prices. An increase in natural gas prices would impact our East Dubuque operations by making us less competitive with competitors who do not use natural gas as their primary feedstock, and would therefore have a material adverse impact on the trading price of our common units. In addition, if natural gas prices in the United States were to increase to a level where foreign nitrogen fertilizer producers were able to improve their competitive position on a price-basis, this would negatively affect our competitive position in the Mid Corn Belt region and thus have a material adverse effect on our results of operations, financial condition, cash flows, and ability to make cash distributions.

The success of our recently-acquired ammonium sulfate fertilizer business depends on our ability to maintain recent production levels and product sales and margins and to implement our expansion plans at the Pasadena Facility.

Our ammonium sulfate fertilizer business has a limited operating history upon which its business and products can be evaluated. The Pasadena Facility produced phosphate fertilizer until early 2011 when it underwent a conversion to produce ammonium sulfate fertilizer products. Because our ammonium sulfate fertilizer business has a limited operating history, we may not be able to effectively:

• maintain or expand production capacity for ammonium sulfate fertilizer at the Pasadena Facility;

• maintain product sales prices, margins and operating costs at levels that we currently expect;

• achieve production rates and on-stream factor that we currently expect;

• implement potential capital improvements, including the ammonium sulfate debottlenecking and production capacity project and the power generation project, to lower costs and increase revenues at the Pasadena Facility;

• attract and retain customers for our products from our existing or expanded production capacity;

• comply with evolving regulatory requirements, including environmental regulations;

• anticipate and adapt to changes in the ammonium sulfate fertilizer market;

• maintain and develop strategic relationships with distributors and suppliers to facilitate the distribution and acquire necessary materials for our products; and

• attract, retain and motivate qualified personnel.

The operations at the Pasadena Facility are subject to many of the risks inherent in the growth of a new business. The likelihood of the facility’s success must be evaluated in light of the challenges, expenses, difficulties, complications and delays frequently encountered in the operation of a new business. We cannot assure you that we will achieve the goals set forth above or any goals we may set in the future. Our failure to meet any of these goals could have a material adverse effect on our business, cash flow and ability to make cash distributions to our unitholders.

There are phosphogypsum stacks located at the Pasadena Facility that will require closure. In the event we become financially obligated for the costs of closure, this would have a material adverse effect on our business, cash flow and ability to make cash distributions to our unitholders.

The Pasadena Facility was used for phosphoric acid production until 2011, which resulted in the creation of a number of phosphogypsum stacks at the Pasadena Facility. Phosphogypsum stacks are composed of the mineral processing waste that is the byproduct of the extraction of phosphorous from mineral ores. Certain of the stacks also have been or are used for other waste materials and wastewater. Applicable environmental laws extensively regulate phosphogypsum stacks.

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The Environmental Protection Agency, or EPA, reached a consent agreement and final order, or CAFO, with ExxonMobil in September 2010 making ExxonMobil responsible for closure of the stacks, proper disposal of process wastewater related to the stacks and other expenses. In addition, the asset purchase agreement between a subsidiary of Agrifos and ExxonMobil, or the 1998 APA, pursuant to which the subsidiary purchased the Pasadena Facility in 1998 also makes ExxonMobil liable for closure and post-closure care of the stacks, with certain limitations relating to use of the stacks after the date of the agreement. ExxonMobil is in the process of closing the “south stack” (a large phosphogypsum stack that combines “stacks 2, 3 and 5”) and “stack 4” at the facility. ExxonMobil has not yet started closure of “stack 1” at the facility, which is the only remaining stack that is currently in use for disposal of waste streams. Although ExxonMobil has expended significant funds and resources relating to the closures, we cannot assure you that ExxonMobil will remain able and willing to complete closure and post-closure care of the stacks in the future, including as a result of actions taken by Agrifos prior to the closing of the Agrifos Acquisition. As of January 2012, ExxonMobil estimated that its total outstanding costs associated with the closures and long-term maintenance, monitoring and care of the stacks will be approximately $102 million over the next 50 years. However, the actual amount of such costs could be in excess of this amount. Subject to the terms and conditions of the Purchase Agreement, the Seller is required to indemnify us for certain environmental matters relating to the Pasadena Facility including costs relating to the closure of the stacks if such costs are not paid for by ExxonMobil. However, the Seller’s indemnification obligations are subject to important limitations including a cap of $29 million on the amount of indemnified losses and a deductible of $2 million. Further, in the event we seek indemnification from the Seller, we cannot assure you that we will be able to receive compensation for any losses we may have incurred on a timely basis, or at all.

As discussed above, the costs of closure and post-closure care of the stacks will be substantial. If we become financially responsible for the costs of closure of the stacks, this would have a material adverse effect on our business, cash flow and ability to make cash distributions to our unitholders.

Soil and groundwater at the Pasadena Facility is pervasively contaminated, and we may incur costs to investigate and remediate known or suspected contamination at the Pasadena Facility. We may also face legal actions or sanctions or incur costs related to contamination or noncompliance with environmental laws at the facility.

The soil and groundwater at the Pasadena Facility is pervasively contaminated. The facility has produced fertilizer since as early as the 1940s, and a large number of spills and releases have occurred at the facility, many of which involved hazardous substances. Furthermore, naturally occurring and other radioactive contaminants have been discovered at the facility in the past, and asbestos-containing materials currently exist at the facility. In the past there have been numerous instances of weather events which have resulted in flooding and releases of hazardous substances from the facility. We cannot assure you that past environmental investigations at the facility were complete, and there may be other contaminants at the facility that have not been detected. Contamination at the Pasadena Facility has the potential to result in toxic tort, property damage, personal injury and natural resources damages claims or other lawsuits. Further, regulators may require investigation and remediation at the facility in the future at significant expense.

ExxonMobil submitted Affected Property Assessment Reports, or APARs, under the Texas Risk Reduction Program to the Texas Commission on Environmental Quality, or the TCEQ, in 2011 for the plant site and one of the phosphogypsum stacks at the Pasadena Facility, and ExxonMobil is in the process of submitting an APAR for another stack at the facility (with an initial portion of it having been submitted to the TCEQ in March 2012). The APARs identify instances in which various regulatory limits for numerous hazardous materials in both the soil and groundwater at the plant site and in the vicinity of the stacks have been exceeded. In October 2012, the TCEQ requested ExxonMobil to perform significant additional investigative work as part of the APAR process. The TCEQ may require further investigation and remediation of the contamination at the Pasadena Facility. The TCEQ or other regulatory agencies may hold Agrifos or its subsidiaries responsible for certain of the contamination at the Pasadena Facility.

In the past, governmental authorities have determined that the Pasadena Facility has been in substantial noncompliance with environmental laws and the Pasadena Facility has been the subject of numerous regulatory enforcement actions. The facility has also been subject to a number of past or current governmental enforcement actions, consent agreements, orders, and lawsuits, including, as examples, actions concerning the closure of the phosphogypsum stacks at the facility, the release of process and wastewater, hydrogen fluoride emissions, emissions of oxides of sulfur, releases of ammonia and other hazardous substances, various alleged Clean Water Act violations, the potential for off-site contamination, and other matters. In the future, we may be required to expend significant funds to attain or maintain compliance with environmental laws. For example, the facility may not comply with wastewater and stormwater discharge requirements and solid and hazardous waste requirements. Following closure of phosphogypsum stack 1 at the facility, we may need to upgrade the facility’s wastewater system and arrange for offsite disposal of wastes that are currently disposed of onsite, and the costs to design, construct, and operate such a system could be material. Regulatory findings of noncompliance could trigger sanctions, including monetary penalties, require installation of control or other equipment or other modifications, adverse permit modifications, the forced curtailment or termination of operations or other adverse impacts.

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The costs we may incur in connection with the matters described above could be material. Subject to the terms and conditions of the 1998 APA and the Purchase Agreement, we are entitled to indemnification from ExxonMobil or the Seller for certain losses relating to environmental matters relating to the facility and arising out of conditions present prior to our acquisition of the facility. However, our rights to indemnification under these agreements are subject to important limitations, and we cannot assure you we will be able to obtain payment from ExxonMobil or the Seller on a timely basis, or at all. Depending on the amount of the costs we may incur for such matters in a given period, this could have a material adverse effect on the results of our business, cash flow and ability to make cash distributions to our unitholders.

Due to our lack of diversification, adverse developments in the nitrogen fertilizer industry or at either of our facilities could adversely affect our results of operations and our ability to make distributions to our unitholders.

We rely exclusively on the revenues generated from our two facilities. An adverse development in the market for nitrogen fertilizer products in our regions generally or at either of our facilities in particular would have a significantly greater impact on our operations and cash available for distribution to our unitholders than it would on other companies that are more diversified geographically or that have a more diverse asset and product base. The largest publicly traded companies with which we compete sell a more diverse range of fertilizer products to broader markets.

Any interruption in the supply of natural gas to our East Dubuque Facility through Nicor Inc. could have a material adverse effect on our results of operations, financial condition and our ability to make cash distributions.

Our East Dubuque operations depend on the availability of natural gas. We have an agreement with Nicor Inc. pursuant to which we access natural gas from the Northern Natural Gas Pipeline. Our access to satisfactory supplies of natural gas through Nicor Inc. could be disrupted due to a number of causes, including volume limitations under the agreement, pipeline malfunctions, service interruptions, mechanical failures or other reasons. The agreement extends for five consecutive periods of 12 months each, with the first period having commenced on November 1, 2010 and the last period ending October 31, 2015. For each period, Nicor Inc. may establish a bidding period during which we may match the best bid received by Nicor Inc. for the natural gas capacity provided under the agreement. We could be out-bid for any of the remaining periods under the agreement. In addition, upon expiration of the last period, we may be unable to renew the agreement on satisfactory terms, or at all. Any disruption in the supply of natural gas to our East Dubuque Facility could restrict our ability to continue to make products at the facility. In the event we needed to obtain natural gas from another source, we would need to build a new connection from that source to our East Dubuque Facility and negotiate related easement rights, which would be costly, disruptive and/or unfeasible. As a result, any interruption in the supply of natural gas through Nicor Inc. could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Our facilities face operating hazards and interruptions, including unplanned maintenance or shutdowns. We could face potentially significant costs 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 are subject to significant operating hazards and interruptions. Any significant curtailing of production at one of our facilities or individual units within one of our facilities could result in materially lower levels of revenues and cash flow for the duration of any shutdown and materially adversely impact our ability to make cash distributions to our unitholders. Operations at our facilities 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:

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

• labor difficulties that result in a work stoppage or slowdown;

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

• increasingly stringent environmental and emission regulations;

• a disruption in the supply of natural gas to our East Dubuque Facility or ammonia and sulfur to our Pasadena Facility; and

• a governmental ban or other limitation on the use of fertilizer products, either generally or specifically those manufactured at our facilities.

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The magnitude of the effect on us of any unplanned shutdown will depend on the length of the shutdown and the extent of the operations affected by the shutdown.

Our East Dubuque Facility and Pasadena Facility also require a planned maintenance turnaround every two years. Turnarounds at our East Dubuque Facility generally last between 18 and 25 days, and turnarounds at our Pasadena Facility generally last between 14 and 25 days. We intend to alternate the year in which a turnaround occurs at each facility, so that both facilities do not experience a turnaround in the same year. Upon completion of a facility turnaround, we may face delays and difficulties restarting production at our facilities. For example, in October 2009, our ammonia facility at our East Dubuque Facility underwent a 15-day maintenance turnaround and a subsequent 15-day unplanned shutdown due to equipment failures. The duration of our turnarounds or other shutdowns, and the impact they have on our operations, could materially adversely affect our cash flow and ability to make cash distributions in the quarter or quarters in which the turnarounds occur.

A major accident, fire, explosion, flood, severe weather event, terrorist attack or other event also could damage our facilities or the environment and the surrounding communities or result in injuries or loss of life. Scheduled and unplanned maintenance could reduce our cash flow and ability to make cash distributions to our unitholders during or for the period of time that any portion of our facilities are not operating. Any unplanned future shutdowns could have a material adverse effect on our ability to make cash distributions to our unitholders.

If we experience significant property damage, business interruption, environmental claims, fines, penalties 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 Rentech’s casualty, environmental, property and business interruption insurance policies. The policies are subject to limits, deductibles, and waiting periods and also contain exclusions and conditions that could have a material adverse impact on our ability to receive indemnification thereunder, as well as customary sub-limits for particular types of losses. For example, the current property policies contain specific sub-limits for losses resulting from business interruptions and for damage caused by covered flooding or named windstorms and resulting flooding or storm surge. We are fully exposed to all losses in excess of the applicable limits and sub-limits and for certain losses due to business interruptions.

Under the insurance policies that cover our Pasadena Facility, property exposures are subject to limits, deductibles and waiting periods with respect to insured physical damage and time element occurrences. Catastrophic perils such as named windstorms, floods and storm surges are subject to additional limitations that apply to each occurrence. The policies also contain exclusions and conditions that could have a material adverse impact on our ability to receive indemnification thereunder, as well as customary sub-limits for particular types of losses. For example the current property policy contains specific sub-limits for losses resulting from business interruption.

Market factors, including but not limited to catastrophic perils that impact our industry, significant changes in the investment returns of insurance companies, insurance company solvency trends and industry loss ratios and loss trends, can negatively impact the future cost and availability of insurance. There can be no assurance that we will be able to buy and maintain insurance with adequate limits, reasonable pricing terms and conditions or collect from insurance claims that we make.

There is no assurance that the transportation costs of our competitors will not decline. Any significant decline in our competitors’ transportation costs could have a material adverse effect on our results of operations, financial condition and our ability to make cash distributions.

Many of our competitors incur greater costs than we and our customers do in transporting their products over longer distances via rail, ships, barges and pipelines. There can be no assurance that our competitors’ transportation costs will not decline or that additional pipelines will not be built in the future, lowering the price at which our competitors can sell their products, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Our results of operations are highly dependent upon and fluctuate based upon business and economic conditions and governmental policies affecting the agricultural industry. These factors are outside of our control and may significantly affect our profitability.

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Our results of operations are highly dependent upon business and economic conditions and governmental policies affecting the agricultural industry, which we cannot control. The agricultural products business can be affected by a number of factors. The most important of these factors, for United States 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 United States exports and world-wide grain markets; and

• United States 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, which are also outside of our control, may also significantly influence our operating results. The international market for nitrogen fertilizers is influenced by such factors as the relative value of the United States 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.

Ammonia can be very volatile and extremely hazardous. Any liability for accidents involving 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 ammonia could increase significantly in the future.

We produce, process, store, handle, distribute and transport ammonia, which can be very volatile and extremely hazardous. Major accidents or releases involving 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. We periodically experience releases of ammonia related to leaks from our equipment or error in operation and use of equipment at our facilities. Similar events may occur in the future.

In some cases, we transport ammonia by railcar. We may incur significant losses or costs relating to the transportation of our products on railcars. Due to the dangerous and potentially toxic nature of the cargo on board railcars, a railcar 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 even if we complied with the laws and regulations in effect at the time of the accident. Litigation arising from accidents involving 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. Given the risks inherent in transporting ammonia, the costs of transporting ammonia could increase significantly in the future. A number of initiatives are underway in the railroad and chemical industries that may result in changes to railcar design in order to minimize railway accidents involving hazardous materials. If any such design changes are implemented, or if accidents involving hazardous freight increase the insurance and other costs of railcars, our transportation costs could increase significantly. In addition, we believe that railroads are taking other actions, such as requiring indemnification from their customers for liabilities relating to TIH chemicals, to shift the risks they face from shipping TIH chemicals to their customers, which may make transportation of ammonia by rail more costly or less feasible.

We are subject to risks and uncertainties related to transportation and equipment that are beyond our control and that may have a material adverse effect on our results of operations, financial condition and ability to make distributions.

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Although our customers and distributors generally pick up our products at our facilities, we occasionally rely on barge and railroad companies to ship products to our customers and distributors. The availability of these transportation services and related equipment is subject to various hazards, including extreme weather conditions, work stoppages, delays, spills, derailments and other accidents and other operating hazards. For example, barge transport can be impacted by lock closures resulting from inclement weather or surface conditions, including fog, rain, snow, wind, ice, strong currents, floods, droughts and other unplanned natural phenomena, lock malfunction, tow conditions and other conditions. Further, the limited number of towing companies and of barges available for ammonia transport may also impact the availability of transportation for our products. In addition, we believe that railroads are taking other actions, such as requiring indemnification from their customers for liabilities relating to TIH chemicals, to shift the risks they face from shipping TIH chemicals to their customers, which may make transportation of ammonia by rail more costly. These transportation services and equipment are also subject to environmental, safety and other regulatory oversight. Due to concerns related to terrorism or accidents, local, state and federal governments could implement new regulations affecting the transportation of our products. In addition, new regulations could be implemented affecting the equipment used to ship products from our facilities. Any delay in our ability to ship our products as a result of transportation companies’ failure to operate properly, the implementation of new and more stringent regulatory requirements affecting transportation operations or equipment, or significant increases in the cost of these services or equipment could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Our business is subject to extensive and frequently changing environmental laws and regulations. We expect that the cost of compliance with these laws and regulations will increase over time, and we could become subject to material environmental liabilities.

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 nitrogen fertilizer products. These laws include the CAA, the federal Clean Water Act, the Resource Conservation and Recovery Act, CERCLA, the Toxic Substances Control Act, and various other federal, state and local laws and regulations. Violations of these laws and regulations could 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 expenditures. Many of these laws and regulations are becoming increasingly stringent, and we expect the cost of compliance with these requirements to increase 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 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 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. 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.

Our business also is subject to accidental spills, discharges or other releases of hazardous substances into the environment. Past or future spills related to our facilities or transportation of products or hazardous substances from our facilities 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 our facilities, facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or byproducts 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. For a discussion of releases at the Pasadena Facility, see the risk factor captioned “Soil and groundwater at the Pasadena Facility is pervasively contaminated, and we may incur costs to investigate and remediate known or suspected contamination at the Pasadena Facility. We may also face legal actions or sanctions or incur costs related to contamination or noncompliance with environmental laws at the facility.” In addition, limited subsurface investigation indicates the presence of certain contamination at the East Dubuque facility. In the future, we may determine that there are conditions at the East Dubuque Facility that require remediation or other response.

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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We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.

We hold numerous environmental and other governmental permits and approvals authorizing operations at our facilities. Expansion of our operations is also predicated upon securing the necessary environmental or other permits or approvals. 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 and on our business, financial condition, results of operations and ability to make cash distributions.

Environmental laws and regulations on fertilizer end-use and application and numeric nutrient water quality criteria could have a material adverse impact on fertilizer demand in the future.

Future environmental laws and regulations on the end-use and application of fertilizers could cause changes in demand for our products. In addition, future 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 proposed bans or other limitations on fertilizer products. In addition, a number of states have adopted or proposed numeric nutrient water quality criteria that could result in decreased demand for our fertilizer products in those states. Similarly, a recent EPA rule establishing numeric nutrient criteria for certain Florida water bodies may require farmers to implement best management practices, including the reduction of fertilizer use, to reduce the impact of fertilizer on water quality. Any such laws, regulations or interpretations could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Climate change laws, regulations, and impacts 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 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 imminent 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 or impose a carbon fee.

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 facilities and began reporting 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 facilities, 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 permit requires a source to install the BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Greenhouse Gas Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Greenhouse Gas Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. The ongoing ammonia production and storage capacity expansion project at our East Dubuque Facility did not trigger the need to install BACT because actual construction was commenced prior to July 1, 2011 and is not considered a major modification with respect to criteria pollutants. However, a future major modification to our East Dubuque Facility or our Pasadena Facility may require us to install BACT and potentially require us to meet other requirements. The EPA’s endangerment finding, the Greenhouse Gas Tailoring Rule and certain other GHG emission rules have been challenged and will likely be subject to extensive litigation, although courts have rejected certain legal challenges to the endangerment findings, the Greenhouse Gas Tailoring Rule, and other regulations. In addition, a number of Congressional bills were introduced in 2010 and 2011 to overturn the endangerment finding and bar the EPA from regulating GHG emissions, or at least to defer such action by the EPA under the CAA, although President Obama has announced his intention to veto any such bills if passed.

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In addition to federal regulations, a number of states have adopted regional GHG initiatives to reduce CO₂ and other GHG emissions. In 2007, a group of Midwest states formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control GHG emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and it is uncertain if or when any such laws or regulations will be finalized in Illinois.

The implementation of additional EPA regulations and/or the passage of federal or state climate change legislation will likely increase the costs we incur 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 agricultural producers that utilize our fertilizer products, thereby potentially decreasing demand for our nitrogen fertilizer products. Decreased demand for our fertilizer products may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

Similarly, the impact of potential climate change on our operations and those of our customers is uncertain and could adversely affect us.

Agrium is a distributor and customer of a significant portion of our nitrogen fertilizer products, and we have the right to store products at Agrium’s terminal in Niota, Illinois. Any loss of Agrium as our distributor or customer, loss of our storage rights or decline in sales of products through or to Agrium could materially adversely affect our results of operations, financial condition and ability to make cash distributions.

We use Agrium as a distributor of a significant portion of our nitrogen fertilizer products of our East Dubuque Facility pursuant to a distribution agreement between Agrium and us. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, between 72% and 81% of our total product sales were made through Agrium. Under the distribution agreement, if we are unable to reach an agreement with Agrium for the purchase and sale of our products, Agrium is under no obligation to make such purchase and sale. Agrium sells products that compete with ours, and may be incentivized to prioritize the sale of its products over ours. In the event of any decline in sales of our products through Agrium as distributor, we may not be able to find buyers for our products.

The distribution agreement has a term that ends in April 2016, but automatically renews for subsequent one-year periods (unless either party delivers a termination notice to the other party at least three months prior to an automatic renewal). The distribution agreement may be terminated prior to its stated term for specified causes. Under the distribution agreement, Agrium bears the credit risk on products sold through Agrium pursuant to the agreement. Agrium also is largely responsible for marketing our products to customers and the associated expense. As a result, if our distribution agreement with Agrium terminates for any reason, Agrium would no longer bear the credit risk on the sale of any of our products and we would become responsible for all of the marketing costs for our products.

Under the distribution agreement, we have the right to store up to 15,000 tons of ammonia at Agrium’s terminal in Niota, Illinois, and we sell a portion of our ammonia at that terminal. Our right to store ammonia at the terminal expires on June 30, 2016, but automatically renews for successive one year periods, unless we deliver a termination notice to Agrium with respect to such storage rights at least three months prior to an automatic renewal. Our right to use the storage space immediately terminates if the distribution agreement terminates in accordance with its terms. Ammonia storage sites and terminals served by barge on the Mississippi River are controlled primarily by CF Industries, Koch and Agrium, each of which is one of our competitors. If we lose the right to store ammonia at the Niota, Illinois terminal, we may not be able to find suitable replacement storage on acceptable terms, or at all, and we may be forced to reduce production. We also may lose sales to customers that purchase products at the terminal.

In addition to distributing our products, Agrium is also one of our significant customers. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, approximately 2%, 1%, 3% and 7%, respectively, of our total product sales were to Agrium as a direct customer (rather than a distributor) and approximately 9%, 7%, 15% and 11%, respectively, of our total product sales were to CPS, a controlled affiliate of Agrium. Agrium or CPS could elect to reduce or cease purchasing our products for a number of reasons, especially if our relationship with Agrium as a distributor were to end. If our sales to Agrium as a direct customer or CPS decline, we may not be able to find other customers to purchase the excess supply of our products.

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Sales of our products through or to Agrium could decline or the distribution agreement or our rights to storage could terminate as a result of a number of causes which are outside of our control. Any loss of Agrium as our distributor or customer, loss of our storage rights or decline in sales of products through Agrium could materially adversely affect our results of operations, financial condition and ability to make cash distributions.

IOC is the exclusive distributor of our ammonium sulfate fertilizer. Any loss of IOC as our distributor could materially adversely affect our results of operations, financial condition and ability to make cash distributions.

We have an exclusive marketing agreement that grants IOC the exclusive right and obligation to market and sell all of our Pasadena Facility’s granular ammonium sulfate in certain specified jurisdictions. The marketing agreement has a term that ends in February 2014, but automatically renews for subsequent one-year periods (unless either party delivers a termination notice to the other party at least 180 days prior to an automatic renewal). The marketing agreement may be terminated prior to its stated term for specified causes. If we are unable to renew our contract with IOC, we may be unable to find buyers for our granular ammonium sulfate. In addition, we have an arrangement with IOC that permits us to store 32,000 tons of ammonium sulfate at IOC-controlled terminals, which are located near end customers of our Pasadena Facility’s ammonium sulfate. This arrangement currently is not governed by a written contract. If we lose the right to store ammonium sulfate at these IOC-controlled terminals, we may not be able to find suitable replacement storage on acceptable terms, or at all, and we may be forced to reduce production. Any loss of IOC as our distributor, loss of our storage rights or decline in sales of products through IOC could materially adversely affect our results of operations, financial condition and ability to make cash distributions.

Due to our dependence on significant customers, the loss of one or more of our significant customers could adversely affect our results of operations and our ability to make distributions to our unitholders.

Our business depends on significant customers, and the loss of one or several significant customers may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions to our unitholders. In the aggregate, our top five ammonia customers represented approximately 54%, 54%, 46% and 52%, respectively, of our ammonia sales for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, and our top five UAN customers represented approximately 38%, 53%, 50% and 60%, respectively, of our UAN sales for the same periods. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, approximately 2%, 1%, 3% and 7%, respectively, of our East Dubuque Facility’s total product sales were to Agrium as a direct customer (rather than a distributor) and approximately 9%, 7%, 15% and 11%, respectively, of our East Dubuque Facility’s total product sales were to CPS, a controlled affiliate of Agrium. During the period beginning November 1, 2012 through December 31, 2012, the marketing agreement with IOC accounted for 100% of our Pasadena Facility’s revenues from the sale of ammonium sulfate. Given the nature of our business, and consistent with industry practice, we generally do not have long-term minimum sales contracts with any of our customers. If our sales to any of our significant customers were to decline, we may not be able to find other customers to purchase the excess supply of our products. The loss of one or several of our significant customers, or a significant reduction in purchase volume by any of them, could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

The sale of our products to customers in international markets exposes us to additional risks that could harm our business, operating results, and financial condition.

Our Pasadena Facility’s products are sold through distributors to customers in the U.S. and in Brazil, New Zealand and Thailand, and our distributors could expand sales to additional international markets in the future. In addition to risks described elsewhere in this section, the sale of our products in international markets expose us to other risks, including the following:

• changes in local political, economic, social and labor conditions, which may adversely harm our business;

• import and export requirements, tariffs, trade disputes and barriers, and customs classifications that may prevent our distributors from offering our products to a particular market;

• longer payment cycles in some countries, increased credit risk, and higher levels of payment fraud;

• still developing foreign laws and legal systems;

• uncertainty regarding liability for products, including uncertainty as a result of local laws and lack of legal precedent;

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• different employee/employer relationships, existence of workers’ councils and labor unions and other challenges caused by distance, language, and cultural differences, making it harder to do business in certain jurisdictions; and

• natural disasters, military or political conflicts, including war and other hostilities and public health issues and outbreaks.

In addition, our distributors must comply with complex foreign and U.S. laws and regulations that apply to international sales and operations. These numerous and sometimes conflicting laws and regulations include internal control and disclosure rules, anti-corruption laws, such as the Foreign Corrupt Practices Act, and other local laws prohibiting corrupt payments to governmental officials, and antitrust and competition regulations, among others. Violations of these laws and regulations could result in fines and penalties, criminal sanctions against our distributors, prohibitions on the conduct of their business and on our ability to offer our products in one or more countries, and could also materially affect our brand, our ability to attract and retain employees, our business and our operating results. Although we have implemented policies and procedures designed to ensure our distributors’ compliance with these laws and regulations, there can be no assurance that our distributors will not violate our policies.

We are largely dependent on our customers and distributors to transport purchased goods from our facilities because we do not maintain a fleet of trucks or rail cars.

We do not maintain a fleet of trucks and, unlike some of our major competitors, we do not maintain a fleet of rail cars. Our customers and distributors generally are located close to our facilities and have been willing and able to transport purchased goods from each facility. In most instances, customers and distributors purchase products FOB delivered basis at the facility and then arrange and pay to transport them to their final destinations by truck. However, in the future, the transportation needs of our customers and distributors as well as their preferences may change, and those customers and distributors may no longer be willing or able to transport purchased goods from our facilities. In the event that our competitors are able to transport their products more efficiently or cost effectively than our customers and distributors, those customers and distributors may reduce or cease purchases of our products. If this were to occur, we could be forced to make a substantial investment in a fleet of trucks and/or rail cars to meet the delivery needs of customers and distributors, 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 business, cash flow and ability to make 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 facilities may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions to our unitholders. 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 facility locations and the transportation of hazardous chemicals. Our business could be materially adversely affected by the cost of complying with new regulations.

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

We are subject to a number of federal and state laws and regulations related to safety, including OSHA and comparable state statutes, the purpose of which are to protect 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 and other related state regulations, 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 penalties, fines or compliance costs.

Failure to prevent accidents at our facilities and to ensure the effectiveness of our safety procedures could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.

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We engage in industrial activities, including use of hazardous chemicals that can result in serious accidents. If our safety procedures are not effective, or if an accident occurs, we could be subject to liabilities arising out of personal injuries or death, our operations could be interrupted and we might have to shut down or abandon affected facilities. Accidents could cause us to expend significant amounts to remediate safety issues or to repair damaged facilities.

Our acquisition strategy involves significant risks.

One of our business strategies is to pursue acquisitions. However, acquisitions involve numerous risks and uncertainties, including intense competition for suitable acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions, difficulties in identifying suitable acquisition targets or in completing any transactions identified on sufficiently favorable terms; and the need to obtain regulatory or other governmental approvals that may be necessary to complete acquisitions. In addition, any future acquisitions may entail significant transaction costs, tax consequences and risks associated with entry into new markets and lines of business.

In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:

• unforeseen difficulties in the acquired operations and disruption of the ongoing operations of our business;

• failure to achieve cost savings or other financial or operating objectives with respect to an acquisition;

• strain on the operational and managerial controls and procedures of our business, and the need to modify systems or to add management resources;

• difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;

• assumption of unknown material liabilities or regulatory non-compliance issues;

• amortization of acquired assets, which would reduce future reported earnings;

• possible adverse short-term effects on our cash flows or operating results; and

• diversion of management’s attention from the ongoing operations of our business.

In addition, in connection with any potential acquisition, we will need to consider whether the business we intend to acquire could affect our tax treatment as a partnership for United States federal income tax purposes.

Failure to manage acquisition growth risks could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. There can be no assurance that we will be able to consummate any acquisitions, successfully integrate acquired entities, or generate positive cash flow at any acquired company.

Failure to comply with Section 404 of the Sarbanes-Oxley Act of 2002, or Section 404, including a delay in or failure to successfully integrate acquisitions into our internal control over financial reporting, or the report by us of a material weakness, may cause vendors, creditors and others to lose confidence in our consolidated financial statements, and our access to the capital markets and other products and services may be restricted. Compliance with Section 404 is time consuming and costly. The integration of acquisitions into our internal control over financial reporting will require additional time and resources from our management and other personnel and will increase compliance costs.

There are significant risks associated with expansion and other projects that may prevent completion of those projects on budget, on schedule or at all.

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We have commenced expansion projects at our East Dubuque Facility and our Pasadena Facility. Projects of the scope and scale we are undertaking or may undertake in the future entail significant risks, including:

• unanticipated cost increases;

• unforeseen engineering or environmental problems;

• work stoppages;

• weather interference;

• unavailability of necessary equipment; and

• unavailability of financing on acceptable terms.

Construction, equipment or staffing problems or difficulties in obtaining any of the requisite licenses, permits and authorizations from regulatory authorities could increase the total cost, delay or prevent the construction or completion of a project.

In addition, we cannot assure you that we will have adequate sources of funding to undertake or complete major projects. As a result, we may need to obtain additional debt and/or equity financing to complete such projects. There is no guarantee that we will be able to obtain other debt or equity financing on acceptable terms or at all. Moreover, if we are able to complete these projects, production levels at our facilities may not meet expectations that we have set.

As a result of these factors, we cannot assure you that our projects will commence operations on schedule or at all, that the costs for the projects will not exceed budgeted amounts or that production levels will achieve the expectations that we have set. Failure to complete a project on budget, on schedule or at all or to achieve expected production levels may adversely impact our ability to grow our business.

Expansion of our production capacity may change the balance of supply and demand in our markets, and our new products may not achieve market acceptance.

As part of our current expansion projects at the East Dubuque Facility, we expect to increase our capacity to produce ammonia and urea and to install the equipment necessary to enable us to produce and sell DEF. Increased production of our existing products may reduce the overall demand for those products as a result of market saturation. We may be required to sell these products at lower prices, or may not be able to sell all of the products we produce. In addition, there can be no assurance that our new products will be well-received or that we will achieve revenues or profitability levels we expect. If we cannot sell our products or are forced to reduce the prices at which we sell them, this would have a material adverse effect on our results of operations, financial condition and the ability to make cash distributions to our unitholders.

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

We depend on the services of the executive officers of our general partner. The loss of the services of any member of our executive officer team could have an adverse effect on our business and reduce our ability to make cash distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if our existing senior management’s or key employees’ services become unavailable.

Certain members of our executive management team on whom we rely to manage important aspects of our business face conflicts regarding the allocation of their time.

We rely on the executive officers and employees of our general partner to manage our operations and activities. Certain of these executive officers and employees of our general partner perform services for Rentech in addition to us. These shared executive officers and employees include our chief executive officer, chief financial officer, president and general counsel. Because the shared officers and employees allocate time among us and Rentech, they may face conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

A shortage of skilled labor, together with rising labor costs, could adversely affect our results of operations and cash available for distribution to our unitholders.

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Efficient production of nitrogen fertilizer using modern techniques and equipment requires skilled employees. To the extent that the services of skilled labor becomes unavailable to us for any reason, including as a result of the expiration and non-renewal of our collective bargaining agreement or the retirement of experienced employees from our aging work force, we would be required to hire other personnel. We have a collective bargaining agreement in place covering unionized employees at our East Dubuque Facility which will expire in October 2016. In addition, we have two collective bargaining agreements for our Pasadena Facility. One of these agreements will expire on March 28, 2013, and the other covers nine employees and will expire on April 30, 2013. Upon expiration, we may be unable to renew the collective bargaining agreements on satisfactory terms or at all. We face hiring competition from our competitors, our customers and other companies operating in our industry, and we may not be able to locate or employ qualified replacements on acceptable terms or at all. If our current skilled employees quit, retire or otherwise cease to be employed by us and we are unable to locate or hire qualified replacements, or if the cost to locate and hire qualified replacements for these employees increases materially, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Our new 2012 credit agreement contains significant limitations on our business operations, including our ability to make distributions and other payments.

We have entered into the new 2012 credit agreement, comprised of a $155.0 million term loan, or the new term loan, a $110.0 million new capex facility and a $35.0 million revolving working capital facility, or the new 2012 revolving credit facility. Our new 2012 credit agreement permits us to incur significant indebtedness in the future, subject to the satisfaction of its conditions to borrowing. Our ability to make cash distributions to our unitholders and our ability to borrow under our new 2012 credit agreement to fund distributions (if we elected to do so) are subject to covenant restrictions under the agreements governing our new 2012 credit agreement. If we were unable to comply with any such covenant restrictions in any quarter, our ability to make cash distributions to our unitholders would be curtailed.

In addition, we are subject to covenants contained in our new 2012 credit agreement and may be subject to additional agreements governing other future indebtedness. These covenants restrict our ability to, among other things, incur, assume or permit to exist additional indebtedness, guarantees and other contingent obligations, incur liens, make negative pledges, pay dividends or make other distributions, make payments to our subsidiaries, make certain loans and investments, consolidate, merge or sell all or substantially all of our assets, enter into sale-leaseback transactions and enter into transactions with our affiliates. Any failure to comply with these covenants could result in a default under our new 2012 credit agreement. Upon a default, unless waived, the lenders under our new 2012 credit agreement 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 our assets, and force us into bankruptcy or liquidation.

We are a holding company and depend upon our subsidiaries for our cash flow.

We are a holding company. All of our operations are conducted and most of our assets are owned by our operating companies, which are our wholly owned subsidiaries, and we intend to continue to conduct our operations at the operating companies and any of our future subsidiaries. Consequently, our cash flow and our ability to meet our obligations or to make cash distributions depend upon the cash flow of our operating companies and any of our future subsidiaries and the payment of funds by our operating companies and any of our future subsidiaries to us in the form of dividends or otherwise. The ability of our operating companies and any of our future subsidiaries to make any payments to us depend on their earnings, the terms of their indebtedness, including the terms of any credit facilities and legal restrictions. In particular, our new 2012 credit agreement imposes, and future credit facilities entered into by our operating companies or any of our future subsidiaries may impose, significant limitations on the ability of our subsidiaries to make distributions to us and consequently our ability to make distributions to our unitholders.

Our relationship with Rentech and its business, results of operations, financial condition and prospects subjects us to potential risks that are beyond our control.

Due to our relationship with Rentech, adverse developments or announcements concerning Rentech, its business, results of operations, financial condition or prospects could materially adversely affect our financial condition, even if we have not suffered any similar development. In addition, the credit and business risk profiles of Rentech may be factors considered in credit evaluations of us. Another factor that may be considered is the financial condition of Rentech, including the degree of its dependence on cash flow from us to further its business strategy and continue its operations. In February 2013, Rentech announced plans to cease operations at, reduce staffing at, and to mothball its product demonstration unit, and to eliminate all related research and development activities related to its technologies. Rentech has a history of operating losses and has never operated at a profit. If Rentech does not achieve significant amounts of revenues and operate at a profit on an ongoing basis in the future, Rentech may be unable to continue its operations at its current level. Ultimately, Rentech’s ability to remain in business will depend upon earning a profit from our nitrogen fertilizer business and/or any new line of business Rentech enters into. The credit and risk profile of Rentech could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital. Furthermore, financial constraints at Rentech may cause Rentech to make business decisions, including decisions to liquidate the common units that it holds in us or its interest in our general partner, which may adversely affect our business and the market price of our common units.

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Risks Related to an Investment in Us

We intend to distribute all of the cash available for distribution we generate each quarter, which could limit our ability to grow and make acquisitions.

Our policy is to distribute all of the cash available for distribution we generate each quarter to our unitholders. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. As a result, our general partner will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities by us, to fund our expansion capital expenditures, and accordingly, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we intend to distribute all of the cash available for distribution that we generate each quarter, our growth may not be as fast as that of businesses that reinvest their cash available for distribution to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the cash available for distribution that we have to distribute to our unitholders.

The board of directors and officers of our general partner have fiduciary duties to Rentech, and the interests of Rentech may differ significantly from, or conflict with, the interests of our public common unitholders.

Our general partner is responsible for managing us. Although our general partner has fiduciary duties to manage us in a manner that is in, or not opposed to, our best interests, the fiduciary duties are specifically limited by the express terms of our partnership agreement, and the directors and officers of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to Rentech and its shareholders. The interests of Rentech and its shareholders may differ from, or conflict with, the interests of our common unitholders. In resolving these conflicts, our general partner may favor its own interests or the interests of holders of Rentech’s common stock over our interests and those of our common unitholders.

The potential conflicts of interest include, among others, the following:

• Neither our partnership agreement nor any other agreement requires the owners of our general partner to pursue a business strategy that favors us. The affiliates of our general partner have fiduciary duties to make decisions in their own best interests and in the best interest of holders of Rentech’s common stock, which may be contrary to our interests. In addition, our general partner is allowed to take into account the interests of parties other than us or our unitholders in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

• Our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

• The board of directors of our general partner will determine the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness and issuances of additional partner interests, each of which can affect the amount of cash that is available for distribution to our common unitholders.

• 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. There is no limitation on the amounts our general partner can cause us to pay it or its affiliates.

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• Our general partner may exercise its rights to call and purchase all of our common units if at any time it and its affiliates own more than 80% of our common units.

• Our general partner controls the enforcement of obligations owed to us by it and its affiliates. In addition, our general partner determines whether to retain separate counsel or others to perform services for us.

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

• Certain of the executive officers of our general partner, and the majority of the directors of our general partner, also serve as directors and/or executive officers of Rentech. The executive officers who work for both Rentech and our general partner, including our chief executive officer, chief financial officer, president and general counsel, divide their time between our business and the business of Rentech. These executive officers will face conflicts of interest from time to time in making decisions which may benefit either us or Rentech.

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner and restricts the remedies available to us and our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our common unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. By purchasing common units, common unitholders consent to some actions that might otherwise constitute a breach of fiduciary or other duties applicable under state law. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example:

• Our partnership agreement provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it subjectively believed that the decisions were in, or not opposed to, our best interests.

• Our partnership agreement provides that the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our general partner. The owners of our general partner are permitted to engage in separate businesses which directly compete with us and are not required to share or communicate or offer any potential business opportunities to us even if the opportunity is one that we might reasonably have pursued. The partnership agreement provides that the owners of our general partner will not be liable to us or any unitholder for breach of any duty or obligation by reason of the fact that such person pursued or acquired for itself any business opportunity.

• Our partnership agreement provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to us for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.

• Our partnership agreement generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable.” In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationship between the parties involved, including other transactions that may be particularly advantageous or beneficial to us.

• Our partnership agreement provides that in resolving conflicts of interest, it will be conclusively deemed that in making its decision, the conflicts committee acted in good faith.

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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Our partnership agreement permits our general partner to make a number of decisions in its individual capacity or in its sole discretion and, as such, our general partner has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our common unitholders in making these decisions.

Our partnership agreement contains provisions that permit our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as our general partner, or in its sole discretion. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our common unitholders. Decisions made by our general partner in its individual capacity or in its sole discretion will be made by RNHI as the sole member of our general partner, and not by the board of directors of our general partner. Examples include the exercise of the general partner’s call right, its voting rights with respect to any common units it may own, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment to our partnership agreement. In effect, the standards to which our general partner would otherwise be held by state fiduciary duty law are reduced. By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

RNHI has the power to appoint and remove our general partner’s directors.

RNHI has the power to appoint and remove all of the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. Our public unitholders do not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Furthermore, the goals and objectives of Rentech, as the indirect owner of our general partner, may not be consistent with those of our public unitholders.

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

If at any time our general partner and its affiliates own more than 80% of our 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 purchase 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. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your 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 call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and then exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right.

Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner’s directors.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Rentech as the indirect owner of the general partner and not by our common unitholders. Unlike publicly traded corporations, we will not hold annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of shareholders. Furthermore, even if our unitholders are dissatisfied with the performance of our general partner, they will have no practical ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished.

Our public unitholders will not have sufficient voting power to remove our general partner without Rentech’s consent.

Rentech indirectly owns 59.9% of our common units. Our general partner may be removed by a vote of the holders of at least 66 2/3% of our outstanding common units, including any common units held by our general partner and its affiliates (including Rentech), voting together as a single class. As a result, public holders of our common units are not able to remove the general partner, under any circumstances, unless Rentech sells some of the common units that it owns or we sell additional units to the public.

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

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

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to you.

Prior to making any distribution on our outstanding units, we will reimburse our general partner for all expenses it incurs on our behalf including, without limitation, our pro rata portion of management compensation and overhead charged by Rentech in accordance with our services agreement. The services agreement does not contain any cap on the amount we may be required to pay pursuant to this agreement. The payment of these amounts, including allocated overhead, to our general partner and its affiliates could adversely affect our ability to make distributions to you.

Limited partners may not have limited liability if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the Partnership, except for those contractual obligations of the Partnership that are expressly made without recourse to the general partner. Our Partnership is organized under Delaware law and our operating companies conduct business in Illinois and Texas. Limited partners could be liable for our obligations as if such limited partners were general partners if a court or government agency determined that:

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

• limited partners’ right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.

Unitholders may have liability to repay distributions.

In the event that: (i) 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 (ii) 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 Act.

Likewise, upon the winding up of the Partnership, in the event that (a) we do not distribute assets in the following order: (i) to creditors in satisfaction of their liabilities; (ii) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (iii) to partners for the return of their contribution; and (iv) to the partners in the proportions in which the partners share in distributions, and (b) a unitholder knows at the time of the distribution 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 17-804 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 the Partnership 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 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 his nationality, citizenship or related status. If a limited partner fails to furnish information about his 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 his 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.

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Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us under certain laws or regulations that may be applicable to our future business or operations, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement gives our general partner the power to amend the partnership agreement. If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the common units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.

Our general partner’s interest in us and 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 in us 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 RNHI to transfer its equity interest in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and the officers of our general partner with its own choices and to influence the decisions taken by the board of directors and officers of our general partner.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.

We cannot predict how interest rates will react to changing market conditions. Interest rates on our new 2012 credit agreement and future credit facilities and debt securities could be higher than current levels, causing our financing costs to increase accordingly. Additionally, as with other yield-oriented securities, we expect that our unit price will be impacted by the level of our quarterly cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have a material adverse impact on our unit price and our ability to issue additional equity to make acquisitions or to incur debt as well as increasing our interest costs.

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

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

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

• the amount of cash distributions on each unit will decrease;

• the ratio of our taxable income to distributions may increase;

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

• the market price of the common units may decline.

In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

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The level of indebtedness we could incur in the future could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations.

On October 31, 2012, RNLLC, the Partnership, RNPLLC and certain subsidiaries of RNPLLC entered into the new 2012 credit agreement. The new 2012 credit agreement has a five-year maturity and is comprised of the $155.0 million term loan, the $110.0 million new capex facility and the $35.0 million new 2012 revolving credit facility. The level of indebtedness we could incur in the future could have important consequences, including:

• increasing our vulnerability to general economic and industry conditions;

• requiring all or a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore restricting or reducing our ability to use our cash flow to make distributions or to fund our operations, capital expenditures and future business opportunities;

• limiting our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;

• incurring higher interest expense in the event of increases in our new 2012 credit agreement’s variable interest rates;

• limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who have greater capital resources;

• limiting our ability to make investments, dispose of assets, pay cash distributions or repurchase common units; and

• subjecting us to financial and other restrictive covenants in our indebtedness, which may restrict our activities, and the failure to comply with which could result in an event of default.

Our ability to make scheduled debt payments, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of our operating assets and properties, as well as to provide capacity for the growth of our business, depends on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors.

If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce distributions, reduce or delay capital expenditures, acquisitions, investments or other business activities, sell assets, seek additional capital or restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Failure to pay our indebtedness on time would constitute an event of default under the agreements governing our indebtedness, which would give rise to our lenders’ ability to accelerate the obligations and seek other remedies against us.

Tax Risks

Our tax treatment depends on our status as a partnership for United States federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for United States federal income tax purposes or if we were to become subject to additional amounts of entity-level taxation for state tax purposes, 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 United States federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS regarding our classification as a partnership.

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 United States federal income tax purposes. A change in our current business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.

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If we were treated as a corporation for United States federal income tax purposes, we would pay United States federal income tax on our taxable income at the applicable corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to our unitholders. Moreover, if we were to be treated as a corporation for United States federal income tax purposes, there would be a material reduction in the anticipated cash flow and after tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

In addition, changes in current state laws 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 or other forms of taxation. If any such entity-level taxes were imposed, our cash available for distribution to our unitholders would be substantially reduced.

The tax treatment of publicly traded limited 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 United States federal income tax treatment of publicly traded limited partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time, including on a retroactive basis. For example, from time to time, members of Congress propose and consider substantive changes to the existing United States federal income tax laws that affect publicly traded limited partnerships. We are unable to predict whether any such changes will ultimately be enacted or, if enacted, whether they will apply to us. Any such changes could cause a substantial reduction in the value of our common units.

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

We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for United States federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. 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.

Unitholders’ share of our income will be taxable for United States federal income tax purposes even if they do not receive any cash distributions from us.

Because we expect to be treated as a partnership for United States federal income tax purposes, our unitholders will be treated as partners 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 United States 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. 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 United States 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 our unitholders sell will, in effect, become taxable income to our unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale of a unitholder’s common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell common units, they may incur a tax liability in excess of the amount of cash the unitholders receive from the sale.

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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 United States 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, generally at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal and state income tax returns and pay United States federal and state tax on their share of our taxable income. Unitholders that are tax-exempt entities or non-U.S. persons should consult their tax advisors before investing in our common units.

We will treat each purchaser of our 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.

Due to our inability to match transferors and transferees of common units and for other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations promulgated under the Internal Revenue Code, referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could cause a substantial reduction in the value of our common units or result in audit adjustments to our unitholders’ tax returns.

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

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed Treasury Regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued requiring a change, we may 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, the unitholder would no longer be treated for United States 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 United States 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 advised to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination of the Partnership for United States federal income tax purposes.

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We will be considered to have technically terminated the Partnership for United States federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same common unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership for United States federal income tax purposes, but instead, we would be treated as a new partnership for such tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a publicly traded limited partnership relief procedure whereby a publicly traded limited partnership that has technically terminated may request special relief that, if granted, would, among other things, permit the Partnership to provide only a single Schedule K-1 to unitholders for the tax year notwithstanding two partnership tax years.

Unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to United States federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or control property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in the State of Illinois and the State of Texas, and the State of Illinois currently imposes a personal income tax on individuals. The State of Illinois also imposes an income tax on corporations and other entities. The State of Texas imposes a franchise tax on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states that impose a personal income tax. It is the responsibility of each unitholder to file all United States federal, state, local and non-U.S. tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 2. PROPERTIES

The information required to be disclosed in this Item 2 is incorporated herein by reference to Part I—Item 1 “Business.”

ITEM 3. LEGAL PROCEEDINGS

We are party to litigation from time to time in the normal course of business. We maintain insurance to cover certain actions and believe that resolution of our current litigation matters will not have a material adverse effect on us.

The TCEQ issued notices of violation of environmental laws relating to alleged unlawful emissions in June 2012 and August 2012 of oxides of sulfur in excess of permitted limits from the sulfuric acid plant at our Pasadena Facility. Based on information provided to the agency, we received a notice of compliance from the TCEQ relating to the June 2012 release stating no further action on our part is required. With respect to the August 2012 release, negotiations with the TCEQ are ongoing, but the settlement order currently proposed by the agency contains a penalty of less than $6,000.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF COMMON UNITS

Our common units began trading on the New York Stock Exchange, or the NYSE, under the symbol “RNF” on November 4, 2011. The following table sets forth the range of high and low closing prices for our common units as reported by the NYSE for each quarterly period during the calendar year ended December 31, 2012 and the period November 4, 2011 through December 31, 2011:

Year Ended December 31, 2012	High		Low
First Quarter, ended March 31, 2012	$	27.74	$	17.09
Second Quarter, ended June 30, 2012	$	29.47	$	21.45
Third Quarter, ended September 30, 2012	$	39.46	$	27.36
Fourth Quarter, ended December 31, 2012	$	40.00	$	34.80
Year Ended December 31, 2011	High		Low
November 4, 2011 through December 31, 2011	$	20.47	$	16.22

The approximate number of unitholders of record as of February 28, 2013 was 38. Based upon the securities position listings maintained for our common units by registered clearing agencies, we estimate the number of beneficial owners is not less than 28,100.

Our policy is to distribute all of the cash available for distribution which we generate each quarter to our unitholders. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of each quarter. We expect that cash available for distribution for each quarter will generally equal the cash flow we generate during the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Any distributions made to our unitholders will be done on a pro rata basis. We may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. We intend to pay our distributions on or about the 15th day of each February, May, August and November to holders of record on or about the 1st day of each such month.

The new 2012 credit agreement provides that dividends and distributions from us and our operating companies are permitted so long as (i) no default or event of default has occurred, exists or will result therefrom and (ii) our operating companies certify pro forma compliance with the terms of the new 2012 credit agreement, including its financial covenants, as of the date of such dividend or distribution, to the administrative agent under the new 2012 credit agreement.

On May 15, 2012, we made a cash distribution to our common unitholders and payments to holders of phantom units for the period November 9, 2011 through and including March 31, 2012 of $1.06 per unit, or approximately $40.7 million in the aggregate. On August 14, 2012, we made a cash distribution to our common unitholders and payments to holders of phantom units for the period April 1, 2012 through and including June 30, 2012 of $1.17 per unit, or approximately $45.0 million in the aggregate. On November 14, 2012, we made a cash distribution to our common unitholders and payments to holders of phantom units for the period July 1, 2012 through and including September 30, 2012 of $0.85 per unit, or approximately $33.1 million in the aggregate. On February 14, 2013, we made a cash distribution to our common unitholders and payments to holders of phantom units for the period October 1, 2012 through and including December 31, 2012 of $0.75 per unit, or approximately $29.2 million in the aggregate.

Equity Compensation Plan Information

See Part III—Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

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Recent Sales of Unregistered Securities

On November 1, 2012, in connection with the Agrifos Acquisition, we issued 538,793 common units and a supplemental unit representing limited partner interests in the Partnership to Seller as a portion of the purchase price for Seller’s member interest in Agrifos. The supplemental unit is convertible into or redeemable for the earn-out consideration, which may not exceed $50.0 million, to be paid under the Purchase Agreement for the Agrifos Acquisition, if any. We issued the common units and supplemental unit in reliance upon the exemption from registration under Section 4(a)(2) under the Securities Act of 1933, as amended, and Rule 506 of Regulation D promulgated thereunder. See Part I—Item 1 “Business—The Agrifos Acquisition.”

Purchases of Equity Securities by the Issuer

We did not repurchase any of our common units during the year ended December 31, 2012, and we do not have any announced or existing plans to repurchase any of our common units.

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ITEM 6. SELECTED FINANCIAL DATA

The following tables include selected summary financial data for the calendar years ended December 31, 2012 and 2011, the three months ended December 31, 2011 and 2010 and each of the four fiscal years ended September 30, 2011, 2010, 2009 and 2008. The operations of the Pasadena Facility are included effective November 1, 2012. The data below should be read in conjunction with Part II—Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part II—Item 8 “Financial Statements and Supplementary Data.”

	Calendar Years Ended December 31,						Three Months Ended December 31,						Fiscal Years Ended September 30,
	2012			2011			2011			2010			2011			2010			2009			2008
				(unaudited)						(unaudited)
	(in thousands, except per unit data, product pricing, $ per MMBtu, $ per  ton and on-stream factors)
STATEMENTS OF INCOME DATA
Revenues	$	261,635		$	199,909		$	63,014		$	42,962		$	179,857		$	131,396		$	186,449		$	216,615
Cost of sales	$	129,796		$	113,911		$	37,460		$	26,835		$	103,286		$	106,020		$	125,888		$	160,633
Gross profit	$	131,839		$	85,998		$	25,554		$	16,127		$	76,571		$	25,376		$	60,561		$	55,982
Operating income	$	111,563		$	77,918		$	22,648		$	14,584		$	69,854		$	20,389		$	55,313		$	51,752
Other income (expenses), net	$	(4,257	)	$	(32,218	)	$	(12,193	)	$	(7,488	)	$	(27,513	)	$	(12,036	)	$	(8,578	)	$	(1,779	)
Income before income taxes	$	107,306		$	45,700		$	10,455		$	7,096		$	42,341		$	8,353		$	46,735		$	49,973
Income tax expense	$	303		$	14,643		$	—		$	2,772		$	17,415		$	3,344		$	18,576		$	19,875
Net income	$	107,003		$	31,057		$	10,455		$	4,324		$	24,926		$	5,009		$	28,159		$	30,098
Net income subsequent to initial public offering (November 9, 2011 through December 31, 2011)				$	11,331		$	11,331
Net income per common unit—Basic	$	2.78		$	0.30		$	0.30
Net income per common unit—Diluted	$	2.78		$	0.30		$	0.30
Weighted-average units used to compute net income per common unit:
Basic		38,350			38,250			38,250
Diluted		38,352			38,255			38,255
FINANCIAL AND OTHER DATA
Net cash flow provided by (used in):
Operating activities	$	132,546		$	53,973		$	(5,979	)	$	23,717		$	83,668		$	20,144		$	23,867		$	61,962
Investing activities	$	(186,825	)	$	(26,740	)	$	(11,566	)	$	(2,212	)	$	(17,386	)	$	(11,583	)	$	(12,259	)	$	(8,260	)
Financing activities	$	65,242		$	(19,018	)	$	11,009		$	(19,818	)	$	(49,844	)	$	(10,288	)	$	(31,215	)	$	(24,814	)
EBITDA(1)	$	124,023		$	88,624		$	25,935		$	17,189		$	79,878		$	30,967		$	63,709		$	60,381
Cash available for distribution per common unit(1)	$	3.30		$	0.53		$	0.53

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KEY OPERATING DATA
Products sold (tons):
Ammonia		149			135			55			44			125			153			126			173
UAN		291			301			65			79			315			294			267			313
Ammonium sulfate		115
Products pricing (dollars per ton):
Ammonia	$	669		$	652		$	684		$	512		$	588		$	377		$	726		$	539
UAN	$	326		$	297		$	307		$	193		$	269		$	180		$	267		$	308
Ammonium sulfate	$	300
Production (tons):
Ammonia		293			261			63			75			273			267			267			299
UAN		301			294			68			86			312			287			274			311
Ammonium sulfate		88
Natural gas used in production(2):
Volume (MMBtu)		10,644			9,789			2,299			2,813			10,303			9,923			10,133			11,086
Pricing ($ per MMBtu)	$	3.55		$	4.74		$	4.71		$	4.82		$	4.76		$	4.95		$	5.67		$	9.34
Natural gas in cost of sales(2):
Volume (MMBtu)		11,166			10,893			3,414			3,056			10,275			11,757			10,210			11,408
Pricing ($ per MMBtu)	$	3.59		$	4.76		$	4.75		$	4.38		$	4.66		$	4.79		$	9.19		$	8.98
Ammonia purchased, used in production(3):
Volume (tons)		23
Pricing ($ per ton)	$	653
Ammonia purchased, in cost of sales(3):
Volume (tons)		23
Pricing ($ per ton)	$	658
Sulfur purchased, used in production(3):
Volume (tons)		26
Pricing ($ per ton)	$	151
Sulfur purchased, in cost of sales(3):
Volume (tons)		25
Pricing ($ per ton)	$	154
On-stream factors(4):
Ammonia		95.4	%		92.3	%		83.7	%		100.0	%		96.4	%		91.8	%		98.1	%		99.5	%
UAN		95.1	%		92.6	%		84.8	%		100.0	%		96.4	%		92.9	%		96.7	%		98.4	%
Ammonium sulfate		88.0	%(5)

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	As of December 31,							As of September 30,
	2012		2011		2010			2011			2010		2009			2008
					(unaudited)
	(in thousands)
BALANCE SHEET DATA
Cash and cash equivalents	$	55,799	$	44,836	$	36,621		$	51,372		$	34,934	$	36,661		$	56,268
Working capital	$	23,218	$	31,645	$	(6,350	)	$	(32,270	)	$	22,565	$	(2,860	)	$	31,251
Construction in progress	$	61,147	$	7,062	$	4,553		$	20,318		$	2,474	$	6,882		$	3,490
Total assets	$	376,645	$	130,443	$	114,052		$	152,408		$	108,837	$	115,769		$	159,552
Credit facilities and term loan	$	193,290	$	—	$	91,779		$	146,250		$	60,875	$	36,416		$	53,000
Total long-term liabilities	$	192,961	$	277	$	68,446		$	114,981		$	54,549	$	7,642		$	59,045
Total partners’ capital / stockholder’s equity (deficit)	$	109,404	$	99,191	$	(22,843	)	$	(76,133	)	$	20,334	$	42,433		$	26,118

(1) EBITDA is defined as net income plus interest expense and other financing costs, loss on debt extinguishment, loss on interest rate swaps, income tax expense and depreciation and amortization, net of interest income. We calculate cash available for distribution as used in this table as EBITDA plus acquisition costs and non-cash compensation expense, less maintenance capital expenditures to the extent not funded by capital proceeds, net interest expense and debt service and distribution of cash reserves for working capital needs. EBITDA and cash available for distribution are used as supplemental financial measures 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 limited partnerships and other public companies, without regard to financing methods and capital structure.

EBITDA and cash available for distribution should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and cash available for distribution may have material limitations as performance measures because they exclude items that are necessary elements of our costs and operations. In addition, EBITDA and cash available for distribution presented by other companies may not be comparable to our presentation, since each company may define these terms differently.

The table below reconciles EBITDA, which is a non-GAAP measurement, to net income for the periods presented.

	Calendar Years Ended December 31,						Three Months Ended December 31,						Fiscal Years Ended September 30,
	2012			2011			2011			2010			2011			2010			2009			2008
	(unaudited, in thousands)
Net income	$	107,003		$	31,057		$	10,455		$	4,324		$	24,926		$	5,009		$	28,159		$	30,098
Add:
Interest income		(45	)		(53	)		(14	)		(13	)		(51	)		(57	)		(190	)		(891	)
Interest expense		1,469			12,788			1,947			2,912			13,752			9,859			8,481			2,747
Loss on debt extinguishment		2,114			19,486			10,263			4,593			13,816			2,268			—			—
Loss on interest rate swaps		951			—			—			—			—			—			—			—
Income tax expense		303			14,643			—			2,772			17,415			3,344			18,576			19,875
Depreciation and amortization		12,460			10,706			3,287			2,601			10,020			10,544			8,683			8,552
Other		(232	)		(3	)		(3	)		—			—			—			—			—
EBITDA	$	124,023		$	88,624		$	25,935		$	17,189		$	79,878		$	30,967		$	63,709		$	60,381

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For the three months and the calendar year ended December 31, 2011, the cash available for distribution is calculated for the period beginning November 9, 2011 (the closing date of our initial public offering) through December 31, 2011.

The table below reconciles cash available for distribution to EBITDA, both of which are non-GAAP measurements, for the periods presented.

	Calendar Year Ended December 31, 2012			Three Months Ended December 31, 2012(a)			November 9, 2011 through December 31, 2011
	(unaudited, in thousands)
EBITDA	$	124,023		$	24,306		$	24,135
Plus: Acquisition costs		4,131			4,131			—
Adjusted EBITDA		128,154			28,437			24,135
Plus: Non-cash compensation expense		2,827			556			63
Less: Maintenance capital expenditures		(8,500	)		(3,116	)		(266	)
Plus: Portion of maintenance capital expenditures funded by offering proceeds		—			—			1,765
Less: Net interest expense and debt service		(1,446	)		(1,303	)		(57	)
Plus: Distribution of cash reserves for working capital		6,110			4,531			(5,391	)
Cash available for distribution	$	127,145		$	29,105		$	20,249
Cash available for distribution, per unit	$	3.30		$	0.75		$	0.53
Common units outstanding		38,529			38,839			38,250

(a) The amounts in this column are also included in the amounts for the calendar year ended December 31, 2012. This column provides information relating to the cash distribution paid on February 14, 2013.

(2) Key operating data for the East Dubuque Facility.

(3) Key operating data for the Pasadena Facility.

(4) The respective on-stream factors for the ammonia, UAN and ammonium sulfate plant equal the total days the applicable plant operated in any given period, divided by the total days in that period.

(5) The ammonium sulfate plant is taken down between 12 and 14 hours per week for regular maintenance.

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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 the financial statements and related notes included elsewhere in this report. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including, but not limited to, those set forth under Part I—Item 1A “Risk Factors,” “Forward-Looking Statements” and elsewhere in this report.

OVERVIEW

We are a Delaware limited partnership formed in July 2011 by Rentech, a publicly traded provider of clean energy solutions and nitrogen fertilizer, to own, operate and expand our fertilizer business. We own and operate two fertilizer facilities: our East Dubuque Facility and our Pasadena Facility. Our East Dubuque Facility, which Rentech acquired in 2006, is located in East Dubuque, Illinois, and has been in operation since 1965. We produce primarily ammonia and UAN at our East Dubuque Facility, using natural gas as the facility’s primary feedstock. Our Pasadena Facility, which we acquired in November 2012, is located in Pasadena, Texas, and has been in operation since the 1940s. In 2011, our Pasadena Facility was retrofitted to produce ammonium sulfate. We produce ammonium sulfate, ammonium thiosulfate and sulfuric acid at our Pasadena Facility, using ammonia and sulfur as the facility’s primary feedstocks.

Our East Dubuque Facility is located in the center of the Mid Corn Belt, the largest market in the United States for direct application of nitrogen fertilizer products. The Mid Corn Belt includes the States of Illinois, Indiana, Iowa, Missouri, Nebraska and Ohio. The States of Illinois and Iowa have been the top two corn producing states in the United States for the last 20 years according to the USDA. We consider the market for our East Dubuque Facility to be comprised of the States of Illinois, Iowa and Wisconsin.

Our East Dubuque Facility’s core market consists of the area located within an estimated 200-mile radius of the facility. In most instances, our customers take delivery of our nitrogen products at our East Dubuque Facility and then arrange and pay to transport them to their final destinations by truck. To the extent our products are picked up at our East Dubuque Facility, we do not incur any shipping costs, in contrast to nitrogen fertilizer producers located outside of the facility’s core market that must incur transportation and storage costs to transport their products to, and sell their products in, our market. In addition, our East Dubuque Facility does not maintain a fleet of trucks and, unlike some of our major competitors, our East Dubuque Facility does not maintain a fleet of rail cars because the facility’s customers generally are located close to the facility and prefer to be responsible for transportation. Having no need to maintain a fleet of trucks or rail cars lowers the East Dubuque Facility’s fixed costs. The combination of the East Dubuque Facility’s proximity to its customers and our storage capacity at the facility also allows for better timing of the pick-up and application of the facility’s products, as nitrogen fertilizer product shipments from more distant locations have a greater risk of missing the short periods of favorable weather conditions during which the application of nitrogen fertilizer may occur.

The Pasadena Facility is the largest producer of synthetic ammonium sulfate and the third largest overall producer of ammonium sulfate in North America. We believe that our ammonium sulfate has several characteristics that distinguish it from competing products. In general, the ammonium sulfate that is available for sale in our industry is a byproduct of other processes and does not have certain characteristics valued by customers. Our ammonium sulfate is sized to the specifications preferred by customers and may more easily be blended with other fertilizer products. We also believe that our ammonium sulfate has a longer shelf-life, is more stable and is more easily transported and stored than many other competing products.

Our Pasadena Facility is located on the Houston Ship Channel with access to transportation at favorable prices. The facility has two deep-water docks and access to the Mississippi waterway system and key international waterways. The facility is also connected to key domestic railways which permit the efficient, cost-effective distribution of its products west of the Mississippi River. Our Pasadena Facility’s distributors purchase our products at our facility and then arrange and pay to transport them to their final destinations by truck, rail car or vessel. Our Pasadena Facility’s products are sold primarily through distributors to customers in the U.S. and in Brazil, and are applied to many types of crops including soybeans, potatoes, cotton, canola, alfalfa, corn and wheat. We believe that the diversification of the geographic markets and applications for this facility’s products should improve the stability of our overall results. Ammonium sulfate prices and margins generally have been less volatile than the prices and margins for the products of the East Dubuque Facility.

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While we experience seasonality in our domestic sales of ammonium sulfate and ammonium thiosulfate, our sales internationally offset a portion of this seasonal impact in our total revenues. Further, we adjust the sales prices of these products seasonally in order to facilitate distribution of the products throughout the year. We operate the ammonium sulfate plant at our Pasadena Facility throughout the year to the extent that there is available on-site storage capacity for this product. We have 60,000 tons of storage capacity for ammonium sulfate at the facility, and an arrangement with IOC that permits us to store 32,000 tons of ammonium sulfate at IOC-controlled terminals. We manage the storage capacity by distributing the product through IOC to customers in both domestic and offshore markets throughout the year. If storage capacity becomes insufficient, we would be forced to cease production of the product until such capacity becomes available. Our Pasadena Facility’s fertilizer products are sold both on the spot market for immediate delivery and, to a much lesser extent, under product prepayment contracts for future delivery at fixed prices. The amount of products we sell under product prepayment contracts is highly variable. As of December 31, 2012, there were approximately 6,300 tons of ammonium sulfate sold under product prepayment contracts.

The Pasadena Facility purchases ammonia as a feedstock at contractual prices based on the monthly Tampa Index market, while the East Dubuque Facility sells ammonia at prevailing prices in the Mid Corn Belt, which are typically significantly higher than Tampa ammonia prices.

For further information concerning our potential financing needs and related risks, see Part I—Item 1 “Business,” and Part I— Item 1A “Risk Factors”.

Factors Affecting Comparability of Financial Information

Our historical results of operations for the periods presented may not be comparable with our results of operations for subsequent periods for the reasons discussed below.

Agrifos Acquisition

The operations of RNPLLC are only included in our historical results of operations from the closing date of the Agrifos Acquisition, which was November 1, 2012. Two months of revenues from RNPLLC accounted for approximately 14% of our revenues for the calendar year ended December 31, 2012. We would expect the percentage of revenues to increase significantly for a full year. As a result of the Agrifos Acquisition, we now produce three new products: ammonium sulfate, ammonium thiosulfate and sulfuric acid. In addition, as a result of the Agrifos Acquisition, we obtained a more diverse geographic area into which our products are sold. We also expect (i) general and administrative expenses as well as sales-related expenses to increase due to the integration of RNPLLC’s operations, (ii) depreciation and amortization expenses to increase due to the increase in fixed and intangible assets, which were recorded at fair value on the date of the Agrifos Acquisition, and (iii) interest expense to increase due to the $155.0 million term loan used to finance a significant portion of the purchase price for the Agrifos Acquisition. As a result, our results of operations for the periods prior to and after the closing date of the Agrifos Acquisition may not be comparable.

Corporate Allocations

Prior to the closing of our initial public offering, REMC was consolidated with Rentech’s operations following its acquisition by Rentech in 2006. Our consolidated financial statements included elsewhere in this report reflect REMC on a stand-alone or “carve-out” basis from Rentech for periods prior to our initial public offering. In the consolidated financial statements, corporate overhead costs incurred by Rentech on behalf of REMC were allocated to REMC and are reflected in operating expenses. These costs include the following:

• compensation of human resources, legal, information systems, accounting and finance, investor relations and other Rentech personnel, which were allocated to REMC based on the estimated amount of time spent by the Rentech personnel on work for REMC;

• stock-based compensation of REMC personnel, all of which was allocated to REMC;

• third-party hosting costs for accounting and financial reporting software, which were allocated to REMC based on the estimated proportion of such costs that related to REMC transactions;

• audit and tax services expenses, which were allocated to REMC based on an estimate of the time spent by third-party providers on REMC audit and tax matters;

• income taxes, which were allocated to REMC on a hypothetical separate tax return basis;

• capital costs of accounting and financial reporting software, which were allocated to REMC based on an estimate of the time the software was used by REMC personnel; and

• amortization of the original issue discount and the loss on the early extinguishment of debt relating to REMC’s former credit agreement, all of which was allocated to REMC.

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For the fiscal years ended September 30, 2011 and 2010, the total operating expenses incurred by Rentech and allocated to REMC were approximately $2.0 million and $1.4 million, respectively. See Note 2 to the financial statements.

REMC and Rentech entered into a management services agreement on April 26, 2006 and amended that agreement on July 29, 2011. As compensation for Rentech’s management services, REMC paid Rentech the actual corporate overhead costs incurred by Rentech on behalf of REMC, including, without limitation, compensation expenses for Rentech personnel providing services to REMC, stock-based and incentive bonus compensation expenses of REMC personnel, legal, audit, accounting and tax services expenses, income tax expenses and software expenses. The management services agreement terminated in accordance with its terms at the closing of our initial public offering and, upon its termination, REMC was required to pay Rentech any corporate overhead costs owed by REMC under the agreement. The amount of these corporate overhead costs was approximately $19.4 million, which primarily represent estimated income taxes attributable to REMC.

On November 9, 2011, the closing date of our initial public offering, we, our general partner and Rentech entered into a services agreement, pursuant to which we and our general partner obtain certain management and other services from Rentech. Our consolidated financial statements following our initial public offering reflect the impact of the reimbursements we are required to make to Rentech under the services agreement instead of those used for purposes of preparing REMC’s stand-alone financial statements. Under the services agreement, we, our general partner and our operating subsidiaries are obligated to reimburse Rentech for (i) all costs, if any, incurred by Rentech or its affiliates in connection with the employment of its employees who are seconded to us and who provide us services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by Rentech or its affiliates in connection with the employment of its employees, excluding seconded personnel, who provide us services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by Rentech on a commercially reasonable basis, based on the estimated percent of total working time that such personnel are engaged in performing services for us; (iii) a prorated share of certain administrative costs, in accordance with the agreement, including office costs, services by outside vendors, other general and administrative costs; and (iv) any taxes (other than income taxes, gross receipt taxes and similar taxes) incurred by Rentech or its affiliates for the services provided under the agreement.

Publicly Traded Limited Partnership Expenses

Our general and administrative expenses have increased due to the costs of operating as a publicly traded limited partnership, including costs associated with SEC reporting requirements, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, work performed by our independent auditors, investor relations activities and registrar and transfer agent services. Our consolidated financial statements following our initial public offering reflect the impact of this expense, which affect the comparability of our post-offering results with our financial statements from periods prior to the closing of our initial public offering.

Expansion Projects

As discussed in Part I—Item 1A “Business—Our East Dubuque Facility—Expansion Projects” and “Business—Our Pasadena Facility —Expansion Projects,” we have commenced or are evaluating potential projects to expand the production capabilities at our facilities. To the extent that we proceed with and complete one or more of these expansion projects, we expect to incur significant costs and expenses for the construction and development of such projects. We expect to finance the costs and expenses of the various expansion projects with indebtedness, which will significantly increase our interest expense. We also expect our depreciation expense to increase from additional assets placed into service from the projects. As a result, our results of operations for periods prior to, during and after the construction of any expansion project may not be comparable.

Key Industry Factors

Supply and Demand

Our earnings and cash flow from operations are significantly affected by nitrogen fertilizer product prices. The price at which we ultimately sell our nitrogen fertilizer products depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and prices, inventory and production levels, changes in world population, the cost and availability of natural gas, ammonia and sulfur in various regions of the world, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports and the extent of government intervention in agriculture markets. Nitrogen fertilizer prices are also affected by local factors, including weather and soil conditions, local market conditions and the operating levels of competing facilities. Construction of new facilities or the expansion or upgrade of our competitors’ existing facilities, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. In addition, 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 factors including crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

56

Natural Gas Prices

Natural gas is the primary feedstock for the production of nitrogen fertilizers at our East Dubuque Facility, accounting for approximately 64% of the production costs for ammonia in the calendar year ended December 31, 2012. Over the last five years, United States natural gas reserves have increased significantly due to, among other factors, advances in extracting shale gas, which have reduced and stabilized natural gas prices, providing North America with a cost advantage over Europe. As a result, our competitive position and that of other North American nitrogen fertilizer producers have been positively impacted.

We historically have purchased natural gas in the spot market, through the use of forward purchase contracts, or a combination of both. We historically have used forward purchase contracts to lock in pricing for a portion of our East Dubuque Facility’s natural gas requirements. These forward purchase contracts are generally either fixed-price or index-price, short-term in nature and for a fixed supply quantity. We are able to purchase natural gas at competitive prices due to our East Dubuque Facility’s connection to Nicor Inc.’s distribution system and its proximity to the Northern Natural Gas interstate pipeline system. Over the past several years, natural gas prices have experienced significant fluctuations, which has had an impact on our East Dubuque Facility’s cost of producing nitrogen fertilizer. During the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, we spent approximately $38.3 million, $10.8 million, $49.2 million and $50.5 million, respectively, on natural gas in cost of sales, which equaled an average cost per MMBtu of approximately $3.59, $4.75, $4.66 and $4.79, respectively.

Ammonia Prices

Ammonia, along with sulfuric acid, are the primary feedstocks for the production of ammonium sulfate at our Pasadena Facility, accounting for 69% and 31%, respectively, of the raw material costs for ammonium sulfate. Ammonia pricing is based on a published Tampa, Florida market index. The Tampa index is commonly used in annual contracts for both the agricultural and industrial sectors, and is based on the most recent major industry transactions in the Tampa market. Pricing considerations for ammonia incorporate international supply-demand, ocean freight and production factors. Over the past several years, ammonia prices have experienced large fluctuations. During the period from May 2011, the time when our Pasadena Facility began to produce ammonium sulfate, through the beginning of March 2013, the low and high prices for a short ton of ammonia were $363 and $653, respectively. During the calendar year ended December 31, 2012, our Pasadena Facility spent approximately $74.8 million on ammonia. During the calendar year ended December 31, 2012, 75% of the sulfuric acid used in our Pasadena Facility’s production of ammonium sulfate was produced at our Pasadena Facility.

Sulfur Prices

Sulfur is the primary feedstock for the production of sulfuric acid at our Pasadena Facility, accounting for 100% of the raw material costs for sulfuric acid. Our contracts with the major suppliers of sulfur to our Pasadena Facility generally have a term of one year. Once pricing for the first quarter of a year is negotiated, the price then fluctuates up or down each subsequent quarter based on changes to a Tampa index that is set on a quarterly basis through negotiations between large industry producers and consumers. Over the past several years, sulfur prices have experienced significant fluctuations. During the period from May 2011 through the beginning of March 2013, the low and high prices for a short ton of sulfur was $134 and $196, respectively. During the calendar year ended December 31, 2012, our Pasadena Facility spent approximately $26.0 million on sulfur.

Transportation Costs

Costs for transporting nitrogen fertilizer can be significant relative to its selling price. For example, ammonia is costly to transport because it is a toxic gas at ambient temperatures and therefore must be transported under refrigeration in specialized equipment. The United States imported an average of over 50% of its annual fertilizer needs between 1999 and 2009 according to the USDA. Therefore, nitrogen fertilizer prices in North America are influenced by the cost to transport product from exporting countries, granting an advantage to local producers who ship over shorter distances.

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The price of our East Dubuque Facility’s nitrogen fertilizer products is impacted by our transportation cost advantage over out-of-region competitors serving our East Dubuque Facility’s core market. In most instances, our East Dubuque Facility’s customers purchase our nitrogen products at the facility and then arrange and pay to transport them to their final destinations by truck. To the extent our products are picked up at the facility, we do not incur any shipping costs, in contrast to nitrogen fertilizer producers outside of our East Dubuque Facility’s core market that must incur transportation and storage costs to transport their products to, and sell their products in, our market. Accordingly, we may offer our East Dubuque Facility’s nitrogen fertilizers at market prices that factor in the storage and transportation costs of out-of-region producers without having incurred such costs. In addition, we do not maintain a fleet of trucks and, unlike some of our major competitors, we do not maintain a fleet of rail cars, which lowers our fixed costs.

Our Pasadena Facility is located on the Houston Ship Channel with access to transportation at favorable prices by barge, truck or rail. The facility has two deep-water docks and access to the Mississippi waterway system and international waterways. The docks at the facility are suitable for loading and unloading bulk or liquid barges with payloads of up to 35,000 tons. The facility is also connected to key domestic railways which permit the efficient, cost-effective distribution of its products west of the Mississippi River. Our location on the Houston Ship Channel allows our distributors or us to use low cost barge and vessel when selling products and purchasing feedstocks. Our Pasadena Facility’s distributors purchase our products at our facility and then arrange and pay to transport them to their final destinations by truck, rail car or vessel.

Key Operational Factors

Product Prepayment Contracts

We enter into product prepayment contracts committing our East Dubuque Facility’s customers to purchase the facility’s nitrogen fertilizer products at a later date. To a lesser extent, we also enter into product prepayment contracts for our Pasadena Facility’s products. These customers pay a portion of the contract price for our products shortly after entering into such contracts and the remaining balance of the contract price prior to picking up or delivery of the products. We recognize revenue when products are picked-up or delivered and the customer takes title. The cash received from product prepayments increases our operating cash flow in the quarter in which the cash is received, but may effectively reduce our operating cash flow in a subsequent quarter if the cash was received in a quarter prior to the one in which the revenue is recorded. Our policy is to purchase under fixed-price forward contracts approximately enough natural gas to manufacture the products that have been sold by our East Dubuque Facility under product prepayment contracts for later delivery, effectively fixing most of the gross margin on pre-sold product. Our earnings and operating cash flow in future periods may be affected by the degree to which we continue this practice or seek to maximize our gross margins by more opportunistically timing product sales and natural gas purchases.

Facility Reliability

Consistent, safe and reliable operations at our facilities are critical to our financial performance and results of operations. Unplanned shutdowns of our facilities may result in lost margin opportunity, increased maintenance expense, a temporary increase in working capital investment and reduced inventory available for sale. The financial impact of planned shutdowns, including facility turnarounds, is mitigated through a diligent planning process that takes into account the availability of resources to perform the needed maintenance, feedstock logistics and other factors. Our facilities generally undergo a facility turnaround every two years. Turnarounds at our East Dubuque Facility typically last 18 to 25 days and cost approximately $3.0 to $5.0 million per turnaround, and turnarounds at our Pasadena Facility generally last between 14 to 25 days and cost approximately $1.0 to $4.0 million per turnaround. These costs are expensed as incurred. Our East Dubuque Facility underwent a turnaround in October 2009 at a cost of approximately $4.0 million and in September and October of 2011 at a cost of approximately $7.5 million. Our Pasadena Facility underwent a turnaround in March and April of 2011 at a cost of approximately $4.5 million. We intend to alternate the year in which a turnaround occurs at each facility, so that both facilities do not experience a turnaround in the same year.

In many cases, we also perform significant maintenance capital projects at our facilities during a turnaround to minimize disruption to our operations. These capital projects are undertaken during turnarounds to minimize disruption to our operations, but are capitalized as property, plant and equipment rather than expensed as turnaround costs. Our East Dubuque Facility’s maintenance capital expenditures for such projects were $24.5 million and $9.9 million for the fiscal years ended September 30, 2011 and 2010, respectively. Our East Dubuque Facility’s maintenance capital expenditures totaled approximately $7.9 million, $2.5 million and $2.7 million for the calendar year ended December 31, 2012 and the three months ended December 31, 2011 and 2010, respectively. As part of the 2011 turnaround, our East Dubuque Facility completed a significant maintenance capital project to replace our existing steam methane reformer tubes, which had been operational since 1980, and made other capital improvements to our facility. Our Pasadena Facility’s maintenance capital expenditures were approximately $4.6 million for the calendar year ended December 31, 2012, which included maintenance on the facility’s sulfuric acid plant. See “—Liquidity and Capital Resources—Capital Expenditures.”

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Factors Affecting Results of Operations

Revenues

We generate revenue primarily from sales of nitrogen fertilizer products. We generate revenue from sales of nitrogen fertilizer products manufactured at our East Dubuque Facility and used primarily in corn production. Our East Dubuque Facility is designed to produce ammonia, UAN, liquid and granular urea, nitric acid and CO₂ using natural gas as a feedstock. We also generate revenue from sales of nitrogen fertilizer products manufactured at our Pasadena Facility and used in the production of corn, soybeans, potatoes, cotton, canola, alfalfa and wheat. Our Pasadena Facility is designed to produce ammonium sulfate, sulfuric acid and ammonium thiosulfate. Revenues for our fertilizer products are seasonal based on the planting, growing and harvesting cycles of customers utilizing nitrogen fertilizer.

Cost of Sales

The most significant element of cost of sales, primarily consists of natural gas for our East Dubuque Facility, ammonia, sulfur and sulfuric acid for our Pasadena Facility, labor costs and depreciation. Turnaround expenses represent the cost of the planned shut-down of our facilities for maintenance. Our East Dubuque Facility and Pasadena Facility require a planned maintenance turnaround every two years. Turnarounds at our East Dubuque Facility generally last between 18 and 25 days, and turnarounds at our Pasadena Facility generally last between 14 and 25 days. We intend to alternate the year in which a turnaround occurs at each facility, so that both facilities do not experience a turnaround in the same year.

Operating Expenses

Operating expenses primarily consist of selling, general and administrative expense and depreciation expense. Selling, general and administrative expense mainly consists of direct and allocated legal expenses; payroll expenses relating to treasury, accounting, marketing and human resources; and expenses for maintaining our corporate offices.

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 as of the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited financial statements included elsewhere in this report. Our critical accounting policies, estimates and assumptions could materially affect the amounts recorded in our financial statements. The most significant estimates and assumptions relate to revenue recognition, inventories, the valuation of long-lived assets and intangible assets, recoverability of goodwill and the acquisition method of accounting.

Revenue Recognition. We recognize revenue when the following elements are substantially satisfied: when the customer takes ownership from our facilities or storage locations and assumes risk of loss; there are no uncertainties regarding customer acceptance; there is persuasive evidence that an agreement exists documenting the specific terms of the transaction; the sales price is fixed or determinable; and collectibility is reasonably assured. Management assesses the business environment, the customer’s financial condition, historical collection experience, accounts receivable aging and customer disputes to determine whether collectibility is reasonably assured. If collectibility is not considered reasonably assured at the time of sale, we do not recognize revenue until collection occurs.

Certain product sales occur under product prepayment contracts which require payment in advance of delivery. We record a liability for deferred revenue in the amount of, and upon receipt of, cash in advance of shipment. We recognize revenue related to the product prepayment contracts and relieve the liability for deferred revenue when customers take ownership of products. A significant portion of the revenue recognized during any period may be related to product prepayment contracts, for which cash may have been collected during an earlier period, with the result being that a significant portion of revenue recognized during a period may not generate cash receipts during that period.

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Natural gas, though not purchased for the purpose of resale, is occasionally sold under certain circumstances. Natural gas is sold when contracted quantities received are in excess of production requirements and storage capacities, in which case the sales price is recorded in revenues and the related cost is recorded in cost of sales.

Inventories. Our inventory is stated at the lower of cost or estimated net realizable value. The cost of inventories is determined using the first-in first-out method. We perform an analysis of our inventory balances at least quarterly to determine if the carrying amount of inventories exceeds their net realizable value. The analysis of estimated net realizable value is based on customer orders, market trends and historical pricing. If the carrying amount exceeds the estimated net realizable value, the carrying amount is reduced to the estimated net realizable value. We allocate fixed production overhead costs to inventory based on the normal capacity of our production facilities.

Valuation of Long-Lived Assets and Intangible Assets. We assess the realizable value of long-lived assets and intangible assets for potential impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. In assessing the recoverability of our assets, we make assumptions regarding estimated future cash flows and other factors to determine the fair value of the respective assets. As applicable, we make assumptions regarding the useful lives of the assets. If these estimates or their related assumptions change in the future, we may be required to record impairment charges for these assets.

Recoverability of Goodwill. We test goodwill assets for impairment annually, or more often if an event or circumstance indicates that an impairment may have occurred. The recoverability of goodwill involves a high degree of judgment since the first step of the required impairment test consists of a comparison of the fair value of a reporting unit with its book value. Based on the assumptions underlying the valuation, impairment is determined by estimating the fair value of a reporting unit and comparing that value to the reporting unit’s book value. If the fair value is more than the book value of the reporting unit, an impairment loss is not recognized. If an impairment exists, the fair value of the reporting unit is allocated to all of its assets and liabilities excluding goodwill, with the excess amount representing the fair value of goodwill. An impairment loss is measured as the amount by which the book value of the reporting unit’s goodwill exceeds the estimated fair value of that goodwill.

Accounting for Major Maintenance. Expenditures during turnarounds or at other times for improving, replacing or adding to assets are capitalized. Expenditures for the acquisition, construction or development of new assets to maintain operating capacity, or to comply with environmental, health, safety or other regulations, are also capitalized. Costs of general maintenance and repairs are expensed. The East Dubuque Facility and Pasadena Facility require a planned maintenance turnaround every two years. Turnarounds at the East Dubuque Facility generally last between 18 and 25 days, and turnarounds at the Pasadena Facility generally last between 14 and 25 days. We intend to alternate the year in which a turnaround occurs at each facility, so that both facilities do not experience a turnaround in the same year. As a result, the facilities incur turnaround expenses which represent the cost of shutting down the plants for planned maintenance. Such costs are expensed as incurred. In many cases, the East Dubuque Facility and the Pasadena Facility also perform significant maintenance capital projects at the plants during a turnaround to minimize disruption to operations. Such projects are capitalized as property, plant and equipment rather than expensed as turnaround costs.

Examples of maintenance capital projects include the installation of additional components and projects that increase an asset’s useful life, increase the quantity or quality of the product manufactured or create efficiencies in the production process. Major turnaround costs, which are expensed, include gas, electric and other shutdown and startup costs, labor, contractor and materials costs used to complete non-capital activities such as opening, dismantling, inspecting and reassembling major vessels, testing pressure and safety devices, cleaning or hydro-jetting major exchangers, replacing gaskets, repacking valves, checking instrument calibration and performing mechanical integrity inspections, all of which are completed with the goal of improving reliability and likelihood for continuous operation until the next turnaround.

Acquisition Method of Accounting. We account for business combinations using the acquisition method of accounting, which requires, among other things, that most assets acquired, liabilities assumed and earn-out consideration be recognized at their fair values as of the acquisition date. The earn-out consideration will be measured at each reporting date with changes in its fair value recognized in the consolidated statements of income.

Business Segments

Prior to the closing of the Agrifos Acquisition, we operated in only one business segment. After the closing of the Agrifos Acquisition, we now operate in two business segments described below. The operations of the Pasadena Facility are only included in our historical results of operations from the date of the closing of the Agrifos Acquisition, which was November 1, 2012.

• East Dubuque – The operations of the East Dubuque Facility, which produces primarily ammonia and UAN.

• Pasadena – The operations of the Pasadena Facility, which produces primarily ammonium sulfate.

On February 1, 2012, the board of directors of our general partner approved a change in our fiscal year end from September 30 to December 31. The statement of income for calendar year ended December 31, 2011 was derived by deducting the statement of income for the three months ended December 31, 2010 from the statement of income for the fiscal year ended September 30, 2011 and then adding the statement of income for the three months ended December 31, 2011. The statements of income for calendar year ended December 31, 2011 and the three months ended December 31, 2010, while not required, are presented for comparison purposes.

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	For the Calendar Years Ended December 31,
	2012			2011
				(unaudited)
	(in thousands)
Revenues:
East Dubuque	$	224,205		$	199,909
Pasadena		37,430			—
Total revenues	$	261,635		$	199,909
Gross profit (loss):
East Dubuque	$	133,543		$	85,998
Pasadena		(1,704	)		—
Total gross profit	$	131,839		$	85,998
Operating income (loss):
East Dubuque	$	125,984		$	77,918
Pasadena		(2,648	)		—
Total operating income	$	123,336		$	77,918
Net income (loss):
East Dubuque	$	123,721		$	31,057
Pasadena		(2,648	)		—
Total net income	$	121,073		$	31,057
Reconciliation of segment net income to consolidated net income:
Segment net income	$	121,073		$	31,057
Partnership and unallocated expenses		(11,844	)		—
Unallocated interest expense and loss on interest rate swaps		(2,226	)		—
Consolidated net income	$	107,003		$	31,057

Partnership and unallocated expenses represent costs that relate directly to the Partnership or to the Partnership and its subsidiaries but are not allocated to a segment. Such expenses consist primarily of business development expenses for the Partnership totaling $4.5 million, including the Agrifos Acquisition costs of approximately $4.1 million, unit-based compensation expense of approximately $2.8 million, labor allocations from Rentech of approximately $2.1 million, accounting and tax fees of approximately $1.2 million, legal fees and taxes of approximately $0.3 million each, certain insurance costs of approximately $0.2 million and board expense of approximately $0.1 million. Unallocated interest expense represents interest expense on the term loan, which was used to finance the Agrifos Acquisition. Prior to calendar year ended December 31, 2012, East Dubuque and the Partnership were considered one entity for financial reporting purposes. Prior to the Agrifos Acquisition, the Partnership operated as one segment. Many of the partnership and unallocated expenses relate to the Partnership being a publicly traded entity, which are consistent with the $3.6 million in incremental publicly traded limited partnership costs estimated in the registration statement on Form S-1 for our initial public offering. We were a publicly traded partnership for twelve full months in 2012 as compared to 52 days in 2011.

East Dubuque

COMPARISON OF THE RESULTS OF OPERATIONS FOR THE CALENDAR YEAR ENDED DECEMBER 31, 2012 AND 2011

Revenues

	For the Calendar Years Ended December 31,
	2012		2011
			(unaudited)
	(in thousands)
Revenues:
Product shipments	$	222,936	$	199,094
Other		1,269		815
Total revenues	$	224,205	$	199,909

	For the Calendar  Year Ended December 31, 2012				For the Calendar  Year Ended December 31, 2011
	Tons		Revenue		Tons		Revenue
					(unaudited)
	(in thousands)				(in thousands)
Revenues:
Ammonia		149	$	99,378		135	$	87,909
UAN		291		94,836		301		89,435
Urea (liquid and granular)		35		21,189		29		14,428
CO2		76		2,517		92		2,476
Nitric Acid		14		5,016		15		4,846
Other		N/A		1,269		N/A		815
Total		565	$	224,205		572	$	199,909

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We generate revenue in our East Dubuque segment primarily from sales of nitrogen fertilizer products manufactured at our East Dubuque Facility and used primarily in corn production. Our East Dubuque Facility is designed to produce ammonia, UAN, liquid and granular urea, nitric acid and CO₂ using natural gas as a feedstock. Revenues are seasonal based on the planting, growing, and harvesting cycles of customers utilizing nitrogen fertilizer.

Revenues were approximately $224.2 million for the calendar year ended December 31, 2012 compared to approximately $199.9 million for the calendar year ended December 31, 2011. The increase in revenue for the calendar year ended December 31, 2012 compared to the calendar year ended December 31, 2011 was primarily due to increased sales prices for all products and sales volume for ammonia, partially offset by a decrease in sales volume for UAN.

The average sales prices per ton in the calendar year ended December 31, 2012 as compared with the calendar year ended December 31, 2011 increased by 3% and 10% for ammonia and UAN, respectively. These increases were due to higher demand. Grain inventory levels were low which created a higher demand for corn, and therefore higher corn prices. Higher demand for corn and corn prices led to expectations of higher corn acreage during the calendar year ended December 31, 2012 which increased the demand for fertilizer. These two products comprised approximately 87% and 89%, respectively, of our revenues for calendar year ended December 31, 2012 and 2011.

Sales volume for ammonia increased as a result of an increase in the amount of product available for sale which was due to production rates being higher in calendar year 2012 as a result of the work performed during the fall 2011 turnaround. Sales volume for UAN decreased as a result of less available product during November and December 2012. During this period, the ammonia plant at our East Dubuque Facility experienced two unexpected outages. Ammonia is upgraded to produce UAN. Production of UAN ceased during the outages, postponing UAN sales into the first quarter of 2013.

Although our East Dubuque Facility’s primary product is ammonia, the facility has the manufacturing capability to upgrade ammonia into other saleable products, including liquid and granular urea, nitric acid and UAN. We regularly evaluate selling prices, incremental margins and demand for the various products we sell in order to determine the appropriate proportion of products to manufacture. Liquid and granular urea, UAN and nitric acid are currently selling at a premium to ammonia per nutrient ton. Our recently completed urea expansion project at our East Dubuque Facility will enable us to upgrade more ammonia and thereby increase gross margins based on current pricing trends.

Other revenue for the year ended December 31, 2012 consists of sales of excess inventory of natural gas and sales of nitrous oxide emission reduction credits of approximately $1.1 million and $0.1 million, respectively. Other revenue for the year ended December 31, 2011 consists of sales of excess inventory of natural gas.

Cost of Sales

	For the Calendar Years Ended December 31,
	2012		2011
			(unaudited)
	(in thousands)
Total cost of sales	$	90,662	$	113,911

Cost of sales was approximately $90.7 million for the calendar year ended December 31, 2012 compared to approximately $113.9 million for the calendar year ended December 31, 2011. The decrease in cost of sales was primarily due to lower natural gas costs of approximately $11.9 million, purchase of ammonia by barge which resulted in additional cost of sales of approximately $8.3 million in the prior year, turnaround expenses in the prior year of approximately $7.4 million, and an out-of-period adjustment for spare parts which resulted in a credit to depreciation expense in cost of sales of approximately $1.2 million. During calendar year 2011, we sold approximately 20,000 tons of ammonia that were purchased by barge, resulting in a cost for the purchased ammonia much higher than the production cost of such ammonia. Since demand for nitrogen fertilizer in our market generally exceeds the amount of nitrogen fertilizer we can produce, we occasionally purchase product for immediate resale when the price of such nitrogen fertilizer available for immediate resale is lower than our sales price at that time. These sales accounted for approximately $8.3 million in additional cost of sales over production cost. Turnaround expenses represent the cost of maintenance during turnarounds, which occur approximately every two years at the East Dubuque Facility. A facility turnaround at the East Dubuque Facility occurred in September and October 2011. The overall decrease in cost of sales was partially offset by additional expenses in 2012, including the following: higher depreciation expense of approximately $1.7 million, prior to the out-of-period adjustment; approximately $2.3 million of expenses related to the two unexpected outages of the ammonia plant, consisting of $1.0 million of direct shutdown expenses and $1.3 million of fixed costs expensed through cost of sales that would have been inventoried had the plant remained operational; and approximately $1.7 million in lime removal costs.

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Natural gas costs comprised approximately 44% of cost of sales for the calendar year ended December 31, 2012 compared to 45% of cost of sales for the calendar year ended December 31, 2011. Labor costs comprised approximately 14% of cost of sales for the calendar year ended December 31, 2012 compared to approximately 11% of cost of sales for the calendar year ended December 31, 2011. Depreciation expense included in cost of sales was approximately $10.7 million and $10.3 million, respectively, for the calendar year ended December 31, 2012 and 2011 and comprised approximately 12% and 9% of cost of sales for the calendar years ended December 31, 2012 and 2011, respectively.

Gross Profit

	For the Calendar Years Ended December 31,
	2012		2011
			(unaudited)
	(in thousands)
Total gross profit	$	133,543	$	85,998

Gross profit was approximately $133.5 million for the calendar year ended December 31, 2012 compared to approximately $86.0 million for the calendar year ended December 31, 2011. Gross profit margin was 60% for the calendar year ended December 31, 2012 as compared to 43% for the calendar year ended December 31, 2011. Gross profit margin can vary significantly from period to period due to changes in nitrogen fertilizer prices and natural gas costs, both of which are commodities. The prices of these commodities can vary significantly from period to period and do not always move in the same direction. The increase in gross profit margin during the calendar year ended December 31, 2012 was primarily due to an increase in revenues and a decrease in cost of sales as described above.

Operating Expenses

	For the Calendar Years Ended December 31,
	2012		2011
			(unaudited)
	(in thousands)
Operating expenses:
Selling, general and administrative	$	6,242	$	7,690
Depreciation		807		374
Other		510		16
Total operating expenses	$	7,559	$	8,080

Operating expenses were approximately $7.6 million for the calendar year ended December 31, 2012 compared to approximately $8.1 million for the calendar year ended December 31, 2011. These expenses were primarily comprised of selling, general and administrative expense and depreciation expense.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were approximately $6.2 million for the calendar year ended December 31, 2012 compared to approximately $7.7 million for the calendar year ended December 31, 2011. This decrease was primarily due to certain expenses for 2012 which are considered partnership and unallocated expenses that historically were reported in one segment.

Depreciation. Depreciation expense was approximately $0.8 million and $0.4 million for the calendar years ended December 31, 2012 and 2011, respectively. This increase was primarily due to the acceleration of depreciation on an asset which was dismantled as part of the ammonia production and storage capacity project. A portion of depreciation expense is associated with assets supporting general and administrative functions and is recorded in operating expense. The majority of depreciation expense, as a manufacturing cost, is distributed between cost of sales and finished goods inventory, based on product volumes.

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Operating Income

	For the Calendar Years Ended December 31,
	2012		2011
			(unaudited)
	(in thousands)
Total operating income	$	125,984	$	77,918

Operating income was approximately $126.0 million for the calendar year ended December 31, 2012 compared to approximately $77.9 million for the calendar year ended December 31, 2011. The increase in operating income was primarily due to higher gross profit as described above.

Other Income (Expense), Net

	For the Calendar Years Ended December 31,
	2012			2011
				(unaudited)
	(in thousands)
Other income (expense), net:
Interest expense	$	(194	)	$	(12,788	)
Loss on debt extinguishment		(2,114	)		(19,486	)
Other income, net		45			56
Total other expense, net	$	(2,263	)	$	(32,218	)

Other expense, net was approximately $2.3 million for the calendar year ended December 31, 2012 compared to approximately $32.2 million for the calendar year ended December 31, 2011. The decrease in interest expense was primarily due to high outstanding principal balances, with substantially higher interest rates, for longer periods of time during the calendar year ended December 31, 2011 as compared to the calendar year ended December 31, 2012. The entry into the new 2012 credit agreement and the payoff of the credit agreement entered into in November 2011, or the 2011 credit agreement, resulted in a loss on debt extinguishment of approximately $2.1 million for the calendar year ended December 31, 2012. In November 2011, the entry into the 2011 credit agreement and the payoff of the previous credit agreement, resulted in a loss on debt extinguishment of approximately $10.3 million. In June 2011, we had a loss on debt extinguishment of $9.2 million relating to a former credit agreement REMC entered into during the fiscal year ended September 30, 2011.

COMPARISON OF THE RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED DECEMBER 31, 2011 AND 2010

Revenues

	For the Three Months Ended December 31,
	2011		2010
			(unaudited)
	(in thousands)
Revenues:
Product shipments	$	62,656	$	42,962
Sales of excess inventory of natural gas		358		—
Total revenues	$	63,014	$	42,962

	For the Three  Months Ended December 31, 2011				For the Three  Months Ended December 31, 2010
	Tons		Revenue		Tons		Revenue
					(unaudited)
	(in thousands)				(in thousands)
Product Shipments:
Ammonia		55	$	37,391		44	$	22,828
UAN		65		20,088		79		15,298
Urea (liquid and granular)		7		3,714		7		2,994
CO2		15		433		34		783
Nitric Acid		3		1,030		3		1,059
Total		145	$	62,656		167	$	42,962

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Revenues were approximately $63.0 million for the three months ended December 31, 2011 compared to approximately $43.0 million for the three months ended December 31, 2010. This increase was primarily the result of higher prices paid for our products during the three months ended December 31, 2011 and higher ammonia sales volume, partially offset by lower UAN and CO₂ sales volumes.

The average sales prices per ton in the three months ended December 31, 2011 as compared with the three months ended December 31, 2010 increased by 34% and 59% for ammonia and UAN, respectively. These increases were due to higher demand caused by a combination of low levels of grain and fertilizer inventories and expectations of higher corn acreage in 2012. These two products comprised approximately 92% and 89%, respectively, of our product sales for three months ended December 31, 2011 and 2010.

Sales volume for ammonia increased during the three months ended December 31, 2011 compared to the comparable period in 2010 as a result of lower inventories available for sale in the fall of 2010 given high deliveries during the summer of 2010. Deliveries in 2011 shifted from summer to fall as a result of strong presales to customers during the summer of 2011 for the fall ammonia application season, whereas, in the prior period, we had fewer ammonia tons presold for shipment in the fall. Sales volumes for UAN and CO₂ decreased due to lower availability of the products during the quarter as a result of the shutdown of the East Dubuque Facility for the fall 2011 turnaround. The net impact of the increase in sales volume of ammonia and the decrease in the sales volume of UAN and CO₂ resulted in a decrease in the total number of product shipments as reflected in the table above.

Although our primary product is ammonia, we have the manufacturing capability to upgrade ammonia into other saleable products, including liquid and granular urea, nitric acid and UAN. During the three months ended December 31, 2011 and 2010, we regularly evaluated selling prices, incremental margins and demand for the various products we sold in order to determine the appropriate proportion of products to manufacture. Liquid and granular urea, UAN and nitric acid sold at a premium to ammonia per nutrient ton during each of the three months ended December 31, 2011 and 2010.

Cost of Sales

	For the Three Months Ended December 31,
	2011		2010
			(unaudited)
	(in thousands)
Cost of sales:
Product shipments	$	34,024	$	26,835
Turnaround expenses		2,957		—
Sales of excess inventory of natural gas		479		—
Total cost of sales	$	37,460	$	26,835

Total cost of sales was approximately $37.5 million for the three months ended December 31, 2011 compared to approximately $26.8 million for the three months ended December 31, 2010. Cost of sales from product shipments was approximately $34.0 million for the three months ended December 31, 2011, compared to approximately $26.8 million for the three months ended December 31, 2010. Since the demand for nitrogen fertilizer in our market generally exceeds the amount of nitrogen fertilizer we can produce, we occasionally purchase product for immediate resale when there is an opportunity to do so at a price that is lower than our sales prices. The increase in total cost of sales on all product shipments for the three months ended December 31, 2011 compared to the three months ended December 31, 2010 was primarily due to (i) higher natural gas costs and (ii) the sale of approximately 12,000 tons of ammonia that were purchased by barge at a cost much higher than the production cost of such ammonia would have been. During the three months ended December 31, 2011, this sale accounted for approximately $5.0 million in additional cost of sales over production cost, $1.1 million of the increase in cost of sales was due to higher natural gas costs and the remaining increase was primarily due to other operating expenses, particularly depreciation expense, as discussed below. There were no sales of purchased ammonia during the three months ended December 31, 2010.

Natural gas costs comprised approximately 47% of cost of sales on product shipments for the three months ended December 31, 2011 compared to 53% of cost of sales on product shipments for the three months ended December 31, 2010. Labor costs comprised approximately 14% of cost of sales on product shipments for the three months ended December 31, 2011 compared to approximately 12% of cost of sales on product shipments for the three months ended December 31, 2010. Depreciation expense included in cost of sales was $3.2 million and $2.5 million, respectively, for the three months ended December 31, 2011 and 2010 and comprised approximately 9% of cost of sales on product shipments for each of the three months ended December 31, 2011 and 2010.

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Turnaround expenses represent the cost of maintenance during turnarounds, which occur approximately every two years. A facility turnaround occurred in September and October 2011. As a result, during the three months ended December 31, 2011, we incurred turnaround expenses of approximately $3.0 million.

Natural gas, though not purchased for the purpose of resale, is occasionally sold under certain circumstances, such as when contracted quantities received exceed our production requirements or our storage capacity. In these situations, which we refer to as sales of excess inventory of natural gas, the sales proceeds are recorded as revenue and the related cost is recorded as a cost of sales.

Gross Profit

	For the Three Months Ended December 31,
	2011			2010
				(unaudited)
	(in thousands)
Gross profit (loss):
Product shipments	$	28,632		$	16,127
Turnaround expenses		(2,957	)		—
Sales of excess inventory of natural gas		(121	)		—
Total gross profit	$	25,554		$	16,127

Gross profit was approximately $25.6 million for the three months ended December 31, 2011 compared to approximately $16.1 million for the three months ended December 31, 2010. Gross profit margin on product shipments was 46% for the three months ended December 31, 2011 as compared to 38% for the three months ended December 31, 2010. Gross profit margin on product shipments can vary significantly from period to period due to changes in nitrogen fertilizer prices and natural gas costs, both of which are commodities. The prices of these commodities can vary significantly from period to period and do not always move in the same direction. Specifically, the increase in gross profit margin during the three months ended December 31, 2011 was due to stronger average sales prices for our products resulting from a combination of low levels of grain and fertilizer inventories and expectations of higher corn acreage in 2012. This increase was partially offset by lower margins received on sales of approximately 12,000 tons of ammonia purchased by barge, as discussed above, approximately $1.1 million in higher natural gas costs, and approximately $0.7 million more in depreciation expense running through cost of sales.

Operating Expenses

	For the Three Months Ended December 31,
	2011			2010
				(unaudited)
	(in thousands)
Operating expenses:
Selling, general and administrative	$	3,336		$	1,431
Depreciation		77			112
Other		(507	)		—
Total operating expenses	$	2,906		$	1,543

Operating expenses were approximately $2.9 million for the three months ended December 31, 2011 compared to approximately $1.5 million for the three months ended December 31, 2010. These expenses were primarily comprised of selling, general and administrative expense and depreciation expense which was partially offset by gain on disposal of property, plant and equipment.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were approximately $3.3 million for the three months ended December 31, 2011 compared to approximately $1.4 million for the three months ended December 31, 2010. This increase was primarily due to approximately $0.5 million in additional payroll of which approximately $0.3 million was payroll costs allocated to us by Rentech, approximately $0.4 million related to publicly traded limited partnership expenses, and an increase in accounting, internal audit, and tax services expenses of approximately $0.8 million due to our change in fiscal year end and becoming a publicly traded limited partnership.

Depreciation. Depreciation expense was approximately $0.1 million for the three months ended December 31, 2011 and 2010. A portion of depreciation expense is associated with assets supporting general and administrative functions and is recorded in operating expense. The majority of depreciation expense, as a manufacturing cost, is distributed between cost of sales and finished goods inventory, based on product volumes.

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Other. For the three months ended December 31, 2011, gain on disposal of property, plant and equipment was primarily due to the sale of tubes and catalyst removed during the turnaround in September and October 2011.

Operating Income

	For the Three Months Ended December 31,
	2011			2010
				(unaudited)
	(in thousands)
Operating income (loss):
Product shipments	$	25,726		$	14,584
Turnaround expenses		(2,957	)		—
Sales of excess inventory of natural gas		(121	)		—
Total operating income	$	22,648		$	14,584

Operating income was approximately $22.6 million for the three months ended December 31, 2011 compared to approximately $14.6 million for the three months ended December 31, 2010. Operating income from product shipments was approximately $25.7 million for the three months ended December 31, 2011 compared to approximately $14.6 million for the three months ended December 31, 2010. The increase in income from operations for product shipments was primarily due to higher sales prices, partially offset by lower margins received on sales of approximately 12,000 tons of ammonia purchased by barge, higher natural gas costs and higher operating expenses.

Other Income (Expense), Net

	For the Three Months Ended December 31,
	2011			2010
				(unaudited)
	(in thousands)
Other income (expense), net:
Interest expense	$	(1,947	)	$	(2,912	)
Loss on debt extinguishment		(10,263	)		(4,593	)
Other income, net		17			17
Total other expense, net	$	(12,193	)	$	(7,488	)

Other expense, net was approximately $12.2 million for the three months ended December 31, 2011 compared to approximately $7.5 million for the three months ended December 31, 2010. The increase in other expense, net for the three months ended December 31, 2011 as compared to the three months ended December 31, 2010 was primarily due to the larger loss on debt extinguishment primarily due to a higher amount of debt issuance costs written off and the payment of a call premium fee of approximately $2.9 million.

COMPARISON OF THE RESULTS OF OPERATIONS FOR THE FISCAL YEARS ENDED SEPTEMBER 30, 2011 AND 2010

Revenues

	For the Fiscal Years Ended September 30,
	2011		2010
	(in thousands)
Revenues:
Product shipments	$	179,400	$	129,392
Sales of excess inventory of natural gas		457		2,004
Total revenues	$	179,857	$	131,396

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	For the Fiscal  Year Ended September 30, 2011				For the Fiscal  Year Ended September 30, 2010
	Tons		Revenue		Tons		Revenue
	(in thousands)				(in thousands)
Product Shipments:
Ammonia		125	$	73,346		153	$	57,909
UAN		315		84,646		294		52,912
Urea (liquid and granular)		29		13,708		32		12,663
CO2		110		2,825		107		2,779
Nitric Acid		15		4,875		11		3,129
Total		594	$	179,400		597	$	129,392

Revenues were approximately $179.9 million for the fiscal year ended September 30, 2011 compared to approximately $131.4 million for the fiscal year ended September 30, 2010. This increase was primarily the result of higher prices paid for our products during fiscal year ended September 30, 2011, resulting from stronger demand for nitrogen fertilizer products during the period. Ammonia sales volumes decreased and UAN sales volumes increased during the fiscal year ended September 30, 2011 as we upgraded more ammonia into UAN to realize higher gross profit margins.

The average sales prices per ton in the current fiscal year as compared with the prior fiscal year increased by 56% and 49% for ammonia and UAN, respectively. These increases were due to higher demand caused by a combination of low levels of corn and fertilizer inventories and expectations of higher corn acreage in 2011. These two products comprised approximately 88% and 86%, respectively, of our product sales for each of the fiscal years ended September 30, 2011 and 2010.

Cost of Sales

	For the Fiscal Years Ended September 30,
	2011		2010
	(in thousands)
Cost of sales:
Product shipments	$	98,250	$	99,749
Turnaround expenses		4,490		3,955
Sales of excess inventory of natural gas		546		2,259
Simultaneous sale and purchase of natural gas		—		57
Total cost of sales	$	103,286	$	106,020

Cost of sales was approximately $103.3 million for the fiscal year ended September 30, 2011 compared to approximately $106.0 million for the fiscal year ended September 30, 2010. Cost of sales from product shipments was approximately $98.3 million for the fiscal year ended September 30, 2011, compared to approximately $99.7 million for the fiscal year ended September 30, 2010. The decrease in cost of sales on product shipments for the fiscal year ended September 30, 2011 compared to the fiscal year ended September 30, 2010 was primarily due to lower natural gas prices during the fiscal year ended September 30, 2011 and unplanned repairs and maintenance costs during the first quarter of fiscal 2010.

Natural gas costs comprised approximately 50% of cost of sales on product shipments for the fiscal year ended September 30, 2011 compared to 54% of cost of sales on product shipments for the fiscal year ended September 30, 2010. Labor costs comprised approximately 12% of cost of sales on product shipments for each of the fiscal years ended September 30, 2011 and 2010. Depreciation expense included in cost of sales was $9.6 million and $10.1 million for the fiscal years ended September 30, 2011 and 2010, respectively, and comprised approximately 10% of cost of sales on product shipments for each of the fiscal years ended September 2011 and 2010.

Turnaround expenses represent the cost of maintenance during turnarounds, which occur approximately every two years. A facility turnaround occurred in September and October 2011 and October 2009. As a result, during the fiscal years ended September 30, 2011 and 2010, we incurred turnaround expenses of approximately $4.5 million and $4.0 million, respectively. In October 2011, we expensed additional costs relating to the turnaround.

Natural gas, though not purchased for the purpose of resale, is occasionally sold under certain circumstances, such as when contracted quantities received exceed our production requirements or our storage capacity. In these situations, which we refer to as sales of excess inventory of natural gas, the sales proceeds are recorded as revenue and the related cost is recorded as a cost of sales.

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When the opportunity presents itself, we may also sell, to a third party at one location, natural gas that we have purchased or are required to purchase under fixed-price contracts and simultaneously purchase, at a different location and at a lower price, the same quantity of natural gas in order to capture an immediate benefit from the price differential between the two delivery points. We refer to these situations as a simultaneous sale and purchase of natural gas. The sale of gas in conjunction with a simultaneous purchase may be at a price lower (or higher) than the purchase price previously committed under a forward purchase contract, which may result in a loss (or profit) compared to the price required in the forward purchase contract. The natural gas is immediately repurchased at a lower price resulting in a lower cost of sales when inventory is sold. All or a portion of a loss relative to the forward purchase contract may be offset (or a profit increased) by a gain on the simultaneous sale and purchase transaction. None of these transactions occurred during the fiscal year ended September 30, 2011, and only a minor amount occurred during the fiscal year ended September 30, 2010.

Gross Profit

	For the Fiscal Years Ended September 30,
	2011			2010
	(in thousands)
Gross profit (loss):
Product shipments	$	81,150		$	29,643
Turnaround expenses		(4,490	)		(3,955	)
Sales of excess inventory of natural gas		(89	)		(255	)
Simultaneous sale and purchase of natural gas		—			(57	)
Total gross profit	$	76,571		$	25,376

Gross profit was approximately $76.6 million for the fiscal year ended September 30, 2011 compared to approximately $25.4 million for the fiscal year ended September 30, 2010. Gross profit margin on product shipments was 45% for the fiscal year ended September 30, 2011 as compared to 23% for the fiscal year ended September 30, 2010. This increase was primarily due to higher sales prices and lower natural gas prices during the fiscal year ended September 30, 2011 and unplanned repairs and maintenance costs during the first quarter of fiscal 2010.

Operating Expenses

	For the Fiscal Years Ended September 30,
	2011		2010
	(in thousands)
Operating expenses:
Selling, general and administrative	$	5,786	$	4,497
Depreciation		409		439
Other		522		51
Total operating expenses	$	6,717	$	4,987

Operating expenses were approximately $6.7 million for the fiscal year ended September 30, 2011 compared to approximately $5.0 million for the fiscal year ended September 30, 2010. These expenses were primarily comprised of selling, general and administrative expense, depreciation expense and loss on disposal of property, plant and equipment.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were approximately $5.8 million for the fiscal year ended September 30, 2011 compared to approximately $4.5 million for the fiscal year ended September 30, 2010. This increase was primarily due to additional audit and tax fees, administrative agent fees under our then-existing credit agreement and sales-based incentive bonuses.

Depreciation. Depreciation expense was approximately $0.4 million for the fiscal years ended September 30, 2011 and 2010. A portion of depreciation expense is associated with assets supporting general and administrative functions and is recorded in operating expense. The majority of depreciation expense, as a manufacturing cost, is distributed between cost of sales and finished goods inventory, based on product volumes.

Loss on Disposal of Property, Plant and Equipment. Loss on disposal or property, plant and equipment was approximately $0.5 million for the fiscal year ended September 30, 2011 compared to a gain of approximately $44,000 for the fiscal year ended September 30, 2010. This increase was primarily due to the removal of a selective catalyst recovery unit for approximately $0.9 million in the fiscal year ended September 30, 2011 which was partially offset by various miscellaneous sales and exchanges of nonmonetary assets totaling approximately $0.4 million in the fiscal year ended September 30, 2011.

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Operating Income

	For the Fiscal Years Ended September 30,
	2011			2010
	(in thousands)
Operating income (loss):
Product shipments	$	74,433		$	24,656
Turnaround expenses		(4,490	)		(3,955	)
Sales of excess inventory of natural gas		(89	)		(255	)
Simultaneous sale and purchase of natural gas		—			(57	)
Total operating income	$	69,854		$	20,389

Operating income was approximately $69.9 million for the fiscal year ended September 30, 2011 compared to approximately $20.4 million for the fiscal year ended September 30, 2010. Operating income from product shipments was approximately $74.4 million for the fiscal year ended September 30, 2011 compared to approximately $24.7 million for the fiscal year ended September 30, 2010. The increase in income from operations for product shipments was primarily due to higher sales prices and lower natural gas prices during the fiscal year ended September 30, 2011 and unplanned repairs and maintenance costs during the first quarter of fiscal 2010, partially offset by additional audit and tax fees, administrative agent fees under a former credit agreement REMC entered into during the fiscal year ended September 30, 2010, or our 2010 credit agreement, and sales-based incentive bonuses incurred during fiscal year ended September 30, 2011.

Other Income (Expense), Net

	For the Fiscal Years Ended September 30,
	2011			2010
	(in thousands)
Other income (expense), net:
Interest expense	$	(13,752	)	$	(9,859	)
Loss on debt extinguishment		(13,816	)		(2,268	)
Other income, net		55			91
Total other expense, net	$	(27,513	)	$	(12,036	)

Other expense, net was approximately $27.5 million for the fiscal year ended September 30, 2011 compared to approximately $12.0 million for the fiscal year ended September 30, 2010. During the fiscal year ended September 30, 2011, we had a loss on debt extinguishment of $4.6 million relating to a November 2010 amendment to our 2010 credit agreement. In June 2011, we had a loss on debt extinguishment of $9.2 million relating to a former credit agreement REMC entered into during the fiscal year ended September 30, 2011, or our 2011 credit agreement. Also, interest expense increased primarily due to higher outstanding principal balances under our 2010 credit agreement and our 2011 credit agreement.

Pasadena

RESULTS OF OPERATIONS FOR THE CALENDAR YEAR ENDED DECEMBER 31, 2012

The operations of the Pasadena Facility are only included in our historical results of operations from the closing date of the Agrifos Acquisition, which was November 1, 2012.

Revenues

	For the Calendar Year Ended December 31,
	2012
	(in thousands)
Total revenues	$	37,430

	For the Calendar Year Ended December 31, 2012
	Tons		Revenue
	(in thousands)
Revenues:
Ammonium sulfate		115	$	34,493
Sulfuric acid		27		2,586
Other		—		351
Total revenues		142	$	37,430

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We generate revenue primarily from sales of nitrogen fertilizer products manufactured at our Pasadena Facility and used in the production of corn, soybeans, potatoes, cotton, canola, alfalfa and wheat. The facility is designed to produce ammonium sulfate, sulfuric acid and ammonium thiosulfate.

Cost of Sales

	For the Calendar Year Ended December 31,
	2012
	(in thousands)
Total cost of sales	$	39,134

Cost of sales primarily consists of ammonia, sulfur, labor costs and depreciation. Ammonia, sulfur and labor costs comprised approximately 49%, 15% and 5%, respectively, of cost of sales for the calendar year ended December 31, 2012. Depreciation expense included in cost of sales was approximately $0.4 million. Cost of sales also includes maintenance expenses. Maintenance at the sulfuric acid plant occurred in November 2012. As a result, we incurred maintenance expenses of approximately $0.8 million. The maintenance was originally scheduled for the first calendar quarter of 2013, but due to two unexpected outages at the sulfuric acid plant, we decided to conduct the maintenance early. As a result of the two unexpected outages, we incurred approximately $0.5 million in additional expenses. The acquisition method of accounting required that the inventory be recognized at fair value as of the closing date of the Agrifos Acquisition. This resulted in the value of inventory, which was sold during the two-month period ended December 31, 2012, being increased by approximately $3.4 million.

Gross Profit

	For the Calendar Year Ended December 31,
	2012
	(in thousands)
Total gross loss	$	(1,704	)

Gross loss was primarily due to reduced margins due to the write-up of inventory to fair value, along with the turnaround expenses at the sulfuric acid plant and expenses related to two unexpected outages of the sulfuric acid plant.

Operating Expenses

	For the Calendar Year Ended December 31,
	2012
	(in thousands)
Operating expenses:
Selling, general and administrative	$	361
Depreciation and amortization	$	583
Total operating expense	$	944

Operating expenses were approximately $0.9 million. These expenses were primarily comprised of selling, general and administrative expense and depreciation expense.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were approximately $0.4 million. These expenses are for general administrative purposes at our Pasadena Facility, such as legal, consulting and banking fees.

Depreciation and Amortization. Amortization expense was approximately $0.6 million. This amount represents amortization of the intangible assets. The depreciation expense relating to fixed assets is a manufacturing cost which is distributed between cost of sales and finished goods inventory, based on product volumes.

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Operating Loss

	For the Calendar Year Ended December 31,
	2012
	(in thousands)
Total operating loss	$	(2,648	)

LIQUIDITY AND CAPITAL RESOURCES

Our principal source of liquidity has historically been cash from operations. We expect to fund our operating needs, including maintenance capital expenditures, from operating cash flow, cash on hand and borrowings under our new 2012 credit agreement. 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. Through borrowings under our new 2012 credit agreement, we intend to fund a substantial portion of the costs of the following projects: our ammonia production and storage capacity expansion project and our nitric acid project at our East Dubuque Facility; and our ammonium sulfate debottlenecking and production capacity project, and our power generation project at our Pasadena Facility. Depending on conditions in the capital markets, we may seek external funding during the next 12 months to refinance our existing indebtedness, fund capital expenditures or supplement our working capital, including financing from the issuance of common units or debt securities. Further, in the event that we pursue any other expansion projects or acquisitions, we would likely require external financing, similar to the external financing required in connection with the Agrifos Acquisition. External financing sources for expansion projects and acquisitions could include equity or debt, including loans from Rentech. There is no assurance that external financing sources would be available when needed.

Distributions

We intend to distribute all of the cash available for distribution we generate each quarter to our unitholders, which could materially impact our liquidity and limit our ability to grow and make acquisitions. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that cash available for distribution for each quarter will generally equal the cash we generate during the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. As a result of our quarterly distributions, our liquidity will be significantly affected, and we expect to finance substantially all of our growth externally, either with commercial bank borrowings or by debt issuances or additional issuances of equity. However, our partnership agreement does not require us to pay cash distributions on a quarterly or other basis, and we may change our distribution policy at any time and from time to time.

On May 15, 2012, we made a cash distribution to our common unitholders and payments to holders of phantom units for the period November 9, 2011 through and including March 31, 2012 of $1.06 per unit or approximately $40.7 million in the aggregate. On August 14, 2012, we made a cash distribution to our common unitholders and payments to holders of phantom units for the period April 1, 2012 through and including June 30, 2012 of $1.17 per unit or approximately $45.0 million in the aggregate. On November 14, 2012, we made a cash distribution to our common unitholders and payments to holders of phantom units for the period July 1, 2012 through and including September 30, 2012 of $0.85 per unit or approximately $33.1 million in the aggregate.

On January 23, 2013, the board of directors of our general partner declared a cash distribution to our common unitholders and payments to holders of phantom units for the period October 1, 2012 through and including December 31, 2012 of $0.75 per unit or approximately $29.2 million in the aggregate. The cash distribution was paid on February 14, 2013, to unitholders of record at the close of business on February 7, 2013.

Credit Agreements

On October 31, 2012, RNLLC, the Partnership, RNPLLC and certain subsidiaries of RNPLLC entered into the new 2012 credit agreement. The new 2012 credit agreement amended, restated and replaced the 2012 credit agreement.

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The new 2012 credit agreement consists of (i) the new term loan of $155.0 million that was used to finance the cash consideration paid in the Agrifos Acquisition and transaction expenses, (ii) the $110.0 million new capex facility which can be used to pay for capital expenditures related to the ammonia production and storage capacity expansion at our East Dubuque Facility and capital expenditures related to our Pasadena Facility (in an amount up to $10.0 million), and (iii) the $35.0 million new 2012 revolving credit facility that can be used for working capital needs, letters of credit and for general corporate purposes.

The new 2012 credit agreement has a maturity date of October 31, 2017. Borrowings under the new 2012 credit agreement bear interest at a rate equal to an applicable margin plus, at RNLLC’s option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.5% or (3) LIBOR for an interest period of three months plus 1.00% or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period on the day that is two business days prior to the first day of such interest period. The applicable margin for borrowings under the new 2012 credit agreement is 2.75% with respect to base rate borrowings and 3.75% with respect to LIBOR borrowings. Additionally, we are required to pay a fee to the lenders under the new capex facility on the undrawn available portion at a rate of 0.75% per annum and a fee to the lenders under the new 2012 revolving credit facility on the undrawn available portion at a rate of 0.50% per annum. We also are required to pay customary letter of credit fees on issued letters of credit.

The new 2012 revolving credit facility includes a letter of credit sublimit of $10.0 million and it can be drawn on or letters of credit can be issued through the day that is seven days prior to the maturity date. The amounts outstanding under the new 2012 revolving credit facility will be required to be reduced to zero (other than outstanding letters of credit) for three periods of ten consecutive business days during each year with each period not less than four months apart, and one period to begin each April.

The principal amount of the new term loan must be paid in equal quarterly installments of approximately $1.9 million on the first day of each fiscal quarter beginning on January 1, 2013, with the final principal payment in the amount of the remaining outstanding principal balance due upon maturity.

The new capex facility is available for borrowing until February 27, 2014 and requires quarterly amortization payments expected to begin in the spring of 2014. In the first two years of amortization, we must make amortization payments of 10% per year, or 2.5% per quarter, and thereafter, 25% per year, or 6.25% per quarter of the aggregate amount drawn, in each case with the final principal payment due upon maturity.

Borrowings under the new 2012 credit agreement will be subject to mandatory prepayment under certain circumstances, with customary exceptions, from the proceeds of permitted dispositions of assets and from certain insurance and condemnation proceeds.

All obligations of our operating companies under the new 2012 credit agreement are unconditionally guaranteed by us. All obligations under the new 2012 credit agreement and the guarantees of those obligations are secured by substantially all of our operating companies’ assets, as well as substantially all our assets (including our equity interest in our operating companies).

The new 2012 credit agreement also contains customary representations and warranties, affirmative and negative covenants and events of default relating to us and our operating companies and our respective subsidiaries. The covenants and events of default include, among other things, compliance with environmental laws, limitations on the incurrence of indebtedness and liens, the making of investments, the sale of assets and the making of restricted payments. The new 2012 credit agreement also contains specific provisions limiting RNHI, the sole member of our general partner, from engaging in certain business activities and owning certain property, and events of default relating to a change in control in the event Rentech ceases to appoint the majority of the board of directors of both RNHI and our general partner. Dividends and distributions from our operating companies and us are permitted so long as (1) no default or event of default has occurred, exists or will result therefrom and (2) our operating companies certify to the new 2012 credit agreement’s administrative agent pro forma compliance with the terms of the new 2012 credit agreement, including its financial covenants, as of the date of such dividend or distribution.

The new 2012 credit agreement expires on October 31, 2017 and requires us and our subsidiaries to meet the following financial covenants (and failure to meet such covenants could result in acceleration of the outstanding loans):

• Maximum Total Leverage Ratio (defined as our and our subsidiaries’ total debt on a consolidated basis, divided by Adjusted EBITDA (as defined in the new 2012 credit agreement)) of not greater than 2.5 to 1.0 as of the end of each fiscal quarter for the 12 month period then ending. As of December 31, 2012, our actual Total Leverage Ratio was 0.4 to 1.0.

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• Maintenance of a Minimum Fixed Charge Coverage Ratio (defined as (a) Adjusted EBITDA (as defined in the new 2012 credit agreement) minus our and our subsidiaries’ unfinanced capital expenditures on a consolidated basis, divided by (b) the sum of (i) interest expense paid or accrued, (ii) scheduled principal payments and (iii) taxes paid or payable of us and ours subsidiaries in each case and (iv) cash payments of the Supplemental Purchase Price (as defined in the new 2012 credit agreement) for the Agrifos Acquisition) of not less than 1.0 to 1.0 as of the end of each fiscal quarter for the 12 month period then ending. As of December 31, 2012, our actual Fixed Charge Coverage Ratio was 57.3 to 1.0.

Capital Expenditures

We divide our capital expenditures into two categories: maintenance and expansion capital expenditures. Maintenance capital expenditures include expenditures for improving, replacing or adding to our assets, as well as expenditures for the acquisition, construction or development of new assets to maintain our operating capacity, or to comply with environmental, health, safety or other regulations. Maintenance capital expenditures that are required to comply with regulations may also improve the output, efficiency or reliability of our facility. Expansion capital expenditures are capital expenditures incurred for acquisitions or capital improvements that we expect will increase our operating capacity or operating income over the long term.

Our maintenance capital expenditures for our East Dubuque Facility totaled approximately $7.9 million in the calendar year ended December 31, 2012, $2.5 million and $2.7 million in the three months ended December 31, 2011 and December 31, 2010, respectively, and $24.5 million and $9.9 million in the fiscal years ended September 30, 2011 and 2010, respectively. Our maintenance capital expenditures for our East Dubuque Facility are expected to be approximately $9.1 million for the year ending December 31, 2013. Our expansion capital expenditures for our East Dubuque Facility totaled approximately $52.4 million in the calendar year ended December 31, 2012 and $1.9 million and $0 in the three months ended December 31, 2011 and December 31, 2010, respectively. Our expansion capital expenditures for our East Dubuque Facility are expected to be approximately $55.0 million for the year ending December 31, 2013 and are expected to be related to our ammonia production and storage capacity expansion project and our nitric acid project. We expect that the ammonia production and storage capacity expansion project could cost approximately $100.0 million. The new 2012 credit agreement, which includes a $110.0 million new capex facility which can be used for this project. We intend to use borrowings under the new capex facility to fund the ammonia production and storage capacity expansion project. We expect that the nitric acid project could cost approximately $2.0 million, with approximately $1.6 million expended in 2013, and will be completed during the first quarter of 2014. Our urea expansion project and DEF build-out project were completed in 2012 at a collective cost of approximately $6.3 million.

Our maintenance capital expenditures for our Pasadena Facility are expected to be approximately $7.0 million for the year ending December 31, 2013. The $7.0 million of maintenance capital expenditures excludes the cost to replace the sulfuric acid converter at the sulfuric acid plant at our Pasadena Facility. We intend to begin the project to replace the converter during the third quarter of 2013, and to complete it during 2014 for an estimated cost of between approximately $15.0 million to $20.0 million. However, the commencement of this project is subject to the approval of the board of directors of our general partner. If approved by the board, approximately 60% of the cost of this project would be expended in 2013 increasing our expected maintenance capital expenditures for the Pasadena Facility during 2013. We will need external funding in order to undertake this project. Our expansion capital expenditures for our Pasadena Facility are expected to be approximately $22.0 million for the year ending December 31, 2013 for expenditures related to the ammonium sulfate debottlenecking and production capacity project and the power generation project. We expect the ammonium sulfate debottlenecking and production capacity project could cost approximately $6.0 million to complete resulting in increased capacity by the end of 2013. We expect the power generation project could cost approximately $30.0 million to complete and will be completed in the fall of 2014. We intend to use borrowings under the accordion facility and new capex facility to fund these projects. The new 2012 credit agreement includes a $35.0 million accordion facility, which allows us to borrow additional funds from any of the lenders, if such lenders agree to lend such amount, and have such borrowings included under the terms of the new 2012 credit agreement. If the lenders do not agree to lend amounts under the accordion facility to us, we would need to seek alternative sources of funding for the expansion projects. Depending on conditions in the capital markets, we also may seek external funding, among other things, to finance a portion of the costs of these projects, including financing from the issuance of common units or debt securities. However, there is no assurance that these sources of capital would be available to us.

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

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CASH FLOWS

Operating Activities

Revenues were approximately $261.6 million for the calendar year ended December 31, 2012 compared to approximately $199.9 million for the calendar year ended December 31, 2011. The increase in revenue for the calendar year ended December 31, 2012 compared to the calendar year ended December 31, 2011 was primarily due to the Agrifos Acquisition, increased sales prices for all of the East Dubuque Facility’s products and increased sales volume for ammonia, partially offset by a decrease in sales volume for UAN. Deferred revenue decreased by $4.0 million during the calendar year ended December 31, 2012. The decrease was a result of a decrease in our Pasadena Facility’s deferred revenue by approximately $5.0 million due to completing a high volume of sales, which was partially offset by an increase in our East Dubuque Facility’s deferred revenue by approximately $1.0 million. The increase in our East Dubuque Facility’s deferred revenue occurred because an unscheduled plant outage at the end of 2012 made us unable to fulfill all fall 2012 product prepayment contracts before December 31, 2012 and the resulting extension of a portion of its fall 2012 product prepayment contracts into the first calendar quarter of 2013.

Revenues were approximately $63.0 million for the three months ended December 31, 2011 compared to approximately $43.0 million for the three months ended December 31, 2010. This increase was primarily the result of higher prices paid for our products during the three months ended December 31, 2011. Deferred revenue decreased $13.8 million during the three months ended December 31, 2011, versus an increase of $17.0 million during the three months ended December 31, 2010. The decrease during the three months ended December 31, 2011 was a result of a high volume of prepaid shipments resulting from the normal seasonality of our business, and due to the fact that few new contracts were signed during the period, as compared to the three months ended December 31, 2010. In comparison, the balance increased during the three months ended December 31, 2010 due to signing a significant number of new contracts during the period, partially offset by the fulfillment of product prepayment contracts during the three months ended December 31, 2010.

Revenues were approximately $179.9 million for the fiscal year ended September 30, 2011 compared to approximately $131.4 million for the fiscal year ended September 30, 2010. This increase was primarily the result of higher prices paid for our products during fiscal year ended September 30, 2011, resulting from stronger demand for nitrogen fertilizer products during the period. Deferred revenue increased $19.6 million during the fiscal year ended September 30, 2011, versus a decrease of $3.7 million during the fiscal year ended September 30, 2010. This increase in deferred revenue was due to higher prepaid sales prices in fiscal year 2011 than in fiscal year 2010, and also a higher quantity of ammonia and UAN product presold in fiscal year 2011. The increase in revenues and deferred revenue from fiscal year 2010 to fiscal year 2011 are the primary reasons net cash flow from operating activities increased from $20.1 million in fiscal year 2010 to $83.7 million in fiscal year 2011.

Our profits, operating cash flows and cash available for distribution are subject to changes in the prices of our products and our primary feedstocks, natural gas for the East Dubuque Facility and ammonia, sulfuric acid and sulfur for the Pasadena Facility. Our products and feedstocks are commodities and, as such, their prices can be volatile in response to numerous factors outside of our control. In addition, the timing of product prepayment contracts and associated cash receipts are factors largely outside of our control that affect our profits, operating cash flows and cash available for distribution.

Net cash provided by operating activities for the calendar year ended December 31, 2012 was approximately $132.5 million. We had net income of approximately $107.0 million for the calendar year ended December 31, 2012. During this period, we entered into our new 2012 credit agreement and paid off the outstanding principal balance under our 2012 credit agreement. This transaction resulted in a loss on the extinguishment of debt of approximately $2.1 million. We also had unit-based compensation expense relating to our common units of approximately $2.8 million. Deposits on natural gas contracts decreased by approximately $2.8 million due to obtaining lines of credit with two natural gas vendors that had previously required prepayment. Accounts payable increased by approximately $1.0 million primarily due to an increase in East Dubuque Facility’s accounts payable of approximately $3.1 million resulting from approximately $2.3 million more in natural gas payables due to obtaining lines of credit with two natural gas vendors that had previously required prepayment, and approximately $0.5 million in lime removal costs, which was partially offset by a decrease in Pasadena Facility’s accounts payable of approximately $2.1 million through normal payment of invoices. Accrued liabilities decreased by approximately $4.7 million due to a decrease in Pasadena Facility’s accrued liabilities of approximately $9.1 million primarily due to the payment of bonuses of approximately $7.2 million, which was partially offset by an increase in East Dubuque Facility’s accrued liabilities primarily from amounts due to customers for recent overpayments and refunds on product prepayment contracts that we chose to cancel.

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Net cash used by operating activities for the three months ended December 31, 2011 was approximately $6.0 million. We had net income of $10.5 million for the three months ended December 31, 2011. During this period, we used a portion of the net proceeds from our initial public offering to repay in full the term loans outstanding under our 2011 credit agreement, including approximately $2.9 million to pay the associated prepayment penalty fees. This transaction resulted in a loss on debt extinguishment of $10.3 million. Accounts receivable increased by approximately $2.9 million due to higher sales volumes in the three months ended December 31, 2011 than in the three months ended September 30, 2011, due to normal seasonality of the business and our facility being down for a turnaround during the second half of September 2011. Inventories decreased by approximately $11.2 million due to a high volume of product sales during this quarter, which was due to the normal seasonality of our business. Deferred revenue decreased by approximately $13.8 million as a result of deliveries on product prepayment contracts being higher than the signing of new product prepayment contracts during the period due to the normal seasonality of our business, and due to the fact that few new product prepayment contracts were signed during the period. Accrued liabilities, accrued payroll and other liabilities decreased by approximately $1.6 million due to a large amount of accruals at September 30, 2011 related to turnaround costs.

Net cash provided by operating activities for the three months ended December 31, 2010 was approximately $23.7 million. We had net income of $4.3 million for the three months ended December 31, 2010. During this period, we entered into the second amendment to our 2010 credit agreement and repaid a portion of the principal outstanding under our 2010 credit agreement. This transaction resulted in a loss on the extinguishment of debt of $4.6 million. Accounts receivable increased by approximately $7.0 million due to higher sales volume leading up to December 31, 2010 than up to September 30, 2010, due to normal seasonality of the business and due to a large increase in UAN sales prices beginning in October 2010. Inventories decreased by approximately $1.5 million due to a high volume of product sales during this quarter which was attributable to the normal seasonality of our business. This decrease was less than the decrease we typically experience during this period due to low inventory levels leading into the period, caused by unusually high sales volume the previous summer. Deferred revenue increased by approximately $17.0 million due to a significant number of new contracts that were signed during the period, partially offset by the fulfillment of product prepayment contracts during the three months ended December 31, 2010.

Net cash provided by operating activities for the fiscal year ended September 30, 2011 was approximately $83.7 million. We had net income of $24.9 million for the fiscal year ended September 30, 2011. During this period, we entered into the second amendment to our 2010 credit agreement and repaid a portion of the principal outstanding under our 2010 credit agreement. This transaction resulted in a loss on the extinguishment of debt of $4.6 million. We also entered into our 2011 credit agreement during this period and paid off the outstanding principal balance under our 2010 credit agreement. This transaction resulted in a loss on debt extinguishment of $9.2 million. These two transactions resulted in a total loss on debt extinguishment of $13.8 million. During the fiscal year ended September 30, 2011, we used $8.3 million of proceeds from our 2011 credit agreement to pay the prepayment penalty fee resulting from the prepayment of term loans outstanding under our 2010 credit agreement. During the fiscal year ended September 30, 2011, accounts receivable decreased by $5.0 million, due to having a high volume of summer sales in fiscal year ended September 30, 2010 which increased the September 30, 2010 balance. Accounts payable and accrued liabilities increased by $0.4 million and $4.6 million, respectively, during the fiscal year ended September 30, 2011 due to significant vendor invoices and accruals for turnaround activities in September 2011, as well as for significant capital expenditures during the turnaround. Inventories increased $9.2 million during the fiscal year ended September 30, 2011 due to having more summer sales contracts in fiscal year 2010, whereas in fiscal year 2011, it followed the normal seasonal trend of having more fall sales contracts, requiring high inventory levels at September 30, 2011 to fulfill those contracts. Deferred revenue increased $19.6 million during the fiscal year ended September 30, 2011. The increase was due to higher prepaid sales prices in the fiscal year ended September 30, 2011 than in the fiscal year ended September 30, 2010, and also a higher quantity of ammonia and UAN product presold in the fiscal year ended September 30, 2011.

Net cash provided by operating activities for the fiscal year ended September 30, 2010 was $20.1 million. We had net income of $5.0 million for fiscal year 2010. During the fiscal year ended September 30, 2010, we entered into our 2010 credit agreement, the proceeds from which were used to repay in full the term loan under the credit agreement we entered into in fiscal year 2008, or our 2008 credit agreement. This transaction resulted in a loss on the extinguishment of debt of $2.3 million. During the fiscal year ended September 30, 2010, accounts receivable increased by $0.9 million due to high summer sales volume, mainly resulting from some large shipments by barge. During the fiscal year ended September 30, 2009, we recorded a property insurance claim receivable for insured property losses related to a weather-related shutdown of our facility in January 2009. During the fiscal year ended September 30, 2010, we collected the outstanding balance of $1.8 million. Inventories decreased during the fiscal year ended September 30, 2010 by $4.7 million due to a combination of inventory levels having been high leading into the fiscal year from a seasonal build-up of inventory prior to the fall ammonia application season and reduction of inventories from higher than normal sales volumes during the summer of 2010, mainly due to some large shipments by barge. This was partially offset by higher costs of natural gas associated with product held in inventory. Deposits on natural gas purchase contracts increased by $1.6 million during the fiscal year ended September 30, 2010 due to timing of purchases and vendor selection, which impact payment terms. Deferred revenue resulting from product pre-sales decreased $3.7 million during the fiscal year ended September 30, 2010 due to timing of cash receipts on fall product prepayment contracts.

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Investing Activities

Net cash used in investing activities was approximately $186.8 million, $11.6 million, $2.2 million, $17.4 million and $11.6 million, respectively, for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and 2010, and the fiscal years ended September 30, 2011 and 2010. In the calendar year ended December 31, 2012, we paid approximately $128.6 million, net of cash received, for the Agrifos Acquisition. The amount for purchase of property, plant, equipment and construction in progress of approximately $57.6 million for the calendar year ended December 31, 2012 relates primarily to the ammonia production and storage capacity expansion project, the urea expansion project and the DEF build-out. The increase in net additions of $9.4 million for the three months ended December 31, 2011 compared to the three months ended December 31, 2010 was primarily due to capital projects completed during the turnaround at the East Dubuque Facility. The increase in net additions of $5.8 million for the fiscal year ended September 30, 2011 compared to the fiscal year ended September 30, 2010 was primarily due to capital projects undertaken during the turnaround which was started in September of 2011.

Financing Activities

Net cash provided by financing activities was approximately $65.2 million for the calendar year ended December 31, 2012. During the calendar year ended December 31, 2012, we had borrowings under our new 2012 credit agreement and our 2012 credit agreement which totaled approximately $222.8 million and repaid borrowings under our 2012 credit agreement of approximately $29.5 million. We also made distributions of approximately $118.8 million.

Net cash provided by (used in) financing activities was approximately $11.0 million and ($19.8 million), respectively, for the three months ended December 31, 2011 and 2010. During the three months ended December 31, 2011, we completed our initial public offering, which raised a total of $300.0 million in gross proceeds, and approximately $276.0 million in net proceeds after deducting underwriting discounts and commissions of $21.0 million and offering expenses of approximately $3.0 million, excluding approximately $1.0 million in offering expenses paid prior to September 30, 2011. We also repaid in full and terminated our 2011 credit agreement, which had an outstanding principal balance of $146.3 million, and made distributions of $117.4 million. During the three months ended December 31, 2010, concurrently with entering into the second amendment to our 2010 credit agreement, we and Rentech entered into a second incremental loan assumption agreement to borrow an additional $52.0 million, with an original issue discount of $1.0 million. We also prepaid $20.0 million of outstanding principal in connection with the second amendment to our 2010 credit agreement, from cash on hand that we had reserved for such purpose, and made $2.5 million in scheduled principal payments.

Net cash used in financing activities was approximately $49.8 million and $10.3 million, respectively, for the fiscal years ended September 30, 2011 and 2010. During the fiscal year ended September 30, 2011, concurrently with entering into the second amendment to our 2010 credit agreement, we and Rentech entered into a second incremental loan assumption agreement to borrow an additional $52.0 million, with an original issue discount of $1.0 million. We also entered into our 2011 credit agreement pursuant to which we borrowed $150.0 million, $85.4 million of which was used to pay off the outstanding principal balance under our 2010 credit agreement. Additionally, for the fiscal year ended September 30, 2011, in addition to $8.7 million of scheduled principal payments, we prepaid $20.0 million of outstanding principal in connection with the second amendment to our 2010 credit agreement, from cash on hand that we had reserved for such purpose, and $5.0 million as a mandatory prepayment in connection with the $5.0 million dividend paid by us to Rentech. During the fiscal year ended September 30, 2010, we replaced our 2008 credit agreement, which had an outstanding balance of $37.1 million and issuance costs of $0.9 million, with the net proceeds from our 2010 credit agreement, which had an initial principal amount of $62.5 million. Our 2010 credit agreement was amended on July 21, 2010 resulting in the increase of the principal balance to $67.5 million. Our 2010 credit agreement had an aggregate original issue discount amount of $3.1 million.

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CONTRACTUAL OBLIGATIONS

The following table lists our significant contractual obligations and their future payments at December 31, 2012:

Contractual Obligations	Total		Less than 1  Year		1-3 Years		3-5 Years		More than 5  Years
	(in thousands)
New 2012 credit agreement (1)	$	193,290	$	7,750	$	22,201	$	163,339	$	—
Earn-out consideration (2)		4,920		—		4,920		—		—
Natural gas (3)		7,531		7,531		—		—		—
Purchase obligations (4)		18,399		18,399		—		—		—
Asset retirement obligation (5)		3,089		2,776		—		—		313
Operating leases		314		263		50		1		—
Gas and electric fixed charges (6)		1,917		913		1,004		—		—
EPA penalties (7)		720		720		—		—		—
Pension plans and postretirement plan (8)		206		206		—		—		—
Total	$	230,386	$	38,558	$	28,175	$	163,340	$	313

(1)    As of the date of this report, there is approximately $207.6 million of principal outstanding under the new 2012 credit agreement.

(2)    We entered into the Purchase Agreement relating to the Agrifos Acquisition which, among other things, provides for the potential payment of earn-out consideration calculated based on the amount by which the two-year Adjusted EBITDA, as defined in the Purchase Agreement, of the Pasadena Facility exceeds certain Adjusted EBITDA thresholds. The amount reflected in the table reflects our current estimate of the amount of the earn-out consideration we will be required to pay. Depending on the two-year Adjusted EBITDA amounts, such additional earn-out consideration may vary from zero to a maximum of $50.0 million. The potential additional consideration would be paid after April 30, 2015 and completion of the relevant calculations in either common units or cash at the option of the Partnership.

(3)    As of December 31, 2012, the natural gas forward purchase contracts included delivery dates through March 31, 2013. Subsequent to December 31, 2012 through February 28, 2013, we entered into additional fixed-quantity forward purchase contracts at fixed and indexed prices for various delivery dates through April 30, 2013. The total MMBtus associated with these additional forward purchase contracts are approximately 1.0 million and the total amount of the purchase commitments are approximately $3.2 million, resulting in a weighted average rate per MMBtu of approximately $3.38. We are required to make additional prepayments under these forward purchase contracts in the event that market prices fall below the purchase prices in the contracts.

(4)    The amount presented represents certain open purchase orders with our vendors. Not all of our open purchase orders are purchase obligations, since some of the orders are not enforceable or legally binding on us until the goods are received or the services are provided.

(5)    We have recorded asset retirement obligations, or AROs, related to future costs associated with the removal of contaminated material upon removal of the phosphorous plant at our Pasadena Facility and handling and disposal of asbestos at our East Dubuque Facility. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to operating expense and the capitalized cost is depreciated over the remaining useful life of the asset. The obligation at our Pasadena Facility is considered short-term due to covenants in our new 2012 credit agreement. Since we own our East Dubuque Facility and currently have no plans to dispose of the property, the obligation is considered long-term and, therefore, considered to be incurred more than five years after December 31, 2012.

(6)    As part of the gas transportation and electric supply contracts at our East Dubuque Facility, we must pay monthly fixed charges over the term of the contracts.

(7)    The EPA issued in December 2011 a CAFO concerning hazardous waste management and air emissions at the Pasadena Facility which imposed civil penalties of $1.8 million plus interest. Pursuant to this CAFO, penalties of approximately $0.7 million were paid prior to the closing of the Agrifos Acquisition, we were obligated to pay penalties of approximately $0.4 million in December 31, 2012, and we are obligated to pay penalties of approximately $0.7 million by December 31, 2013. All amounts to be paid under this CAFO after the closing of the Agrifos Acquisition were covered by the Seller through adjustment of the purchase price.

(8)    We expect to contribute approximately $109,000 and $97,000 to pension plans and a postretirement plan, respectively, in 2013. We acquired these plans as part of the Agrifos Acquisition.

OFF-BALANCE SHEET ARRANGEMENTS

We did not have any material off-balance sheet arrangements as of December 31, 2012.

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RECENT ACCOUNTING PRONOUNCEMENTS FROM FINANCIAL STATEMENT DISCLOSURES

In May 2011, the Financial Accounting Standards Board, or the FASB, issued guidance clarifying the application of existing fair value measurement and disclosure requirements, as well as changing certain measurement requirements and disclosures. This guidance became effective during interim and annual periods beginning after December 15, 2011, and thus became effective for our reporting periods beginning on January 1, 2012. The adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or disclosures.

In February 2013, the FASB issued guidance requiring companies to disclose information about amounts reclassified out of accumulated other comprehensive income and their corresponding effect on net income. This guidance is effective for interim and annual periods beginning after December 15, 2012. It is effective for our interim period beginning on January 1, 2013. The adoption of this guidance is not expected to have a material impact on our consolidated financial position, results of operations or disclosures.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk. We are exposed to interest rate risks related to the new 2012 credit agreement. The borrowings under the new 2012 credit agreement bear interest at a rate equal to an applicable margin, plus at RNLLC’s option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.5% and (3) the LIBOR for an interest period of three months plus 1.00% or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. The applicable margin for borrowings under the new 2012 credit agreement is 2.75% with respect to base rate borrowings and 3.75% with respect to LIBOR borrowings. As of December 31, 2012, we had outstanding borrowings under our new 2012 credit agreement of approximately $193.3 million. Based upon this outstanding balance, and assuming interest rates are above the applicable minimum and no interest rate swaps, an increase or decrease by 100 basis points of interest would result in an increase or decrease in annual interest expense of approximately $1.9 million. Historically, we did not use interest rate derivative instruments to manage exposure to interest rate changes. On April 2, 2012, we entered into two interest rate swaps in notional amounts which now cover a portion of the borrowings under our new capex facility. The initial forward starting interest rate swap started on September 1, 2012 and will terminate on September 1, 2013. The second forward starting interest rate swap will start on September 30, 2013 and terminate on December 31, 2015. Through the two interest rate swaps, we are essentially fixing the variable interest rate to be paid on a portion of the borrowings under our new capex facility. At December 31, 2012, the fair value of the interest rate swaps was a liability of approximately $0.9 million. An increase of 100 basis points in the LIBOR rates would result in the liability for interest rate swaps decreasing by approximately $0.7 million. A decrease of 100 basis points in the LIBOR rates would result in the liability for interest rate swaps increasing by approximately $0.8 million.

Commodity Price Risk. Our East Dubuque Facility is exposed to significant market risk due to potential changes in prices for fertilizer products and natural gas. Natural gas is the primary raw material used in the production of various nitrogen-based products manufactured at our East Dubuque Facility. Market prices of nitrogen-based products are affected by changes in the prices of commodities such as corn and natural gas as well as by supply and demand and other factors. Currently, we purchase natural gas for use in our East Dubuque Facility on the spot market, and through short-term, fixed supply, fixed price and index price purchase contracts. Natural gas prices have fluctuated during the last several years, increasing substantially in 2008 and subsequently declining to the current lower levels. A hypothetical increase of $0.10 per MMBtu of natural gas would increase the cost to produce one ton of ammonia by approximately $3.50.

In the normal course of business, we currently produce nitrogen-based fertilizer products throughout the year to supply the needs of our East Dubuque Facility’s customers during the high-delivery-volume spring and fall seasons. The value of fertilizer product inventory is subject to market risk due to fluctuations in the relevant commodity prices. We believe that market prices of nitrogen products are affected by changes in grain prices and demand, natural gas prices and other factors.

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We enter into product prepayment contracts committing our East Dubuque Facility’s customers to purchase our nitrogen fertilizer products at a later date. To a lesser extent, we also enter into product prepayment contracts for our Pasadena Facility’s products. By using fixed-price forward contracts, we purchase approximately enough natural gas to manufacture the products that have been sold by our East Dubuque Facility under product prepayment contracts for later delivery. We believe that entering into such fixed-price contracts for natural gas and product prepayment contracts effectively allows us to fix most of the gross margin on pre-sold product and mitigate risk of increasing market prices of natural gas or decreasing market prices of nitrogen products. However, this practice also subjects us to the risk that we may have locked in margins at levels lower than those that might be available if, in periods following these contract dates, natural gas prices were to fall, or nitrogen fertilizer commodity prices were to increase. In addition, we occasionally make forward purchases of natural gas that are not directly linked to specific product prepayment contracts. To the extent we make such purchases, we may be unable to benefit from lower natural gas prices in subsequent periods.

Our Pasadena Facility is exposed to significant market risk due to potential changes in prices for fertilizer products, and for ammonia, sulfuric acid and sulfur. Ammonia and sulfuric acid are the primary raw materials used in the production of ammonium sulfate which is the primary product manufactured at our Pasadena Facility. Sulfur is the primary raw material used in the production of sulfuric acid, which our Pasadena Facility produces for both internal consumption in the production of ammonium sulfate and for sales to third parties. During the calendar year ended December 31, 2012, 75% of the sulfuric acid used in our Pasadena Facility’s production of ammonium sulfate was produced at our Pasadena Facility. The market price of ammonium sulfate is affected by changes in the prices of commodities such as soybeans, potatoes, cotton, canola, alfalfa, corn, wheat, ammonia and sulfur as well as by supply and demand and other factors such as the price of its other inputs. The margins on the sale of ammonium sulfate fertilizer products are relatively low. If our costs to produce ammonium sulfate fertilizer products increase and the prices at which we sell these products do not correspondingly increase, our profits from the sale of these products may decrease and we may suffer losses on these sales. A hypothetical increase of $10.00 per ton of ammonia would increase the cost to produce one ton of ammonium sulfate by approximately $2.50. A hypothetical increase of $10.00 per ton of sulfur would also increase the cost to produce one ton of ammonium sulfate by approximately $2.50.

Our Pasadena Facility purchases ammonia as a feedstock at contractual prices based on a published Tampa, Florida market index, while the East Dubuque Facility sells similar quantities of ammonia at prevailing prices in the Mid Corn Belt, which are typically significantly higher than Tampa ammonia prices. Because we both buy and sell similar quantities of ammonia, we believe that our consolidated exposure to the fluctuations in ammonia prices is lower than is the exposure to ammonia prices of either of our facilities considered alone.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

RENTECH NITROGEN PARTNERS, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Financial Statements of Rentech Nitrogen Partners, L.P.:
Report of Independent Registered Public Accounting Firm		82
Consolidated Balance Sheets		83
Consolidated Statements of Income		84
Consolidated Statements of Comprehensive Income		85
Consolidated Statements of Stockholder’s Equity (Deficit) / Partners’ Capital		86
Consolidated Statements of Cash Flows		87
Notes to Consolidated Financial Statements

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of Rentech Nitrogen GP, LLC and Unitholders of Rentech Nitrogen Partners, L.P.

In our opinion, the accompanying consolidated balance sheets as of December 31, 2012 and 2011 and the related consolidated statements of income, of comprehensive income, of stockholder’s equity (deficit) / partners’ capital and of cash flows for the year ended December 31, 2012, three months ended December 31, 2011 and fiscal years ended September 30, 2011 and 2010 present fairly, in all material respects, the financial position of Rentech Nitrogen Partners, L.P. and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for the year ended December 31, 2012, three months ended December 31, 2011, and the fiscal years ended September 30, 2011 and 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Annual Report on Internal Control Over Financial Reporting, management has excluded its wholly owned subsidiary, RNPLLC from its assessment of internal control over financial reporting as of December 31, 2012 because the entity was acquired by the Company in a purchase business combination on November 1, 2012. We have also excluded RNPLLC from our audit of internal control over financial reporting. RNPLLC total assets and total revenues represent approximately 29% and 14%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2012.

/s/PricewaterhouseCoopers LLP

Los Angeles, California

March 18, 2013

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RENTECH NITROGEN PARTNERS, L.P.

Consolidated Balance Sheets

(Amounts in thousands, except per share data)

	As of December 31,
	2012		2011
ASSETS
Current assets
Cash	$	55,799	$	44,836
Accounts receivable, net of allowance for doubtful accounts of $0 at December 31, 2012 and 2011		9,705		7,428
Inventories		27,140		4,991
Deposits on gas contracts		—		2,807
Prepaid expenses and other current assets		2,228		1,712
Other receivables, net		2,626		846
Total current assets		97,498		62,620
Property, plant and equipment, net		128,340		59,348
Construction in progress		61,147		7,062
Other assets
Goodwill		56,592		—
Intangible assets		26,185		—
Debt issuance costs		6,458		872
Other assets		425		541
Total other assets		89,660		1,413
Total assets	$	376,645	$	130,443
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable	$	15,144	$	3,201
Payable to general partner		4,247		2,333
Accrued liabilities		14,271		5,110
Deferred revenue		29,660		20,331
Credit facilities and term loan		7,750		—
Asset retirement obligation		2,776		—
Other		432		—
Total current liabilities		74,280		30,975
Long-term liabilities
Credit facilities and term loan, net of current portion		185,540		—
Earn-out consideration		4,920		—
Other		2,501		277
Total long-term liabilities		192,961		277
Total liabilities		267,241		31,252
Commitments and contingencies (Note 8)
Partners’ capital
Common unitholders — 38,839 and 38,250 units issued and outstanding at December 31, 2012 and 2011, respectively		109,238		99,191
Accumulated other comprehensive income		166		—
General partner’s interest		—		—
Total partners’ capital		109,404		99,191
Total liabilities and partners’ capital	$	376,645	$	130,443

See Accompanying Notes to Consolidated Financial Statements.

83

RENTECH NITROGEN PARTNERS, L.P.

Consolidated Statements of Income

(Amounts in thousands, except per unit data)

	For the Calendar Years Ended December 31,						For the Three Months Ended December 31,						For the Fiscal Years Ended September 30,
	2012			2011			2011			2010			2011			2010
				(unaudited)						(unaudited)
Revenues	$	261,635		$	199,909		$	63,014		$	42,962		$	179,857		$	131,396
Cost of sales		129,796			113,911			37,460			26,835			103,286			106,020
Gross profit		131,839			85,998			25,554			16,127			76,571			25,376
Operating expenses
Selling, general and administrative expense		18,376			7,690			3,336			1,431			5,786			4,497
Depreciation		1,390			374			77			112			409			439
Other		510			16			(507	)		—			522			51
Total operating expenses		20,276			8,080			2,906			1,543			6,717			4,987
Operating income		111,563			77,918			22,648			14,584			69,854			20,389
Other income (expense), net
Interest expense		(1,469	)		(12,788	)		(1,947	)		(2,912	)		(13,752	)		(9,859	)
Loss on debt extinguishment		(2,114	)		(19,486	)		(10,263	)		(4,593	)		(13,816	)		(2,268	)
Loss on interest rate swaps		(951	)		—			—			—			—			—
Other income, net		277			56			17			17			55			91
Total other expense, net		(4,257	)		(32,218	)		(12,193	)		(7,488	)		(27,513	)		(12,036	)
Income before income taxes		107,306			45,700			10,455			7,096			42,341			8,353
Income tax expense		303			14,643			—			2,772			17,415			3,344
Net income	$	107,003		$	31,057		$	10,455		$	4,324		$	24,926		$	5,009
Net income subsequent to initial public offering (November 9, 2011 through December 31, 2011)				$	11,331		$	11,331
Net income per common unit subsequent to initial public offering—Basic	$	2.78		$	0.30		$	0.30
Net income per common unit subsequent to initial public offering—Diluted	$	2.78		$	0.30		$	0.30
Weighted-average units used to compute net income per common unit:
Basic		38,350			38,250			38,250
Diluted		38,352			38,255			38,255

See Accompanying Notes to Consolidated Financial Statements.

84

RENTECH NITROGEN PARTNERS, L.P.

Consolidated Statements of Comprehensive Income

(Amounts in thousands)

	For the Calendar Years Ended December 31,				For the Three Months Ended December 31,				For the Fiscal Years Ended September 30,
	2012		2011		2011		2010		2011		2010
			(unaudited)				(unaudited)
Net income	$	107,003	$	31,057	$	10,455	$	4,324	$	24,926	$	5,009
Other comprehensive income:
Pension and postretirement plan adjustments		166		—		—		—		—		—
Other comprehensive income		166		—		—		—		—		—
Comprehensive income	$	107,169	$	31,057	$	10,455	$	4,324	$	24,926	$	5,009

See Accompanying Notes to Consolidated Financial Statements.

85

RENTECH NITROGEN PARTNERS, L.P.

Consolidated Statements of Stockholder’s Equity (Deficit) / Partners’ Capital

(Amounts in thousands)

						Additional Paid-in Capital			Receivable from Parent Company			Retained Earnings (Accumulated Deficit)			Total Stockholder’s Equity			Number  of Common Units					Accumulated Other Comprehensive					Total Partners’
	Common Stock																			Common Unitholders					General Partner
	Shares			Amount																			Income					Capital
Balance, September 30, 2009		985		$	—	$	70,773		$	(87,050	)	$	58,710		$	42,433			—	$	—		$	—	$	—		$	—
Net advances to parent company		—			—		—			(27,108	)		—			(27,108	)		—		—			—		—			—
Net income		—			—		—			—			5,009			5,009			—		—			—		—			—
Balance, September 30, 2010		985		$	—	$	70,773		$	(114,158	)	$	63,719		$	20,334			—	$	—		$	—	$	—		$	—
Dividends paid		—			—		—			112,740			(235,551	)		(122,811	)		—		—			—		—			—
Net advances from parent company		—			—		—			1,418			—			1,418			—		—			—		—			—
Initial contribution to RNP		—			—		—			—			—			—			—		—			—		—			—
Net income		—			—		—			—			24,926			24,926			—		—			—		—			—
Balance, September 30, 2011		985		$	—	$	70,773		$	—		$	(146,906	)	$	(76,133	)		—	$	—		$	—	$	—		$	—
Deferred tax adjustment		—			—		—			—			5,462			5,462			—		—			—		—			—
Net loss attributable to the period from October 1, 2011 through November 8, 2011		—			—		—			—			(876	)		(876	)		—		—			—		—			—
Contribution to RNP for common units		(985	)		—		(70,773	)		—			142,320			71,547			23,250		—			—		(71,547	)		(71,547	)
Contribution through reduction of due to parent company		—			—		—			—			—			—			—		—			—		1,678			1,678
Transfer equity to limited partners		—			—		—			—			—			—			—		(187,295	)		—		187,295			—
Issuance of common units to public, net of offering and other costs		—			—		—			—			—			—			15,000		275,092			—		—			275,092
Distributions		—			—		—			—			—			—			—		—			—		(117,426	)		(117,426	)
Unit-based compensation expense		—			—		—			—			—			—			—		63			—		—			63
Net income attributable to the period from November 9, 2011 through December 31, 2011		—			—		—			—			—			—			—		11,331			—		—			11,331
Balance, December 31, 2011		—		$	—	$	—		$	—		$	—		$	—			38,250	$	99,191		$	—	$	—		$	99,191
Common units issued for acquisition		—			—		—			—			—			—			539		20,000			—		—			20,000
Common units		—			—		—			—			—			—			50		(736	)		—		—			(736	)
Distributions to common unitholders — affiliates		—			—		—			—			—			—			—		(71,610	)		—		—			(71,610	)
Distributions to common unitholders — non-affiliates		—			—		—			—			—			—			—		(47,205	)		—		—			(47,205	)
Unit-based compensation expense		—			—		—			—			—			—			—		2,827			—		—			2,827
Net income		—			—		—			—			—			—			—		107,003			—		—			107,003
Other comprehensive income		—			—		—			—			—			—			—		—			166		—			166
Other		—			—		—			—			—			—			—		(232	)		—		—			(232	)
Balance, December 31, 2012		—		$	—	$	—		$	—		$	—		$	—			38,839	$	109,238		$	166	$	—		$	109,404

See Accompanying Notes to Consolidated Financial Statements.

86

RENTECH NITROGEN PARTNERS, L.P.

Consolidated Statements of Cash Flows

(Amounts in thousands)

	For the Calendar Year Ended December 31,			For the Three Months Ended December 31,						For the Fiscal Years Ended September 30,
	2012			2011			2010			2011			2010
							(unaudited)
Cash flows from operating activities
Net income	$	107,003		$	10,455		$	4,324		$	24,926		$	5,009
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation		12,460			3,287			2,600			10,021			10,544
Utilization of spare parts		2,042			309			380			1,698			1,521
Non-cash interest expense		387			357			496			1,632			2,907
Loss on debt extinguishment		2,114			10,263			4,593			13,816			2,268
Unrealized loss on interest rate swaps		929			—			—			—			—
Unit-based compensation		2,827			—			—			—			—
Deferred income taxes		—			—			—			(718	)		(2,846	)
Payment of call premium fee		—			(2,933	)		—			(8,261	)		—
Other		(118	)		(435	)		8			376			78
Changes in operating assets and liabilities:
Accounts receivable		999			(2,883	)		(7,034	)		4,962			(861	)
Other receivables		2			194			91			(137	)		1,713
Inventories		8,727			11,164			1,451			(9,218	)		4,655
Deposits on gas contracts		2,807			(1,409	)		303			955			(1,629	)
Prepaid expenses and other current assets		(90	)		161			(482	)		(1,118	)		1,853
Accounts payable		1,020			(682	)		266			402			87
Deferred revenue		(3,972	)		(13,750	)		17,028			19,608			(3,730	)
Due to parent company		—			(18,395	)		—			20,073			—
Accrued interest		119			(41	)		10			18			(414	)
Accrued liabilities, accrued payroll and other		(4,710	)		(1,641	)		(317	)		4,633			(1,011	)
Net cash provided by (used in) operating activities		132,546			(5,979	)		23,717			83,668			20,144
Cash flows from investing activities
Payment for acquisition, net of cash acquired		(128,596	)		—			—			—			—
Capital expenditures		(57,571	)		(11,656	)		(2,212	)		(17,411	)		(11,597	)
Other items		(658	)		90			—			25			14
Net cash used in investing activities		(186,825	)		(11,566	)		(2,212	)		(17,386	)		(11,583	)
Cash flows from financing activities
Proceeds from initial public offering, net of costs		(245	)		276,007			—			—			—
Proceeds from credit facilities and term loan, net of original issue discount		222,780			—			50,960			200,960			64,425
Proceeds from bridge loan from parent		5,860			—			—			—			—
Payment of bridge loan to parent		(5,860	)		—			—			—			—
Retirement of credit facilities and term loan, including costs		(29,490	)		(146,250	)		—			(85,383	)		(38,040	)
Payment of debt issuance costs		(7,788	)		(904	)		(290	)		(8,747	)		(4,060	)
Payment of bridge loan fee to parent, net		(200	)		—			—			—			—
Payments on term loan		—			—			(22,522	)		(33,658	)		(4,209	)
Payments on notes payable for financed insurance premiums		(1,000	)		(418	)		(465	)		(1,623	)		(1,296	)
Payment of dividends		—			(117,426	)		(50,857	)		(122,811	)		—
Net receipts from (advances to) parent company		—			—			3,356			1,418			(27,108	)
Distributions to common unitholders – affiliates		(71,610	)		—			—			—			—
Distributions to common unitholders – non-affiliates		(47,205	)		—			—			—			—
Net cash provided by (used in) financing activities		65,242			11,009			(19,818	)		(49,844	)		(10,288	)
Increase (decrease) in cash		10,963			(6,536	)		1,687			16,438			(1,727	)
Cash and cash equivalents, beginning of period		44,836			51,372			34,934			34,934			36,661
Cash and cash equivalents, end of period	$	55,799		$	44,836		$	36,621		$	51,372		$	34,934

See Accompanying Notes to Consolidated Financial Statements.

87

RENTECH NITROGEN PARTNERS, L.P.

Consolidated Statements of Cash Flows—Continued

(Amounts in thousands)

For the year ended December 31, 2012, the three months ended December 31, 2011 and 2010 and the fiscal years ended September 30, 2011 and 2010, the Partnership made certain cash payments as follows:

	For the Calendar Year Ended December 31,		For the Three Months Ended December 31,				For the Fiscal Years Ended September 30,
	2012		2011		2010		2011		2010
					(unaudited)
Cash payments of interest, net of capitalized interest of $701 (Dec 2012) and $0 for all other periods	$	964	$	1,631	$	2,406	$	12,102	$	7,366

Excluded from the statements of cash flows were the effects of certain non-cash financing and investing activities as follows:

	For the Calendar Year Ended December 31,		For the Three Months Ended December 31,				For the Fiscal Years Ended September 30,
	2012		2011		2010		2011		2010
					(unaudited)
Purchase of insurance policies financed with notes payable	$	—	$	679	$	428	$	1,537	$	1,547
Receivable from parent company reclassified as dividend		—		—		—		112,740		—
Receivable for sales of property, plant and equipment in other receivables		—		741		—		325		—
Purchase of property, plant, equipment and construction in progress in accounts payable and accrued liabilities		5,223		2,329		792		9,605		261
Current deposits transferred into construction in progress		1,505		—		—		—		—
Deferred taxes written off through retained earnings		—		5,462		—		—		—
Capital contribution through reduction of due to parent company		—		1,678		—		—		—
Prepaid IPO costs offset against proceeds of IPO		—		3,907		—		—		—
IPO costs in accrued liabilities		—		72		—		—		—
Units issued for acquisition		20,000		—		—		—		—

See Accompanying Notes to Consolidated Financial Statements

88

Note 1 — Description of Business

Description of Business

Rentech Nitrogen Partners, L.P. (“RNP”, “the Partnership,” “we,” “us” or “our”) owns and operates two fertilizer facilities: our East Dubuque Facility and our Pasadena Facility. Our East Dubuque Facility is located in East Dubuque, Illinois, and has been in operation since 1965. We primarily produce ammonia and urea ammonium nitrate solution (“UAN”) at our East Dubuque Facility, using natural gas as the facility’s primary feedstock. Our Pasadena Facility, which we acquired in November 2012, is located in Pasadena, Texas, and has been in operation since the 1940s. In 2011, our Pasadena Facility was retrofitted to produce ammonium sulfate. We produce ammonium sulfate, ammonium thiosulfate and sulfuric acid at our Pasadena Facility, using ammonia and sulfur as the facility’s primary feedstocks.

In fiscal years 2010 and 2011, Rentech Energy Midwest Corporation (“REMC” or “the Company”), the predecessor of RNP, was a wholly-owned subsidiary of Rentech, Inc. (“Rentech”). On November 9, 2011, the Partnership completed its initial public offering (the “Offering”) of 15,000,000 common units representing limited partner interests at a public offering price of $20.00 per common unit. The common units sold to the public in the Offering represented 39.2% of the Partnership common units outstanding as of the closing of the Offering. Rentech Nitrogen Holdings, Inc. (“RNHI”), Rentech’s indirect wholly-owned subsidiary, owned the remaining 60.8% of the Partnership common units outstanding as of the closing of the Offering and Rentech Nitrogen GP, LLC (the “General Partner”), RNHI’s wholly-owned subsidiary, owns 100% of the non-economic general partner interest in us. The Partnership’s assets consisted as of the closing of the Offering of all of the equity interests of REMC, which owned the East Dubuque Facility. At the Offering, REMC was converted into a limited liability company, Rentech Nitrogen, LLC (“RNLLC”).

On November 1, 2012, the Partnership completed its acquisition of 100% of the membership interests of Agrifos LLC (“Agrifos”) from Agrifos Holdings Inc. (the “Seller”), pursuant to a Membership Interest Purchase Agreement (the “Purchase Agreement”). Upon the closing of this transaction (the “Agrifos Acquisition”), Agrifos became a wholly-owned subsidiary of the Partnership and its name changed to Rentech Nitrogen Pasadena Holdings, LLC. Rentech Nitrogen Pasadena Holdings, LLC owns all of the member interests in Rentech Nitrogen Pasadena, LLC (“RNPLLC”), formerly known as Agrifos Fertilizer, LLC, which owns and operates the Pasadena Facility. For information on the Agrifos Acquisition refer to Note 3 — Agrifos Acquisition.

Change in Fiscal Year End

On February 1, 2012, the board of directors of the General Partner approved a change in the Partnership’s fiscal year end from September 30 to December 31. References to calendar 2012 and 2011 mean the twelve-month period ended December 31, 2012 and 2011. References to any of our fiscal years mean the fiscal year ending September 30 of that calendar year. The statement of income for the calendar year ended December 31, 2011 was derived by deducting the statement of income for the three months ended December 31, 2010 from the statement of income for the fiscal year ended September 30, 2011 and then adding the statement of income for the three months ended December 31, 2011. The statements of income for calendar year ended December 31, 2011 and the three months ended December 31, 2010, while not required, are presented for comparison purposes. Financial information in these notes with respect to calendar year 2011 and the three months ended December 31, 2010 is unaudited.

Note 2 — Summary of Certain Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Partnership and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Presentation

Prior to the closing of the Offering, REMC was consolidated with Rentech’s operations following its acquisition by Rentech in 2006. During that time REMC benefitted from certain corporate services provided by Rentech. These consolidated financial statements reflect REMC on a stand-alone or “carve-out” basis from Rentech for the period prior to the Offering and certain corporate overhead costs were allocated to REMC and certain transactions between the Company and Rentech were re-categorized as if REMC were a standalone entity. Management believes that the method used to allocate the corporate overhead costs is reasonable and reflects management’s estimate of what the expenses would have been on a stand-alone basis for REMC.

89

Intercompany loans and advances from REMC to Rentech are recorded in a contra-equity account receivable from parent company. No interest has been recorded on this receivable. Amortization of the discount on REMC’s term loan, which was recorded by Rentech, was pushed down to REMC. An estimate of the cost of time spent on REMC’s matters by Rentech human resources, legal, information systems, accounting and finance, investor relations and other Rentech personnel has been reflected in REMC’s statements of income. A percentage of third party costs relating to the information technology operating system was pushed down to REMC. Actual audit and tax services expenses for REMC were pushed down to REMC. Rentech over the years granted Restricted Stock Units and stock options to employees of REMC. The related stock based compensation for such grants was recorded by Rentech. These costs have also been recorded by REMC in these financial statements. Total operating expenses allocated to REMC were $2,026,000 and $1,414,000 for the fiscal years ended September 30, 2011 and 2010, respectively. The entries relating to income taxes have been determined on a separate return basis.

Subsequent Events

The Partnership has evaluated events, if any, which occurred subsequent to December 31, 2012 through the date these financial statements were issued, to ensure that such events have been properly reflected in these statements.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Fair Value of Financial Instruments

Fair values of receivables, other current assets, accounts payable, accrued liabilities and other current liabilities were assumed to approximate carrying values for these financial instruments since they are short term in nature or they are receivable or payable on demand. These items meet the definition of Level 1 financial instruments. Fair values of credit facilities and term loan were assumed to approximate carrying values for these financial instruments because the agreement for the credit facilities and term loan was executed near year end, October 31, 2012. These items meet the definition of Level 2 financial instruments. Since the Partnership is required to measure the earn-out consideration at each reporting date, earn-out consideration is recorded at fair value. This item meets the definition of Level 3 financial instruments. See Note 4—Fair Value.

Revenue Recognition

Revenues are recognized when customers take ownership upon shipment from the East Dubuque Facility, Pasadena Facility, East Dubuque Facility’s leased facility or Pasadena Facility’s distributors’ facilities and assumes risk of loss, collection of the related receivable is probable, persuasive evidence of a sale arrangement exists and the sales price is fixed or determinable. Management assesses the business environment, the customer’s financial condition, historical collection experience, accounts receivable aging and customer disputes to determine whether collectability is reasonably assured. If collectability is not considered reasonably assured at the time of sale, the Partnership does not recognize revenue until collection occurs.

Natural gas, though not purchased for the purpose of resale, is occasionally sold by the East Dubuque Facility when contracted quantities received are in excess of production and storage capacities, in which case the sales price is recorded in revenues and the related cost is recorded in cost of sales.

On April 26, 2006, Rentech’s subsidiary, Rentech Development Corporation (“RDC”), entered into a Distribution Agreement (the “Distribution Agreement”) with Royster-Clark Resources, LLC, who subsequently assigned the agreement to Agrium U.S.A., Inc. (“Agrium”), and RDC similarly assigned the agreement to REMC, prior to its conversion into RNLLC. The Distribution Agreement is for a 10 year period, subject to renewal options. Pursuant to the Distribution Agreement, Agrium is obligated to use commercially reasonable efforts to promote the sale of, and solicit and secure orders from its customers for nitrogen fertilizer products manufactured at the East Dubuque Facility, and to purchase from RNLLC nitrogen fertilizer products manufactured at the facility for prices to be negotiated in good faith from time to time. Under the Distribution Agreement, Agrium is appointed as the exclusive distributor for the sale, purchase and resale of nitrogen products manufactured at the East Dubuque Facility. Sale terms are negotiated and approved by RNLLC. Agrium bears the credit risk on products sold through Agrium pursuant to the Distribution Agreement. If an agreement is not reached on the terms and conditions of any proposed Agrium sale transaction, RNLLC has the right to sell to third parties provided the sale is on the same timetable and volumes and at a price not lower than the one proposed by Agrium. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, the Distribution Agreement accounted for 83%, 92%, 83% and 80%, respectively, of net revenues from continuing operations for the East Dubuque Facility. Receivables from Agrium accounted for 73% and 83% of the total accounts receivable balance of the East Dubuque Facility as of December 31, 2012 and 2011, respectively. RNP negotiates sales with other customers and these transactions are not subject to the terms of the Distribution Agreement.

90

Under the Distribution Agreement, the East Dubuque Facility pays commissions to Agrium not to exceed $5 million during each contract year on applicable gross sales during the first 10 years of the agreement. The commission rate was 2% during the first year of the agreement and increased by 1% on each anniversary date of the agreement up to the current maximum rate of 5%. For the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, the effective commission rate associated with sales under the Distribution Agreement was 2.7%, 2.6%, 4.3% and 4.2%, respectively.

We sell substantially all of our Pasadena Facility’s products through marketing and distribution agreements that automatically renew for successive one year periods. Pursuant to an exclusive marketing agreement we have entered into with Interoceanic Corporation (“IOC”), IOC has the exclusive right and obligation to market and sell all of our Pasadena Facility’s granular ammonium sulfate in certain specified jurisdictions. Under the marketing agreement, IOC is required to use commercially reasonable efforts to market the product to obtain the most advantageous price. We compensate IOC for transportation and storage costs relating to the granular ammonium sulfate it markets through the pricing structure under the marketing agreement. The marketing agreement has a term that ends in February 2014, but automatically renews for subsequent one-year periods (unless either party delivers a termination notice to the other party at least 180 days prior to an automatic renewal). The marketing agreement may be terminated prior to its stated term for specified causes. During the period beginning November 1, 2012 through December 31, 2012, the marketing agreement with IOC accounted for 100% of our Pasadena Facility’s revenues from the sale of ammonium sulfate. In addition, we have an arrangement with IOC that permits us to store 32,000 tons of ammonium sulfate at IOC-controlled terminals, which are located near end customers of our Pasadena Facility’s ammonium sulfate. This arrangement currently is not governed by a written contract.

Deferred Revenue

At the East Dubuque Facility, we record a liability for deferred revenue to the extent that payment has been received under product prepayment contracts, which create obligations for delivery of product within a specified period of time in the future. The terms of these product prepayment contracts require payment in advance of delivery. At the Pasadena Facility, IOC pre-pays a portion of the sales price for shipments received into its storage facilities. The Partnership recognizes revenue related to the product prepayment contracts or products stored at IOC facilities and relieves the liability for deferred revenue when products are shipped (including shipments to end customers from IOC facilities). A significant portion of the revenue recognized during any period may be related to product prepayment contracts or products stored at IOC facilities, for which cash was collected during an earlier period, with the result that a significant portion of revenue recognized during a period may not generate cash receipts during that period. As of December 31, 2012 and 2011, deferred revenue was approximately $29.7 million and $20.3 million, respectively.

Cost of Sales

Cost of sales are comprised of manufacturing costs related to the Partnership’s fertilizer and industrial products. Cost of sales expenses include direct materials (such as natural gas, ammonia, sulfur and sulfur acid), direct labor, indirect labor, employee fringe benefits, depreciation on plant machinery, electricity and other costs, including shipping and handling charges incurred to transport products sold.

The Partnership enters into short-term contracts to purchase physical supplies of natural gas in fixed quantities at both fixed and indexed prices. We anticipate that we will physically receive the contract quantities and use them in the production of fertilizer and industrial products. We believe it is probable that the counterparties will fulfill their contractual obligations when executing these contracts. Natural gas purchases, including the cost of transportation to the East Dubuque Facility, are recorded at the point of delivery into the pipeline system.

Accounting for Derivative Instruments

We elect the normal purchase normal sale exemption for our commodity-based derivative instruments. As such, we do not recognize the unrealized gains or losses related to these derivative instruments in our financial statements. For interest rate swaps, the Partnership does not use hedge accounting; however, the Partnership reflects the instruments at fair value and any change in value is recorded to the statement of income.

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Cash

The Partnership has various checking and savings accounts with major financial institutions. At times balances with these financial institutions may be in excess of federally insured limits.

Accounts Receivable

Trade receivables are recorded at net realizable value. The allowance for doubtful accounts reflects the Partnership’s best estimate of probable losses inherent in the accounts receivable balance. The Partnership determines the allowance based on known troubled accounts, historical experience, and other currently available evidence. The Partnership reviews its allowance for doubtful accounts quarterly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Inventories

Inventories consist of raw materials and finished goods. The primary raw material used by the East Dubuque Facility in the production of its nitrogen products is natural gas. The primary raw materials used by the Pasadena Facility in the production of its products is ammonia and sulfur. Raw materials also include certain chemicals used in the manufacturing process. Finished goods include the products stored at each plant that are ready for shipment along with any inventory that may be stored at remote facilities. The Partnership allocates fixed production overhead costs to inventory based on the normal capacity of its production facilities and unallocated overhead costs are recognized as expense in the period incurred. At December 31, 2012 and 2011, inventories on the balance sheets included depreciation of approximately $1.0 million and $0.5 million, respectively.

Inventories are stated at the lower of cost or estimated net realizable value. The cost of inventories is determined using the first-in first-out method. The estimated net realizable value is based on customer orders, market trends and historical pricing. On at least a quarterly basis, the Partnership performs an analysis of its inventory balances to determine if the carrying amount of inventories exceeds their net realizable value. If the carrying amount exceeds the estimated net realizable value, the carrying amount is reduced to the estimated net realizable value.

Deposits on Gas Contracts

The Partnership enters into forward contracts with fixed delivery prices to purchase portions of the natural gas required to produce fertilizer for the East Dubuque Facility’s nitrogen fertilizer business. Some of the forward contracts require the Partnership to pay a deposit for the natural gas at the time of contract signing, and all of the contracts require deposits in the event that the market price for natural gas falls after the date of the contract to a price below the fixed price in the contracts.

Property, Plant and Equipment

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation expense is calculated using the straight-line method over the estimated useful lives of the assets, except for platinum catalyst, as follows:

Type of Asset	Estimated Useful Life
Building and building improvements	20-40 years
Land improvements	10-20 years
Machinery and equipment	7-10 years
Furniture, fixtures and office equipment	5-10 years
Computer equipment and software	3-5 years
Vehicles	3-5 years
Ammonia catalyst	3-10 years
Platinum catalyst	Based on units of production

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Expenditures during turnarounds or at other times for improving, replacing or adding to RNP’s assets are capitalized. Expenditures for the acquisition, construction or development of new assets to maintain RNP’s operating capacity, or to comply with environmental, health, safety or other regulations, are also capitalized. Costs of general maintenance and repairs are expensed.

When property, plant and equipment is retired or otherwise disposed of, the asset and accumulated depreciation are removed from the accounts and the resulting gain or loss is reflected in operating expenses.

Spare parts are maintained by each facility to reduce the length of possible interruptions in plant operations from an infrastructure breakdown at the facility. The spare parts may be held for use for years before the spare parts are used. As a result, they are capitalized as a fixed asset at cost. When spare parts are utilized, the book values of the assets are charged to earnings as a cost of production. Periodically, the spare parts are evaluated for obsolescence and impairment and if the value of the spare parts is impaired, it is charged against earnings. Prior to calendar year 2012, the Partnership incorrectly depreciated the cost on a straight-line basis over the useful life of the related equipment until the spare parts were installed. When the spare parts were utilized, the net book values of the assets were charged to earnings as a cost of sale. Management concluded the impact of this error was not material to any prior period and the impact of correcting this error was not material to calendar year 2012. For the year ended and the fourth quarter of calendar year 2012, the net impact of correcting this out-of-period adjustment was a decrease to cost of sales of approximately $1.2 million.

Long-lived assets and construction in progress are reviewed whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the expected future cash flow from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized and measured using the asset’s fair value.

The Partnership capitalizes certain direct development costs associated with internal-use software, including external direct costs of material and services, and payroll costs for employees devoting time to software implementation projects. Costs incurred during the preliminary project stage, as well as maintenance and training costs, are expensed as incurred.

Grants that compensate the Partnership for the cost of property, plant and equipment are recorded as a reduction to the cost of the related asset and are recognized over the useful life of the asset by reducing depreciation expense.

The Partnership has recorded asset retirement obligations (“AROs”) related to future costs associated with the removal of contaminated material upon removal of the phosphorous plant at the Pasadena Facility and handling and disposal of asbestos at the East Dubuque Facility. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to operating expense and the capitalized cost is depreciated over the remaining useful life of the asset. The liability at December 31, 2012 and 2011 was approximately $3.1 million, most of which is short-term, and $0.3 million, respectively. The long-term portion of the liability is included in other long-term liabilities. The accretion expense for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010 was approximately $36,000, $9,000, $31,000 and $27,000, respectively.

Construction in Progress

We also capitalize costs for improvements to the existing machinery and equipment at our facilities and certain costs associated with our information technology initiatives. We do not depreciate construction in progress costs until the underlying assets are placed into service.

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Intangible Assets

Intangible assets arose in conjunction with the Agrifos Acquisition and consist of technology to produce ammonium sulfate and the Pasadena Facility’s marketing agreement with IOC. The cost of the technology was approximately $23.7 million with accumulated amortization of approximately $0.2 million at December 31, 2012. The cost of the marketing agreement was approximately $3.1 million with accumulated amortization of approximately $0.4 million at December 31, 2012. Both assets are amortized using the straight-line method with the technology amortized over a twenty-year life and the marketing agreement amortized over its remaining contract term of sixteen months. The amortization of the assets will result in amortization expense of approximately $3.5 million, $1.6 million, $1.2 million, $1.2 million and $1.2 million for the next five years.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in a business acquisition. The Partnership tests goodwill assets for impairment annually, or more often if an event or circumstance indicates that an impairment may have occurred. The recoverability of goodwill involves a high degree of judgment since the first step of the required impairment test consists of a comparison of the fair value of a reporting unit with its book value. Based on the assumptions underlying the valuation, impairment is determined by estimating the fair value of a reporting unit and comparing that value to the reporting unit’s book value. If the fair value is more than the book value of the reporting unit, an impairment loss is not recognized. If an impairment exists, the fair value of the reporting unit is allocated to all of its assets and liabilities excluding goodwill, with the excess amount representing the fair value of goodwill. An impairment loss is measured as the amount by which the book value of the reporting unit’s goodwill exceeds the estimated fair value of that goodwill.

For purposes of evaluating whether goodwill is impaired, goodwill is allocated to reporting units, which are either at the operating segment level or one reporting level below the operating segment. The reporting unit with goodwill is RNPLLC. The Partnership utilizes the fair value based upon the discounted cash flows that the business can be expected to generate in the future (the “Income Approach”) when evaluating goodwill for impairment. The Income Approach valuation method requires the Partnership to make projections of revenue and operating costs for the reporting unit over a multi-year period. Additionally, management must make an estimate of a weighted average cost of capital that a market participant would use as a discount rate. Changes in these projections or estimates could result in passing or failing the first step of the impairment model, which could significantly change the amount of any impairment ultimately recorded. As of December 31, 2012, the Partnership performed the annual impairment test for goodwill as required and determined that its goodwill was not impaired since the fair value of the reporting unit exceeded its carrying amount.

Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner’s tax attributes in us.

The description that follows relates to REMC prior to the Offering. REMC was not a separate tax-paying entity. REMC was included in Rentech’s consolidated federal and certain state income tax groups for income tax reporting purposes and was responsible for its separate company income taxes calculated upon its taxable income at a current estimate of the annual effective tax rate. On a separate return basis, the Company had income taxes payable owed to Rentech.

The Company accounted for income taxes in accordance with applicable accounting guidance. Such accounting guidance requires deferred tax assets and liabilities to be recognized for temporary differences between the tax basis and financial reporting basis of assets and liabilities, computed at the expected tax rates for the periods in which the assets or liabilities will be realized, as well as for the expected tax benefit of net operating loss and tax credit carryforwards.

Accounting guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The guidance requires that the Company recognize in its financial statements, only those tax positions that are “more-likely-than-not” of being sustained, based on the technical merits of the position. The Company had performed a comprehensive review of its material tax positions in accordance with accounting guidance and had determined that no uncertain tax positions existed.

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In accordance with its accounting policy, the Company recognized accrued interest and penalties related to unrecognized tax benefits as a component of tax expense. Since the Company had no uncertain tax positions, no interest or penalties have been accrued related to uncertain tax positions in the balance sheet or statement of income. The Company was subject to examination for federal and Illinois income taxes for the tax years ended September 30, 2007 through September 30, 2009.

While management believes the Company had adequately provided for all tax positions, amounts asserted by taxing authorities could materially differ from our accrued positions as a result of uncertain and complex application of tax regulations. Additionally, the recognition and measurement of certain tax benefits includes estimates and judgment by management and inherently includes subjectivity. Accordingly, additional provisions on federal and state tax-related matters could be recorded in the future as revised estimates are made or the underlying matters are settled or otherwise resolved.

Net Income Per Common Unit

The Partnership’s net income is allocated wholly to the common unitholders since the General Partner has a non-economic interest. The net income per common unit for the three months and year ended December 31, 2011 on the Consolidated Statement of Income are based on net income of the Partnership after the closing of the Offering on November 9, 2011 through December 31, 2011, since this is the amount of net income that is attributable to the newly issued common units.

Basic income per common unit is calculated by dividing net income by the weighted average number of common units outstanding for the period. Diluted net income per common unit is calculated by dividing net income by the weighted average number of common units outstanding plus the dilutive effect, calculated using the “treasury stock” method for the unvested phantom units. Phantom units are settled for common units upon vesting and are issued in tandem with distribution rights during the vesting period.

Comprehensive Income

Comprehensive income includes all changes in partners’ capital during the period from non-owner sources. To date, accumulated other comprehensive income is comprised of adjustments to the defined benefit pension plans and the postretirement benefit plan.

Quarterly Distributions of Available Cash

The Partnership’s policy is to distribute all of the cash available for distribution which it generates each quarter. Cash available for distribution for each quarter will be determined by the board of directors of the General Partner following the end of each quarter. The Partnership expects that cash available for distribution for each quarter will generally equal the cash flow it generates during the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate. The Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in its quarterly distribution or otherwise to reserve cash for distributions, nor does it intend to incur debt to pay quarterly distributions. The Partnership has no legal obligation to pay distributions. Distributions are not required by the Partnership’s partnership agreement and the Partnership’s distribution policy is subject to change at any time at the discretion of the board of directors of the General Partner. Any distributions made by the Partnership to its unitholders will be done on a pro rata basis.

Acquisition Method of Accounting

The Partnership accounts for business combinations using the acquisition method of accounting, which requires, among other things, that most assets acquired, liabilities assumed and earn-out consideration be recognized at their fair values as of the acquisition date. The earn-out consideration will be measured at each reporting date with changes in its fair value recognized in the consolidated statements of income.

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Related Parties

On November 9, 2011, the closing date of the Offering, the Partnership, the General Partner and Rentech entered into a services agreement, pursuant to which the Partnership and the General Partner will obtain certain management and other services from Rentech. The Partnership’s consolidated financial statements following the Offering reflect the impact of the reimbursements the Partnership is required to make to Rentech under the services agreement instead of those used for purposes of preparing REMC’s stand-alone financial statements. Under the services agreement, the Partnership and its subsidiaries and the General Partner are obligated to reimburse Rentech for (i) all costs, if any, incurred by Rentech or its affiliates in connection with the employment of its employees who are seconded to the Partnership and who provide the Partnership services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by Rentech or its affiliates in connection with the employment of its employees, excluding seconded personnel, who provide the Partnership services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by Rentech on a commercially reasonable basis, based on the estimated percent of total working time that such personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs, in accordance with the agreement, including office costs, services by outside vendors, other general and administrative costs; and (iv) any taxes (other than income taxes, gross receipt taxes and similar taxes) incurred by Rentech or its affiliates for the services provided under the agreement. During the calendar year ended December 31, 2012, Rentech, in accordance with the services agreement, billed the Partnership approximately $14.1 million.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (the “FASB”) issued guidance clarifying the application of existing fair value measurement and disclosure requirements, as well as changing certain measurement requirements and disclosures. This guidance became effective during interim and annual periods beginning after December 15, 2011, and thus became effective for the Partnership’s reporting periods beginning on January 1, 2012. The adoption of this guidance did not have a material impact on the Partnership’s consolidated financial position, results of operations or disclosures.

In February 2013, the FASB issued guidance requiring companies to disclose information about amounts reclassified out of accumulated other comprehensive income and their corresponding effect on net income. This guidance is effective for interim and annual periods beginning after December 15, 2012. It is effective for the Partnership’s interim period beginning on January 1, 2013. The adoption of this guidance is not expected to have a material impact on the Partnership’s consolidated financial position, results of operations or disclosures.

Note 3 — Agrifos Acquisition

The purchase price for Agrifos and its subsidiaries consisted of an initial purchase price of $136.0 million in cash, less estimated working capital adjustments, and $20.0 million in common units representing limited partnership interests in the Partnership (the “Common Units”), which reduced Rentech’s ownership interest in the Partnership from 60.8% to 59.9%, as well as potential earn-out consideration of up to $50.0 million to be paid in Common Units or cash at the Partnership’s option based on the amount by which the two-year Adjusted EBITDA, as defined in the Purchase Agreement, of the Pasadena Facility exceeds certain Adjusted EBITDA thresholds. Among other terms, the Seller is required to indemnify us for a period of six years after the closing for certain environmental matters relating to the Pasadena Facility, which indemnification obligations are subject to important limitations including a deductible and an overall cap. We deposited with an escrow agent in several escrow accounts a portion of the initial consideration consisting of an aggregate of $7.25 million in cash, and 323,276 Common Units, representing a value of $12.0 million, which amounts may be used to satisfy certain indemnity claims upon the occurrence of certain events. Any earn-out consideration would be paid after April 30, 2015 and the completion of the relevant calculations in either common units or cash at our option.

This business combination has been accounted for using the acquisition method of accounting, which requires, among other things, that most assets acquired, liabilities assumed and earn-out consideration be recognized at their fair values as of the acquisition date.

The preliminary purchase price consisted of the following (amounts in thousands):

Cash (through borrowings under the Credit Agreement) less estimated working capital adjustments	$	136,018
Fair market value of 538,793 Common Units issued		20,000
Estimate of potential earn-out consideration		4,920
Total preliminary purchase price	$	160,938

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The amount of earn-out consideration reflected in the table above reflects the Partnership’s current estimate of the amount of the earn-out consideration it will be required to pay pursuant to the Purchase Agreement.

The Partnership’s preliminary purchase price allocation as of November 1, 2012 is as follows (amounts in thousands):

Cash	$	2,622
Accounts receivable		3,204
Inventories		30,373
Prepaid expenses and other current assets		566
Property, plant and equipment		68,688
Construction in progress		7,011
Intangible assets (Technology—$23,680 and Marketing Agreement—$3,088)		26,768
Goodwill		56,592
Other assets		73
Accounts payable		(10,638	)
Accrued liabilities		(6,291	)
Customer deposits		(13,301	)
Asset retirement obligation		(2,776	)
Other long-term liabilities		(1,953	)
Total preliminary purchase price	$	160,938

The final purchase price and the allocation thereof will not be known until the final working capital adjustments are performed, a final environmental assessment of the property is completed and a determination of the earn-out consideration is finalized.

The operations of Agrifos are included in the consolidated statement of income effective November 1, 2012. The Partnership recorded revenue and net loss related to Agrifos of approximately $37.4 million and $2.6 million, respectively. Acquisition related costs for this acquisition totalled approximately $4.1 million for the calendar year ended December 31, 2012 and have been included in the consolidated statements of income within selling, general and administrative expense.

Pro Forma Information

The unaudited pro forma information has been prepared as if the Agrifos Acquisition and the Offering had taken place on January 1, 2011. The unaudited pro forma information is not necessarily indicative of the results that the Partnership would have achieved had the transactions actually taken place on January 1, 2011, and the unaudited pro forma information does not purport to be indicative of future financial operating results.

	For the Calendar Year Ended December 31, 2012
	As Reported		Pro Forma Adjustments			Pro Forma
	(in thousands)
Revenues	$	261,635	$	126,484		$	388,119
Net income	$	107,003	$	(2,479	)	$	104,524
Net income per common unit	$	2.78	$	(0.10	)	$	2.68
	For the Calendar Year Ended December 31, 2011
	As Reported		Pro Forma Adjustments			Pro Forma
	(in thousands)
Revenues	$	199,909	$	146,897		$	346,806
Net income	$	31,057	$	21,372		$	52,429
Net income per common unit	$	0.30	$	1.05		$	1.35

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Note 4 — Fair Value

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Partnership makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Partnership and its counterparties is incorporated in the valuation of assets and liabilities. The Partnership believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

A fair value hierarchy has been established that prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Partnership classifies fair value balances based on the fair value hierarchy, defined as follows:

• Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Partnership has the ability to access as of the reporting date.

• Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

• Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The following table presents the financial instruments that require fair value disclosure as of December 31, 2012.

	Fair Value						Carrying Value
			(in thousands)
	Level 1		Level 2		Level 3
Liabilities
Credit facilities and term loan	$	—	$	193,290	$	—	$	193,290
Interest rate swaps	$	—	$	929	$	—	$	929
Earn-out consideration	$	—	$	—	$	4,920	$	4,920

There were no financial instruments that required fair value disclosure as of December 31, 2011.

Credit Facilities and Term Loan

The credit facilities and term loan are deemed to be Level 2 financial instruments because the measurement is based on observable market data. It was concluded that the carrying values of the credit facilities and term loan approximate the fair values of such facilities and term loan as of December 31, 2012 because the agreement for the credit facilities and term loan was executed near year end, October 31, 2012.

Interest Rate Swaps

On April 2, 2012, RNLLC entered into two forward starting interest rate swaps in notional amounts which now cover a portion of the borrowings under its New CapEx Facility, as defined in Note 7 — Debt. Through the two interest rate swaps, RNLLC is essentially fixing the variable interest rate to be paid on a portion of the borrowings under the New CapEx Facility.

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The initial forward starting interest rate swap (the “Construction Period Swap”) is based on a notional amount beginning at approximately $20.8 million and increasing, as specified in the swap agreement, to approximately $45.8 million. The increases in the notional amounts are designed to mirror a proportion of the expected increases in outstanding borrowings under the New CapEx Facility as RNLLC continues its ammonia production and storage capacity expansion project. The Construction Period Swap started on September 1, 2012 and will terminate on September 1, 2013. Under the Construction Period Swap, RNLLC will receive one-month LIBOR on the notional amount, and the rate will be reset at the end of each month; RNLLC will pay a fixed rate of 48.8 basis points on the same notional amount. The second forward starting interest rate swap (the “Term Swap”) will start on September 30, 2013 and terminate on December 31, 2015. The Term Swap is based on a notional amount beginning at $50.0 million and decreasing, as specified in the swap agreement, to $40.0 million. The decreases in the notional amounts are designed to mirror a proportion of the decrease in outstanding borrowings under the New CapEx Facility as RNLLC begins to make principal payments. Under the Term Swap, RNLLC will receive three-month LIBOR on the notional amount, and the rate will be reset at the end of each calendar quarter; RNLLC will pay a fixed rate of 129.5 basis points on the same notional amount.

The interest rate swaps are not designated as hedging instruments for accounting purposes. The interest rate swaps are deemed to be Level 2 financial instruments because the measurements are based on observable market data. The Partnership uses a standard swap contract valuation method to value its interest rate derivatives, and the inputs it uses for present value discounting include forward one-month and three-month LIBOR rates, risk-free interest rates and an estimate of credit risk. The fair value of the interest rate swaps at December 31, 2012 represents the unrealized loss which is recorded in loss on interest rate swaps on the consolidated statement of income. The realized loss represents the current cash payment required under the interest rate swaps.

Loss on interest rate swaps (in thousands) for the calendar year ended December 31, 2012:

Realized loss	$	22
Unrealized loss		929
Total loss on interest rate swaps	$	951

Earn-out Consideration

The earn-out consideration is deemed to be Level 3 because the measurement is based on unobservable inputs. The fair value of earn-out consideration was determined based on the Partnership’s analysis of various scenarios involving the achievement of certain levels of Adjusted EBITDA, as defined in the Purchase Agreement, over a two year period. The scenarios, which included a weighted probability factor, involved assumptions relating to the market prices of our products and feedstocks, as well as product profitability and production. The earn-out consideration will be measured at each reporting date with changes in its fair value recognized in the consolidated statements of income.

The levels within the fair value hierarchy at which the Partnership’s financial instruments have been evaluated have not changed for any of our financial instruments during the year ended December 31, 2012.

Note 5 — Inventories

Inventories consisted of the following:

	As of December 31,
	2012		2011
	(in thousands)
Finished goods	$	21,756	$	4,567
Raw materials		5,269		377
Other		115		47
Total inventory	$	27,140	$	4,991

Note 6 — Property, Plant and Equipment

Property, plant and equipment consisted of the following:

	As of December 31,
	2012			2011
	(in thousands)
Land and land improvements	$	22,386		$	1,281
Buildings and building improvements		22,149			5,140
Machinery and equipment		134,979			94,929
Furniture, fixtures and office equipment		232			57
Computer equipment and computer software		2,675			2,053
Vehicles		186			125
Conditional asset (asbestos removal)		210			210
		182,817			103,795
Less accumulated depreciation		(54,477	)		(44,447	)
Total depreciable property, plant and equipment, net	$	128,340		$	59,348

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The construction in progress balance at December 31, 2012 of approximately $61.1 million, which includes $0.9 million of capitalized interest costs, represents the costs associated with the ammonia production and storage capacity expansion project.

Note 7 — Debt

The Partnership’s debt obligations at December 31, 2012 consist of approximately $193.3 million in outstanding advances under its New 2012 Credit Agreement, as defined below. The Partnership’s debt obligations at December 31, 2011 consisted of short-term notes payable, a $25.0 million revolving credit facility and a bridge loan. At December 31, 2011, there were no outstanding borrowings under the revolving credit facility and the bridge loan.

Short-term Notes Payable

The Partnership, through Rentech, would enter into non-collateralized short-term notes payable to finance insurance premiums. During the fiscal year ended September 30, 2011, REMC entered into non-collateralized short-term notes payable to finance insurance premiums totaling approximately $1.5 million. The notes payable bore interest between 2.55% and 3.04% with monthly payments of principal and interest and a scheduled maturity date in March 2012. The balance due as of December 31, 2011 was approximately $0.4 million, which was included in accrued liabilities. During the three months ended December 31, 2011, the Partnership entered into non-collateralized short-term note payable to finance insurance premiums totaling approximately $0.7 million. The note payable bore interest at 3.04% with monthly payments of principal and interest and a scheduled maturity date in September 2012. The balance due as of December 31, 2011 was approximately $0.6 million, which was included in accrued liabilities. During 2012, the Partnership ceased utilizing non-collateralized short-term notes to finance insurance premiums.

Credit Agreements

On November 10, 2011, the Partnership and RNLLC entered into a credit agreement (the “2011 Credit Agreement”), providing for a $25.0 million senior secured revolving credit facility with a two year maturity (the “2011 Revolving Credit Facility”) and paid associated financing costs of approximately $0.9 million. The 2011 Revolving Credit Facility included a letter of credit sublimit of up to $2.5 million for issuance of letters of credit. The borrowings under the 2011 Revolving Credit Facility would have borne interest at a rate equal to an applicable margin plus, at the Partnership’s option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.5% and (3) LIBOR for an interest period of three months plus 1.00% or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. The applicable margin for borrowings under the 2011 Revolving Credit Facility was 3.25% with respect to base rate borrowings and 4.25% with respect to LIBOR borrowings. Additionally, the Partnership was required to pay a fee to the lenders under the 2011 Revolving Credit Facility on the unused amount at a rate of 0.5% per annum. The Partnership was also required to pay customary letter of credit fees on issued letters of credit. In the event the Partnership reduced or repaid in full any borrowings outstanding under the 2011 Revolving Credit Facility prior to its first anniversary, it was required to pay a prepayment premium of 2.0% of the principal amount repaid, subject to certain exceptions. There were never any borrowings made under the 2011 Revolving Credit Facility.

On February 28, 2012, RNLLC entered into the 2012 Credit Agreement. The 2012 Credit Agreement amended, restated and replaced the 2011 Credit Agreement. The 2012 Credit Agreement consisted of (i) a $100.0 million multiple draw term loan (the “CapEx Facility”) that could be used to pay for capital expenditures related to the ammonia production and storage capacity expansion, and (ii) a $35.0 million revolving facility (the “2012 Revolving Credit Facility”) that could be used for working capital needs, letters of credit and for general purposes.

The 2012 Credit Agreement had a maturity date of February 27, 2017. Borrowings under the 2012 Credit Agreement bore interest at a rate equal to an applicable margin plus, at RNLLC’s option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.5% or (3) LIBOR for an interest period of three months plus 1.00% or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period on the day that was two business days prior to the first day of such interest period. The applicable margin for borrowings under the 2012 Credit Agreement was 2.75% with respect to base rate borrowings and 3.75% with respect to LIBOR borrowings. Additionally, RNLLC was required to pay a fee to the lenders under the CapEx Facility on the undrawn available portion at a rate of 0.75% per annum and a fee to the lenders under the 2012 Revolving Credit Facility on the undrawn available portion at a rate of 0.50% per annum. RNLLC also was required to pay customary letter of credit fees on issued letters of credit. In the event RNLLC reduced or terminated the 2012 Credit Agreement prior to its third anniversary, RNLLC was required to pay a prepayment premium of 1.0% of the principal amount reduced or terminated, subject to certain exceptions.

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The 2012 Revolving Credit Facility included a letter of credit sublimit of $10.0 million, and it could be drawn on, or letters of credit could be issued, through the day that was seven days prior to the maturity date. The amounts outstanding under the 2012 Revolving Credit Facility would be required to be reduced to zero (other than outstanding letters of credit) for three periods of ten consecutive business days during each year with each period not less than 60 days apart, with one of those periods to have begun each April.

The CapEx Facility was available for borrowing until February 28, 2014 and required quarterly amortization payments expected to begin in the spring of 2014. In the first two years of amortization, RNLLC was required to make amortization payments of 10% per year, or 2.5% per quarter, and thereafter, 25% per year, or 6.25% per quarter, of the aggregate amount drawn, in each case, with the final principal payment due upon maturity.

Upon entry into the 2012 Credit Agreement, RNLLC borrowed approximately $8.5 million under the CapEx Facility (i) to repay in full outstanding borrowings under the credit agreement it had entered into on December 28, 2011, with Rentech as lender and the Partnership as guarantor (the “Bridge Loan Agreement”), of approximately $5.9 million and (ii) to pay fees associated with the 2012 Credit Agreement of approximately $2.6 million.

On October 31, 2012, RNLLC, the Partnership, RNPLLC and certain subsidiaries of RNPLLC entered into a new credit agreement (the “New 2012 Credit Agreement”). The New 2012 Credit Agreement amended, restated and replaced the 2012 Credit Agreement. The New 2012 Credit Agreement consists of (i) a $110.0 million multiple draw term loan (the “New CapEx Facility”) which can be used to pay for (x) capital expenditures related to the ammonia production and storage capacity expansion at the East Dubuque Facility and (y) capital expenditures related to our Pasadena Facility (in an amount up to $10.0 million), (ii) a $155.0 million term loan (the “New Term Loan”) that was used to finance the cash consideration paid in the acquisition of Agrifos and transaction expenses and (iii) the $35.0 million revolving credit facility (the “New 2012 Revolving Credit Facility”) that can be used for working capital needs, letters of credit and for general corporate purposes. The New 2012 Credit Agreement also provides for a $35.0 million incremental term loan facility (the “Accordion Facility”) which allows RNPLLC to borrow additional funds from any of the lenders, if such lenders agree to lend such amount, and have such borrowings included under the terms of the New 2012 Credit Agreement. Proceeds from the Accordion Facility must be used for certain specified development projects at the Pasadena Facility. If the lenders do not agree to lend amounts under the accordion facility to us, we would need to seek alternative sources of funding for the expansion projects. Depending on conditions in the capital markets, we also may seek external funding, among other things, to finance a portion of the costs of these expansion projects, including financing from the issuance of common units or debt securities. However, there is no assurance that these sources of capital would be available to us. The New 2012 Credit Agreement has a maturity date of October 31, 2017. The principal amount of the New Term Loan must be paid in equal quarterly installments of approximately $1.9 million on the first day of each fiscal quarter beginning on January 1, 2013, with the final principal payment in the amount of the remaining outstanding principal balance due upon maturity. The other terms of the New 2012 Credit Agreement are substantially similar to the 2012 Credit Agreement. In structuring the New 2012 Credit Agreement, the prepayment premium fee under the 2012 Credit Agreement was waived and the terms of the New 2012 Credit Agreement do not include any prepayment penalties.

The entry into the New 2012 Credit Agreement and the payoff of the 2012 Credit Agreement resulted in a loss on debt extinguishment, for the calendar year ended December 31, 2012, of approximately $2.1 million. The entry into the 2011 Credit Agreement and the payoff of the previous credit agreement, resulted in a loss on debt extinguishment, for the three months ended December 31, 2011, of approximately $10.3 million. The entry into and payoff of various credit agreements, resulted in a loss on debt extinguishment for the fiscal years ended September 30, 2011 and 2010 of approximately $13.8 million and $2.3 million respectively.

As of December 31, 2012, the Partnership was in compliance with all covenants under the New 2012 Credit Agreement.

Long-term debt consists of the following:

	As of December 31,
	2012		2011
	(in thousands)
Outstanding advances under the credit agreements	$	193,290	$	—
Less current portion		7,750		—
Credit facilities and term loan, long term portion	$	185,540	$	—

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Future maturities of credit facilities and term loan under the New 2012 Credit Agreement are as follows (in thousands):

For the Years Ending December 31,
2013	$	7,750
2014		10,622
2015		11,579
2016		15,887
2017		147,452
	$	193,290

Bridge Loan

The Bridge Loan Agreement consisted of a commitment by Rentech to lend up to $40.0 million to the Borrower until May 31, 2012 (the “Bridge Loan”). The Partnership entered into the Bridge Loan to fund certain capital expenditures and construction costs relating to its ammonia capacity expansion project until a term loan facility for the cost of the entire project could be put in place. Borrowings under the Bridge Loan initially bore interest at a rate equal to LIBOR plus a margin of 5.5%.

Upon signing the Bridge Loan Agreement, the Borrower agreed to pay Rentech a closing fee equal to 2.0% of the committed amount, or $800,000. In the event the Bridge Loan had been repaid on or prior to March 31, 2012, then 75% of the closing fee would have been credited toward Borrower’s repayment amount. RNLLC terminated the Bridge Loan Agreement upon entry into the 2012 Credit Agreement. Rentech reimbursed RNLLC for $600,000 in closing fees originally paid by RNLLC in accordance with the terms of the Bridge Loan Agreement.

Note 8 — Commitments and Contingencies

Natural Gas Forward Purchase Contracts

The Partnership’s policy and practice are to enter into fixed-price forward purchase contracts for natural gas in conjunction with contracted product sales in order to substantially fix gross margin on those product sales contracts. The Partnership may enter into a limited amount of additional fixed-price forward purchase contracts for natural gas in order to minimize monthly and seasonal gas price volatility. Occasionally the Partnership enters into index-price contracts. The Partnership elects the normal purchase normal sale exemption for these derivative instruments. As such, the Partnership does not recognize the unrealized gains or losses related to these derivative instruments in its financial statements. The Partnership has entered into multiple natural gas forward purchase contracts for various delivery dates through March 31, 2013. Commitments for natural gas purchases consist of the following:

	As of December 31,
	2012		2011
	(in thousands)
MMBtus under fixed-price contracts		1,955		3,040
MMBtus under index-price contracts		143		—
Total MMBtus under contracts		2,098		3,040
Commitments to purchase natural gas	$	7,531	$	12,337
Weighted average rate per MMBtu based on the fixed rates and the indexes applicable to each contract	$	3.59	$	4.06

Subsequent to December 31, 2012 through February 28, 2013, the Partnership entered into additional fixed-quantity forward purchase contracts at fixed and indexed prices for various delivery dates through April 30, 2013. The total MMBtus associated with these additional forward purchase contracts are approximately 1.0 million and the total amount of the purchase commitments are approximately $3.2 million, resulting in a weighted average rate per MMBtu of approximately $3.38. The Partnership is required to make additional prepayments under these forward purchase contracts in the event that market prices fall below the purchase prices in the contracts. These payments are recorded as deposits on gas contracts in the accompanying balance sheets.

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Operating Leases

The Partnership has various operating leases of real and personal property which expire through February 2016. Total lease expense for the year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010 was $1.1 million, $0.3 million, $0.8 million and $1.2 million, respectively.

Future minimum lease payments as of December 31, 2012 are as follows (in thousands):

For the Calendar Years Ending December 31,
2013	$	263
2014		38
2015		12
2016		1
	$	314

Litigation

The Partnership is party to litigation from time to time in the normal course of business. The Partnership accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where the Partnership determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss, if such estimate can be made. While the outcome of the Partnership’s current matters are not estimable or probable, the Partnership maintains insurance to cover certain actions and believes that resolution of its current litigation matters will not have a material adverse effect on the Partnership.

Our business is subject to extensive and frequently changing federal, state and local, environmental, health and safety regulations governing a wide range of matters, including the emission of air pollutants, the release of hazardous substances into the environment, the treatment and discharge of waste water and the storage, handling, use and transportation of our fertilizer products, raw materials, and other substances that are part of our operations. These laws include the Clean Air Act (the “CAA”), the federal Water Pollution Control Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Toxic Substances Control Act, and various other federal, state and local laws and regulations. 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 result in increased capital, operating and compliance costs.

The Texas Commission on Environmental Quality (the “TCEQ”) issued notices of violation of environmental laws relating to alleged unlawful emissions in June 2012 and August 2012 of oxides of sulfur in excess of permitted limits from the sulfuric acid plant at the Pasadena Facility. Based on information provided to the agency, the Partnership received a notice of compliance from the TCEQ relating to the June 2012 release stating no further action on our part is required. With respect to the August 2012 release, negotiations with the TCEQ are ongoing, but the settlement order currently proposed by the agency contains a penalty of less than $6,000.

Note 9 — Partners’ Capital and Partnership Distributions

The Partnership’s policy is to distribute all of the cash available for distribution which it generates each quarter. Cash available for distribution for each quarter will be determined by the board of directors (the “Board”) of the General Partner following the end of each quarter. The Partnership expects that cash available for distribution for each quarter will generally equal the cash it generates during the quarter, less cash needed for maintenance capital expenditures, debt service (if any) and other contractual obligations, and reserves for future operating or capital needs that the Board of the General Partner deems necessary or appropriate. The Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in its quarterly distribution or otherwise to reserve cash for distributions, nor does it intend to incur debt to pay quarterly distributions. The Partnership has no legal obligation to pay distributions. Distributions are not required by the Partnership’s partnership agreement and the Partnership’s distribution policy is subject to change at any time at the discretion of the Board of the General Partner. Any distributions made by the Partnership to its unitholders will be done on a pro rata basis. At December 31, 2012, the Partnership had outstanding 154,938 unit-settled phantom units. Each phantom unit entitles the holder to payments in amounts equal to the amounts of any distributions made to an outstanding unit by the Partnership. Payments to outstanding phantom units are not subtracted from operating cash flow in the calculation of cash available for distribution, but the payments made to phantom unitholders are recorded as distributions for accounting purposes. For information on the declaration of cash distributions refer to Note 16 —   Subsequent Events.

On May 15, 2012, the Partnership made a cash distribution to its common unitholders and payments to holders of phantom units for the period November 9, 2011 through and including March 31, 2012 of $1.06 per unit, approximately $40.7 million in the aggregate. On August 14, 2012, the Partnership made a cash distribution to its common unitholders and payments to holders of phantom units for the period April 1, 2012 through and including June 30, 2012 of $1.17 per unit, approximately $45.0 million in the aggregate. On November 14, 2012, the Partnership made a cash distribution to its common unitholders and payments to holders of phantom units for the period July 1, 2012 through and including September 30, 2012 of $0.85 per unit, approximately $33.1 million in the aggregate.

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Note 10 — Long-Term Incentive Equity Awards and Other Equity Based Compensation

On November 2, 2011, the Board of the General Partner adopted the Rentech Nitrogen Partners, L.P. 2011 Long-Term Incentive Plan (the “2011 LTIP”). The General Partner’s officers, employees and non-employee directors, as well as other key employees of Rentech, the indirect parent of the General Partner, and certain of the Partnership’s other affiliates who make significant contributions to its business, are eligible to receive awards under the 2011 LTIP, thereby linking the recipients’ compensation directly to the Partnership’s performance. The 2011 LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, 3,825,000 common units may be delivered pursuant to awards under the 2011 LTIP.

The accounting guidance requires all share-based payments, including grants of stock options, to be recognized in the statement of income, based on their fair values. Grants under the 2011 LTIP are marked-to market at each reporting date. Most grants have graded vesting provisions where an equal number of shares vest on each anniversary of the grant date. Rentech and RNP allocate the total compensation cost on a straight-line attribution method over the requisite service period. Equity based compensation expense that the Partnership records is included in selling, general and administrative expense.

During the calendar year ended December 31, 2012 and the three months ended December 31, 2011, charges associated with all equity-based grants issued by RNP under the 2011 LTIP were recorded as follows:

	For the Calendar Year Ended December 31,		For the Three Months Ended December 31,
	2012		2011
	(in thousands)
Unit-based compensation expense	$	2,827	$	63

Phantom unit transactions during the calendar year ended December 31, 2012 and the three months ended December 31, 2011 are summarized as follows:

	Number of Shares			Weighted Average Grant Date Fair Value			Aggregate Intrinsic Value
Granted		163,388		$	18.40
Outstanding at December 31, 2011		163,388			18.40
Granted		54,059			34.86
Vested and Settled in Shares		(42,350	)		(15.68	)
Vested and Surrendered for Withholding Taxes Payable		(20,040	)		(18.40	)
Canceled / Expired		(119	)		(18.40	)
Outstanding at December 31, 2012		154,938		$	23.78		$	5,839,626

During the calendar year ended December 31, 2012, the Partnership issued 54,059 unit-settled phantom units (which entitle the holder to distribution rights during the vesting period) covering the Partnership’s common units. Forty-one thousand eight hundred and thirty-nine of the phantom units are time-vested awards that vest in three equal annual installments. Six thousand two hundred and fifty of the phantom units were time-vested awards issued to the directors that vested on the one-year anniversary of the Offering. Three thousand nine hundred and seventy of the phantom units are time-vested awards issued to the directors that vest in one year. The remaining 2,000 phantom units are performance awards which vest upon the mechanical completion, successful performance testing and final spend within specified budget of the ammonia production and storage capacity expansion project at the East Dubuque Facility, subject to the holder’s continuing employment with RNP. The phantom unit grants resulted in unit-based compensation expense of $2,651,000 for the calendar year ended December 31, 2012.

As of December 31, 2012, there was $5,211,000 of total unrecognized compensation cost related to non-vested share-based compensation arrangements from previously granted phantom units. That cost is expected to be recognized over a weighted-average period of 2.1 years.

During the calendar year ended December 31, 2012, the Partnership issued a total of 7,890 common units which were fully vested at date of grant. The common units were issued to the directors and resulted in unit-based compensation expense of $176,000.

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Rentech Awards

During the year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, charges associated with all Rentech equity-based grants issued to RNP employees were recorded as follows:

	For the Calendar Year Ended December 31,		For the Three Months Ended December 31,		For the Fiscal Years Ended September 30,
	2012		2011		2011		2010
	(in thousands)
Stock based compensation expense	$	—	$	18	$	173	$	121

Note 11 — Employee Benefit Plans

Defined Contribution Plan

Salaried employees participate in Rentech’s 401(k) plan while union employees participate in the Partnership’s 401(k) plan. Salaried employees who are at least 18 years of age and have 60 days of service are eligible to participate in Rentech’s plan. During 2012, Rentech matched 75% of the first 6% of the participant’s salary deferrals. Participants are fully vested in both matching and any discretionary contributions made to the plan by Rentech. Union employees who are at least 18 years of age and have been employed by RNP for 120 days are eligible to participate in the Partnership’s plan. Union employees hired before October 20, 1999 receive a Partnership contribution of 4% of compensation and a Partnership match of 50% of the first 2% of the participant’s salary deferrals. Union employees hired after October 19, 1999 receive a Partnership matching contribution of 75% of the first 6% of the participant’s salary deferrals. Participants are fully vested in both matching and any discretionary contributions made to the plan by RNP. The Partnership contributed $475,000, $122,000, $450,000 and $442,000 to the plans for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and the fiscal years ended September 30, 2011 and 2010, respectively. Additionally, the Partnership has a savings and profit sharing plan for the benefit of qualified employees at the Pasadena Facility. The plan cost for the period November 1, 2012 through December 31, 2012 was approximately $7,000.

Pension Plans

Reporting and disclosures related to pension and other postretirement benefit plans require that companies include an additional asset or liability on the balance sheet to reflect the funded status of retirement and other postretirement benefit plans, and a corresponding after-tax adjustment to accumulated other comprehensive income.

The Partnership has two noncontributory pension plans (the “Pension Plans”), which cover either hourly paid employees represented by collective bargaining agreements in effect at its Pasadena Facility or hourly employees at its Pasadena Facility who have 1,000 hours of service during a year of employment.

Postretirement Benefits

The Partnership has a postretirement benefit plan (the “Postretirement Plan”) for certain employees at its Pasadena Facility. The plan provides a fixed dollar amount to supplement payment of eligible medical expenses. The amount of the supplement under the plan is based on years of service and the type of coverage elected (single or family members and spouses). Participants are eligible for supplements at retirement after age 55 with at least 20 years of service to be paid until the attainment of age 65 or another disqualifying event, if earlier.

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The Pension Plans and the Postretirement Plan were acquired as part of the Agrifos Acquisition. The following tables summarize the projected benefit obligation, the assets and the funded status of the Pension Plans and the Postretirement Plan at December 31, 2012:

	Pension			Post- retirement
	(in thousands)
Projected benefit obligation
Benefit obligation at beginning of year	$	5,213		$	863
Service cost		29			4
Interest cost		31			5
Amendment		—			332
Actuarial (gain) loss		(412	)		(54	)
Actual benefit paid		(20	)		(14	)
Benefit obligation at end of year		4,841			1,136
Fair value of plan assets
Fair value of plan assets at beginning of year		4,279			—
Actual return on plan assets		74			—
Employer contributions		—			14
Actual benefit paid		(20	)		(14	)
Fair value of plan assets at end of year		4,333			—
Funded status at end of year	$	(508	)	$	(1,136	)
Amounts recognized in the consolidated balance sheet
Current liabilities	$	—		$	(95	)
Noncurrent liabilities		(508	)		(1,041	)
	$	(508	)	$	(1,136	)

The components of net periodic benefit cost are as follows for the two-month period ended December 31, 2012:

	Pension			Post- retirement
	(in thousands)
Service cost	$	29		$	4
Interest cost		31			5
Expected return on plan assets		(42	)		—
Net periodic pension costs	$	18		$	9

Accumulated other comprehensive income (loss) at December 31, 2012 consists of the following amounts that have not yet been recognized in net periodic benefit cost:

	Pension			Post- retirement
	(in thousands)
Net (gain) loss	$	(444	)	$	(54	)
Prior service costs		—			332
Total recognized in other comprehensive (income) loss	$	(444	)	$	278

The expected portion of the accumulated other comprehensive (income) loss expected to be recognized as a component of net periodic benefit cost in 2013 is approximately $(1,000) and $9,000 for the Pension Plans and Postretirement Plan, respectively.

The above measures are based upon the following assumptions at December 31, 2012:

	Pension			Post- retirement
Weighted average discount rate		3.6	%		3.6	%
Weighted average expected rate of return on assets		6.0	%		N/A

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As the Postretirement Plan provides a fixed dollar amount to participants, increasing or decreasing the health care cost trend rate by 1% would not have a material impact on the December 31, 2012 obligation.

	Target Allocation as of December 31, 2012			Percentage of Pension Plan Assets 2012
Asset Category
Equity securities		50	%		51	%
Debt securities		50	%		49	%

The pension plan assets, which are deemed to be Level 1, measured at fair value consist of the following at December 31, 2012 (in thousands):

Mutual funds — equity	$	2,193
Mutual funds — fixed income		2,134
Cash		6
Fair value of plan assets	$	4,333

The Partnership expects to contribute approximately $109,000 and $97,000 to Pension Plans and a Postretirement Plan, respectively, in 2013. We acquired these plans as part of the Agrifos Acquisition. The Partnership made contributions of $0 and approximately $14,000 to the Pension Plans and Postretirement Plan, respectively, during the period November 1, 2012 through December 31, 2012.

Expected Future Benefit Payments:

	Pension		Postretirement
	(in thousands)
2013	$	188	$	97
2014		202		100
2015		216		90
2016		228		84
2017		240		79
2018-2022		1,285		253

Note 12 — Income Taxes

For the year ended December 31, 2012, the Partnership recorded a state income tax provision of approximately $303,000 on income attributable to the Partnership, $800 of which is attributable to annual minimum franchise tax due to California Franchise Tax Board, $257,000 is attributable to replacement tax due to Illinois Department of Revenue and $45,000 is attributable to Texas Margin Tax due to the Texas Comptroller.

The components of income taxes included in the year ended December 31, 2011 were for REMC prior to its conversion to a partnership.

The provision for income taxes for the three months ended December 31, 2011 and 2010 and the fiscal years ended September 30, 2011 and 2010 was as follows:

	For the Three Months Ended December 31,					For the Fiscal Years Ended September 30,
	2011		2010			2011			2010
			(unaudited)
	(in thousands)
Current:
Federal	$	—	$	2,436		$	15,540		$	5,454
State		—		312			2,593			736
Total Current		—		2,748			18,133			6,190
Deferred:
Federal	$	—	$	54		$	(764	)	$	(2,507	)
State		—		(30	)		46			(339	)
Total Deferred		—		24			(718	)		(2,846	)
		—		2,772			17,415			3,344

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A reconciliation of the income taxes at the federal statutory rate to the effective tax rate was as follows:

	For the Three Months Ended December 31,					For the Fiscal Years Ended September 30,
	2011		2010			2011		2010
			(unaudited)
	(in thousands)
Federal income tax benefit calculated at the federal statutory rate	$	—	$	2,483		$	14,754	$	2,924
State income tax benefit net of federal benefit		—		320			2,466		397
Permanent. True ups, other		—		6			22		23
Change in state tax rate		—		(37	)		173		—
Income tax expense	$	—	$	2,772		$	17,415	$	3,344

The components of the net deferred tax liability and net deferred tax asset as of December 31, 2011 are presented below. The amounts are pro forma amounts, which reflect balances just before the Offering.

	Pro Forma as of December 31,
	2011
	(in thousands)
Current deferred tax assets/(liabilities):
Accruals for financial statement purposes not allowed for income taxes	$	1,910
Basis difference in prepaid expenses		(335	)
Inventory		82
Current deferred tax asset (liability), net	$	1,657
Long-term deferred tax assets/(liabilities):
Basis difference relating to intangibles	$	—
Basis difference in property, plant and equipment		(625	)
Other		—
Long-term deferred tax asset/(liability), net	$	(625	)
Net deferred tax assets/(liabilities)	$	1,032

Note 13 — Segment Information

Prior to the Agrifos Acquisition, the Partnership operated in only one business segment. After the Agrifos Acquisition, the Partnership operates in two business segments.

• East Dubuque – The operations of the East Dubuque Facility, which produces primarily ammonia and UAN.

• Pasadena – The operations of the Pasadena Facility, which produces primarily ammonium sulfate.

The Partnership’s reportable operating segments have been determined in accordance with the Partnership’s internal management structure, which is organized based on operating activities. The Partnership evaluates performance based upon several factors, of which the primary financial measure is segment-operating income.

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	For the Calendar Year Ended December 31,
	2012
	(in thousands)
Revenues
East Dubuque	$	224,205
Pasadena		37,430
Total revenues	$	261,635
Gross profit
East Dubuque	$	133,543
Pasadena		(1,704	)
Total gross profit	$	131,839
Selling, general and administrative expense
East Dubuque	$	6,242
Pasadena		361
Total selling, general and administrative expense	$	6,603
Depreciation and amortization
East Dubuque	$	807
Pasadena		583
Total depreciation and amortization recorded in operating expenses	$	1,390
East Dubuque – expense recorded in cost of sales		10,690
Pasadena – expense recorded in cost of sales		380
Total depreciation and amortization recorded in cost of sales	$	11,070
Total depreciation and amortization	$	12,460
Other operating (income) expenses
East Dubuque	$	510
Pasadena		—
Total other operating (income) expenses	$	510
Operating income (loss)
East Dubuque	$	125,984
Pasadena		(2,648	)
Total operating income (loss)	$	123,336
Interest expense
East Dubuque	$	194
Pasadena		—
Total interest expense	$	194
Net income
East Dubuque	$	123,721
Pasadena		(2,648	)
Total net income	$	121,073
Reconciliation of segment net income to consolidated net income:
Segment net income	$	121,073
Partnership and unallocated expenses		(11,844	)
Unallocated interest expense and loss on interest rate swaps		(2,226	)
Consolidated net income	$	107,003

	As of December 31,
	2012
	(in thousands)
Total assets
East Dubuque	$	125,100
Pasadena		191,279
Total assets	$	316,379
Reconciliation of segment total assets to consolidated total assets:
Segment total assets	$	316,379
Partnership and other		60,266
Consolidated total assets	$	376,645

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Partnership and unallocated expenses represent costs that relate directly to the Partnership or to the Partnership and its subsidiaries but are not allocated to a segment. Such expenses consist primarily of business development expenses for the Partnership, including the Agrifos Acquisition costs, labor allocations from Rentech, accounting, tax, and legal fees, unit-based compensation, taxes, board expense and certain insurance costs. Unallocated interest expense represents interest expense on the New Term Loan, which was used to finance the Agrifos Acquisition. Prior to calendar year ended December 31, 2012, East Dubuque and the Partnership were considered one entity for financial reporting purposes. Prior to the Agrifos Acquisition, the Partnership operated as one segment.

All revenues are derived from customers in the United States.

Note 14 — Net Income Per Common Unit

The following table sets forth the computation of basic and diluted net income per common unit (in thousands, except for per unit data).

	For the Calendar Year Ended December 31,		For the Period November 9, 2011 Through December 31,
	2012		2011
Numerator:
Net income	$	107,003	$	11,331
Less: Income attributable to unvested units		491		48
Net income attributable to common unit holders	$	106,512	$	11,283
Denominator:
Weighted average common units outstanding		38,350		38,250
Effect of dilutive units:
Phantom units		2		5
Diluted units outstanding		38,352		38,255
Basic net income per common unit	$	2.78	$	0.30
Diluted net income per common unit	$	2.78	$	0.30

For the year ended December 31, 2012, approximately 149,000 phantom units were excluded from the calculation of diluted net income per common unit because their inclusion would have been anti-dilutive. For the period November 9, 2011 through December 31, 2011, no phantom units were excluded from the calculation of diluted net income per common unit.

Note 15 — Selected Quarterly Financial Data (Unaudited)

Selected unaudited condensed financial information for the calendar years ended December 31, 2012 and 2011 is presented in the tables below (in thousands).

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
For the 2012 Calendar Year
Revenues	$	38,473	$	70,643	$	60,112	$	92,407
Gross profit	$	22,572	$	45,646	$	35,035	$	28,586
Operating income	$	19,457	$	41,604	$	29,200	$	21,302
Income before income taxes	$	19,373	$	41,228	$	28,848	$	17,857
Net income	$	19,373	$	41,228	$	28,848	$	17,554
Net income per common unit—Basic	$	0.51	$	1.08	$	0.75	$	0.44
Net income per common unit—Diluted	$	0.51	$	1.08	$	0.75	$	0.44

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	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
For the 2011 Calendar Year
Revenues	$	23,943	$	74,385	$	38,567	$	63,014
Gross profit	$	10,201	$	37,427	$	12,816	$	25,554
Operating income	$	9,012	$	35,882	$	10,376	$	22,648
Income before income taxes	$	6,003	$	23,377	$	5,865	$	10,455
Net income	$	3,533	$	13,757	$	3,312	$	10,455

Note 16 — Subsequent Events

On January 23, 2013, the Board of the General Partner declared a cash distribution to the Partnership’s common unitholders for the period October 1, 2012 through and including December 31, 2012 of $0.75 per unit which will result in total distributions in the amount of approximately $29.2 million, including payments to phantom unitholders. The cash distribution was paid on February 14, 2013 to unitholders of record at the close of business on February 7, 2013.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. We have established and currently maintain disclosure controls and procedures designed to ensure that information required to be disclosed by us in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, or the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partners’ principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2012.

Management’s Annual Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of our management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies and procedures may deteriorate.

Our management, including our general partner’s Chief Executive Officer and our Chief Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. In connection with management’s assessment of our internal control over financial reporting described above, management concluded that our internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Management has excluded the Partnership’s wholly-owned subsidiary, RNPLLC, from its assessment of internal control over financial reporting as of December 31, 2012 because RNPLLC was acquired by the Partnership in a purchase business combination on November 1, 2012 which did not allow management enough time to make a proper assessment. The total assets, excluding goodwill and intangible assets resulting from purchase price adjustments, and total revenues of RNPLLC represent approximately 29% and 14%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2012.

Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting during the quarter ended December 31, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

There is no information required to be disclosed in a report on Form 8-K during the three months ended December 31, 2012 that has not previously been reported.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of Rentech Nitrogen Partners, L.P.

Our general partner, Rentech Nitrogen GP, LLC, manages our operations and activities subject to the terms and conditions specified in our partnership agreement. Our general partner is owned by RNHI, an indirect wholly owned subsidiary of Rentech. The operations of our general partner in its capacity as general partner are managed by its board of directors. Actions by our general partner that are made in its individual capacity or in its sole discretion will be made by RNHI as the sole member of our general partner and not by the board of directors of our general partner. Our general partner is not elected by our unitholders. The officers of our general partner manage the day-to-day affairs of our business.

Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and it is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law or any other law. Examples include the exercise of its call right or its registration rights, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the Partnership. Actions by our general partner that are made in its individual capacity or in its sole discretion are made by RNHI, the sole member of our general partner, not by its board of directors.

Limited partners are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our partnership agreement contains various provisions which replace default fiduciary duties with contractual governance standards. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it. Our new 2012 credit agreement is non-recourse to our general partner.

As a publicly traded limited partnership, we qualify for certain exemptions from the New York Stock Exchange’s corporate governance requirements, including:

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

• the requirement that the board of directors of our general partner have a nominating/corporate governance committee and a compensation committee that are composed entirely of independent directors.

Our general partner’s board of directors currently is comprised of a majority of independent directors. However, our general partner’s board of directors does not currently intend to establish a nominating/corporate governance committee or a compensation committee. Accordingly, unitholders do not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the New York Stock Exchange.

The board of directors of our general partner currently consists of seven directors. In accordance with the rules of the New York Stock Exchange, we are required to have at least three independent directors. Our seven-member board of directors currently includes five independent directors.

The board of directors of our general partner has one standing committee, which is its audit committee. The members of the audit committee currently consist of Michael S. Burke, James F. Dietz and Keith B. Forman, and Mr. Burke is the chairman of the audit committee. The board of directors of our general partner has determined that Messrs. Burke, Dietz and Forman are each independent directors who meet the independence requirements established by the New York Stock Exchange and the Exchange Act, and that, based upon their education and experience, Messrs. Burke, Dietz and Forman each have the requisite qualifications to qualify under the rules of the SEC, and designated them as audit committee financial experts. The audit committee’s primary functions include reviewing our external financial reporting, recommending engagement of our independent auditors and reviewing procedures for internal auditing and the adequacy of our internal accounting controls.

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The board of directors of our general partner may from time to time establish a conflicts committee, which would not be a standing committee, consisting entirely of independent directors. Pursuant to our partnership agreement, the board may, but is not required to, seek the approval of the conflicts committee whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any public unitholder, on the other. The conflicts committee may then determine whether the resolution of the conflict of interest is in the best interests of the Partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standard established by the New York Stock Exchange and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by the general partner of any duties it may owe us or our unitholders.

Meetings and Other Information

During calendar year 2012, the board of directors of our general partner has had eight regularly scheduled meetings and our audit committee has had four meetings. None of the directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board on which the director served.

Our committee charters and governance guidelines, as well as our Code of Business Conduct Ethics that applies to our directors, officers and employees, Disclosure Policy and our Whistleblower Policy are available on our website at http://www.rentechnitrogen.com. We intend to disclose any amendment to or waiver of our Code of Business Conduct or Ethics either on our website or by filing a Current Report on Form 8-K. Our website address referenced above is not intended to be an active hyperlink, and the contents of our website shall not be deemed to be incorporated herein.

Section 16(a) of the Exchange Act requires the executive officers and directors of our general partner, and persons who own more than ten percent of a registered class of our equity securities, or, collectively, the Insiders, to file initial reports of ownership and reports of changes in ownership with the SEC. Insiders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. To our knowledge, based solely on our review of the copies of such reports furnished to us or written representations from certain Insiders that they were not required to file a Form 5 to report previously unreported ownership or changes in ownership. We believe that, during the calendar year ending December 31, 2012, the Insiders complied with all such filing requirements.

Report of the Audit Committee

The audit committee of our general partner oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process. In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this report.

Our independent registered public accounting firm, PricewaterhouseCoopers LLP, is responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted in the United States of America. The audit committee reviewed with PricewaterhouseCoopers LLP their judgment as to the quality, not just the acceptability, of our accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards.

The audit committee discussed with PricewaterhouseCoopers LLP the matters required to be discussed by SAS 61 (Codification of Statement on Auditing Standards, AU § 380), as may be modified or supplemented. The committee received written disclosures and the letter from PricewaterhouseCoopers LLP required by PCAOB Rule 3526 Communication with Audit Committees Concerning Independence, as may be modified or supplemented, and has discussed with PricewaterhouseCoopers LLP its independence from management and the Partnership.

Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in this report for filing with the SEC.

Michael S. Burke, Chairman

James F. Dietz

Keith B. Forman

Executive Officers and Directors

The following table sets forth the names, positions and ages (as of February 28, 2013) of the executive officers and directors of our general partner.

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D. Hunt Ramsbottom, Dan J. Cohrs, John H. Diesch and Colin M. Morris are also officers of Rentech and provide their services to our general partner and us pursuant to the services agreement we entered into among us, Rentech and our general partner. These officers divide their working time between the management of Rentech and us.

Name	Age	Position With Our General Partner
D. Hunt Ramsbottom	55	Chief Executive Officer and Director
Dan J. Cohrs	60	Chief Financial Officer
John H. Diesch	55	President and Director
John A. Ambrose	59	Chief Operating Officer
Wilfred R. Bahl, Jr.	62	Senior Vice President of Finance and Administration
Marc E. Wallis	52	Senior Vice President of Sales and Marketing
Colin M. Morris	40	Senior Vice President, General Counsel and Secretary
Halbert S. Washburn	52	Director
Michael F. Ray	59	Director
Michael S. Burke	49	Director
James F. Dietz	66	Director
Keith B. Forman	54	Director

D. Hunt Ramsbottom D. Hunt Ramsbottom was appointed Chief Executive Officer and as a member of the board of directors of our general partner in July 2011. Since September 2005, Mr. Ramsbottom has served as President and a director of Rentech and, since December 2005, he has served as Chief Executive Officer of Rentech. Mr. Ramsbottom had been serving as a consultant to Rentech since August 2005 under the terms of a Management Consulting Agreement Rentech entered into with Management Resource Center, Inc. Mr. Ramsbottom has over 25 years of experience building and managing growth companies. Prior to accepting his position at Rentech, Mr. Ramsbottom held various key management positions including: from 2004 to 2005, as Principal and Managing Director of Circle Funding Group, LLC, a buyout firm; from 1997 to 2004, as Chief Executive Officer and Chairman of M2 Automotive, Inc., an automotive repair venture; and from 1989 to 1997, as Chief Executive Officer of Thompson PBE, a supplier of paints and related supplies, which was acquired by FinishMaster, Inc. in 1997. On April 17, 2005, M2 Automotive, Inc. completed an assignment for the benefit of its creditors pursuant to a state law insolvency proceeding. The board of directors of our general partner has determined that Mr. Ramsbottom brings to the board knowledge of our business, a historical understanding of our operations gained through his service as President and Chief Executive Officer of Rentech and experience with companies as Chief Executive Officer and Principal and Managing Director, and therefore he should serve on the board of directors of our general partner.

Dan J. Cohrs. Dan J. Cohrs was appointed Chief Financial Officer of our general partner in July 2011. Since October 2008, Mr. Cohrs has served as Executive Vice President and Chief Financial Officer of Rentech. Mr. Cohrs was also Treasurer of Rentech from October 2008 until November 2009 and was re-appointed Treasurer in October 2010. Mr. Cohrs has more than 25 years of experience in corporate finance, strategy and planning, and mergers and acquisitions. From April 2008 through September 2008, Mr. Cohrs served as Chief Development and Financial Officer of Agency 3.0, LLC, a private digital advertising and consulting agency in Los Angeles, California and he was a Partner and a Board Member of Agency 3.0, LLC until September 2009. From August 2007 through September 2008, he served as Chief Development & Financial Officer of Skycrest Ventures, LLC, a private investment and consulting firm in Los Angeles that was related to Agency 3.0, LLC. From June 2006 to May 2007, Mr. Cohrs served as a consultant for finance and corporate development, as well as Interim Chief Financial Officer for several months during that period of time, for Amp’d Mobile, a private mobile media entertainment company in Los Angeles. From 2003 to 2007, Mr. Cohrs worked as an independent consultant and advised companies regarding financings, investor presentations and business plans. From November 2005 to March 2006, Mr. Cohrs served as a Visiting Senior Lecturer at Cornell University’s Johnson School of Management in the area of corporate governance. From May 1998 to June 2003, Mr. Cohrs served as Executive Vice President and Chief Financial Officer of Global Crossing Ltd. Prior to being employed at Global Crossing Ltd., Mr. Cohrs held senior positions in finance and strategy at Marriot Corporation, Northwest Airlines, Inc. and GTE Corporation, a predecessor of Verizon Communications, Inc.

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On June 1, 2007, Amp’d Mobile, Inc. filed a petition for bankruptcy under chapter 11 of title 11 of the United States Code, 11 U.S.C. § 101, et seq., or the Bankruptcy Code, with the United States Bankruptcy Court for the District of Delaware. On January 28, 2002, Global Crossing Ltd., and certain of its direct and indirect subsidiaries, filed a petition for bankruptcy under chapter 11 of title 11 of the Bankruptcy Code with the United States Bankruptcy Court for the Southern District of New York. On April 11, 2005, the SEC, Global Crossing Ltd., Mr. Cohrs (at the relevant time, the Chief Financial Officer of Global Crossing Ltd.) and other members of Global Crossing Ltd.’s senior management reached a settlement related to an SEC investigation regarding alleged violations of the reporting provisions of Section 13(a) of the Securities Exchange Act of 1934 (and the regulations thereunder). The parties to the agreement (other than the SEC) agreed not to cause any violations of such reporting provisions in the future, and in connection with a parallel civil action, Mr. Cohrs agreed to pay a $100,000 civil penalty. In the SEC order, none of the allegations related to fraud, no party admitted liability and no other violations of securities laws were alleged. Also in connection with Global Crossing, Ltd., on July 16, 2004, Mr. Cohrs and the Secretary of the United States Department of Labor entered into a settlement agreement, the relevant restrictions of which expired on July 16, 2009, pursuant to which Mr. Cohrs agreed, among other things, that he would give notice to the Secretary, and if the Secretary objected, then he would not serve in a fiduciary capacity with respect to any plan covered by the Employee Retirement Income Security Act, or ERISA.

John H. Diesch. John H. Diesch was appointed President and a member of the board of directors of our general partner in July 2011. Since January 2008, Mr. Diesch has served as Senior Vice President of Operations of Rentech and is responsible for plant operations at our facilities, Rentech’s Product Demonstration Unit in Commerce City, Colorado and the operation of future synthetic fuels plants, including Rentech’s proposed facility near Natchez, Mississippi. From April 2006 to January 2008, Mr. Diesch served as President of RNLLC (formerly REMC) and Vice President of Operations for Rentech. From April 1999 to April 2006, Mr. Diesch served as Managing Director of Royster-Clark Nitrogen, Inc., and previously served as Vice President and General Manager of nitrogen production and distribution for IMC AgriBusiness Inc., an agricultural fertilizer manufacturer. In 1991, he joined Vigoro Industries Inc., a manufacturer and distributor of potash, nitrogen fertilizers and related products, as North Bend, Ohio Plant Manager after serving as Plant Manager, Production Manager and Process Engineer with Arcadian Corporation, a nitrogen manufacturer, Columbia Nitrogen Corp., a manufacturer of fertilizer products, and Monsanto Company, a multinational agricultural biotechnology corporation. Mr. Diesch is a member of the board of directors of the Fertilizer Institute, a former member of the board of directors of the Gasification Technologies Council and previously served as director of the Dubuque Area Chamber of Commerce, and was recently management Chairman of the Board for the Dubuque Area Labor Management Council. The board of directors of our general partner has determined that Mr. Diesch brings to the board knowledge of our business and our industry and valuable insight into the operation of our facility, and therefore he should serve on the board of directors of our general partner.

John A. Ambrose. John A. Ambrose was appointed Chief Operating Officer of our general partner in July 2011. Since December 2007, Mr. Ambrose has served as the President of RNLLC (formerly REMC) after joining RNLLC in April 2007 as Operations Director. Mr. Ambrose has 37 years of chemical manufacturing experience in specialty chemical, commodity chemical and fertilizer manufacturing, including international responsibilities. From 2003 to 2007, he served as Plant Manager at Ferro Corporation, a global producer of technology-based performance materials for manufacturers. Mr. Ambrose began his career with PPG Industries, Inc., a global supplier of paints, coatings, optical products, specialty materials, chemicals, glass and fiber glass, where he advanced through several manufacturing positions over the course of 28 years, initially in chlor-alkali, then holding positions such as environmental compliance/remediation manager and manufacturing manager within the Optical Monomers business unit. As director of manufacturing from 1996 to 2003, he managed and expanded multiple worldwide plants for the company’s precipitated silica business unit. He serves on the executive committee of the board of directors of the Chemistry Industry Council of Illinois.

Wilfred R. Bahl, Jr. Wilfred R. Bahl, Jr. was appointed Senior Vice President of Finance and Administration of our general partner in July 2011. Since April 2006, Mr. Bahl has also served as the Vice President and Chief Financial Officer of RNLLC (formerly REMC). He is a Certified Public Accountant and has 39 years of finance experience, with 33 of those years in the fertilizer industry. From 1999 to 2006, Mr. Bahl was the Director of Finance and Energy for Royster-Clark Nitrogen, Inc. From 1998 to 1999, he served as Vice President of Business Development and, from 1995 to 1998, he served as the Vice President of Finance and Administration of IMC Nitrogen Co. From 1991 to 1995, he served as Vice President of Finance for Phoenix Chemical Co. In 1987, he served as Treasurer and was appointed to the board of directors of Phoenix Chemical Co and, in 1989, was appointed to the executive committee of the board of directors. From 1980 to 1987, Mr. Bahl served as the Administrative and Accounting Manager of N-Ren Corporation and later served as its Controller. Prior to joining N-Ren Corporation, he held various accounting positions, primarily in the accounting sector.

Marc E. Wallis. Marc E. Wallis was appointed Senior Vice President of Sales and Marketing of our general partner in July 2011. Mr. Wallis has served as Vice President, Sales and Marketing of REMC since 2006 and has a long history working with our facility. From 2000 to 2006, he held the position of National Accounts Sales Manager of our company. From 1995 to 2000, Mr. Wallis held the positions of Director of Sales and Purchasing at IMC Agribusiness Inc., the prior owner of our facility. From 1987 to 1995, Mr. Wallis held the position of Director of Purchasing at the Vigoro Corporation, a manufacturer and distributor of potash, nitrogen fertilizers and related products.

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Colin M. Morris. Colin M. Morris was appointed Senior Vice President, General Counsel and Secretary of our general partner and Rentech in October 2011. From July 2011 to October 2011, Mr. Morris served as the Vice President, General Counsel and Secretary of our general partner and from June 2006 to October 2011, Mr. Morris served as the Vice President, General Counsel and Secretary of Rentech. Mr. Morris practiced corporate and securities law at the Los Angeles office of Latham & Watkins LLP from June 2004 to May 2006. From September 2000 to May 2004, Mr. Morris practiced corporate and securities law in the Silicon Valley office of Wilson, Sonsini, Goodrich and Rosati. Prior to that, Mr. Morris practiced corporate and securities law in the Silicon Valley office of Pillsbury Winthrop Shaw Pittman LLP.

Halbert S. Washburn. Halbert S. Washburn was appointed as a member of the board of directors of our general partner in July 2011. Since December 2005, Mr. Washburn has served as a member of the board of directors of Rentech, and since June 2011 has served as its Chairman. Mr. Washburn has over 25 years of experience in the energy industry. Since August 2006, Mr. Washburn has been the Chief Executive Officer of BreitBurn GP, LLC, the general partner of BreitBurn Energy Partners LP. Since August 2006, he was the Co-Chief Executive Officer and served on the board of directors of BreitBurn GP, LLC. He has served as the Co-President and a director of BreitBurn Energy Corporation since 1988. He also has served as a Co-Chief Executive Officer and a director for BreitBurn Energy Holdings, LLC and as Co-Chief Executive Officer and a director of BEH (GP), LLC. Mr. Washburn previously served as Chairman on the Executive Committee of the board of directors of the California Independent Petroleum Association. He also served as Chairman of the Stanford University Petroleum Investments Committee and as Secretary and Chairman of the Wildcat Committee. The board of directors of our general partner has determined that Mr. Washburn brings to the board knowledge of our business and extensive experience with master limited partnerships, including his service as an executive officer and director of several BreitBurn entities, and therefore he should serve on the board of directors of our general partner.

Michael F. Ray. Michael F. Ray was appointed as a member of the board of directors of our general partner in July 2011. Since May 2005, Mr. Ray has served as a member of the board of directors of Rentech and served as the Chairman of Rentech’s Compensation Committee from 2005 until 2010. Mr. Ray founded and, since 2001, has served as President of ThioSolv, LLC. ThioSolv, LLC is in the business of developing and licensing technology to the refining and chemical sector. Also, since May 2005, Mr. Ray has served as General Partner of GBTX Leasing, LLC, a company that owns and leases rail cars for the movement of liquid chemicals and salts. Since 2008, Mr. Ray has served as a member of the board of directors and the Technology Committee for Cyanco Corporation, a producer of sodium cyanide in the Western United States, and a subsidiary of Oaktree Capital Management, OCM Cyanco Holdings, LLC, which holds a controlling interest in Cyanco Corporation. From 1995 to 2001, Mr. Ray served as Vice President of Business Development for the Catalyst and Chemicals Division of The Coastal Corporation, a company that principally gathered, processed, stored and distributed natural gas. Mr. Ray served as President (from 1990 to 1995), Vice President of Corporate Development and Administration (from 1986 to 1990) and Vice President of Carbon Dioxide Marketing (from 1985 to 1986) of Coastal Chem, Inc., a manufacturer of dry ice and solid carbon dioxide. Mr. Ray served as Regional Operations Manager (from 1981 to 1985) and Plant Manager (from 1980 to 1981) of Liquid Carbonic Corporation, a seller of carbon dioxide products. Mr. Ray previously served as a member of the board of directors of Coastal Chem, Inc., Cheyenne LEADS and Wyoming Heritage Society. Mr. Ray also served on the Nitrogen Fertilizer Industry Ad Hoc Committee, the University of Wyoming EPSCOR Steering Committee and Wyoming Governor’s committee for evaluating state employee compensation. The board of directors of our general partner has determined that Mr. Ray brings to the board valuable knowledge of and experience in the chemical and nitrogen fertilizer industries and directorial and governance experience as a director of Coastal Chem, Inc., and therefore he should serve on the board of directors of our general partner.

Michael S. Burke. Michael S. Burke was appointed as a member of the board of directors of our general partner in July 2011. Since March 2007, Mr. Burke has served as a member of the board of directors of Rentech. Mr. Burke was appointed President of AECOM Technology Corporation, or AECOM, on October 1, 2011. AECOM is a global provider of professional technical and management support services to government and commercial clients. From December 2006 through September 2011, Mr. Burke served as Executive Vice President, Chief Financial Officer of AECOM. Mr. Burke joined AECOM as Senior Vice President, Corporate Strategy in October 2005. From 1990 to 2005, Mr. Burke was with the accounting firm, KPMG LLP, where he served in various senior leadership positions, most recently as a Western Area Managing Partner from 2002 to 2005 and was a member of the board of directors of KPMG from 2000 through 2005. While on the board of directors of KPMG, Mr. Burke served as the Chairman of the Board Process and Governance Committee and a member of the Audit and Finance Committee. Mr. Burke also serves on various charitable and community boards. Mr. Burke received a B.S. degree in accounting from the University of Scranton and a J.D. degree from Southwestern University. The board of directors of our general partner has determined that Mr. Burke brings to the board extensive accounting, financial and business experience, including experience with a public company, and therefore he should serve on the board of directors of our general partner.

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James F. Dietz. James F. Dietz was appointed as a member of the board of directors of our general partner in February 2012. Mr. Dietz served on the board of directors of Prospect Global Resources, Inc., a publicly traded company on NASDAQ engaged in the development of a potash mine in the Holbrook Basin of eastern Arizona, from November 2012 to March 2013. Mr. Dietz has over 41 years of experience in the fertilizer and chemical industries. Mr. Dietz most recently served as Executive Vice President and Chief Operating Officer of Potash Corporation of Saskatchewan Inc., or PotashCorp, from November 2000 until his retirement in June 2010. In November 2000, Mr. Dietz was named Executive Vice President & Chief Operating Officer for PotashCorp. From 1998 to November 2000, Mr. Dietz served as President of PotashCorp Nitrogen, and from 1997 to 1998, as Executive Vice President. In addition to responsibility for PotashCorp’s worldwide operations, Mr. Dietz had responsibility for the corporation’s Safety, Health, and Environment performance and the Procurement functions. From 1993 to 1997, Mr. Dietz was Vice President of Manufacturing with Arcadian Corporation in Memphis, Tennessee. From 1969 to 1993, Mr. Dietz had increasing operational responsibility for Standard Oil of Ohio (Sohio) and BP, both in the United States and the United Kingdom. The board of directors of our general partner has determined that Mr. Dietz brings to the board valuable knowledge of and experience in the chemical and nitrogen fertilizer industries, and therefore he should serve on the board of directors of our general partner.

Keith B. Forman. Keith B. Forman was appointed as a member of the board of directors of our general partner at the closing of our initial public offering. Since April 2007, Mr. Forman has been a director of Capital Product Partners L.P., a publicly traded shipping limited partnership specializing in the seaborne transportation of oil, refined oil products and chemicals. Mr. Forman currently serves as the Chairman of its conflicts committee and is a member of its audit committee. Since May of 2011, Mr. Forman has served as a Senior Advisor to Industry Funds Management (IFM). IFM is an Australian based fund investing in infrastructure projects around the world including making investments in energy related infrastructure. From November 2007 until March 2010, Mr. Forman served as Partner and Chief Financial Officer of Crestwood Midstream Partners LP, a private investment partnership focused on making equity investments in the midstream energy market. The other partners of Crestwood Mainstream Partners LP included the Blackstone Group L.P., Kayne Anderson Energy Funds and GSO Capital Partners LP. From February 2005 to 2007, Mr. Forman was a member of the board of directors of Kayne Anderson Energy Development, a closed-end investment fund focused on making debt and equity investments in energy companies, and was a member of its audit committee. Mr. Forman was also a member of the board of directors of Energy Solutions International Ltd., a privately held supplier of oil and gas pipeline software management systems, from April 2004 to January 2009. From January 2004 to July 2005, Mr. Forman was Senior Vice President, Finance for El Paso Corporation, a provider of natural gas services. From January 1992 to December 2003, he served as Chief Financial Officer of GulfTerra Energy Partners L.P., a publicly traded master limited partnership, and was responsible for the financing activities of the partnership, including in commercial and investment banking relationships. Mr. Forman received a B.A. degree in economics and political science from Vanderbilt University. The board of directors of our general partner has determined that Mr. Forman brings to the board accounting, financial and directorial experience, including extensive experience with master limited partnerships, and therefore he should serve on the board of directors of our general partner.

The directors of our general partner hold office until the earliest of their death, resignation or removal.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Executive Summary

This Compensation Discussion and Analysis provides an overview and analysis of our executive compensation program during the fiscal year ended December 31, 2012, or fiscal year 2012, for our named executive officers, or NEOs. Our executive compensation program is designed to align executive pay with individual performance on both short and long-term bases, link executive pay to specific, measurable financial, technological and development achievements intended to create value for securityholders and utilize compensation as a tool to attract and retain the high-caliber executives that are critical to our long-term success.

The following table sets forth the key elements of our NEOs’ compensation, along with the primary objectives associated with each element of compensation.

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Compensation Element	Primary Objective
Base salary	To recognize performance of job responsibilities, provide stable income and attract and retain experienced individuals with superior talent.
Annual incentive compensation	To promote short-term performance objectives and reward individual contributions to the achievement of those objectives.
Long-term equity incentive awards	To emphasize long-term performance objectives, align the interests of our NEOs with unitholder interests, encourage the maximization of our unit value and retain key executives.
Severance and change in control benefits	To encourage the continued attention and dedication of our NEOs and provide reasonable individual security to enable our NEOs to focus on our best interests, particularly when considering strategic alternatives.
Retirement savings (401(k) plan)	To provide an opportunity for tax-efficient savings with the added economic incentive of employer matching contributions.
Other elements of compensation and perquisites	To attract and retain talented executives in a cost-efficient manner by providing benefits with high perceived values at relatively low cost.

To serve the foregoing objectives, our overall compensation program is generally designed to be flexible rather than purely formulaic. In alignment with the objectives set forth above, the board of directors of our general partner and Rentech’s Compensation Committee, have generally determined the overall compensation of our NEOs and its allocation among the elements described above, relying on the analyses and advice provided by Rentech’s compensation consultant as well as input from our management team.

Our compensation decisions for our NEOs with respect to 2012 are discussed in detail below. This discussion is intended to be read in conjunction with the executive compensation tables and related disclosures that follow this Compensation Discussion and Analysis.

Named Executive Officers

Rentech Nitrogen GP, LLC, our general partner, manages our operations and activities on our behalf through its officers and directors and is solely responsible for providing the employees and other personnel necessary to conduct our operations. Although all of the employees that conduct our business are employed by our general partner, its affiliates and certain of our subsidiaries, we sometimes refer to these individuals in this report as our officers and employees for ease of reference. Please see “Certain Relationships and Related Party Transactions, and Director Independence—Our Agreements with Rentech.”

The following discussion describes and analyses our compensation objectives and policies, as well as the material components of our executive compensation program for each of D. Hunt Ramsbottom, Dan J. Cohrs, John A. Ambrose, Wilfred R. Bahl, Jr. and Marc E. Wallis, our NEOs. Our NEOs were appointed to their positions during 2011 in connection with our formation and the formation of our general partner. Messrs. Ramsbottom and Cohrs also serve as officers of Rentech, our parent company, and are sometimes referred to in this registration statement as our “Shared NEOs” (and Messrs. Ambrose, Bahl and Wallis are sometimes referred to as our “Non-Shared NEOs”).

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Following our formation and the formation of our general partner, our Shared NEOs, who were already officers of Rentech and REMC, also became officers of our general partner, while our Non-Shared NEOs, who were already officers of REMC, also became officers of our general partner. Upon the closing of our initial public offering, all of our NEOs ceased to be officers of, and to be employed by, as applicable, REMC. The following table sets forth each NEO’s title(s) during 2012 and currently:

Officer	Title(s)
D. Hunt Ramsbottom	Chief Executive Officer, Rentech, Inc. and Rentech Nitrogen GP, LLC
Dan J. Cohrs	Executive Vice President & Chief Financial Officer, Rentech, Inc. and Chief Financial Officer, Rentech Nitrogen GP, LLC
John A. Ambrose	Chief Operating Officer, Rentech Nitrogen GP, LLC
Wilfred R. Bahl, Jr.	Senior Vice President of Finance and Administration, Rentech Nitrogen GP, LLC
Marc E. Wallis	Senior Vice President of Sales and Marketing, Rentech Nitrogen GP, LLC

Compensation Philosophy

We operate in a highly competitive and dynamic industry, characterized by rapidly changing market requirements. To succeed in this environment, we need to recruit and retain a highly talented and seasoned team of executive, technical, sales, marketing, operations, financial and other business professionals. We recognize that our ability to attract and retain these professionals largely depends on how we compensate and reward our employees, including our NEOs. As discussed under the heading “Compensation Decisions: Roles of Rentech’s Compensation Committee, our General Partner and our Chief Executive Officer” below, responsibility and authority for compensation-related decisions: (i) for our Shared NEOs resides with Rentech’s Compensation Committee (subject to input and advice from our Chief Executive Officer with regard to our Chief Financial Officer), and (ii) for our Non-Shared NEOs resides with the board of directors of our general partner (subject to input and advice from our Chief Executive Officer), taking into consideration the recommendation of Rentech’s Compensation Committee, in all cases, administered in a manner consistent with the compensation philosophy discussed above. For ease of reference, we refer below to determinations and perspectives formulated by this group as our own. Rentech’s Compensation Committee and our general partner, as applicable, conduct periodic reviews of our NEOs’ compensation and consider adjustments as appropriate.

We have designed and implemented our compensation strategy and objectives to address our recruiting and retention needs, which we have built around the following principles and objectives:

• Attract, engage and retain the best executives to work for us, with experience and managerial talent that will build our reputation as an employer of choice in a highly-competitive and dynamic industry;

• Align compensation with our corporate strategies, business and financial objectives and the long-term interests of our unitholders with a focus on increasing long-term value and rewarding achievements of our short- and mid-term financial and strategic objectives;

• Motivate and reward executives whose knowledge, skills and performance ensure our continued success; and

• Ensure that our total compensation is fair, reasonable and competitive.

We seek to create an environment that is responsive to the needs of our employees, is open to employee communication and continual performance feedback, encourages teamwork and rewards commitment and performance. Our compensation program is intended to be flexible and complementary and to collectively serve the principles and objectives of our compensation philosophy. Each of the key elements of our executive compensation program is discussed in more detail below (see “—Core Components of Executive Compensation”).

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Compensation Decisions: Roles of Rentech’s Compensation Committee, our General Partner and our Chief Executive Officer

Prior to our formation and the formation of our general partner, each of our NEOs served as an officer of our predecessor, REMC. Upon the closing of our initial public offering in 2011, all of our NEOs ceased to be officers of, and to be employed by, REMC and became officers of, and employed by, our general partner. Our Shared NEOs also serve as officers of, and are employed by, Rentech. Historically, the initial compensation arrangements for our NEOs have been determined in arm’s-length negotiations with each individual executive at the time of such executive’s hiring. Mr. Ramsbottom has been an officer of Rentech since September 2005 and an officer of REMC since its acquisition by Rentech in April 2006. Mr. Ramsbottom negotiated his initial employment terms with Rentech’s then-current board of directors at the time of his hiring. Mr. Cohrs was hired in October 2008 and negotiated his employment terms with Mr. Ramsbottom, our Chief Executive Officer, subject to the oversight and approval of Rentech’s Compensation Committee. Messrs. Wallis and Ambrose joined REMC shortly after its acquisition by Rentech, each negotiating his employment terms individually with our Chief Executive Officer, subject to the oversight and approval of Rentech’s Compensation Committee. Mr. Bahl was hired by REMC prior to Rentech’s acquisition of REMC in April 2006, but negotiated new terms of employment with our Chief Executive Officer, subject to the oversight and approval of Rentech’s Compensation Committee and board of directors, or Rentech’s board of directors, as applicable, at the time of Rentech’s acquisition of REMC.

In the years subsequent to their hiring (or, in the case of Mr. Bahl, since Rentech’s acquisition of REMC), including during 2012, changes to the terms and conditions of our NEOs’ employment, other than our Chief Executive Officer, have been determined by our Chief Executive Officer with the oversight and approval of Rentech’s Compensation Committee, subject to the terms of applicable employment arrangements that are in place with our NEOs (discussed under the heading “—Severance Benefits” below). Changes to the terms and conditions of our Chief Executive Officer’s employment have historically, including during 2012, been determined by Rentech’s Compensation Committee and board of directors, as applicable, subject to the terms and conditions of his employment agreement.

Decisions regarding the terms and conditions of our NEOs’ employment have been influenced by a variety of factors, including, but not limited to:

• The NEO’s background, experience and accomplishments;

• Our financial condition, performance and available resources;

• Our need to fill a particular position or retain a particular executive;

• An evaluation of the competitive market, based on the collective experience of the members of Rentech’s Compensation Committee, our Chief Executive Officer and advice from Rentech’s compensation consultant;

• The NEO’s length of service; and

• The compensation levels of our other executive officers.

Generally, the focus of these compensation decisions has been to retain these skilled individuals and to incentivize them to help meet prescribed financial and other goals. The current compensation levels of our executive officers, including our NEOs, primarily reflect the varying roles and responsibilities of each individual, their accomplishments and the length of time each executive has been employed by Rentech and/or us.

Compensation Consultant

During 2010 and 2011 and continuing through February 2012, Rentech’s Compensation Committee engaged Radford, an Aon Hewitt Company, as an independent compensation consultant to assist in the analysis of the executive compensation program for certain of our officers, including our Shared NEOs. In early 2012, the Compensation Committee evaluated the scope of consulting services historically provided to Rentech and determined that it was appropriate to reevaluate our executive compensation programs, including to reflect our status as a newly public company. Based on this assessment, in March 2012, Rentech’s Compensation Committee engaged a new independent compensation consultant, Frederic W. Cook & Co., Inc. (“Cook”), to analyze our existing executive compensation programs, assist with the design of future compensation programs that more closely align our executive officers’ interests with those of our unitholders, and ensure that the levels and types of compensation provided to our executives (including our NEOs) and directors continue to reflect market practices. Following the engagement of Cook by Rentech’s Compensation Committee to provide this advice, Radford ceased providing such services, with the exception of certain equity valuation services.

Services Provided With Respect to 2012 Compensation

Radford and Cook each provided services with respect to the compensation provided to our NEOs in respect of 2012. Services provided by Radford in late 2011 and early 2012 included the following:

• Advising on the levels of our officers, including our NEOs’, base salaries, as well as any appropriate changes to such salaries;

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• Advising on the reasonableness and effectiveness of the annual incentive programs in which our executive officers, including our NEOs, participate; and

• Analyzing the effectiveness of our use of long-term equity compensation, including award levels and types of equity awards used to compensate our employees and officers, including our NEOs, as well as any appropriate changes or additions to equity compensation.

The services provided by Cook following its engagement by Rentech’s Compensation Committee in March 2012 included the following:

• Analyzing Rentech’s peer group companies and advising on appropriate changes to such companies;

• Reviewing compensation data and analysis provided by Radford with regard to historical levels and types of compensation provided to our officers, including our NEOs, and directors;

• Analyzing the reasonableness and effectiveness of our compensation components, levels and programs for our directors and officers, including our NEOs, as well as any appropriate compensation changes, including changes to our long-term equity compensation program, to bring the compensation levels of our directors and officers in line with the median compensation levels of our peer group companies; and

• Analyzing and advising on the reasonableness and competitiveness of the annual incentive compensation awards earned by our executive officers, including our NEOs.

Comparison to Market Practices

Rentech’s Compensation Committee provides levels and elements of executive compensation, including base salaries, target annual incentive as a percentage of salary, total cash compensation, long-term incentives and total direct compensation, based on information gathered from the public filings of (i) Rentech’s peer group companies (with respect to our Shared NEOs) and (ii) the Partnership’s peer group companies (with respect to our Non-Shared NEOs), as well as industry-specific published survey data (discussed in more detail below).

From 2010 through the first half of 2012, Rentech’s peer group was based on companies selected in 2010 based on discussions among the members of Rentech’s Compensation Committee, certain of Rentech’s executive officers (including the Shared NEOs) and Radford (the “2010 Peer Group”). In June 2012, the members of Rentech’s Compensation Committee, certain of Rentech’s executive officers (including the Shared NEOs) and Cook & Co. reviewed and discussed the composition of the 2010 Peer Group. Based on these discussions, certain changes were made to Rentech’s peer group in order to (i) remove approximately twelve companies, including companies that had been acquired, had become insolvent or that were no longer appropriate to Rentech’s peer group based on size, industry and/or market value, and (ii) add approximately ten companies that are more similar to Rentech in terms of industry, revenue and market value. We refer to Rentech’s current peer group (after giving effect to the changes discussed above) as the “New 2012 Peer Group.”

Rentech’s 2010 Peer Group consisted of alternative energy companies and certain technology companies with a related focus, in each case, with (i) annual revenues ranging from $50 million to $550 million (with a median of $316 million), (ii) market values ranging from $70 million to $550 million, and (iii) similar employee numbers. Following are the companies that comprised Rentech’s 2010 Peer Group:

Advanced Energy Industries	Fuel Tech
Broadwind Energy	Fuelcell Energy
Cohu, Inc.	LSB Industries
Converge, Inc.	Maxwell Technologies
Echelon Corp.	MGP Ingredients
EMCORE Corp.	Rudolph Technologies
Energy Conversion Devices	Satcon Technology
EnerNoc Inc.	Ultra Clean Holdings
Evergreen Solar	Vicor Corp.
FormFactor Inc.	Zoltek

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Rentech’s New 2012 Peer Group consists of alternative energy, energy, energy technology, chemical and fertilizer companies, in each case, with (i) annual revenues ranging from approximately $60 million to $800 million and (ii) market values ranging from approximately $100 million to $1.2 billion at the time the peer group was selected. Following are the companies that comprise Rentech’s New 2012 Peer Group:

ADA-ES, Inc.	Fuel Tech
Advanced Energy Industries	Fuelcell Energy
American Vanguard Corp.	Hawkins Inc.
Amyris Inc.	LSB Industries
Arabian American Development Co.	Maxwell Technologies
Balchem Corp.	Quaker Chemical
Clean Energy Fuels Corp.	REX American Resources
EnerNoc Inc.	Vicor Corp.
Flotek Industries	Zoltek

The Partnership’s current peer group was established in September 2011 based on discussions among the members of Rentech’s Compensation Committee, certain of Rentech’s executive officers (including certain Shared NEOs) and Radford. The peer group consists of chemical manufacturing, fertilizer, and oil and gas companies, in each case, with (i) annual revenues ranging from $90 million to $715 million, (ii) market values ranging from $57 million to $4.0 billion (with a median of $732 million), and (iii) similar employee numbers. Following are the companies that comprise our current peer group:

American Vanguard Corp.	Innophos Holdings
American Pacific Corp.	Innospec
Balchem Corp.	LSB Industries
Calgon Carbon Corp.	NL Industries
Cambrex	PAA Natural Gas Storage
Chesapeake Midstream Partners, L.P.	Quaker Chemical Corp.
CVR Partners, L.P.	Terra Nitrogen Company LP
Flotek Industries	Tesoro Logistics LP
FutureFuel	Western Gas Partners, LP
Hawkins Inc.

In October 2011, Rentech’s Compensation Committee reviewed data and analysis provided by Radford with regard to the levels and types of compensation, including base salaries, target incentive as a percentage of salary, total cash compensation, long-term incentives and total direct compensation, provided to our NEOs and directors. The information provided by Radford included data gathered from the public filings of Rentech’s 2010 Peer Group (with respect to our Shared NEOs) and our peer group (with respect to our Non-Shared NEOs), and was utilized by Rentech’s Compensation Committee in its review and adjustment of our NEOs’ base salaries for 2012 and its review and establishment of our NEOs’ cash incentive opportunities for 2012.

In June 2012, Rentech’s Compensation Committee conducted a similar review of compensation data provided by Cook with regard to the levels and types of compensation provided to our NEOs and directors. The information provided by Cook included data gathered from the public filings of our peer group and of Rentech’s New 2012 Peer Group (instead of its 2010 Peer Group). Rentech’s Compensation Committee considered this data when determining the final incentive awards earned by our NEOs’ for 2012 under our annual incentive compensation programs and the levels and types of equity awards granted to our NEOs during 2012.

During its 2012 review, Rentech’s Compensation Committee reviewed the compensation of the Shared NEOs as it related to the New 2012 Peer Group with respect to total compensation and for individual components of compensation and determined it was within reasonable market practices and in line with our compensation philosophy. A comparison of long-term equity incentives showed (i) equity award levels slightly above the median of the market for our Shared NEOs (with respect to the New 2012 Peer Group), but (ii) that these equity awards were weighted considerably more toward performance-based vesting than the equity awards granted to similarly-situated executives of its peer group. In contrast, Rentech’s Compensation Committee determined that the compensation of our Non-Shared NEOs was generally below the market median (compared to our peer group) with respect to total compensation. However, certain individual components of compensation, including Mr. Wallis’ annual incentive opportunity and the long-term equity incentives were above the median of the market for our Non-Shared NEOs (compared to our peer group).

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Based on these reviews, Rentech’s Compensation Committee concluded that the level of our NEOs’ total compensation was well positioned to attract and retain the type of management team that we believe is necessary to successfully implement our business strategy. Specifically, the compensation levels of our Shared NEOs are appropriate in light of the scope of duties they provide both to us and to Rentech, as well as the high degree of performance required for the incentive award components of their compensation to actually be delivered, while the Non-Shared NEOs are provided with reasonable levels of cash compensation (compared to our peer group) and are weighted towards variable compensation that is based on the appreciation in our unit value over time, which we believe is appropriate to incentivize them to work toward the long-term growth of our newly public company and aligns their interests with those of our unitholders. We believe that these levels and types of compensation are also consistent with our compensation philosophy, foster our compensation objectives and continued to provide appropriate incentives through 2012.

Allocation

All of the executive officers and other personnel necessary for our business to function are employed and compensated by our general partner, our subsidiaries and/or Rentech, subject to reimbursement of the appropriate entity by us in accordance with the terms of the services agreement. Because each of our Shared NEOs is also an officer of Rentech, our Shared NEOs generally devote less than a majority of their total business time specifically to our general partner and to us. Rentech has the ultimate decision-making authority with respect to the portion of our Shared NEOs’ compensation that is allocated to us pursuant to Rentech’s allocation methodology, subject to the terms of the services agreement. Any such compensation allocation decisions are not subject to approval by us or our general partner. Please see “Certain Relationships and Related Party Transactions—Our Agreements with Rentech—Services Agreement.”

Core Components of Executive Compensation

Through Rentech’s Compensation Committee, we design the principal components of our executive compensation program to fulfill one or more of the principles and objectives described above. Compensation of our NEOs consists of the following elements:

• Cash compensation comprised of base salary and annual cash incentive compensation;

• Equity incentive compensation;

• Certain severance and change in control benefits;

• Health and welfare benefits and certain limited perquisites and other personal benefits; and

• Retirement savings (401(k)) plan.

We view each component of our executive compensation program as related but distinct, and we have historically reassessed the total compensation of our NEOs periodically to ensure that overall compensation objectives are met. In addition, in determining the appropriate level for each compensation component, we have considered, but not relied on exclusively, our understanding of the competitive market based on the collective experience of members of Rentech’s Compensation Committee (and our Chief Executive Officer with regard to the other NEOs), our recruiting and retention goals, our view of internal equity and consistency, the length of service of our executives, our overall financial and operational performance and other relevant considerations.

We have not adopted any formal or informal policies or guidelines for allocating compensation between currently-paid and long-term compensation, between cash and non-cash compensation, or among different forms of non-cash compensation. Generally, we offer a competitive, but balanced, total compensation package that provides the stability of a competitive, fixed income while also affording our executives the opportunity to be appropriately rewarded through cash and equity incentives if we attain short-term goals and perform well over time. However, we have increasingly used performance-based metrics to incentivize our employees and specifically our NEOs.

Each of the primary elements of our executive compensation program is discussed in more detail below. While we have identified particular compensation objectives that each element of executive compensation serves, our compensation programs are intended to be flexible and complementary and to collectively serve all of the executive compensation objectives described above. Accordingly, whether or not specifically mentioned below, we believe that, as a part of our overall executive compensation policy, each individual element, to a greater or lesser extent, serves each of our compensation objectives.

Cash Compensation

We provide our NEOs with cash compensation in the form of base salaries and annual cash incentive awards. Our cash compensation is structured to provide a market-level base salary for our NEOs while creating an opportunity to exceed market levels for total compensation if short- and long-term performance exceeds expectations. We believe that this mix appropriately combines the stability of non-variable compensation (in the form of base salary) with variable performance awards (in the form of annual cash incentives) that reward individual contributions to the success of the business.

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Base Salary

As discussed above, base salaries for our NEOs were initially set in arm’s-length negotiations during the hiring process for these executives. These base salaries have historically been reviewed annually by Rentech’s Compensation Committee (with input from our Chief Executive Officer with respect to the other NEOs) and were again reviewed at the end of 2012 for purposes of determining 2013 salaries. Our NEOs are not entitled to any contractual or other formulaic base salary increases. The Compensation Committee increased the base salaries of our NEOs, effective January 2013, in connection with its annual salary review at the end of our fiscal year 2012. Effective January 2013, Mr. Ramsbottom’s base salary increased by approximately 11% to $550,000 in recognition of his leadership of both Rentech and RNP, in recognition of Rentech’s high annual shareholder return, and in order to more closely align his base salary with the median base salaries for chief executive officers of our New 2012 Peer Group companies. Mr. Cohrs’ base salary also increased in January 2013 by approximately 5% to $450,000 in recognition of his effective capital raising efforts on behalf of Rentech, his efforts in facilitating and completing the Agrifos Acquisition and his continued leadership as the Chief Financial Officer of two publicly traded entities. Each of Messrs. Ambrose, Bahl and Wallis also received an annual salary increase, effective January 2013, of approximately 15%, 9% and 10%, respectively, in connection with their annual reviews in order to more closely align their base salaries with median base salaries for similarly situated executives of our Partnership’s current peer group companies.

The base salaries for our NEOs, both during fiscal year 2012 and following their January 2013 salary increases, are set forth in the following table:

Name	2012 Base Salary (Before Increase) ($)		2013 Base Salary (After Increase) ($)
D. Hunt Ramsbottom.		497,200		550,000
Dan J. Cohrs		426,575		450,000
John A. Ambrose		217,661		250,000
Wilfred R. Bahl, Jr.		205,965		225,000
Marc E. Wallis		195,615		215,000

Annual Incentive Compensation

Rentech maintains an annual incentive compensation program to reward its executive officers, including our Shared NEOs, based on its financial and operational performance, achievement of specific milestones related to technology and commercial work, and the individual NEO’s relative contribution to that performance during the year (referred to below as the Rentech annual incentive program). We separately maintain an annual incentive program to reward our executive officers, including our Non-Shared NEOs (but excluding our Shared NEOs and Mr. Wallis), based on our financial and operational performance, achievement of specific milestones related to the expansion of our facilities and the individual NEO’s relative contributions to that performance during the year (referred to below as the RNP annual incentive program). In addition, in lieu of Mr. Wallis’ participation in the RNP annual incentive program, we maintain a sales-based annual incentive program for Mr. Wallis to incentivize him in light of his position and responsibilities (referred to below as the sales incentive program). We recognize that successful completion of short-term objectives is critical in achieving our planned level of growth and attaining our other long-term business objectives. Accordingly, our annual and sales incentive programs are designed to reward executives for successfully taking the immediate steps necessary to implement our long-term business strategy.

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On February 1, 2012, we changed our fiscal year-end from September 30 to December 31 to coincide with the end of the calendar year, in order to align our financial reporting periods with the tax reporting periods of our limited partners and our publicly- traded peer group companies. We felt that the change would also make it easier for our unitholders and analysts to compare our financial performance to that of our peer group companies. At the same time, Rentech approved an identical change to its fiscal year for similar reasons. We set 2012 performance metrics and calculated 2012 annual incentive payments, in each case, based on our fiscal year 2012 rather than on the 15-month period beginning on October 1, 2011 and ending on December 31, 2012. We did not maintain a cash-based incentive program for the three-months ended December 31, 2011, or the Transition Period. However, in recognition that our employees, including our NEOs, should be consistently compensated based on our and their performance for all relevant periods, we determined to provide our NEOs with annual incentive compensation in respect of the Transition Period based on our and our NEOs’ performance during fiscal 2012. Accordingly, after the initial awards were determined for our NEOs based on the performance metrics set forth below for 2012, the Compensation Committee multiplied each award earned for 2012 performance by 125% to provide each NEO with a cash-based incentive award that compensated these executives for services over a 15-month (rather than a 12-month) period. In summary, we measured performance only for fiscal/calendar year 2012 for purposes of the 2012 incentive plan, but the award earned for this annual period was expanded to reflect the additional three month transition period from October 1, 2011 through December 31, 2011. We viewed this approach as the most an appropriate way to re-align compensation planning with the fiscal year, while also compensating NEOs in a performance-based manner for service and accomplishments during the three-month fiscal year transition period that was too short for effective goal-setting and measurement.

Annual Incentive Programs.

During fiscal 2012, (i) each of our Shared NEOs was eligible to receive an incentive payment pursuant to the Rentech annual incentive program and (ii) each of our Non-Shared NEOs (other than Mr. Wallis) was eligible to receive an incentive payment pursuant to the RNP annual incentive program. Under both annual incentive programs, cash incentives were determined and paid by reference to (i) the achievement of certain pre-established operational and financial goals and technology, commercial and project development criteria, and (ii) target bonus amounts (as set forth in the NEOs’ respective employment agreements). In the beginning of 2012, as in prior fiscal years with respect to Rentech, our CEO and other senior officers of Rentech developed a series of broad objectives for each of Rentech and us, which were then reviewed and revised by Rentech’s Compensation Committee and board of directors and the board of directors of our general partner. Following that review, Rentech’s board of directors and our general partner’s board of directors set the 2012 performance goals for the Rentech and RNP annual incentive programs, respectively, but retained discretion based on input from the Compensation Committee (and our Chief Executive Officer with respect to the other NEOs who participate in the annual incentive programs) to increase or decrease annual incentive awards to levels as high as 200% of the NEO’s target bonus and as low as zero, in each case, based on performance during the relevant period. The 2012 annual incentive awards were targeted for Messrs. Ramsbottom, Cohrs, Ambrose and Bahl at 100%, 60%, 40% and 30% of their respective base salaries (in accordance with their respective employment agreements). Payment of annual incentive awards to our NEOs (other than Mr. Wallis) was based on the achievement by Rentech and/or us, as applicable, of the specific targets and goals set forth below for the applicable annual incentive program, as well as the performance of the individual executive (and was subject to adjustment as described above). As discussed above, performance versus the 2012 bonus plan goals was used to determine the bonus for the three month transition period associated with moving our fiscal year-end from the last day of September to the last day of December.

Rentech Annual Incentive Program Performance Goals

The 2012 performance goals applicable to our Shared NEOs under the Rentech annual incentive program are set forth below, along with determinations as to the attainment of these goals (parentheticals following the description of each goal provide guidelines indicating the approximate weight given to the attainment of each goal).

1. Goal: A continued strong safety record at Rentech’s facilities, including RNP’s facilities, with an OSHA recordable rate below a target rate of 4.0 (failure to attain this goal reduces the final bonus pool by 20%).

Result: Goal attained. Rentech completed fiscal year 2012 with an OSHA recordable rate of approximately 2.35 recordable incidents for every 200,000 hours worked at Rentech facilities.

2. Goal: Operations goals, including:

• Total ammonia production ranging from approximately 275,000 tons to 315,000 tons, targeted at approximately 300,000 tons (10% weight).

Result: Goal attained below the target level. Total ammonia production for the fiscal year ending December 31, 2012 equalled approximately 293,000 tons.

• Concurrently decrease nitrogen production and increase ammonia production in amounts ranging from approximately 130,000 tons to 150,000 tons, targeted at approximately 145,000 tons (10% weight).

Result: Goal attained below the target level. Total decrease in nitrogen production and corresponding increase in ammonia production for the fiscal year ending December 31, 2012 equalled approximately 142,000 tons.

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3. Goal: Consolidated EBITDA ranging from approximately $50.5 million to $80.5 million, targeted at approximately $62 million (15% weight).

Result: Goal attained above the maximum level considered. Consolidated EBITDA for fiscal year 2012 equalled approximately $80.7 million.

4. Goal: Successful operation of the ClearFuels Gasifier and Rentech’s Integrated Biorefinery (“IBR”) utilizing wood and bagasse feedstocks for at least 2,000 hours (15% weight).

Result: Goal not attained. As of December 31, 2012, the IBR project had successfully operated for approximately 750 hours.

5. Goal: Commercial achievements, including:

• Execution of definitive agreements for partnerships, grants and/or in-kind contributions for research and development funding and/or technology commercialization opportunities, ranging from approximately $10 million to $20 million, targeted at $15 million (15% weight).

Result: Goal not attained. As of December 31, 2012, Rentech was in discussions with potential partners, but no definitive agreements had been executed.

• Achievement of milestones within a new line of business (15% weight).

Result: Goal not attained, however, the Compensation Committee recognized that significant progress toward such milestones was achieved.

6. Goal: Other factors which contribute to the success of Rentech as determined by Rentech’s Compensation Committee and board of directors (20% weight).

Result: The Compensation Committee exercised its discretion to recognize significant shareholder value creation as a result of the Partnership’s acquisition of Agrifos, LLC and, in particular, our extraordinary total shareholder and unitholder return and stock and unit value appreciation during 2012. Specifically, as of December 30, 2011, Rentech’s stock price was $1.31 per share and our unit price was $16.35 per unit, which had increased to $2.63 per share (after taking into account a special distribution of $0.19 per share on December 27, 2012, as discussed in more detail under “-Special Distribution” below) and $37.69 per unit, respectively, as of December 31, 2012.

RNP Annual Incentive Program Performance Goals

The 2012 performance goals applicable to our Non-Shared NEOs under the RNP annual incentive program are set forth below, along with determinations as to the attainment of these goals (parentheticals following the description of each goal provide guidelines indicating the approximate weight given to the attainment of each goal).

1. Goal: A continued strong safety record at our facilities with an OSHA recordable rate below a target rate of 4.0 and less than 4 environmental and Federal Railroad Administration compliance incidents. A failure to attain this goal would have reduced the final bonus pool by 20%).

Result: Goal attained. We completed fiscal year 2012 with an OSHA recordable rate of approximately 3.84 recordable incidents for every 200,000 hours worked at our facilities and fewer than 4 environmental and Federal Railroad Administration compliance incidents.

2. Goal: Operations goals, including:

• Total ammonia production ranging from approximately 275,000 tons to 315,000 tons, targeted at approximately 300,000 tons (10% weight).

Result: Goal attained below target level. Total ammonia production for the fiscal year ending December 31, 2012 equalled approximately 293,000 tons.

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• Concurrently decrease nitrogen production and increase ammonia production in amounts ranging from approximately 130,000 tons to 150,000 tons, targeted at approximately 145,000 tons (10% weight).

Result: Goal attained below target level. Total decrease in nitrogen production and corresponding increase in ammonia production for the fiscal year ending December 31, 2012 equalled approximately 142,000 tons.

3. Goal: Financial goals, including:

• EBITDA (excluding transaction costs with respect to the Agrifos Acquisition and certain other items) ranging from approximately $100 million to $130 million, targeted at approximately $110 million (20% weight).

Result: Goal attained above maximum level. EBITDA for fiscal year 2012 equalled approximately $130.2 million.

• Continued development of the urea and DEF projects at a budgeted rate, targeted at $5.8 million (10% weight).

Result: Goal not attained. As of December 31, 2012, total development costs were approximately $6 million.

• Capital expenditures targeted at or below approximately $9.9 million (10% weight).

Result: Goal attained. Capital expenditures for fiscal year 2012 equalled approximately $7.9 million.

4. Goal: Project expansion goals, including:

• Completion of (i) 30% to 50% (targeted at 40%) of the construction of our ammonia capacity and storage expansion project, and (ii) 90% to 100% (targeted at 95%) of the engineering and procurement for our ammonia capacity and storage expansion project (15% weight).

Result: Goal attained at maximum level. As of December 31, 2012, 50% of the construction and 100% of engineering and procurement had been completed.

• Completion and implementation of our DEF system and the upgrade of our three urea reactors (5% weight).

Result: Goal attained.

5. Goal: Other factors which contribute to the success of the Partnership and Rentech, as determined our board of directors, (20% weight).

Result: The board of directors of our general partner, upon the recommendation of the Rentech Compensation Committee, exercised its discretion to recognize significant unitholder value creation as a result of the Partnership’s acquisition of Agrifos, LLC and, in particular, our extraordinary unitholder return and unit value appreciation during 2012. Specifically, as of December 30, 2011, our unit price was $16.35 per unit, which had more than doubled to $37.69 per unit, as of December 31, 2012.

At the end of 2012, our Chief Executive Officer developed his own assessment including input from other members of Rentech’s and our senior management teams of performance for each of his direct reports (including the other NEOs who participated in the Rentech and RNP annual incentive programs) compared to certain pre-established individual goals, taking into consideration any key accomplishments outside of the set goals for the year. Final incentive payments for our NEOs participating in the annual incentive programs were determined based on Rentech’s and/or our (as applicable) performance compared to the set goals under the applicable programs. In addition, the Compensation Committee determined to make discretionary increases to the final incentive payments for our NEOs in recognition of Rentech’s and our extraordinary total shareholder and unitholder return and stock and unit value appreciation in 2012. Specifically, as of December 31, 2011, Rentech’s stock price was $1.31 per share and our unit price was $16.35 per unit, which had increased to $2.63 per share (after taking into account a special distribution of $0.19 per share on December 27, 2012, as discussed in more detail under “-Special Distribution” below) and $37.69 per unit, respectively, as of December 31, 2012. As explained in more detail above, each incentive payment was then multiplied by 125% to compensate appropriately for the 15-month period that included the Transition Period and our fiscal year 2012. Messrs. Ramsbottom, Cohrs, Ambrose and Bahl received 2012 annual incentive payments equal to approximately 150%, 150%, 141% and 141% of their respective target bonuses based on the performance results described above (or 150%, 90%, 56.4% and 42.3% of their respective base salaries).

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In order to help our most senior executives mitigate some of the tax uncertainties that existed at year-end 2012 relating to the “fiscal cliff” and other tax policy debates which were ongoing at that time, we paid seventy percent of our Shared NEOs’ annual incentives prior to year-end 2012. These advance payments, which offset the annual incentive payments made to our Shared NEOs during 2013 on a dollar-for-dollar basis, and thus did not increase the cost of these annual incentive payments, were intended to afford our Shared NEOs the certainty of known tax rates then in effect. Prior to making these advance payments, we determined, based on performance to date, that our Shared NEOs would be entitled to annual incentives under the Rentech annual incentive program in amounts at least equal to the amounts advanced. We paid the remaining thirty percent of the Shared NEOs’ annual incentives in early 2013 upon our determination that these full amounts had been earned.

Sales Incentive Program

In light of the continued strong demand for experienced sales and marketing executives in the nitrogen fertilizer industry through 2012, we continued our use of a sales incentive program for Mr. Wallis similar to the program implemented for Mr. Wallis in fiscal year 2011, which linked his annual incentive opportunity with performance factors specifically designed to promote sales and marketing activities advancing sales objectives. We believe that a sales-based incentive program better ties Mr. Wallis’ variable compensation opportunity to his duties and responsibilities. Under the sales incentive program, Mr. Wallis was eligible to receive an incentive payment of up to 100% of his base salary based on the corresponding percentage (up to 100%) at which we attained our budgeted 2012 EBITDA, and Mr. Wallis received an actual incentive payment of $195,600 based on our EBITDA performance.

In addition to Mr. Wallis’ EBITDA-based incentive opportunity, Mr. Wallis was eligible to receive an additional payment of up to 50% of his base salary based on the attainment of the following scorecard of individual performance goals, determined and approved by Messrs. Ambrose and Diesch, as well as Rentech’s Senior Vice President, Human Resources (parentheticals following the description of each goal provide guidelines indicating the approximate weight given to the attainment of each goal).

1. Goal: Finalize the Urea distribution contract no later than February 15, 2012 and sell a total of 30,000 tons of urea (including granular urea, liquid urea and DEF) during calendar year 2012 (10% weight).

Result: Goal attained.

2. Goal: Prevent reductions in the production of ammonia and urea due to inventory builds (10% weight).

Result: Goal attained.

3. Goal: Forward sell climate reserve tons valued, in the aggregate, at $1 million no later than June 20, 2012 (10% weight).

Result: Goal attained at approximately 14.7%. Actual sales through December 31, 2012 were substantially lower than the target amount and forward sales opportunities exceeding $1 million were not pursued in light of the cost of building and maintaining the nitric acid plant at the East Dubuque Facility and the unstable carbon markets.

4. Goal: Establish a contract or memorandum of understanding for the sale of 20,000 tons of ammonia with a 2013 ratable take at a price per ton that is more than $75 above the Tampa ammonia index (10% weight).

Result: Goal attained, as a contract for sales of 18,000 tons of ammonia with a ratable take at a price per ton that is $120 above the Tampa ammonia index was drafted, but we determined not to enter into the contract and instead to pursue a larger and more advantageous business opportunity.

5. Goal: Establish a contract or memorandum of understanding for the sale of 10,000 tons of aqua ammonia at a price (or prices) exceeding the price of non-industrial sales, beginning in 2013 (10% weight).

Result: Goal not attained.

Mr. Wallis received a payout under his non-EBITDA-based annual incentive at approximately 40% of base salary based on attainment of approximately 80% of these performance objectives. Thus, Mr. Wallis earned a total 2012 annual incentive (combining his sales incentive payment and his individual performance incentive payment) of $273,840. The Compensation Committee determined to make a discretionary increase in Mr. Wallis’ annual incentive payment in recognition of our extraordinary total unitholder return and unit appreciation during 2012 as explained in more detail above. In addition, as explained in more detail above, this amount was then multiplied by 125% to recognize that each payment for performance in 2012 was being made in respect of a 15-month period that included the Transition Period and our fiscal year 2012. Accordingly, Mr. Wallis was provided a total 2012 annual incentive payment of $342,300.

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Long-Term Equity Incentive Awards

We believe that senior executives, including our NEOs, should have an ongoing stake in the success of their employer, including, in the case of the Shared NEOs, Rentech, in order to closely align their interests with those of our unitholders and, for our Shared NEOs, Rentech’s shareholders. We further believe that equity awards provide meaningful retention and performance incentives that appropriately encourage our executive officers, including our NEOs, to remain employed with us and, in the case of our Shared NEOs, with Rentech, and to put forth their best efforts and performance at all times. Accordingly, equity incentive awards have historically been a key component of Rentech’s and our compensation program, including during 2012, as these awards have served to align the interests of our NEOs with those of our unitholders and, in the case of our Shared NEOs, Rentech’s shareholders, and to incentivize our NEOs to work toward long-term growth. During 2012, Rentech granted equity awards to our Shared NEOs under its 2006 and 2009 Incentive Awards Plans and we granted equity awards to all of our NEOs under our 2011 Long-Term Incentive Plan. Each of these plans is intended to provide incentives for a broad group of service providers, including employees (both NEOs and other employees), directors and consultants, in each case, who are critical to our success (and, in the case of our Shared NEOs, to the success of Rentech) and to the creation of unitholder/shareholder value.

During 2012, in order to promote the unit/share ownership, performance and retention goals described above, (i) Rentech granted equity awards to our Shared NEOs comprised of time-vesting restricted stock units (“RSUs”) and performance-vesting restricted stock units (“PSUs”), and (ii) we granted equity awards to all of our NEOs comprised of phantom units (“phantom units”) that are settled in our common units upon vesting and which entitle their holders to dividend and other distribution rights while the phantom units are outstanding (these equity awards are collectively referred to below as the “2012 Awards”). Each RSU, PSU and phantom unit confers upon its holder the right to receive one share of Rentech common stock (in the case of RSUs and PSUs) or one of our common units (in the case of phantom units) without payment of purchase price, thereby delivering the full grant-date value of the underlying shares or units, as well as any post-grant share or unit price appreciation. Accordingly, each of these awards enables us to confer upon our executives value in excess of simple future appreciation. Awards were granted at the end of 2012 in order to allow the amounts to be calibrated to reflect performance during the year versus internal goals and in terms of shareholder return.

We note that, in respect of 2012 services, Rentech equity awards were granted only to our Shared NEOs and only in respect of services provided to Rentech. We include a discussion of these awards here in order to provide a comprehensive discussion of compensation decisions pertaining to our NEOs for the relevant year, but note that the full expense of the Rentech equity awards was borne by Rentech (and, similarly, the full expense of all Partnership equity awards, which are granted solely in respect of services provided to the Partnership, was borne by the Partnership, as reflected in the compensation tables below).

Rentech RSUs and Partnership Phantom Units.

The Rentech RSUs and RNP phantom units granted as 2012 Awards vest in substantially equal, annual increments over a period of three years from the grant date, subject to continued service through the applicable vesting date. RSUs and phantom units are tied to time-vesting requirements in order to provide a strong retention incentive to our NEOs through the applicable vesting period. Each RSU and phantom unit confers upon its holder the right to receive dividend equivalent payments for dividends declared over the portion of the vesting period during which such RSU and phantom unit is outstanding payable as and when dividends are paid to stockholders or unitholders, as applicable, without regard to the vested status of the award. Overall, our Shared NEOs received 2012 Awards with an aggregate value that was based 70% on the achievement of performance criteria, and 30% on the satisfaction of time-based vesting criteria, which we believe emphasizes the importance of achieving shareholder return goals before our Shared NEOs’ awards are earned and paid.

Rentech PSUs.

The Rentech PSUs granted to our Shared NEOs as 2012 Awards require both continued service and the attainment of performance criteria as conditions to vesting, thereby providing both retention and enhanced performance incentives. Specifically, PSUs granted as 2012 Awards confer upon the Shared NEOs the right receive a number of stock-settled PSUs determined based on Rentech’s total shareholder return (TSR) over a three-year performance period beginning on the grant date. Each PSU also confers upon its holder the right to receive dividend equivalent payments for dividends declared over the portion of the performance period during which such PSU is outstanding, payable only if and when the underlying PSU vests. Rentech’s Compensation Committee determined to award PSUs that vest based on Rentech’s TSR achievement because it believes that long-term TSR is a key measure of Rentech’s performance for its shareholders.

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Pursuant to their respective PSU award agreements, each Shared NEO is eligible to earn a specified number of target PSUs (based on 100% attainment of the TSR goal and satisfaction of the continued service vesting conditions described below), with actual PSU payouts (if any) ranging from 0% to 175% of the target PSU levels depending on the actual level of TSR attained. For purposes of the PSUs, TSR is calculated as the per share increase in value equal to the sum of (i) Rentech’s per share stock price increase plus (ii) Rentech’s aggregate per share dividends, in each case, over the performance period (or relevant portion thereof), with stock price generally calculated as the trailing thirty-day stock price average through the date on which TSR is measured.

Generally, one-third of the PSUs are eligible to vest on each of the first three anniversaries of the grant date based on Rentech’s per share TSR (and the executive’s continued service) through the applicable anniversary (each such anniversary, a “measurement date”). The number of PSUs that vests on the applicable measurement date is determined based on the increase in Rentech’s stock price over the one-year, two-year or three-year period, as applicable, following the grant date. Any PSUs that are not earned over the one-year or two-year periods following the grant date remain eligible to vest on the third anniversary of the grant date based on the increase in per share TSR over the full three-year performance period, as demonstrated by the chart below.

Rentech’s Compensation Committee believes that this vesting structure emphasizes long-term stock performance without penalizing our Shared NEOs if short-term stock performance is below target levels.

The number of PSUs that actually vest on each of the first, second and third anniversaries of the grant date is determined based on the percentage of Rentech’s per share TSR increase from the date of grant through the applicable measurement date. The table below sets forth the percentage of target PSUs that will vest upon Rentech’s attainment of per share TSR increase at threshold, target and maximum levels (e.g., upon Rentech’s per share TSR increase of 25%, 50% and 100%, respectively, through the applicable measurement date).

Achievement Level	TSR Increase Through the Applicable Measurement Date (%)	Number of PSUs That Actually Vest (% of Target)
Maximum	100% or more	175%
Between Target and Maximum	More than 50% and less than 100%	Between 100% and 175% (determined pro rata based on the percentage of actual TSR increase)
Target	50%	100%
Between Threshold and Target	More than 25% and less than 50%	Between 50% and 100% (determined pro rata based on the percentage of actual TSR increase)
Threshold	25%	50%
Below Threshold	Less than 25%	0%

As indicated above, Rentech must achieve a per share TSR increase of at least 25% through the applicable measurement date (the “threshold” level) in order for any PSUs to vest on such date. Upon Rentech’s achievement of per share TSR increase at the threshold, target or maximum level (e.g., a per share TSR increase of 25%, 50% and 100%, respectively, through the applicable measurement date), the number of PSUs that will vest on the applicable measurement date equals 50%, 100% or 175%, respectively, of the target PSUs eligible to vest on such date. If Rentech achieves a per share TSR increase between these specified achievement levels, the number of PSUs that will vest on the applicable measurement date is determined pro rata based on the actual TSR increase achieved within the range of applicable achievement levels. For example, if Rentech achieves per share TSR increase of 25% as of an applicable measurement date, the number of PSUs that will vest equals (a) one-third of the target PSUs multiplied by (b) 50%. If Rentech instead achieves a per share TSR increase between 25% and 50% as of an applicable measurement date, the number of PSUs that will vest equals (a) one-third of the target PSUs multiplied by (b) a percentage ranging from 50% to 100% (with such percentage determined pro rata based on the actual TSR increase as of the applicable measurement date).

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PSUs will be paid to our Shared NEOs in shares of Rentech’s stock as and when they are earned and vest, subject to the executive’s continued service through the applicable measurement date. Dividend equivalents that become payable with respect to vested PSUs will generally be paid in cash upon or shortly after vesting of the underlying PSU to which such dividend equivalents relate (only if and when the underlying PSU ultimately vests).The 2012 Awards are subject to accelerated vesting only in connection with certain qualifying terminations of employment in connection with a change in control and in the case of death or disability (as described under “—Potential Payments upon Termination or Change-in-Control” below). We believe that the applicable vesting periods provide an important retention incentive, while accelerated vesting (where appropriate) protects executives against forfeiture of their awards in appropriate circumstances and aligns management’s incentives more closely with the interests of our unitholders.

2012 Awards Table

In determining appropriate levels of equity grants for the 2012 Awards, we considered, among other things, the role(s) and responsibilities of each NEO and the perceived need to reward and retain the NEO. The following table sets forth the 2012 Awards that we and Rentech granted to our NEOs during 2012:

Officer	Grant Date		Rentech Restricted Stock Units (RSUs)		Rentech Performance Stock Units (PSUs)(1)		Partnership Phantom Units
D. Hunt Ramsbottom		12/14/12		73,944		387,351		5,600
Dan J. Cohrs		12/14/12		31,690		166,007		2,400
John A. Ambrose		12/14/12		—		—		2,800
Wilfred R. Bahl, Jr.		12/14/12		—		—		1,867
Marc E. Wallis		12/14/12		—		—		1,867

(1) Performance units reflect target amounts.

Severance Benefits

We believe that vulnerability to termination of employment at the senior executive level creates uncertainty for our NEOs that is appropriately addressed by providing severance protections which enable and encourage these executives to focus their attention on their work duties and responsibilities in all situations. We operate in a highly volatile and acquisitive industry that heightens this vulnerability in the change-in-control context. Accordingly, in order to attract and retain our key managerial talent, Rentech (in the case of our Shared NEOs) and our general partner (in the case of our Non-Shared NEOs) are parties to employment agreements with our NEOs which provide for specified severance payments and benefits in connection with certain qualifying terminations of employment. The principles underlying the various components of these agreements are discussed in this section. For a description of the specific terms and conditions of each agreement, see “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” and “—Potential Payments upon Termination or Change-in-Control” below. Under their employment agreements, our Shared NEOs are entitled to severance upon involuntary terminations without “cause” or for “good reason” (each as defined in the applicable employment agreement) consisting of (i) three years (in the case of Mr. Ramsbottom) or one year (in the case of Mr. Cohrs) of base salary continuation (payable over two years for Mr. Ramsbottom), (ii) in the case of Mr. Cohrs, payment of target bonus and (iii) up to eighteen months of subsidized healthcare premiums, in addition to certain accelerated equity vesting under the terms of individual equity awards. In the case of an involuntary termination of employment in connection with our non-renewal of the applicable agreement, Mr. Ramsbottom is entitled to the same severance, while Mr. Cohrs is entitled to a reduced severance consisting of only the salary continuation described above (but not payment of the target bonus or subsidized healthcare continuation) and, at Rentech’s discretion, an annual bonus for the fiscal year preceding the non-renewal. We believe that, in light of these NEOs’ seniority and the resulting vulnerability to involuntary termination, these severance payments and benefits provide an appropriate level of assurance in the non-transactional context. The specific levels of payments and benefits are determined by the relative seniority and duration of service of the NEOs.

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In addition, if our Shared NEOs are involuntarily terminated (without cause, for good reason or due to non-renewal) in connection with a change in control, these NEOs are entitled to receive their cash severance in a lump-sum and are further eligible for a severance enhancement equal to the amounts by which their respective prior-year bonuses exceed their then-current target bonuses (in the case of Mr. Ramsbottom, payment of this enhanced bonus, if applicable, would be in lieu of one year of salary payments, such that Mr. Ramsbottom would receive two years of salary payment plus the amount of his prior-year bonus instead of three years of salary). We believe that the lump-sum payment is appropriate to limit the NEOs’ exposure to any credit risk associated with new owners/management and that the potential enhancement provides an appropriate additional incentive to focus on the best interests of the shareholders in the context of a potential transaction. These NEOs are also entitled to a tax gross-up payment in the event that any “golden parachute” excise taxes are imposed on them under Section 280G of the Internal Revenue Code in connection with a transaction. The gross-up payments are provided under employment agreements that were not amended or entered into during 2011 or 2012 (including the three-month Transition Period), and are intended to counter any disincentive the NEOs may have to consummate a beneficial transaction as a result of the potential imposition of these golden parachute excise taxes.

Under their employment agreements, Messrs. Ambrose, Bahl and Wallis are entitled to severance payments and benefits upon an involuntary termination without “cause” or for “good reason” (each as defined in the applicable employment agreement). These severance benefits are comprised of continuation salary payments for one year and payment of the executive’s target bonus for the year, in addition to up to one year of subsidized healthcare premiums. In the case of an involuntary termination of employment in connection with our non-renewal of the applicable agreement, Messrs. Ambrose, Bahl and Wallis are entitled to a reduced severance consisting of only the salary continuation described above (but not payment of the target bonus or subsidized healthcare continuation) and, at our discretion, an annual bonus for the fiscal year preceding the non-renewal.

Benefits and Perquisites

Rentech maintains a standard complement of health and retirement benefit plans for our employees, including our NEOs, that provide medical, dental, and vision benefits, flexible spending accounts, a 401(k) savings plan (including an employer-match component), short-term and long-term disability insurance, accidental death and dismemberment insurance and life insurance coverage. These benefits are generally provided to our NEOs on the same terms and conditions as they are provided to our other non-union employees.

We believe that these health and retirement benefits comprise key elements of a comprehensive compensation program. Our health benefits help provide stability and peace of mind to our NEOs, thus enabling them to better focus on their work responsibilities, while our 401(k) plan provides a vehicle for tax-preferred retirement savings with additional compensation in the form of an employer match that adds to the overall desirability of our executive compensation package. Our employee benefits programs are designed to be affordable and competitive in relation to the market, as well as compliant with applicable laws and practices. We periodically review and adjust these employee benefits programs as needed based upon regular monitoring of applicable laws and practices in the competitive market.

Messrs. Ramsbottom and Cohrs receive reimbursement of certain financial advisor costs, and these executives, as well as Messrs. Ambrose and Bahl, also receive a monthly car allowance. Mr. Wallis has access to a company-provided car intended primarily for business use, but Mr. Wallis may make use of this car for certain personal matters as well. While we believe that these benefits are appropriate and commensurate with these NEOs’ positions, we do not generally view perquisites or other personal benefits as a material component of our executive compensation program. In the future, we may provide additional or different perquisites or other personal benefits in limited circumstances, such as where we believe doing so is appropriate to assist an individual in the performance of his or her duties, to make our executive officers more efficient and effective, and for recruitment, motivation and/or retention purposes.

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Tax and Accounting Considerations

Section 280G of the Internal Revenue Code

Section 280G of the Internal Revenue Code disallows a tax deduction with respect to excess parachute payments to certain executives of companies which undergo a change in control. In addition, Section 4999 of the Internal Revenue Code imposes a 20% excise tax on the individual with respect to the excess parachute payment. Parachute payments are compensation linked to or triggered by a change in control and may include, but are not limited to, bonus payments, severance payments, certain fringe benefits, and payments and acceleration of vesting from long-term incentive plans including stock options and other equity-based compensation. Excess parachute payments are parachute payments that exceed a threshold determined under Section 280G of the Internal Revenue Code based on the executive’s prior compensation. In approving compensation arrangements for our NEOs in the future, we expect to consider all elements of the cost of providing such compensation, including the potential impact of Section 280G of the Internal Revenue Code. However, we may authorize compensation arrangements that could give rise to loss of deductibility under Section 280G of the Internal Revenue Code and the imposition of excise taxes under Section 4999 of the Internal Revenue Code if we feel that such arrangements are appropriate to attract and retain executive talent.

Under their employment agreements with Rentech, Messrs. Ramsbottom and Cohrs are entitled to gross-up payments in the event that any excise taxes are imposed on them. Rentech has historically provided these protections to its senior executives to ensure that they will be properly incentivized in the event of a potential change in control of Rentech to maximize shareholder value in a transaction while minimizing concern for potential consequences of the transaction to these executives.

Section 409A of the Internal Revenue Code

Section 409A of the Internal Revenue Code requires that “nonqualified deferred compensation” be deferred and paid under plans or arrangements that satisfy the requirements of the statute with respect to the timing of deferral elections, timing of payments and certain other matters. Failure to satisfy these requirements can expose employees and other service providers to accelerated income tax liabilities, substantial additional taxes and interest on their vested compensation under such plans. Accordingly, as a general matter, it is our intention to design and administer our compensation and benefit plans and arrangements for all of our employees and other service providers, including our NEOs, so that they are either exempt from, or satisfy the requirements of, Section 409A of the Internal Revenue Code.

Accounting for Stock-Based and Unit-Based Compensation

We have followed Financial Accounting Standards Board Accounting Standards Codification Topic 718, or ASC Topic 718, in accounting for stock-based and unit-based compensation awards. ASC Topic 718 requires companies to calculate the grant date “fair value” of their stock-based and unit based awards using a variety of assumptions. ASC Topic 718 also requires companies to recognize the compensation cost of their stock-based and unit-based awards in their income statements over the period that an employee is required to render service in exchange for the award. We expect that we will regularly consider the accounting implications of significant compensation decisions, especially in connection with decisions that relate to our equity incentive award plans and programs. As accounting standards change, we may revise certain programs to appropriately align accounting expenses of our equity awards with our overall executive compensation philosophy and objectives.

Compensation Report

The board of directors of our general partner does not have a Compensation Committee. The board of directors has reviewed and discussed with management the foregoing Compensation Discussion and Analysis and, based on such review and discussion, the board of directors determined that the Compensation Discussion and Analysis should be included in this report.

Michael S. Burke

John H. Diesch

James F. Dietz

Keith B. Forman

Michael F. Ray

D. Hunt Ramsbottom

Halbert S. Washburn

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Compensation Committee Interlocks and Insider Participation

During fiscal year 2012, the following individuals served as members of Rentech’s Compensation Committee: Michael S. Burke, Halbert S. Washburn, and Edward M. Stern. None of these individuals has ever served as an officer or employee of Rentech or any of its subsidiaries (including our general partner). No executive officer of Rentech or us has served as a director or member of the compensation committee of another entity at which an executive officer of such entity is also a director of Rentech.

Summary Compensation Table

We and our general partner were formed in July 2011. Accordingly, neither we nor our general partner accrued any obligations with respect to management compensation or benefits for directors and executive officers for any prior periods. On February 1, 2012, we changed our fiscal year-end from September 30 to December 31 to coincide with the end of the calendar year. The following table summarizes the compensation that was attributable to services performed for us during the calendar year ending December 31, 2012, the three months ended December 31, 2011, or the Transition Period (under the heading “3 Mo 2011”) and the fiscal year ending September 30, 2011 for each of our NEOs.

With respect to our Shared NEOs, the non-equity amounts contained in the summary compensation table reflect the portion of these NEOs’ total compensation paid by Rentech that we estimate was attributable to services performed by these NEOs for us during the relevant period, calculated by multiplying each amount by a good faith estimate of the percentage of time such NEO dedicated to such services for us. The estimated percentage of time allocable to us for Messrs. Ramsbottom and Cohrs are: (i) 50% and 37%, respectively, during the calendar year 2012, (ii) 53% and 45%, respectively, during the Transition Period, and (iii) 20% and 20%, respectively, during fiscal year 2011. Our Non-Shared NEOs devoted substantially all of their business time to us during the relevant periods.

For reported periods prior to 2012, all of our NEOs received Rentech equity incentive awards for services provided to us and Rentech and, in connection with our IPO, received Partnership equity incentive awards for services to us. Beginning in 2012, our Non-Shared NEOs received only Partnership equity awards, while our Shared NEOs received both Rentech equity awards (for service to Rentech) and Partnership equity incentive awards (for service to us). Accordingly, for periods prior to 2012, with respect to which the cost of Rentech equity awards (including Rentech RSUs and PSUs) was allocated over both Rentech and us for Shared NEOs, Rentech equity awards are included in the tables below. For tables (or portions thereof) specific to 2012 compensation, only the values of Partnership equity awards are included, as no portion of any 2012 Rentech equity awards were paid in respect of services to us in 2012.

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The values of both 2012 Rentech equity awards and cash compensation paid to our Shared NEOs by, and allocated to, Rentech, are disclosed in the footnotes to the tables.

Name and Principal Position	Year (1)	Salary ($)		Stock Awards ($) (2)		Option Awards ($) (3)		Non- Equity Incentive Plan Compensation ($)(4)		All Other Compensation ($)(5)		Total ($)
D. Hunt Ramsbottom(6) Chief Executive Officer	CY2012		248,600		210,000		—		466,125		194,877		1,119,602
	3 Mo 2011		61,701		1,830,757		—		—		2,188		1,894,646
	FY2011		86,950		48,357		91,452		44,000		8,648		279,407
Dan J. Cohrs,(7) Chief Financial Officer	CY2012		157,833		90,000		—		177,562		119,369		544,764
	3 Mo 2011		44,946		1,000,651		—		—		1,424		1,047,021
	FY 2011		74,775		28,445		53,795		22,650		8,105		187,770
John A. Ambrose, Chief Operating Officer	CY2012		217,661		105,000		—		153,450		85,881		561,992
	3 Mo 2011		49,719		552,644		—		—		3,753		606,116
	FY 2011		181,127		21,334		40,346		87,780		13,855		344,442
Wilfred R. Bahl, Jr., Senior Vice President of Finance and Administration	CY2012		205,965		70,013		—		108,904		74,024		458,906
	3 Mo 2011		47,866		481,389		—		—		4,508		533,763
	FY 2011		179,810		8,533		16,139		65,124		17,470		287,076
Marc E. Wallis, Senior Vice President of Sales and Marketing	CY2012		195,615		70,013		—		342,300		58,195		666,123
	3 Mo 2011		46,313		415,443		—		—		1,050		462,806
	FY 2011		164,416		7,112		13,449		220,500		8,354		413,831

(1) CY2012 amounts include the compensation earned by each NEO during calendar year 2012, which comprised our fiscal 2012. 3 Mo 2011 refers to the three-month Transition Period from October 1, 2011 through December 31, 2011. The FY2011 amounts include the compensation earned by each NEO during the full twelve-month period that comprised our fiscal year 2011 (ending on September 30, 2011).

(2) Amounts disclosed for CY2012 reflect the full grant-date fair value of 2012 Partnership phantom unit awards granted to our NEOs. In addition to the reported Partnership awards, Messrs. Hunt and Cohrs received 2012 Rentech stock awards with full grant-date fair values of $1,188,707 and $509,444, respectively. Amounts disclosed for periods prior to CY2012 reflect the full grant-date fair value of RSU and phantom unit awards granted to our NEOs (pro-rated with respect to Rentech stock awards for Messrs. Ramsbottom and Cohrs as described in Notes 6 and 7 below). All equity award values described in this Note have been computed in accordance with ASC Topic 718, rather than the amounts paid to or realized by the named individual. There can be no assurance that unvested awards will vest (and, absent vesting, no value will be realized by the executive for the unvested award). The Partnership provides information regarding the assumptions used to calculate the value of all Partnership unit awards made to executive officers in note 10 to its consolidated financial statements included in this report. Rentech provides information regarding the assumptions used to calculate the value of all Rentech stock awards made to executive officers in note 17 to its consolidated financial statements included in Rentech’s Form 10-K, filed March 18, 2013.

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(3) Amounts reflect the full grant-date fair value of stock options granted (pro-rated with respect to Rentech stock option awards for Messrs. Ramsbottom and Cohrs as described in Notes 6 and 7 below), computed in accordance with ASC Topic 718, rather than the amounts paid to or realized by the named individual. There can be no assurance that unvested awards will vest (and, absent vesting, no value will be realized by the executive for the unvested award). Rentech provides information regarding the assumptions used to calculate the value of all Rentech stock options granted to executive officers in note 17 to its consolidated financial statements included in Rentech’s Form 10-K, filed March 18, 2013.

(4) Each of our Shared NEOs participated in the Rentech annual incentive program and each of our Non-Shared NEOs (other than Mr. Wallis) participated in the RNP annual incentive program during 2012 and each such NEO received an annual incentive award based on the achievement of certain pre-established financial and other performance criteria and determined by reference to target bonuses as set forth in their respective employment agreements. Mr. Wallis participated in our sales incentive program and received an annual incentive award based on the attainment of sales and marketing goals. For 2012, the amount of compensation payable under the annual and sales incentive programs was determined (i) for Messrs. Ramsbottom, Cohrs, Ambrose and Bahl at approximately 150%, 150%, 141% and 141% of their respective target levels and (ii) for Mr. Wallis in an amount equal to approximately 175% of his base salary. For Messrs. Ramsbottom and Cohrs, disclosed amounts were pro-rated as described in Notes 6 and 7 below – the full amounts of their 2012 incentive awards (including the portions reported in the table) were $932,250 and $479,897, respectively. For a description of the annual incentive programs in which our NEOs participated during 2012, please see “Annual Incentive Compensation” above.

(5) Amounts under the “All Other Compensation” column for the year ended December 31, 2012 consist of (i) 401(k) matching contributions for Messrs. Ramsbottom, Cohrs, Ambrose, Bahl and Wallis of $5,152, $6,093, $9,589, $9,285 and $8,361, respectively; (ii) perquisites consisting of company-paid auto allowances, financial and tax planning benefits and long-term disability insurance, (iii) payments made to Messrs. Ramsbottom, Cohrs, Ambrose, Bahl and Wallis of $69,533, $29,739, $22,253, $19,130 and $17,000, respectively, with respect to their outstanding RSUs as a result of Rentech’s declaration of a special cash distribution, as discussed below under “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table—Special Cash Distribution,” and (iv) payments made to Messrs. Ramsbottom, Cohrs, Ambrose, Bahl and Wallis of $102,481, $71,327, $41,361, $36,394 and $31,753, respectively, with respect to their outstanding phantom units as a result of our declaration of cash distributions. For Messrs. Ramsbottom and Cohrs, disclosed amounts (in both the table above and the Perquisites table below) were pro-rated as described in Notes 6 and 7 below – the full amounts of their 2012 “All Other Compensation” (including the portions reported in the table) were $184,791 and $129,844, respectively. The following table identifies and quantifies these perquisites for the calendar year 2012.

Perquisites

Name	Auto Allowance			Long-Term Disability		Supplemental Life Insurance		Financial and Tax Planning		Tax Gross-up Payment		Total
D. Hunt Ramsbottom		7,200			210		123		10,178		—		17,711
Dan J. Cohrs		4,440			155		91		7,524		—		12,210
John A. Ambrose		12,000			420		258		—		—		12,678
Wilfred R. Bahl, Jr.		8,400			420		396		—		—		9,216
Marc E. Wallis		523	(A)		420		138		—		—		1,081

(A) Represents the value of personal usage of a company-provided vehicle determined by multiplying 10% (the percentage of time that we estimate Mr. Wallis used the vehicle for personal purposes) by $5,230 (the total company costs associated with the vehicle).

(6) We estimate that Mr. Ramsbottom dedicated approximately 50%, 53% and 20% of his work time to our business and affairs during calendar year 2012, the Transition Period and the fiscal year ended September 30, 2011, respectively, and, accordingly, the compensation figures attributable to Mr. Ramsbottom in this Summary Compensation Table reflect 50%, 53% and 20% of his total compensation for each category, except that 100% of the grant-date fair value of the Partnership phantom units is included in the “Stock Awards” column because the Partnership phantom units were made in respect of services performed solely for us. Mr. Ramsbottom’s “Total Compensation” for calendar year 2012, the Transition Period and the fiscal year ended September 30, 2011, including amounts paid for services provided to Rentech and its affiliates, equalled $3,115,429, $3,031,889 and $1,397,035, respectively.

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(7) We estimate that Mr. Cohrs dedicated approximately 37%, 45% and 20% of his work time to our business and affairs during calendar year 2012, the Transition Period and the fiscal year ended September 30, 2011 and, accordingly, the compensation figures attributable to Mr. Cohrs in this Summary Compensation Table reflect 37%, 45% and 20% of his total compensation for each category, except that 100% of the grant-date fair value of the Partnership phantom units is included in the “Stock Awards” column because the Partnership phantom units were made in respect of services performed solely for us. Mr. Cohrs’ “Total Compensation” for calendar year 2012, the Transition Period and the fiscal year ended September 30, 2011, including amounts paid for services provided to Rentech and its affiliates, equalled $1,707,087, $1,805,916 and $938,854, respectively.

Grants of Plan-Based Awards

The following table sets forth information with respect to the NEOs concerning the grant of plan-based awards from the Partnership’s plan during the calendar year 2012. With respect to our Shared NEOs, the non-equity incentive amounts set forth below reflect the portion of these NEOs’ plan-based awards that we estimate was attributable to services performed by these NEOs for us during the calendar year 2012, calculated in the same manner as amounts disclosed for these Shared NEOs in the Summary Compensation Table. As noted above, during 2012, Partnership equity awards granted to our NEOs (including our Shared NEOs) were made entirely in respect of services (and were thus allocated in their entirety) to the Partnership, and Rentech equity awards (granted only to our Shared NEOs) were made entirely in respect of services (and were thus allocated in their entirety) to Rentech – accordingly, the table below does not include 2012 grants of Rentech equity awards; however, the value of 2012 Rentech equity awards granted to our Shared NEOs is disclosed in the notes to the table.

Name	Grant Date	Estimated Possible Payouts Under Non-Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards						All  Other Stock Awards: Number of Shares of Stock or Units (#)(1)			All Other Option Awards: Number of Securities Underlying Options (#)(1)				Grant Date Fair Value of Stock and Option Awards ($)(1)
		Threshold ($)		Target ($)		Maximum ($)		Threshold (#)		Target (#)		Maximum (#)							Exercise or Base Price of Option Awards ($/Sh)
D. Hunt Ramsbottom	12/14/2012		—		—		—		—		—		—		5,600	(2)		—		—	$	210,000
	2012 Annual Non-     Equity Incentive	$	—	$	248,600	$	497,200		—		—		—		—			—		—		—
Dan J. Cohrs	12/14/2012		—		—		—		—		—		—		2,400	(2)		—		—	$	90,000
	2012 Annual Non-     Equity Incentive	$	—	$	94,700	$	189,399		—		—		—		—			—		—		—
John A. Ambrose	12/14/2012		—		—		—		—		—		—		2,800	(2)		—		—	$	105,000
	2012 Annual Non-     Equity Incentive	$	—	$	87,064	$	174,129		—		—		—		—			—		—		—
Wilfred R. Bahl, Jr.	12/14/2012		—		—		—		—		—		—		1,867	(2)		—		—	$	70,013
	2012 Annual Non-     Equity Incentive	$	—	$	61,790	$	123,579		—		—		—		—			—		—		—
Marc E. Wallis	12/14/2012		—		—		—		—		—		—		1,867	(2)		—		—	$	70,013
	2012 Annual Non-     Equity Incentive (3)	$	—	$	220,500	$	293,423		—		—		—		—			—		—		—

(1) All of our equity grant awards were made under the Rentech Nitrogen Partners, L.P. 2011 Long-Term Incentive Plan. In addition to the awards disclosed in this table, Messrs. Ramsbottom and Cohrs received 2012 grants of equity incentive awards from Rentech in respect of services provided to Rentech with grant-date fair values of $1,188,707 and $509,444, respectively, which are disclosed in the 2012 Awards Table. Amounts disclosed in the table reflect the full grant date fair value of Partnership phantom units granted during fiscal year 2012, computed in accordance with ASC Topic 718, rather than the amounts paid to or realized by the named individual. We provide information regarding the assumptions used to calculate the fair value of all compensatory equity awards made to executive officers in note 10 to our consolidated financial statements included in this report. There can be no assurance that awards will vest (and, absent vesting no value will be realized by the executive for the unvested award), or that the value upon vesting will approximate the aggregate grant date fair value determined under ASC Topic 718.

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(2) These Partnership phantom units vest in three substantially equal installments on December 14, 2013, 2014 and 2015, subject to the executive’s continued employment through the applicable vesting date and accelerated vesting (i) upon the executive’s termination of employment by the employer without cause or by the executive for good reason, in either case, in connection with a change of control of the Partnership or (ii) upon the executive’s death or disability.

(3) Mr. Wallis’ target amount is based on his sales commission incentive payment for our fiscal year 2011.

Narrative Disclosure to Summary Compensation Table

and Grants of Plan-Based Awards Table

Employment Agreements with Shared NEOs

Messrs. Ramsbottom and Cohrs are parties to employment agreements with Rentech that expire on December 31 and October 22, 2013, respectively, subject in each case to automatic one-year renewals absent 90-days’ advance notice from either party to the contrary. Under these employment agreements, Messrs. Ramsbottom and Cohrs are entitled, respectively, to (i) base salaries which, effective as of January 1, 2013, were $550,000 and $450,000, and (ii) annual incentive bonuses targeted at 100% and 60% of applicable base salary (with actual bonus eligibility for each executive ranging from zero to twice the applicable target).

In addition, the employment agreements provide for monthly auto allowances, as well as customary indemnification, health, welfare, retirement and vacation benefits. The Shared NEOs also receive reimbursement of certain financial and tax planning costs (though only Mr. Ramsbottom’s employment agreement expressly provides for such benefits; Rentech reimburses these costs for each of the Shared NEOs). The agreements also contain customary confidentiality and other restrictive covenants. Each of the Shared NEOs has executed a corporate confidentiality and proprietary rights agreement. Though not addressed in the employment agreements, each of the NEOs is entitled to accelerated vesting of certain equity awards in the event of a change in control of Rentech. For a discussion of the severance and change-in-control benefits for which our Shared NEOs are eligible under their employment agreements, as well as a description of the severance benefits for which our Non-Shared NEOs are eligible in connection with a change in control, see “—Potential Payments upon Termination or Change-in-Control” below.

Employment Agreements with Non-Shared NEOs

Our general partner is party to employment agreements with each of our Non-Shared NEOs, which became effective upon the closing of our IPO on November 9, 2011. Each of these employment agreements continues for an initial term of two years, subject to automatic one-year renewals thereafter. Under their employment agreements, Messrs. Ambrose, Bahl and Wallis receive annual base salaries which, effective as of January 1, 2013, were $250,000, $225,000 and $215,000, respectively. In addition, these agreements provide that Messrs. Ambrose and Bahl will be eligible to receive annual cash bonuses targeted at 40% and 30% of base salary, respectively (and capped at 80% and 60% of base salary, respectively), while Mr. Wallis will be eligible to receive a non-targeted annual bonus of up to 150% of base salary, in each case, based on the attainment of performance criteria established by our general partner’s board of directors.

Under their employment agreements, our Non-Shared NEOs are entitled to severance upon a termination of employment without “cause” or for “good reason” (each as defined in the applicable agreement) consisting of (i) one year of base salary continuation, (ii) payment of the executive’s target bonus for the year in which termination occurs (or, in the case of Mr. Wallis who does not have a target bonus, payment of an additional amount equal to 100% of his base salary), and (iii) up to twelve months of subsidized healthcare premiums. In addition, if our general partner elects not to renew the employment term, the affected executive is entitled to a reduced severance consisting solely of one year of base salary continuation.

Under the terms of their employment agreements, our Non-Shared NEOs are eligible to participate in our customary retirement, health, welfare, disability and other benefit plans. In addition, the employment agreements contain customary non-competition and non-solicitation covenants effective during employment and for one year following termination.

Special Cash Distribution

On December 27, 2012, Rentech paid a special one-time distribution of $0.19 per common share, to its shareholders of record as of the close of business on December 20, 2012 (the “Special Distribution”). In connection with the Special Distribution and in accordance with and pursuant to Rentech’s various equity plans, Rentech equitably adjusted its outstanding stock options, RSUs and PSUs, as follows: (i) the exercise price of each outstanding stock option and the number of shares subject to each option were adjusted to reflect the impact of the Special Distribution, while preserving the aggregate spread of the options (i.e., the difference between the aggregate fair market value of the shares underling the option and the aggregate exercise price for such shares); (ii) holders of time-vesting RSUs received a distribution equivalent distribution of $0.19 per RSU on December 27, 2012, (iii) holders of PSUs became eligible to receive $0.19 per PSU, payable, in the case of any unvested PSUs, only upon the subsequent vesting of the PSUs, and (iv) for purposes of determining whether the performance vesting requirement of a $3.00 weighted average closing share price over a trailing thirty-day period has been met for outstanding PSUs, $0.19 per share is added to the closing price for each day occurring on or after December 18, 2012. Some of the PSUs vested in January 2013 and the Special Distributions related to such PSUs were paid. There is still approximately $0.3 million which will be paid when the remaining PSUs vest.

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Outstanding Equity Awards at December 31, 2012

The following table sets forth information with respect to the NEOs detailing outstanding equity awards from Rentech and the Partnership as of December 31, 2012. With respect to our Shared NEOs, the amounts set forth below reflect the total number of each NEO’s outstanding equity awards as of December 31, 2012 rather than an allocation based on the estimated percentage of time each Shared NEO dedicated to services for the Partnership or based on the entity issuing the award due to the fact that outstanding awards include prior year awards, part of which were allocable to services provided to the Partnership. In addition to the vesting schedules described for each outstanding award in the notes to this table, certain awards may be eligible for accelerated vesting in certain circumstances (for a discussion of accelerated equity vesting, see “—Potential Payments upon Termination or Change-in-Control” below).

	Option Awards										Stock Awards
					Equity										Equity
					Incentive										Incentive		Equity Incentive
					Plan Awards:								Market		Plan Awards:		Plan Awards:
	Number of		Number of		Number of						Number		Value		Number of		Market or
	Securities		Securities		Securities						of Units or		of Units or		Unearned		Payout
	Underlying		Underlying		Underlying						Shares of		Shares of		Shares, Units		Value of Unearned
	Unexercised		Unexercised		Unexercised		Option				Stock		Stock		or		Shares, Units or
	Options		Options		Unearned		Exercise		Option		that have not		that have not		Other Rights		Other Rights
	(#)		(#)		Options		Price		Expiration		Vested		Vested		that have not		that have not
Name	Exercisable		Unexercisable		(#)		($)		Date		(#)		($) (1)		Vested (#)		Vested ($)(1)		Notes
D. Hunt Ramsbottom		268,773		—		—	$	3.87		7/13/2016		—		—		—		—		(2	)
		501,711		250,856		—	$	0.89		10/4/2020		—		—		—		—		(3	)
		—		—		—		—		—		—		—		1,000,000	$	2,630,000		(4	)
		—		—		—		—		—		100,000	$	263,000		—		—		(5	)
		—		—		—		—		—		290,065	$	762,871		—		—		(6	)
		—		—		—		—		—		267,917	$	704,622		—		—		(7	)
		—		—		—		—		—		—		—		800,625	$	2,105,644		(8	)
		—		—		—		—		—		22,182	$	836,040		—		—		(9	)
		—		—		—		—		—		73,944	$	194,473		—		—		(10	)
		—		—		—		—		—		—		—		193,676	$	509,367		(11	)
		—		—		—		—		—		5,600	$	211,064		—		—		(12	)
Dan J. Cohrs		295,125		147,562		—	$	0.89		10/4/2020		—		—		—		—		(3	)
		—		—		—		—		—		—		—		700,000	$	1,841,000		(4	)
		—		—		—		—		—		58,823	$	154,704		—		—		(5	)
		—		—		—		—		—		201,889	$	530,968		—		—		(6	)
		—		—		—		—		—		130,625	$	343,544		—		—		(7	)
		—		—		—		—		—		—		—		397,812	$	1,046,246		(8	)
		—		—		—		—		—		15,439	$	581,896		—		—		(9	)
		—		—		—		—		—		31,690	$	83,345		—		—		(10	)
		—		—		—		—		—		—		—		83,004	$	218,299		(11	)
		—		—		—		—		—		2,400	$	90,456		—		—		(12	)
John A. Ambrose		—		22,134		—	$	0.89		10/4/2020		—		—		—		—		(3	)
		—		—		—		—		—		8,823	$	23,204		—		—		(5	)
		—		—		—		—		—		97,327	$	255,970		—		—		(6	)
		—		—		—		—		—		10,973	$	28,859		—		—		(7	)
		—		—		—		—		—		—		—		33,416	$	87,884		(8	)
		—		—		—		—		—		7,443	$	280,527		—		—		(9	)
		—		—		—		—		—		2,800	$	105,532		—		—		(12	)
		—		—		—		—		—		1,663	$	62,678		—		—		(13	)
Wilfred R. Bahl, Jr.		32,252		—		—	$	3.87		7/13/2016		—		—		—		—		(2	)
		17,707		8,854		—	$	0.89		10/4/2020		—		—		—		—		(3	)
		—		—		—		—		—		3,530	$	9,284		—		—		(5	)
		—		—		—		—		—		89,840	$	236,279		—		—		(6	)
		—		—		—		—		—		7,315	$	19,238		—		—		(7	)
		—		—		—		—		—		—		—		22,277	$	58,589		(8	)
		—		—		—		—		—		6,871	$	258,968		—		—		(9	)
		—		—		—		—		—		1,867	$	70,367		—		—		(12	)
		—		—		—		—		—		1,109	$	41,798		—		—		(13	)
Marc E. Wallis		14,756		7,378		—	$	0.89		10/4/2020		—		—		—		—		(3	)
		—		—		—		—		—		2,942	$	7,737		—		—		(5	)
		—		—		—		—		—		82,353	$	216,588		—		—		(6	)
		—		—		—		—		—		4,180	$	10,993		—		—		(7	)
		—		—		—		—		—		—		—		12,730	$	33,480		(8	)
		—		—		—		—		—		6,298	$	237,372		—		—		(9	)
		—		—		—		—		—		1,867	$	70,367		—		—		(12	)
		—		—		—		—		—		633	$	23,858		—		—		(13	)

(1) Rentech equity award values were calculated based on the $2.63 closing price of Rentech’s common stock on December 31, 2012. The Partnership’s phantom unit award values were calculated based on the $37.69 closing price of the Partnership’s common units on December 31, 2012.

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(2) Represents a stock option award granted on July 14, 2006 that vested in three equal annual installments on each of July 14, 2007, 2008 and 2009. Pursuant to the Special Cash Distribution, as described above, the number of options and the exercise price were adjusted.

(3) Represents Rentech stock options granted on October 4, 2010, which vested in one-third installments on October 4, 2011 and 2012, and the remaining unvested one-third of which will vest on October 4, 2013, subject to the executive’s continued employment through the applicable vesting date (these stock options are referred to below as the 2010 Options). Pursuant to the Special Cash Distribution, as described above, the number of options and the exercise price were adjusted.

(4) Represents Rentech RSUs granted on November 17, 2009 that are eligible to vest upon the attainment of milestones related to the development, construction and operation of Rentech’s Rialto Project or another comparable project designated by Rentech’s Compensation Committee. Subject to the executive’s continued employment through the applicable vesting date, sixty percent (60%) of the shares underlying each RSU award will vest upon the closing of financing for the project, twenty percent (20%) of the shares underlying each RSU award will vest upon completion of construction and initial operation of the project facility and twenty percent (20%) of the shares underlying each RSU award will vest upon sustained operation of the project facility (these RSUs are referred to below as the 2009 Performance-Vest RSUs).

(5) Represents Rentech RSUs granted on October 4, 2010, which vested in one-third installments on October 4, 2011 and 2012, and the remaining unvested one-third of which will vest on October 4, 2013, subject to the executive’s continued employment through the applicable vesting date (these RSUs are referred to below as the 2010 RSUs).

(6) Represents Rentech RSUs granted on December 13, 2011, which vested as to one-third on November 9, 2012, and the remaining unvested two-thirds of which will vest in two substantially equal annual installments on November 9, 2013 and 2014, subject to the executive’s continued employment through the applicable vesting date (these RSUs are referred to below as the 2011 IPO RSUs).

(7) Represents Rentech RSUs granted on December 13, 2011, which vested as to one-third on October 12, 2012, and the remaining unvested two-thirds of which will vest in two substantially equal annual installments on October 12, 2013 and 2014, subject to the executive’s continued employment through the applicable vesting date (these RSUs are referred to below as the 2011 Time-Vest RSUs).

(8) Represents Rentech PSUs granted on December 13, 2011 vesting in full on the first date occurring on or prior to October 12, 2014 on which Rentech’s value weighted average share price for any thirty-day period equals or exceeds $3.00 (after taking into account the adjustments made to the calculation of the value weighted average share price pursuant to the Special Distribution, as described above), subject to the executive’s continued employment through the applicable vesting date (these PSUs are referred to below as the 2011 PSUs). These PSUs vested based on attainment of the share price goal in 2013.

(9) Represents the Partnership’s phantom units granted on December 13, 2011, which vested as to one-third on November 9, 2012, and the remaining unvested two-thirds of which will vest in two substantially equal annual installments on November 9, 2013 and 2014, subject to the executive’s continued employment through the applicable vesting date (these units are referred to below as the 2011 IPO Units).

(10) Represents Rentech RSUs granted on December 14, 2012, vesting in three substantially equal annual installments on December 14, 2013, 2014 and 2015, subject to the executive’s continued employment through the applicable vesting date (these RSUs are referred to below as the 2012 RSUs).

(11) Represents Rentech PSUs granted on December 14, 2012, vesting on each of the first three anniversaries of the grant date based on the level of total shareholder return over the average fair market value for the thirty-day trading period through the grant date, subject to the executive’s continued employment through the applicable vesting date, as described in more detail in “—Long-Term Equity Incentive Awards” above (these PSUs are referred to below as the 2012 PSUs).

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(12) Represents the Partnership’s phantom units granted on December 14, 2012, vesting in three substantially equal installments on December 14, 2013, 2014 and 2015, subject to the executive’s continued employment through the applicable vesting date (these units are referred to below as the 2012 Phantom Units).

(13) Represents the Partnership’s phantom units granted on December 13, 2011, which vested as to one-third on October 12, 2012, and the remaining unvested two-thirds of which will vest in two substantially equal annual installments on October 12, 2013 and 2014, subject to the executive’s continued employment through the applicable vesting date (these units are referred to below as the 2011 Time-Vest Units).

Option Exercises, Stock Vested and Units Vested

The following table sets forth information with respect to the NEOs concerning the option exercises and stock vested under Rentech’s equity plan(s) and the phantom units vested under the Partnership’s plan during the calendar year 2012. With respect to our Shared NEOs, the amounts set forth below reflect the total number of each NEO’s equity awards rather than an allocation based on the estimated percentage of time each Shared NEO dedicated to services for us due to the fact that awards exercised and/or vested include prior year awards, portions of which were allocable to services provided to the Partnership.

	Option Awards				Stock Awards				Unit Awards
Name	Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($)(1)		Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)(2)		Number of Units Acquired on Vesting (#)		Value Realized on Vesting ($)(3)
D. Hunt Ramsbottom		—		—		616,967	$	1,630,063		11,091	$	416,356
Dan J. Cohrs		—		—		303,150	$	795,751		7,719	$	289,771
John A. Ambrose		41,176	$	55,382		79,639	$	212,520		4,552	$	168,605
Wilfred R. Bahl, Jr.		—		—		62,107	$	167,016		3,989	$	148,229
Marc E. Wallis		—		—		54,542	$	147,063		3,466	$	129,245

(1) Amounts shown are based on the fair market value of Rentech’s common stock on the applicable exercise dates less the exercise price.

(2) Amounts shown are based on the fair market value of Rentech’s common stock on the applicable vesting date.

(3) Amounts shown are based on the fair market value of the Partnership’s common units on the applicable vesting date.

Potential Payments upon Termination or Change-in-Control

Our NEOs are entitled to certain payments and benefits upon qualifying terminations of employment, and in certain cases, upon a change in control. The following discussion describes the terms and conditions of these payments and benefits and the circumstances in which they will be paid or provided. All severance payments are conditioned upon the executive’s execution of a general release of claims against the employer.

For purposes of the following discussion, “change in control” refers to a change in control of Rentech or the Partnership, as follows: with respect to (i) the severance payments and benefits provided to our Shared NEOs pursuant to their respective employment agreements, (ii) the 2011 Time-Vest RSUs, (iii) the 2011 PSUs, (iv) the 2011 IPO RSUs, (v) the 2010 Options, (vi) the 2010 RSUs and (vii) the 2009 Performance-Vest RSUs, a change in control refers to a change in control of Rentech. With respect to (a) the severance payments and benefits provided to our Non-Shared NEOs pursuant to their respective employment agreements, (b) the 2012 Phantom Units and (c) the 2011 IPO Units, a change in control refers to a change in control of the Partnership. Note that 2012 Rentech equity awards are not included in the discussion below, as such awards pertain solely to services provided by our Shared NEOs to Rentech (and the costs of such awards are borne solely by Rentech). Prior-year Rentech equity awards, which were allocated proportionately to the Partnership, continue to be included below.

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Shared NEOs, Termination Not in Connection with a Change in Control

Under the Shared NEOs’ employment agreements (described in “—Severance Benefits” above), upon termination of the executive’s employment by Rentech without cause, by the executive with good reason or, in the case of Mr. Ramsbottom only, due to a non-renewal of his employment term by Rentech (each as defined in the employment agreements), the executive is entitled to receive: (i) an amount equal to three times (in the case of Mr. Ramsbottom) or one times (in the case of Mr. Cohrs) base salary, payable in substantially equal installments over a two-year period (for Mr. Ramsbottom) or a one-year period (for Mr. Cohrs), plus (ii) in the case of Mr. Cohrs, payment of his target annual bonus on the date that annual bonuses are paid generally for the year in which termination occurs, and (iii) company-paid continuation health benefits for up to eighteen months following the date of termination. Upon termination of Mr. Cohrs’ employment in connection with Rentech’s non-renewal of his employment term, he will be entitled to receive an amount equal to one times base salary, payable over the one-year period following termination, and, at Rentech’s discretion, an annual bonus for the fiscal year preceding the non-renewal.

In addition, the Shared NEOs will be entitled to the following enhanced vesting provisions with respect to qualifying terminations occurring outside of the context of a change in control of Rentech:

• The 2012 Phantom Units, 2011 Time-Vest RSUs, 2011 PSUs, 2010 Options and 2010 RSUs held by the executive will accelerate and vest in full upon a termination of employment due to the applicable executive’s death or disability.

• The 2011 IPO RSUs and the 2011 IPO Units held by the executive will (i) accelerate and vest in full upon the executive’s termination of employment without cause or for good reason, or due to the executive’s death or disability, and (ii) vest with respect to a pro rata portion of the number of unvested RSUs or units that would have vested on the next subsequent vesting date upon any other termination of employment other than a termination for cause.

• The 2009 Performance-Vest RSUs held by the executive will, following the executive’s termination due to his death or disability, remain outstanding and eligible to vest for a period of six months following such termination and will vest if and to the extent that applicable vesting milestones are attained during such period.

Shared NEOs, Change in Control (No Termination)

The Shared NEOs are not entitled to any cash payments based solely on the occurrence of a change in control of Rentech (absent any qualifying termination). The 2012 Phantom Units, 2011 IPO RSUs, 2011 Time-Vest RSUs, 2011 PSUs, 2011 IPO Units, 2010 Options, 2010 RSUs, and 2009 Performance-Vest RSUs are not impacted by a change in control of Rentech (absent a qualifying termination in connection with such change in control).

Shared NEOs, Termination in Connection with a Change in Control

If either of the Shared NEOs terminates employment without cause, for good reason or due a non-renewal of his employment term by Rentech, in any case, within three months before or two years after a change in control, then the executive will receive the severance described above, except that (i) the base salary component of the executive’s severance will be paid in a lump sum and (ii) if the executive’s actual annual bonus for the year immediately preceding the change in control exceeds his target bonus for the year in which the termination occurs, (A) in the case of Mr. Ramsbottom, he will receive two times base salary plus the amount of such prior-year bonus (instead of three times his base salary) and (B) in the case of Mr. Cohrs, he will receive one times base salary plus the amount of such prior-year bonus (instead of base salary plus target annual bonus). The Shared NEOs’ employment agreements entitle each of these executives to a “gross-up” payment from Rentech covering all taxes, penalties and interest associated with any “golden parachute” excise taxes that are imposed on the executives by reason of Internal Revenue Code Section 280G in connection with a change in control.

In addition, the Shared NEOs will be entitled to the following enhanced vesting provisions with respect to qualifying terminations occurring in connection with a change in control:

• The 2011 Time-Vest RSUs, 2011 PSUs, 2010 Options and the 2010 RSUs will vest in full if the executive terminates employment without cause or for good reason, in either case, within sixty days prior to or one year after the change in control.

• The 2012 Phantom Units will vest in full if the executive terminates employment without cause or for good reason, in either case, within sixty days prior to or eighteen months after the change in control.

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• As noted above, the 2011 IPO RSUs and 2011 IPO Units will vest in full upon a termination without cause or for good reason, or due to the executive’s death or disability (whether or not in connection with a change in control). In addition, these awards will vest with respect to a pro rata portion of the number of unvested RSUs or units that would have vested on the next subsequent vesting date upon any other termination of employment other than a termination for cause (whether or not in connection with a change in control).

• The 2009 Performance-Vest RSUs held by the executive will remain outstanding and eligible to vest for a period of six months following the executive’s termination without cause or for good reason, in either case, occurring within sixty days prior to or one year after the change in control, and these RSUs will vest if and to the extent that applicable vesting milestones are attained during such period.

Non-Shared NEOs, Termination Not in Connection with a Change in Control

Under the Non-Shared NEOs’ employment agreements, upon termination of employment by the employer without cause or by the executive for good reason (each as defined in the applicable agreement), the executive is entitled to receive: (i) an amount equal to one times his annual base salary, payable in substantially equal instalments over a twelve-month period following the date of termination, plus one times his target bonus for the year in which termination occurs (or, in the case of Mr. Wallis, who does not have a target bonus, payment of an additional amount equal to 100% of his base salary), and (ii) up to 12 months of subsidized healthcare premiums. If our general partner elects not to renew the employment term, the executive is entitled to a reduced severance consisting solely of one year of base salary continuation. During employment and for one year following termination, the employment agreements prohibited these NEOs from soliciting certain of our employees and customers.

In addition, the Non-Shared NEOs will be entitled to the following enhanced vesting provisions with respect to qualifying terminations:

• The 2012 Phantom Units, 2011 Time-Vest RSUs, 2011 PSUs, 2011 Time-Vest Units, 2010 Options and 2010 RSUs held by the executive will accelerate and vest in full upon a termination of employment due to the applicable executive’s death or disability.

• The 2011 IPO RSUs and the 2011 IPO Units held by the executive will (i) accelerate and vest in full upon the executive’s termination of employment without cause or for good reason, or due to the executive’s death or disability, and (ii) vest with respect to a pro rata portion of the number of unvested RSUs that would have vested on the next subsequent vesting date upon any other termination of employment other than a termination for cause.

Non-Shared NEOs, Change in Control (No Termination)

The Non-Shared NEOs are not entitled to any cash payments or any accelerated vesting of equity awards based solely on the occurrence of a change in control (absent any qualifying termination).

Non-Shared NEOs, Termination in Connection with a Change in Control

If the Non-Shared NEOs terminate employment without cause, for good reason or due a non-renewal of the applicable employment term by us, in any case, in connection with a change in control, then the executive will receive the severance described above. In addition, the following enhanced vesting provisions will apply:

• The 2011 Time-Vest RSUs, 2011 PSUs, 2011 Time-Vest Units, 2010 Options and 2010 RSUs held by the executive will vest in full if the executive terminates employment without cause or for good reason, in either case, within sixty days prior to or one year after the change in control. Each of these awards also vests in full upon the executive’s termination of employment due to death or disability (whether or not in connection with a change in control).

• The 2012 Phantom Units held by the executive will vest in full if the executive terminates employment without cause or for good reason, in either case, within sixty days prior to or eighteen months after the change in control. The 2012 Phantom Units also vest in full upon the executive’s termination of employment due to death or disability (whether or not in connection with a change in control).

• As noted above, the 2011 IPO RSUs and 2011 IPO Units will vest in full upon a termination without cause or for good reason, or due to the executive’s death or disability (whether or not in connection with a change in control). In addition, these awards will vest with respect to a pro rata portion of the number of unvested RSUs or units that would have vested on the next subsequent vesting date upon any other termination of employment other than a termination for cause (whether or not in connection with a change in control).

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The following table summarizes the change-in-control and/or severance payments and benefits to which we expect that our NEOs would have become entitled if the relevant event(s) had occurred on December 31, 2012, in accordance with applicable disclosure rules. For purposes of the following table, we have assumed that a change in control of each relevant entity, whether Rentech and/or the Partnership, occurred on December 31, 2012, in order to provide a complete representation of the payments and benefits that each NEO would have become entitled to receive upon the occurrence of the relevant event(s). With respect to our Shared NEOs, the amounts set forth below reflect the portion of these NEOs’ change-in-control and severance payments that we estimate will be attributable to services performed by these NEOs for the Partnership during fiscal year 2012, calculated in the same manner as amounts disclosed for these Shared NEOs in the Summary Compensation Table.

Name	Benefit	Termination without Cause or for Good Reason ($)			Termination due to Non- Renewal ($)			Termination due to Death/ Disability ($)			Qualifying Termination in Connection with a Change in Control			Other Terminations
D. Hunt Ramsbottom	Cash Severance	$	825,000	(1)	$	825,000	(1)		—		$	922,900	(2)		—
	Value of Accelerated Stock Awards(3)	$	381,435	(4)	$	381,435	(5)	$	1,918,068	(6)	$	3,233,068	(7)	$	27,171	(8)
	Value of Accelerated Option Awards(9)		—			—		$	218,245	(10)	$	218,245	(11)		—
	Value of Accelerated Units(12)	$	836,040	(13)	$	836,040	(5)	$	1,047,104	(14)	$	1,047,104	(15)	$	59,554	(16)
	Value of Healthcare Premiums	$	14,411	(17)	$	14,411	(17)		—		$	14,411	(17)		—
	Value of Excise Tax Gross-Up		—			—			—		$	2,019,114	(18)		—
	Total	$	2,056,886		$	2,056,886		$	3,183,417		$	7,454,842		$	86,725
Dan J. Cohrs	Cash Severance	$	266,400	(19)	$	166,500	(20)		—		$	308,549	(21)		—
	Value of Accelerated Stock Awards(3)	$	196,458	(22)	$	196,458	(5)	$	767,921	(23)	$	1,449,091	(24)	$	13,994	(25)
	Value of Accelerated Option Awards(9)		—			—		$	95,000	(26)	$	95,000	(27)		—
	Value of Accelerated Units(12)	$	581,896	(28)	$	581,896	(5)	$	672,352	(29)	$	672,352	(30)	$	41,450	(31)
	Value of Healthcare Premiums	$	10,664	(17)		—			—		$	10,664	(17)		—
	Value of Excise Tax Gross-Up		—			—			—		$	945,846	(18)		—
	Total	$	1,055,418		$	944,854		$	1,535,273		$	3,481,502		$	55,444

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Name	Benefit	Termination without Cause or for Good Reason ($)			Termination due to Non- Renewal ($)			Termination due to Death/ Disability ($)			Qualifying Termination in Connection with a Change in Control			Other Terminations
John A. Ambrose	Cash Severance	$	350,000	(19)	$	250,000	(20)		—			—			—
	Value of Accelerated Stock Awards(3)	$	255,970	(32)	$	255,970	(5)	$	395,918	(33)	$	395,918	(34)	$	18,233	(35)
	Value of Accelerated Option Awards(9)		—			—		$	38,513	(36)	$	38,513	(36)		—
	Value of Accelerated Units(12)	$	280,527	(37)	$	280,527	(5)	$	448,737	(38)	$	448,737	(39)	$	19,983	(40)
	Value of Healthcare Premiums	$	19,214	(17)		—			—			—			—
	Total	$	905,711		$	786,497		$	883,168		$	883,168		$	38,216
Wilfred R. Bahl, Jr.	Cash Severance	$	292,500	(19)	$	225,000	(20)		—			—			—
	Value of Accelerated Stock Awards(3)	$	236,279	(41)	$	236,279	(5)	$	323,390	(42)	$	323,390	(43)	$	16,831	(44)
	Value of Accelerated Option Awards(9)		—			—		$	15,406	(45)	$	15,406	(45)		—
	Value of Accelerated Units(12)	$	258,968	(46)	$	258,968	(5)	$	371,133	(47)	$	371,133	(48)	$	18,447	(49)
	Value of Healthcare Premiums	$	19,214	(17)		—			—			—			—
	Total	$	806,961		$	720,247		$	709,929		$	709,929		$	35,278
Marc E. Wallis	Cash Severance	$	430,000	(19)	$	215,000	(20)		—			—			—
	Value of Accelerated Stock Awards(3)	$	216,588	(50)	$	216,588	(5)	$	268,799	(51)	$	268,799	(52)	$	15,428	(53)
	Value of Accelerated Option Awards(9)		—			—		$	12,838	(54)	$	12,838	(54)		—
	Value of Accelerated Units(12)	$	237,372	(55)	$	237,372	(5)	$	331,597	(56)	$	331,597	(57)	$	16,909	(58)
	Value of Healthcare Premiums	$	19,214	(17)		—			—			—			—
	Total	$	903,174		$	668,960		$	613,234		$	613,234		$	32,337

⁽¹⁾  Represents three times Mr. Ramsbottom’s annual base salary, payable over the two-year period after his termination date.

⁽²⁾  Represents two times Mr. Ramsbottom’s annual base salary plus target bonus which equals the prior year’s bonus, payable in a lump sum upon termination.

⁽³⁾  Value of RSUs determined by multiplying the number of accelerating RSUs by the fair market value of Rentech’s common stock on December 30, 2012 ($2.63).

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⁽⁴⁾  Represents the aggregate value of 145,033 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Ramsbottom’s termination without cause or for good reason on December 31, 2012.

⁽⁵⁾  The applicable award agreements do not address acceleration upon a non-renewal of the applicable executive’s employment agreement. Additionally, none of the NEOs’ employment agreements was up for renewal as December 31, 2012. However, for purposes of this column, we have assumed that, if a non-renewal of the applicable executive’s employment agreement had occurred on December 31, 2012 (had a non-renewal been possible on such date), these equity awards would be treated as though the applicable executive’s employment was terminated without cause on December 31, 2012. Pursuant to the terms of the applicable award agreements, 2011 IPO RSUs and 2011 IPO Units vest in full upon a termination of employment without cause. Accordingly, (i) amounts described under “Value of Accelerated Stock Awards” represent the value of the accelerated 2011 IPO RSUs described in Notes 4, 22, 32, 41 and 50 for Messrs. Ramsbottom, Cohrs, Ambrose, Bahl and Wallis, respectively, and (ii) amounts described under “Value of Accelerated Units” represent the value of the accelerated 2011 IPO Units described in Notes 13, 28, 37, 46, and 55 for Messrs. Ramsbottom, Cohrs, Ambrose, Bahl and Wallis, respectively. None of the 2012 Phantom Units, 2011 Time-Vest RSUs, 2010 RSUs and 2009 Performance-Vest RSUs are subject to accelerated vesting upon a termination of the applicable executive’s employment without cause (absent a change in control) and, as a result, no acceleration of such awards would have occurred in connection with a non-renewal of the applicable executive’s employment agreement on December 31, 2012.

⁽⁶⁾  Represents the aggregate value of 145,033 unvested 2011 IPO RSUs, 133,959 unvested 2011 Time-Vest RSUs, 400,313 unvested 2011 PSUs and 50,000 unvested 2010 RSUs held by Mr. Ramsbottom that would have vested on an accelerated basis upon Mr. Ramsbottom’s termination due to death or disability on December 31, 2012. We have assumed for purposes of this calculation that that all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012.

⁽⁷⁾  Represents the aggregate value of 145,033 unvested 2011 IPO RSUs, 133,959 unvested 2011 Time-Vest RSUs, 400,313 unvested 2011 PSUs, 50,000 unvested 2010 RSUs and 500,000 unvested 2009 Performance-Vest RSUs that would have vested on an accelerated basis if Mr. Ramsbottom terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after a change in control of Rentech. We have assumed for purposes of this calculation that all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012 (and, accordingly, the unvested 2011 PSUs held by Mr. Ramsbottom vested in full on such date).

⁽⁸⁾  Represents the aggregate value of 10,331 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Ramsbottom’s termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽⁹⁾  Value of options determined by multiplying the fair market value of Rentech’s common stock on December 31, 2012 ($2.63), less the applicable exercise price, by the number of accelerating options.

⁽¹⁰⁾  Represents the aggregate value of 125,428 unvested 2010 Options held by Mr. Ramsbottom that would have vested on an accelerated basis upon Mr. Ramsbottom’s termination due to death or disability on December 31, 2012.

⁽¹¹⁾  Represents the aggregate value of 125,428 unvested 2010 Options held by Mr. Ramsbottom that would have vested on an accelerated basis if Mr. Ramsbottom terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after the change in control.

⁽¹²⁾  Value of 2012 Phantom Units, 2011 IPO Units and 2011 Time-Vest Units determined by multiplying the number of accelerating Partnership units by the fair market value of the Partnership’s common unit on December 31, 2012 ($37.69).

⁽¹³⁾  Represents the aggregate value of 22,182 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Ramsbottom’s termination without cause or for good reason on December 31, 2012.

⁽¹⁴⁾  Represents the aggregate value of 5,600 unvested 2012 Phantom Units and 22,182 unvested 2011 IPO Units held by Mr. Ramsbottom that would have vested on an accelerated basis upon Mr. Ramsbottom’s termination due to death or disability on December 31, 2012.

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⁽¹⁵⁾  Represents the aggregate value of 5,600 unvested 2012 Phantom Units and 22,182 unvested 2011 IPO Units held by Mr. Ramsbottom that would have vested on an accelerated basis if Mr. Ramsbottom terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after the change in control (or within eighteen months after a change in control with respect to the 2012 Phantom Units).

⁽¹⁶⁾  Represents the aggregate value of 1,580 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Ramsbottom termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽¹⁷⁾  Represents the cost of Company-paid continuation health benefits for eighteen months (in the case of the Shared NEOs) or twelve months (in the case of the Non-Shared NEOs), based on our estimated costs to provide such coverage.

⁽¹⁸⁾  Represents tax gross-up payments to compensate for excise taxes imposed by Section 4999 of the Internal Revenue Code on the payments and benefits provided (as well as any related taxes on such payment). The assumptions used to calculate the excise tax gross-up include the following: an excise tax rate of 20%, a federal tax rate of 25%, California state tax rate of 8.0929% and a Medicare tax rate of 1.45%.

⁽¹⁹⁾  Represents the executive’s annual base salary, payable over the one-year period after his termination date, plus (i) with respect to Messrs. Cohrs, Ambrose and Bahl, their target annual incentive bonuses and (ii) with respect to Mr. Wallis, a bonus equal to 100% of his annual base salary.

⁽²⁰⁾  Represents executive’s annual base salary, payable over the one-year period after his termination date.

⁽²¹⁾  Represents Mr. Cohrs’ annual base salary plus target bonus which equals the prior year’s bonus, payable in a lump sum upon termination.

⁽²²⁾  Represents the aggregate value of 74,699 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Cohrs’ termination without cause or for good reason on December 31, 2012.

⁽²³⁾  Represents the aggregate value of 74,699 unvested 2011 IPO RSUs, 48,331 unvested 2011 Time-Vest RSUs, 147,190 unvested 2011 PSUs and 21,765 unvested 2010 RSUs held by Mr. Cohrs that would have vested on an accelerated basis upon Mr. Cohrs’ termination due to death or disability on December 31, 2012. We have assumed for purposes of this calculation that all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012.

⁽²⁴⁾  Represents the aggregate value of 74,699 unvested 2011 IPO RSUs, 48,331 unvested 2011 Time-Vest RSUs, 147,190 unvested 2011 PSUs, 21,765 unvested 2010 RSUs and 259,000 unvested 2009 Performance-Vest RSUs that would have vested on an accelerated basis if Mr. Cohrs terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after a change in control of Rentech. We have assumed for purposes of this calculation that all performance criteria applicable to the 2009 Performance-Vest RSUs and 2011 PSUs were attained on December 31, 2012 (and, accordingly, the unvested 2009 Performance-Vest RSUs and 2011 PSUs held by Mr. Cohrs vested in full on such date).

⁽²⁵⁾  Represents the aggregate value of 5,321 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Cohrs’ termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽²⁶⁾  Represents the aggregate value of 54,598 unvested 2010 Options held by Mr. Cohrs that would have vested on an accelerated basis upon Mr. Cohrs’ termination due to death or disability on December 31, 2012.

⁽²⁷⁾  Represents the aggregate value of 54,598 unvested 2010 Options held by Mr. Cohrs that would have vested on an accelerated basis if Mr. Cohrs terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after the change in control.

⁽²⁸⁾  Represents the aggregate value of 15,439 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Cohrs’ termination without cause or for good reason on December 31, 2012.

⁽²⁹⁾  Represents the aggregate value of 2,400 unvested 2012 Phantom Units and 15,439 unvested 2011 IPO Units held by Mr. Cohrs that would have vested on an accelerated basis upon Mr. Cohrs’ termination due to death or disability on December 31, 2012.

148

⁽³⁰⁾  Represents the aggregate value of 2,400 unvested 2012 Phantom Units and 15,439 unvested 2011 IPO Units held by Mr. Cohrs that would have vested on an accelerated basis if Mr. Cohrs terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after the change in control (or within eighteen months after a change in control with respect to the 2012 Phantom Units).

⁽³¹⁾  Represents the aggregate value of 1,100 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Cohrs’ termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽³²⁾  Represents the aggregate value of 97,327 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Ambrose’s termination without cause or for good reason on December 31, 2012.

⁽³³⁾  Represents the aggregate value of 97,327 unvested 2011 IPO RSUs, 10,973 unvested 2011 Time-Vest RSUs, 33,416 unvested 2011 PSUs and 8,823 unvested 2010 RSUs held by Mr. Ambrose that would have vested on an accelerated basis upon Mr. Ambrose’s termination due to death or disability on December 31, 2012. We have assumed for purposes of this calculation that all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012 (and, accordingly, the unvested 2011 PSUs held by Mr. Ambrose vested in full on such date).

⁽³⁴⁾  Represents the aggregate value of 97,327 unvested 2011 IPO RSUs, 10,973 unvested 2011 Time-Vest RSUs, 33,416 unvested 2011 PSUs and 8,823 unvested 2010 RSUs that would have vested on an accelerated basis if Mr. Ambrose terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after a change in control of Rentech. We have assumed for purposes of this calculation that (A) all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012 and (B) the relevant change in control occurred on December 31, 2012.

⁽³⁵⁾  Represents the aggregate value of 6,933 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Ambrose’s termination of employment for any reason not described in the prior columns (other than a termination for cause).

⁽³⁶⁾  Represents the aggregate value of 22,134 unvested 2010 Options held by Mr. Ambrose that would have vested on an accelerated basis upon either (i) Mr. Ambrose’s termination due to death or disability on December 31, 2012, or (ii) Mr. Ambrose’s termination without cause or for good reason within one month before or one year after a change in control of the Partnership.

⁽³⁷⁾  Represents the aggregate value of 7,443 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Ambrose’s termination without cause or for good reason on December 31, 2012.

⁽³⁸⁾  Represents the aggregate value of 2,800 unvested 2012 Phantom Units, 7,443 unvested 2011 IPO Units and 1,663 unvested 2011 Time-Vest Units held by Mr. Ambrose that would have vested on an accelerated basis upon Mr. Ambrose’s termination due to death or disability on December 31, 2012.

⁽³⁹⁾  Represents the aggregate value of (i) 2,800 unvested 2012 Phantom Units and 1,663 unvested 2011 Time-Vest Units held by Mr. Ambrose that would have vested on an accelerated basis if Mr. Ambrose terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year (or eighteen months with respect to the 2012 Phantom Units) after the change in control, and (ii) 7,443 unvested 2011 IPO Units that would have vested on an accelerated basis if Mr. Ambrose terminated employment without cause or for good reason on December 31, 2012.

⁽⁴⁰⁾  Represents the aggregate value of 530 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Ambrose’s termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽⁴¹⁾  Represents the aggregate value of 89,840 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Bahl’s termination without cause or for good reason on December 31, 2012.

⁽⁴²⁾  Represents the aggregate value of 89,840 unvested 2011 IPO RSUs, 7,315 unvested 2011 Time-Vest RSUs, 22,277 unvested 2011 PSUs and 3,530 unvested 2010 RSUs held by Mr. Bahl that would have vested on an accelerated basis upon Mr. Bahl’s termination due to death or disability on December 31, 2012. We have assumed for purposes of this calculation that all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012.

⁽⁴³⁾  Represents the aggregate value of 89,840 unvested 2011 IPO RSUs, 7,315 unvested 2011 Time-Vest RSUs, 22,277 unvested 2011 PSUs and 3,530 unvested 2010 RSUs that would have vested on an accelerated basis if Mr. Bahl terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after a change in control of Rentech. We have assumed for purposes of this calculation that (A) all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012 and (B) the relevant change in control occurred on December 31, 2012.

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⁽⁴⁴⁾  Represents the aggregate value of 6,400 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Bahl’s termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽⁴⁵⁾  Represents the aggregate value of 8,854 unvested 2010 Options held by Mr. Bahl that would have vested on an accelerated basis upon either (i) Mr. Bahl’s termination due to death or disability on December 31, 2012, or (ii) Mr. Bahl’s termination without cause or for good reason within one month before or one year after a change in control of the Partnership.

⁽⁴⁶⁾  Represents the aggregate value of 6,871 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Bahl’s termination without cause or for good reason on December 31, 2012.

⁽⁴⁷⁾  Represents the aggregate value of 1,867 unvested 2012 Phantom Units, 6,871 unvested 2011 IPO Units and 1,109 unvested 2011 Time-Vest Units held by Mr. Bahl that would have vested on an accelerated basis upon Mr. Bahl termination due to death or disability on December 31, 2012.

⁽⁴⁸⁾  Represents the aggregate value of (i) 1,867 unvested 2012 Phantom Units and 1,109 unvested 2011 Time-Vest Units held by Mr. Bahl that would have vested on an accelerated basis if Mr. Bahl terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year (or eighteen months with respect to the 2012 Phantom Units) after the change in control, and (ii) 6,871 unvested 2011 IPO Units that would have vested on an accelerated basis if Mr. Bahl terminated employment without cause or for good reason on December 31, 2012.

⁽⁴⁹⁾  Represents the aggregate value of 489 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Bahl’s termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽⁵⁰⁾  Represents the aggregate value of 82,353 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Wallis’ termination without cause or for good reason on December 31, 2012.

⁽⁵¹⁾  Represents the aggregate value of 82,353 unvested 2011 IPO RSUs, 4,180 unvested 2011 Time-Vest RSUs, 12,730 unvested 2011 PSUs and 2,942 unvested 2010 RSUs held by Mr. Wallis that would have vested on an accelerated basis upon Mr. Wallis’ termination due to death or disability on December 31, 2012. We have assumed for purposes of this calculation that all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012.

⁽⁵²⁾  Represents the aggregate value of 82,353 unvested 2011 IPO RSUs, 4,180 unvested 2011 Time-Vest RSUs, 12,730 unvested 2011 PSUs and 2,942 unvested 2010 RSUs that would have vested on an accelerated basis if Mr. Wallis terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year after a change in control of Rentech. We have assumed for purposes of this calculation that (A) all performance criteria applicable to the 2011 PSUs were attained on December 31, 2012 and (B) the relevant change in control occurred on December 31, 2012.

⁽⁵³⁾  Represents the aggregate value of 5,866 unvested 2011 IPO RSUs that would have vested on an accelerated basis upon Mr. Wallis’ termination of employment for any other reason not described in the prior columns (other than a termination for cause).

⁽⁵⁴⁾  Represents the aggregate value of 7,378 unvested 2010 Options held by Mr. Wallis that would have vested on an accelerated basis upon either (i) Mr. Wallis’ termination due to death or disability on December 31, 2012, or (ii) Mr. Wallis’ termination without cause or for good reason within one month before or one year after a change in control of the Partnership.

⁽⁵⁵⁾  Represents the aggregate value of 6,298 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Wallis’ termination without cause or for good reason on December 31, 2012.

⁽⁵⁶⁾  Represents the aggregate value of 1,867 unvested 2012 Phantom Units, 6,298 unvested 2011 IPO Units and 633 unvested 2011 Time-Vest Units held by Mr. Wallis that would have vested on an accelerated basis upon Mr. Wallis termination due to death or disability on December 31, 2012.

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⁽⁵⁷⁾  Represents the aggregate value of (i) 1,867 unvested 2012 Phantom Units and 633 unvested 2011 Time-Vest Units held by Mr. Wallis that would have vested on an accelerated basis if Mr. Wallis terminated employment without cause or for good reason on December 31, 2012 and, in either case, such termination occurred within sixty days prior to or one year (or eighteen months with respect to the 2012 Phantom Units) after the change in control, and (ii) 6,298 unvested 2011 IPO Units that would have vested on an accelerated basis if Mr. Wallis terminated employment without cause or for good reason on December 31, 2012.

⁽⁵⁸⁾  Represents the aggregate value of 449 unvested 2011 IPO Units that would have vested on an accelerated basis upon Mr. Wallis’ termination of employment for any other reason not described in the prior columns.

Director Compensation

We have implemented a compensation program for the non-employee directors of our board of directors. Directors who are also employees of the Partnership do not receive additional compensation for their services on our board of directors. During 2012, Michael S. Burke, Michael F. Ray and Halbert S. Washburn served as non-employee members of our board of directors and of the board of directors of Rentech and are referred to in this registration statement as our “Shared Directors” (James F. Dietz and Keith B. Forman, who served only as non-employee members of our board of directors, are referred to herein as our “Non-Shared Directors”).

The compensation plan for Non-Shared Directors provides for an annual retainer of $30,000 to be paid in quarterly increments of $7,500 to each Non-Shared Director. The Chairman of our board of directors, if any, receives $25,000 per year. Any Non-Shared Director serving as the Chairman of our Audit Committee receives $15,000 per year and any Non-Shared Director serving as a member of our Audit Committee receives $7,500 per year. Our Shared Directors are entitled to receive reduced retainers equal to $15,000 to be paid in quarterly increments of $3,750 to each Shared Director based on the substantial overlap of the services they provide to us and the services they provide as directors of Rentech. Any Shared Director serving as the Chairman of the Audit Committee receives $7,500 per year and any Shared Director serving as a member of the Audit Committee receive $4,000 per year. Directors are also reimbursed for reasonable out-of-pocket expenses incurred in their capacity as directors. No additional cash fees are paid to directors for attendance at our board of directors or committee meetings.

Each newly elected non-employee member of our board of directors is granted a phantom unit award with a fair market value on the date of grant equal to $25,000, with such award vesting on the one-year anniversary of the grant date. Each Non-Shared Director serving immediately following Rentech’s annual meeting of stockholders also is granted (i) an award of our common units with a fair market value on the date of grant equal to $50,000 and (ii) a phantom unit award with a fair market value on the date of grant equal to $25,000, with each such award vesting on the one-year anniversary of the grant date. Each Shared Director serving immediately following Rentech’s annual meeting of stockholders also is granted (i) an award of our common units with a fair market value on the date of grant equal to $25,000 and (ii) a phantom unit award with a fair market value on the date of grant equal to $12,500, with each such award vesting on the one-year anniversary of the grant date. The following table sets forth compensation information with respect to our non-employee directors for the fiscal year ended December 31, 2012:

Name	Fees Earned or Paid  in Cash ($)		Unit Awards ($)		Total ($)
Michael S. Burke	$	22,500	$	72,273	$	94,773
James F. Dietz	$	34,375	$	109,737	$	144,112
Keith B. Forman	$	37,500	$	109,737	$	147,237
Michael F. Ray	$	15,000	$	72,273	$	87,273
Halbert S. Washburn	$	15,000	$	72,273	$	87,273

(1) Amounts reflect the full grant-date fair value of the 2012 phantom unit awards, calculated in accordance with ASC Topic 718. We provide information regarding the assumptions used to calculate the value of all Partnership phantom unit awards made to non-employee directors in note 10 to our consolidated financial statements included in this report. The aggregate number of phantom unit awards held by our non-employee directors as of December 31, 2012 was for Messrs. Burke, Dietz, Forman, Ray and Washburn 570, 1,130, 1,130, 570 and 570 phantom units, respectively.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table presents information regarding beneficial ownership of our common units as of February 28, 2013 by:

• our general partner;

• each of our general partner’s directors;

• each of our general partner’s named executive officers;

• each unitholder known by us to beneficially hold five percent or more of our outstanding common units; and

• all of our general partner’s executive officers and directors as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all common units beneficially owned, subject to community property laws where applicable. Except as otherwise indicated, the business address for each of our beneficial owners is c/o Rentech Nitrogen Partners, L.P., 10877 Wilshire Boulevard, Suite 600, Los Angeles, California 90024.

Name and Address of Beneficial Owner	Amount and Nature of Common Units Beneficially Owned(1)		Percentage of Total Common Units(2)
Rentech Nitrogen GP, LLC(3)		—		—
RNHI(4)		23,250,000		59.9	%
D. Hunt Ramsbottom		7,023		—
Dan J. Cohrs		4,888		—
John H. Diesch		3,422		—
John A. Ambrose		2,940		—
Wilfred R. Bahl, Jr.		2,576		—
Marc E. Wallis		3,230		—
Halbert S. Washburn		2,380		—
Michael F. Ray		2,380		—
Michael S. Burke		2,380		—
James F. Dietz		7,928		—
Keith B. Forman		3,500		—
All directors and executive officers as a group (12 persons)		46,516		—

* Less than 1%.

(1) The Security Ownership table above does not include unvested phantom units held by NEOs that will vest assuming the continued employment of the NEO beyond each applicable vesting date:

• D. Hunt Ramsbottom – 27,782 phantom units;

• Dan J. Cohrs – 17,839 phantom units;

• John H. Diesch – 12,330 phantom units;

• John A. Ambrose – 11,906 phantom units;

• Wilfred R. Bahl, Jr. – 9,847 phantom units;

• Marc E. Wallis – 8,798 phantom units;

• Halbert S. Washburn – 570 phantom units;

• Michael F. Ray – 570 phantom units;

• Michael S. Burke – 570 phantom units;

• James F. Dietz – 1,130 phantom units; and

• Keith B. Forman – 1,130 phantom units.

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(2) Based on 38,839,033 common units outstanding as of February 28, 2013.

(3) Our general partner, a wholly owned subsidiary of RNHI, manages and operates our business and has a non-economic general partner interest.

(4) RNHI is an indirect wholly owned subsidiary of Rentech.

The following table sets forth, as of February 28, 2013, the number of shares of common stock of Rentech owned by each of the named executive officers and directors of our general partner and all executive officers and directors of our general partner as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all shares of common stock beneficially owned, subject to community property laws where applicable. Except as otherwise indicated, the business address for each of the following persons is c/o Rentech Nitrogen Partners, L.P., 10877 Wilshire Boulevard, Suite 600, Los Angeles, California 90024.

Name and Address of Beneficial Owner	Amount and Nature of Common Stock Beneficially Owned(1)(2)		Percentage of Total Common Stock(1)(3)
D. Hunt Ramsbottom(4)(5)		2,353,562		*
Dan J. Cohrs		983,274		*
John H. Diesch		567,182		*
John A. Ambrose		124,239		*
Wilfred R. Bahl, Jr.		247,841		*
Marc E. Wallis		93,340		*
Halbert S. Washburn		361,768		*
Michael F. Ray(6)		458,505		*
Michael S. Burke		324,439		*
James F. Dietz		—		*
Keith B. Forman		—		*
All directors and executive officers as a group (12 persons)		6,201,924		2.7	%

* Less than 1%

(1) If a person has the right to acquire shares of common stock subject to options or other convertible or exercisable securities within 60 days of February 28, 2013, then such shares (including certain restricted stock units which are fully vested but will not be yet paid out until the earlier of the recipient’s termination and three years from the applicable award date, subject to any required payment delays arising under applicable tax laws) are deemed outstanding for purposes of computing the percentage ownership of that person, but are not deemed outstanding for purposes of computing the percentage ownership of any other person. The following shares of common stock subject to stock options and warrants may be acquired within 60 days of February 28, 2013 and are included in the table above:

• D. Hunt Ramsbottom—770,484 under options;

• Dan J. Cohrs—295,125 under options;

• John H. Diesch—161,473 under options;

• Wilfred R. Bahl, Jr.—49,959 under options;

• Marc E. Wallis—14,756 under options;

• Halbert S. Washburn—76,868 under options;

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• Michael F. Ray—60,742 under options;

• Michael S. Burke—60,742 under options; and

• all directors and executive officers as a group—1,688,830 under options.

(2) The Security Ownership table above does not include the following:

(A) PSUs held by NEOs that vest upon each of the first three anniversaries of the grant date based on the level of total shareholder return over the average fair market value for the thirty-day trading period through the grant date (the numbers below represent the greatest number of PSUs that may be issued to the NEOs):

• D. Hunt Ramsbottom — 677,864 PSUs;

• Dan J. Cohrs — 290,512 PSUs; and

• John H. Diesch — 290,512 PSUs;

(B) unvested RSUs and options held by NEOs that will vest assuming the continued employment of the officer beyond each applicable vesting date:

• D. Hunt Ramsbottom — 731,926 RSUs and 250,856 options;

• Dan J. Cohrs — 423,027 RSUs and 147,562 options;

• John H. Diesch — 248,407 RSUs and 59,025 options;

• John A. Ambrose — 117,123 RSUs and 22,134 options;

• Wilfred R. Bahl, Jr. — 100,685 RSUs and 8,854 options;

• Marc E. Wallis — 89,475 RSUs and 7,378 options;

• Halbert S. Washburn — 14,700 RSUs;

• Michael F. Ray — 14,700 RSUs; and

• Michael S. Burke — 14,700 RSUs.

(3) Based on 225,815,970 shares of common stock outstanding as of February 28, 2013.

(5) Includes 68,000 shares held for the benefit of Mr. Ramsbottom’s children as to which Mr. Ramsbottom disclaims beneficial ownership and 10,000 shares held by the L.E. Ramsbottom Living Trust beneficially owned by Mr. Ramsbottom’s spouse as to which Mr. Ramsbottom disclaims beneficial ownership.

(6) Includes 7,500 shares held by Mr. Ray’s spouse’s IRA as to which Mr. Ray disclaims beneficial ownership.

Equity Compensation Plan Information

The following table provides information as of December 31, 2012 with respect to our compensation plan under which our equity securities are authorized for issuance.

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)			Weighted-average exercise price of outstanding options, warrants and rights (b)			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected  in column (a)) (c)
Equity compensation plans approved by security holders		154,938	(1)		—	(2)		3,599,782
Equity compensation plans not approved by security holders		—			—			—
Total		154,938			—			3,599,782

(1) Represents phantom units awarded under the 2011 LTIP.

(2) Phantom units do not have an exercise price. Payout is based on completing a specified period of employment.

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The 2011 LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

For a discussion of director independence, see Part III—Item 10 “Directors, Executive Officers and Corporate Governance.”

RNHI, an indirect wholly-owned subsidiary of Rentech, owns (i) 23,250,000 common units, representing 59.9% of our outstanding common units and (ii) all of the member interests in our general partner and our general partner own a general partner interest in us.

Distributions and Payments to Rentech and its Affiliates

The following table summarizes the distributions and payments to be made by us to Rentech and its affiliates (including our general partner) in connection with the ongoing operation and any liquidation of the Partnership. These distributions and payments were or will be determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Operational Stage

Distributions to RNHI and its affiliates	•	We will generally make cash distributions to our unitholders pro rata, including to RNHI, as a holder of common units. RNHI owns 23,250,000 common units, representing 59.9% of our outstanding common units, and would receive a pro rata percentage of the cash available for distribution that we distribute in respect thereof.
Payments to our general partner and its affiliates	•	We will reimburse our general partner and its affiliates for all expenses incurred on our behalf. In addition we will reimburse Rentech for certain operating expenses and for the provision of various general and administrative services for our benefit under the services agreement.

Liquidation Stage

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

Our Agreements with Rentech

At the closing of our initial public offering, we, our general partner and Rentech entered into the following agreements which govern the business relations among us, our general partner and Rentech. These agreements were not the result of arm’s-length negotiations and the terms of these agreements are not necessarily at least as favorable to each party to these agreements as terms which could have been obtained from unaffiliated third parties.

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Omnibus Agreement

At the closing of our initial public offering, we entered into an omnibus agreement with our general partner and Rentech. Under the omnibus agreement, Rentech has agreed to indemnify us for:

• environmental liabilities of REMC (excluding environmental liabilities relating to the potential removal of asbestos at our East Dubuque Facility in an amount not to exceed $325,000) to the extent arising out of the ownership or operation of REMC prior to the closing of our initial public offering and that are asserted during the period ending on the third anniversary of the closing of our initial public offering;

• liabilities relating to REMC (excluding environmental liabilities, pre-closing income tax liabilities, liabilities reflected on the balance sheet of REMC as of June 30, 2011 and liabilities that have arisen since June 30, 2011 in the ordinary course of business) to the extent arising out of the ownership or operation of REMC prior to the closing of our initial public offering and that are asserted during the period ending on the seventh anniversary of the closing of our initial public offering;

• pre-closing income tax liabilities that are asserted during the period ending on the 30th day after the expiration of the applicable statute of limitations;

• our failure, as of the closing of our initial public offering, to be the owner of valid and indefeasible easement rights, contractual rights, leasehold interests and/or fee ownership interests in and to the lands on which our East Dubuque Facility or our ammonia storage space in Niota, Illinois are located, and if such failure renders us liable to a third party or unable to use our East Dubuque Facility or such ammonia storage space in substantially the same manner they were used and operated immediately prior to the closing of our initial public offering, which failure(s) are identified prior to the fifth anniversary of the closing of our initial public offering; and

• events and conditions associated with any assets retained by Rentech.

Rentech’s obligation to indemnify us for liabilities described in the first two bullets above will be subject to (i) a $250,000 aggregate annual deductible; and (ii) a $10.0 million aggregate cap. In addition, Rentech is not obligated to indemnify us for liabilities satisfied through the use of net operating loss carry-forwards in accordance with the terms of our management services agreement with Rentech.

We have agreed to indemnify Rentech and any of its direct or indirect subsidiaries (excluding us and any of our direct or indirect subsidiaries) for:

• liabilities of REMC (excluding post-closing income tax liabilities) to the extent arising out of the ownership or operation of REMC on or after the closing of our initial public offering;

• post-closing income tax liabilities (excluding pre-closing income tax liabilities and income tax liabilities attributable to Rentech’s indirect ownership of REMC through its ownership in us after the closing of our initial public offering) that are asserted during the period ending on the 30th day after the expiration of the applicable statute of limitations;

• environmental liabilities relating to the potential removal of asbestos at our East Dubuque Facility in an amount not to exceed $325,000;

• any liabilities (excluding environmental liabilities and pre-closing income tax liabilities) to the extent reflected on the balance sheet of REMC as of June 30, 2011; and

• any liabilities (excluding environmental liabilities and pre-closing income tax liabilities) that have arisen since June 30, 2011 in the ordinary course of business.

Our obligation to indemnify Rentech for liabilities described in the first bullet above will be subject to (i) a $250,000 aggregate annual deductible and (ii) a $10.0 million aggregate cap.

Subject to the terms and conditions of the omnibus agreement, Rentech and its affiliates granted us and our general partner a royalty-free, worldwide, non-exclusive, non-sublicensable and non-transferable (without the prior written consent of Rentech) right and license to use the Rentech corporate logo and the Rentech name.

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Services Agreement

At the closing of our initial public offering, we, our general partner and Rentech entered into a services agreement, pursuant to which we, our general partner and our operating subsidiaries obtain certain management and other services from Rentech. Under this agreement, our general partner have engaged Rentech to provide certain administrative services to us. Rentech provides us with the following services under the agreement, among others:

• services from certain of Rentech’s employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement shall serve us on a shared, part-time basis only, unless we and Rentech agree otherwise;

• administrative and professional services, including legal, accounting services, human resources, information technology, insurance, tax, credit, finance, payroll, investor and public relations, communications, government affairs and regulatory affairs;

• recommendations on capital raising activities to the board of directors of our general partner, including the issuance of debt or equity securities, the entry into credit facilities and other capital market transactions;

• managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for us, and providing safety and environmental advice;

• recommendations regarding the declaration and payment of cash distributions; and

• managing or providing advice for other projects, including acquisitions, as may be agreed by Rentech and our general partner from time to time.

As payment for services provided under the agreement, we, our general partner, and our operating subsidiaries, are obligated to reimburse Rentech for (i) all costs, if any, incurred by Rentech or its affiliates in connection with the employment of its employees who are seconded to us and who provide us services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by Rentech or its affiliates in connection with the employment of its employees, excluding the seconded personnel, who provide us services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by Rentech on a commercially reasonable basis, based on the estimated percent of total working time that such personnel are engaged in performing services for us; (iii) a prorated share of certain administrative costs in accordance with the terms of the agreement, including office costs, services by outside vendors (including employee compensation and benefit plan services), other general and administrative costs; (iv) any costs, expenses and claims related to employee benefits provided to employees of our general partner, us or our operating subsidiaries that have been paid by Rentech, but excluding share-based compensation; and (v) any taxes (other than income taxes, gross receipt taxes and similar taxes) incurred by Rentech or its affiliates for the services provided under the agreement. We are required to pay Rentech within 30 days for invoices it submits to us under the agreement.

We, our general partner and our operating subsidiaries are not required to pay any salaries, bonuses or benefits directly to any of Rentech’s employees who provide services to us on a full-time or part-time basis; Rentech will continue to be responsible for their compensation. We expect that personnel performing the actual day-to-day business and operations at our facilities will be employed directly by our general partner, and we will bear all salaries, bonuses, employee benefits and other personnel costs for these employees.

Either Rentech or our general partner may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days’ notice unless such notice is waived in writing by our general partner. At any time, Rentech may temporarily or permanently exclude any employee of Rentech or its affiliates from providing the services under the agreement. Rentech also has the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of its affiliates or any other person or entity, though such delegation will not relieve Rentech from its obligations under the agreement. Either Rentech or our general partner has the right to terminate the agreement upon at least 180 days’ notice, but not more than one year’s notice. Furthermore, our general partner will have the right to terminate the agreement immediately if Rentech becomes bankrupt, or dissolves and commences liquidation or winding-up.

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In order to facilitate the carrying out of services under the agreement, we, on the one hand, and Rentech and its affiliates, on the other, have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances. However, Rentech did not grant any right to license its alternative energy technology under the agreement.

The agreement also contains an indemnity provision whereby we, our general partner and our operating subsidiaries, as indemnifying parties, have agreed to indemnify Rentech and its affiliates (other than the indemnifying parties themselves) against losses and liabilities incurred in connection with the performance of services under the agreement or any breach of the agreement, unless such losses or liabilities arise from a breach of the agreement by Rentech or other misconduct on its part, as provided in the agreement. The agreement also contains a provision stating that Rentech is an independent contractor under the agreement and nothing in the agreement may be construed to impose an implied or express fiduciary duty owed by Rentech, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of loss of profits or revenue, or special, incidental, exemplary, punitive or consequential damages from Rentech or certain affiliates.

Indemnification Agreements

At the closing of our initial public offering, we entered into indemnification agreements with each of the directors and executive officers of our general partner. These agreements provide indemnification to these directors and executive officers under certain circumstances for acts or omissions which may not be covered by directors’ and officers’ liability insurance.

Procedures for Review; Approval and Ratification of Related Person Transactions

The board of directors of our general partner adopted a Code of Business Conduct and Ethics in connection with the closing of our initial public offering that provides that the independent members of the board of directors of our general partner or an authorized independent committee of the board of directors periodically will review all transactions with a related person that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the independent members of the board of directors of our general partner or the authorized independent committee considers ratification of a transaction with a related person and determines not to so ratify, the Code of Business Conduct and Ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

The Code of Business Conduct and Ethics provides that, in determining whether or not to recommend the initial approval or ratification of a transaction with a related person, the independent members of the board of directors of our general partner or the authorized independent committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the Code of Business Conduct and Ethics.

The Code of Business Conduct and Ethics described above was adopted in connection with the closing of our initial public offering, and as a result the transactions described above were not reviewed under such policy.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The charter of the audit committee of the board of directors of our general partner, which is available on our website at www.rentechnitrogen.com, requires the audit committee to pre-approve all audit services and non-audit services (other than de minimis non-audit services as defined by the Sarbanes-Oxley Act of 2002) to be provided by our independent registered public accounting firm. The audit committee pre-approved all fees incurred in the calendar year ended December 31, 2012, the three months ended December 31, 2011 and fiscal year 2011.

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The following table presents fees billed and expected to be billed for audit fees, audit-related fees, tax fees and other services rendered by PricewaterhouseCoopers LLC for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and fiscal year 2011.

	Calendar Year Ended December 31, 2012		Three Months  Ended December 31, 2011		Fiscal Year 2011
Audit Fees (1)	$	794,500	$	400,000	$	1,516,918
Audit-Related Fees (2)		21,710		—		—
Tax Fees (3)		44,663		179,944		—
All Other Fees		—		—		—
Total	$	860,873	$	579,944	$	1,516,918

(1) Represents the aggregate fees billed and expected to be billed for professional services rendered for the audit of RNP’s financial statements for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and fiscal year ended September 30, 2011, assistance with Securities Act filings and related matters, consents issued in connection with Securities Act filings, and consultations on financial accounting and reporting standards arising during the course of the audit for the calendar year ended December 31, 2012, the three months ended December 31, 2011 and fiscal year 2011. Also includes RNP’s portion of aggregate fees billed and expected to be billed to Rentech for its consolidated financial statements for the fiscal year end September 30, 2011, and for the audit of Rentech’s internal control over financial reporting and for reviews of the consolidated financial statements included in Rentech’s quarterly reports on Form 10-Q.

(2) Represents fees billed for assurance and related services that are reasonably related to the performance of the audit or review of RNP’s financial statements, and are not reported as Audit Fees.

(3) Represents tax consultation regarding various issues including our structure.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) and (2) Financial Statements and Schedules.

The information required by this Item is included in Part II—Item 8 “Financial Statements and Supplementary Data” of this report.

(b) Exhibits.

See Exhibit Index starting on page 160.

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EXHIBIT INDEX

2.1*	Membership Interest Purchase Agreement between Rentech Nitrogen Partners, L.P. and Agrifos Holdings Inc., dated as of October 31, 2012 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by the Registrant on November 5, 2012).
3.1	Certificate of Limited Partnership of Rentech Nitrogen Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Form S-1 filed by the Registrant on August 5, 2011).
3.2	Third Amended and Restated Agreement of Limited Partnership of Rentech Nitrogen Partners, L.P., dated as of November 1, 2012 (including form of common unit certificate) (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by the Registrant on November 5, 2012).
3.3	Certificate of Formation of Rentech Nitrogen GP, LLC (incorporated by reference to Exhibit 3.3 to the Form S-1 filed by the Registrant on August 5, 2011).
3.4	Second Amended and Restated Limited Liability Company Agreement of Rentech Nitrogen GP, LLC, dated November 9, 2011 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by the Registrant on November 9, 2011).
10.1	Distribution Agreement, dated April 26, 2006, between Royster-Clark Resources LLC and Rentech Development Corporation (incorporated by reference to Exhibit 10.1 to the Form S-1 filed by the Registrant on August 5, 2011).
10.2	Amendment to Distribution Agreement, dated October 13, 2009, among Rentech Energy Midwest Corporation, Rentech Development Corporation and Agrium U.S.A., Inc. (incorporated by reference to Exhibit 10.2 to the Form S-1 filed by the Registrant on August 5, 2011).
10.3	Assignment and Assumption Agreement, dated as of September 29, 2006, by and between Royster-Clark, Inc., Agrium U.S.A., Inc., and Rentech Development Corporation (incorporated by reference to Exhibit 10.3 to the Form S-1 filed by the Registrant on August 5, 2011).
10.4	Credit Agreement, dated June 10, 2011, by and among Rentech Energy Midwest Corporation, as the borrower, Rentech, Inc., the lenders party thereto, Credit Suisse AG, Cayman Islands Branch, individually and as Administrative Agent and Collateral Agent and Credit Suisse Securities (USA) LLC as Sole Bookrunner, Sole Syndication Agent and Sole Lead Arranger (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-15795) filed by Rentech, Inc. on June 14, 2011).
10.5	Guarantee and Collateral Agreement, dated June 10, 2011, by and among Rentech Energy Midwest Corporation, Rentech, Inc., the subsidiaries of Rentech, Inc. listed therein and Credit Suisse AG, Cayman Islands Branch, as Collateral Agent (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-15795) filed by Rentech, Inc. on June 14, 2011).
10.6	Real Estate Mortgage, Assignment of Rents, Security Agreement and UCC Fixture Filing, dated June 10, 2011, by and among Rentech Energy Midwest Corporation, Rentech, Inc. and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K (File No. 001-15795) filed by Rentech, Inc. on June 14, 2011).
10.7	Agreement, dated November 1, 2010, between Northern Illinois Gas Company, d/b/a Nicor Gas Company and Rentech Energy Midwest (incorporated by reference to Exhibit 10.14 to the Form S-1 filed by the Registrant on August 5, 2011).
10.8	Services Agreement, dated as of November 9, 2011, by and among Rentech Nitrogen Partners, L.P., Rentech Nitrogen GP, LLC and Rentech, Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by the Registrant on November 9, 2011).
10.9	Contribution, Conveyance and Assignment Agreement, dated as of November 9, 2011, by and among Rentech, Inc., Rentech Development Corporation, Rentech Nitrogen Holdings, Inc., Rentech Nitrogen GP, LLC, Rentech Nitrogen Partners, L.P. and Rentech Energy Midwest Corporation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Registrant on November 9, 2011).

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10.10	Omnibus Agreement, dated as of November 9, 2011, by and among Rentech, Inc., Rentech Nitrogen GP, LLC and Rentech Nitrogen Partners, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Registrant on November 9, 2011).
10.11†	Amended and Restated Employment Agreement by and between Rentech, Inc. and D. Hunt Ramsbottom, dated December 31, 2008 (incorporated by reference to Exhibit 10.43 to Amendment No. 1 to Annual Report on Form 10-K/A (File No. 001-15795) filed by Rentech, Inc. on January 28, 2009).
10.12†	Employment Agreement by and between Rentech, Inc. and Daniel J. Cohrs, dated October 22, 2008 (incorporated by reference to Exhibit 10.21 to Annual Report on Form 10-K for the fiscal year ended September 30, 2008 (File No. 001-15795) filed by Rentech, Inc. on December 15, 2008).
10.13†	Employment Agreement by and between Rentech, Inc. and John H. Diesch, dated November 3, 2009 (incorporated by reference to Exhibit 10.20 to the Form S-1 filed by the Registrant on August 5, 2011).
10.14†	Change in Control Severance Benefits Agreement by and between Rentech Energy Midwest Corporation and John A. Ambrose, dated August 1, 2010 (incorporated by reference to Exhibit 10.21 to the Form S-1 filed by the Registrant on August 5, 2011).
10.15†	Change in Control Severance Benefits Agreement by and between Rentech Energy Midwest Corporation and Wilfred R. Bahl, Jr., dated May 10, 2011 (incorporated by reference to Exhibit 10.22 to the Form S-1 filed by the Registrant on August 5, 2011).
10.16†	Change in Control Severance Benefits Agreement by and between Rentech Energy Midwest Corporation and Marc E. Wallis, dated August 12, 2008 (incorporated by reference to Exhibit 10.23 to the Form S-1 filed by the Registrant on August 5, 2011).
10.17†	Amended and Restated Rentech, Inc. 2006 Incentive Award Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-15795) filed by Rentech, Inc. on March 29, 2007).
10.18†	First Amendment to Rentech, Inc. Amended and Restated 2006 Incentive Award Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-15795) filed by Rentech, Inc. on November 6, 2009).
10.19†	Rentech, Inc. 2009 Incentive Award Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-15795) filed by Rentech, Inc. on May 22, 2009).
10.20†	First Amendment to Rentech, Inc. 2009 Incentive Award Plan (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-15795) filed by Rentech, Inc. on November 6, 2009).
10.21†	Employment Agreement, dated as of November 3, 2009 by and between Rentech, Inc. and Colin Morris (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by Rentech, Inc. on November 6, 2009).
10.22†	Employment Agreement, dated as of October 15, 2011 by and between Rentech Nitrogen GP, LLC and John A. Ambrose (incorporated by reference to Exhibit 10.31 to the Form S-1 filed by the Registrant on October 20, 2011).
10.23†	Employment Agreement, dated as of October 15, 2011 by and between Rentech Nitrogen GP, LLC and Wilfred R. Bahl, Jr. (incorporated by reference to Exhibit 10.32 to the Form S-1 filed by the Registrant on October 20, 2011).
10.24†	Employment Agreement, dated as of October 16, 2011 by and between Rentech Nitrogen GP, LLC and Marc E. Wallis (incorporated by reference to Exhibit 10.33 to Form S-1 filed by the Registrant on October 20, 2011).
10.25	Credit Agreement, dated as of November 10, 2011, among Rentech Nitrogen, LLC, as borrower, Rentech Nitrogen Partners, L.P., as guarantor, General Electric Capital Corporation, as administrative agent, and the other lender parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Registrant on November 15, 2011).
10.26	Guaranty and Security Agreement, dated as of November 10, 2011, among Rentech Nitrogen, LLC, as borrower, Rentech Nitrogen Partners, L.P., as guarantor and General Electric Capital Corporation, as administrative agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Registrant on November 15, 2011).

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10.27	Indemnification Agreement dated November 9, 2011, by and between Rentech Nitrogen Partners, L.P. and D. Hunt Ramsbottom (all other Indemnification Agreements, which are substantially identical in all material respects, except as to the parties thereto and the dates of execution, are omitted pursuant to Instruction 2 to Item 601 of Regulation S-K) (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K filed by the Registrant on December 14, 2012).
10.28	Credit Agreement, dated as of December 28, 2011, among Rentech Nitrogen, LLC, as borrower, Rentech Nitrogen Partners, L.P., as guarantor, and Rentech, Inc. as Lender (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Registrant on January 4, 2012).
10.29	First Amendment to Credit Agreement, dated as of December 28, 2011 among Rentech Nitrogen, LLC, as borrower, Rentech Nitrogen Partners, L.P., as guarantor and General Electric Capital Corporation, as administrative agent for the Lender and as a Lender (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Registrant on January 4, 2012).
10.30	Amended and Restated Credit Agreement, dated as of February 28, 2012 among Rentech Nitrogen, LLC, as borrower, Rentech Nitrogen Partners, L.P., as guarantor, General Electric Capital Corporation, as administrative agent and bookrunner, BMO Harris Bank, N.A., as syndication agent, and the other lender parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Registrant on March 2, 2012).
10.31	Second Amended and Restated Credit Agreement, dated as of October 31, 2012, by and among Rentech Nitrogen, LLC, Agrifos LLC, Agrifos Fertilizer L.L.C. and Agrifos SPA LLC, as borrowers, Rentech Nitrogen Partners, L.P., as guarantor, General Electric Capital Corporation, as administrative agent and swingline lender, GE Capital Markets, Inc. as sole lead arranger and bookrunner, BMO Harris Bank, N.A., as syndication agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Registrant on November 5, 2012).
10.32**	First Amendment to Second Amended and Restated Credit Agreement, dated as of November 30, 2012, by and among Rentech Nitrogen, LLC, Rentech Nitrogen Pasadena Holdings, LLC (formerly known as Agrifos LLC), Rentech Nitrogen Pasadena, LLC (formerly known as Agrifos Fertilizer L.L.C.) and Rentech Nitrogen Pasadena SPA, LLC (formerly known as Agrifos SPA LLC), as borrowers, Rentech Nitrogen Partners, L.P., as guarantor, General Electric Capital Corporation, as administrative agent and swingline lender, GE Capital Markets, Inc. as sole lead arranger and bookrunner, BMO Harris Bank, N.A., as syndication agent, and the lenders party thereto.
10.33**	Second Amendment to Second Amended and Restated Credit Agreement, dated as of December 30, 2012, by and among Rentech Nitrogen, LLC, Rentech Nitrogen Pasadena Holdings, LLC (formerly known as Agrifos LLC), Rentech Nitrogen Pasadena, LLC (formerly known as Agrifos Fertilizer L.L.C.) and Rentech Nitrogen Pasadena SPA, LLC (formerly known as Agrifos SPA LLC), as borrowers, Rentech Nitrogen Partners, L.P., as guarantor, General Electric Capital Corporation, as administrative agent and swingline lender, GE Capital Markets, Inc. as sole lead arranger and bookrunner, BMO Harris Bank, N.A., as syndication agent, and the lenders party thereto.
10.34**	Third Amendment to Second Amended and Restated Credit Agreement, dated as of January 18, 2013, by and among Rentech Nitrogen, LLC, Rentech Nitrogen Pasadena Holdings, LLC (formerly known as Agrifos LLC), Rentech Nitrogen Pasadena, LLC (formerly known as Agrifos Fertilizer L.L.C.) and Rentech Nitrogen Pasadena SPA, LLC (formerly known as Agrifos SPA LLC), as borrowers, Rentech Nitrogen Partners, L.P., as guarantor, General Electric Capital Corporation, as administrative agent and swingline lender, GE Capital Markets, Inc. as sole lead arranger and bookrunner, BMO Harris Bank, N.A., as syndication agent, and the lenders party thereto.
10.35**	Asset Purchase Agreement, dated as of September 10, 1998, by and between ExxonMobil Corporation (formerly known as Mobil Oil Corporation) and Rentech Nitrogen Pasadena, LLC (formerly known as Agrifos Fertilizer L.P.).
10.36**+	Marketing Agreement, dated as of March 22, 2011, by and between Interoceanic Corporation and Rentech Nitrogen Pasadena, LLC (Agrifos Fertilizer L.L.C.).
21.1**	List of Subsidiaries of Rentech Nitrogen Partners, L.P.
23.1**	Consent of Independent Registered Public Accounting Firm.
31.1**	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a).

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31.2**	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a).
32.1**	Certification of Registrant’s Chief Executive Officer pursuant to 18 U.S.C. Section 1350. This certification is being furnished solely to accompany this Annual Report on Form 10-K and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company.
32.2**	Certification of Registrant’s Chief Financial Officer pursuant to 18 U.S.C. Section 1350. This certification is being furnished solely to accompany this Annual Report on Form 10-K and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company.
101	The following financial information from the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012 formatted in Extensible Business Reporting Language (“XBRL”) includes: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements, detailed tagged.

* Schedules and exhibits have been omitted from this Exhibit pursuant to Item 601(b)(2) of Regulation S-K and are not filed herewith. The Partnership agrees to furnish supplementally a copy of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.

** Included with this filing.

† Management contract or compensatory plan or arrangement.

+ Certain portions of this Exhibit have been omitted and filed separately under an application for confidential treatment.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

RENTECH NITROGEN PARTNERS, L.P.

BY: RENTECH NITROGEN GP, LLC, ITS GENERAL PARTNER

/s/ D. Hunt Ramsbottom

D. Hunt Ramsbottom,

Chief Executive Officer

Date: March 18, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/S/ D. HUNT RAMSBOTTOM D. Hunt Ramsbottom	Chief Executive Officer and Director of Rentech Nitrogen GP, LLC (Principal Executive Officer)	March 18, 2013
/S/ DAN J. COHRS Dan J. Cohrs	Chief Financial Officer of Rentech Nitrogen GP, LLC (Principal Financial Officer)	March 18, 2013
/S/ JEFFREY R. SPAIN Jeffrey R. Spain	Senior Vice President and Treasurer of Rentech Nitrogen GP, LLC (Principal Accounting Officer)	March 18, 2013
/S/ JOHN H. DIESCH John H. Diesch	President and Director of Rentech Nitrogen GP, LLC	March 18, 2013
/S/ HALBERT S. WASHBURN Halbert S. Washburn	Director of Rentech Nitrogen GP, LLC	March 18, 2013
/S/ MICHAEL S. BURKE Michael S. Burke	Director of Rentech Nitrogen GP, LLC	March 18, 2013
/S/ JAMES F. DIETZ James F. Dietz	Director of Rentech Nitrogen GP, LLC	March 18, 2013
/S/ KEITH B. FORMAN Keith B. Forman	Director of Rentech Nitrogen GP, LLC	March 18, 2013
/S/ MICHAEL F. RAY Michael F. Ray	Director of Rentech Nitrogen GP, LLC	March 18, 2013

164