UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarter ended June 30, 2009

OR

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

For the transition period from                      to                     

Commission file number 033-43007

TERRA NITROGEN COMPANY, L.P.

(Exact name of registrant as specified in its charter)

Delaware	73-1389684
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

Terra Centre
PO Box 6000
600 Fourth Street
Sioux City, Iowa	51102-6000
(Address of principal executive office)	(Zip Code)

Registrant’s telephone number, including area code: (712) 277-1340

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. þ Yes o 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. þ Yes o No

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 o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

At the close of business on July 24, 2009 there were 18,501,576 Common Units.

TABLE OF CONTENTS

Part I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets	3
Consolidated Statements of Operations	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Partners’ Capital	6
Notes to Consolidated Financial Statements	7
Item 2. Management Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures about Market Risk	29
Item 4. Controls and Procedures	29
Part II — OTHER INFORMATION
Item 1. Legal Proceedings	31
Item 1A. Risk Factors	31
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3. Defaults upon Senior Securities	31
Item 4. Submission of Matters to a Vote of Security Holders	31
Item 5. Other Information	31
Item 6. Exhibits	32
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TERRA NITROGEN COMPANY, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)

	June 30,			December 31,			June 30,
	2009			2008			2008
ASSETS
Current assets:
Cash and cash equivalents	$	95,183		$	154,681		$	161,320
Demand deposits with affiliate		3,765			—			2,639
Accounts receivable, less allowance for doubtful accounts of $760, $0 and $0		26,550			38,053			50,700
Inventories, net		29,357			57,207			36,960
Prepaid expenses and other current assets		4,134			11,815			42,505
Total current assets		158,989			261,756			294,124
Property, plant and equipment, net		71,410			68,208			70,374
Other assets		7,907			11,442			15,471
Total assets	$	238,306		$	341,406		$	379,969
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	16,054		$	24,844		$	47,216
Customer prepayments		12,890			45,067			41,471
Derivative hedge liabilities		2,350			43,315			5,503
Total current liabilities		31,294			113,226			94,190
Other long-term liabilities		632			871			1,220
Total liabilities		31,926			114,097			95,410
Partners’ capital:
Limited partners’ interests, 18,502 Common Units authorized and outstanding		189,544			217,894			208,002
Limited partners’ interests, 184 Class B Common Units authorized and outstanding		532			1,024			969
General partners’ interest		17,402			39,172			43,353
Accumulated other comprehensive income (loss)		(1,098	)		(30,781	)		32,235
Total partners’ capital		206,380			227,309			284,559
Total liabilities and partners’ capital	$	238,306		$	341,406		$	379,969

See Accompanying Notes to the Consolidated Financial Statements.

3

TERRA NITROGEN COMPANY, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues:
Product revenues	$	142,634		$	256,792		$	307,710		$	431,045
Other		137			(121	)		363			158
Total revenues		142,771			256,671			308,073			431,203
Costs and expenses:
Cost of goods sold		77,982			121,861			194,998			213,832
Gross profit		64,789			134,810			113,075			217,371
Operating expenses		4,125			6,113			9,402			9,637
Income from operations		60,664			128,697			103,673			207,734
Interest expense		(81	)		(82	)		(162	)		(163	)
Interest income		195			1,540			609			4,180
Net income	$	60,778		$	130,155		$	104,120		$	211,751
Allocation of net income:
General Partner	$	22,184		$	54,701		$	37,607		$	62,797
Class B Common Units		593			1,269			1,016			2,065
Common Units		38,001			74,185			65,497			146,889
Net income	$	60,778		$	130,155		$	104,120		$	211,751
Net income per Common Unit	$	2.05		$	4.01		$	3.54		$	7.94

See Accompanying Notes to the Consolidated Financial Statements.

4

TERRA NITROGEN COMPANY, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Six Months Ended
	June 30,
	2009			2008
Operating activities:
Net income	$	104,120		$	211,751
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		8,574			11,530
Non-cash (gain) loss on derivative instruments		287			(4,201	)
Changes in operating assets and liabilities:
Receivables		11,503			(1,065	)
Inventories		27,850			(17,617	)
Accounts payable and customer prepayments		(39,964	)		(104,448	)
Other assets and liabilities		(4,993	)		(2,803	)
Net cash flows from operating activities		107,377			93,147
Investing activities:
Capital expenditures and plant turnaround expenditures		(8,378	)		(4,103	)
Change in demand deposits with affiliate		(3,765	)		(2,639	)
Net cash flows from investing activities		(12,143	)		(6,742	)
Financing activities:
Partnership distributions paid		(154,732	)		(171,225	)
Net cash flows from financing activities		(154,732	)		(171,225	)
Decrease to cash and cash equivalents		(59,498	)		(84,820	)
Cash and cash equivalents at beginning of period		154,681			246,140
Cash and cash equivalents at end of period	$	95,183		$	161,320
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	126		$	127

See Accompanying Notes to the Consolidated Financial Statements.

5

TERRA NITROGEN COMPANY, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except for units)

(unaudited)

										Accumulated
				Class B			General			Other			Total
	Common			Common			Partners’			Comprehensive			Partners’			Comprehensive
(in thousands, except for Units)	Units			Units			Interests			Income (Loss)			Capital			Income
Partners’ capital at January 1, 2009	$	217,894		$	1,024		$	39,172		$	(30,781	)	$	227,309
Net income		65,497			1,016			37,607			—			104,120		$	104,120
Change in fair value of derivatives		—			—			—			29,683			29,683			29,683
Comprehensive income																$	133,803
Distributions		(93,847	)		(1,508	)		(59,377	)		—			(154,732	)
Partners’ capital at June 30, 2009	$	189,544		$	532		$	17,402		$	(1,098	)	$	206,380
Limited partner units issued and outstanding June 30, 2009:
Common Units								18,501,576
Class B Common Units								184,072
Total units outstanding at June 30, 2009								18,685,648

										Accumulated
				Class B			General			Other			Total
	Common			Common			Partners’			Comprehensive			Partners’			Comprehensive
(in thousands, except for Units)	Units			Units			Interests			Income (Loss)			Capital			Income
Partners’ capital at January 1, 2008	$	221,153		$	573		$	(9,928	)	$	(4,699	)	$	207,099
Net income		146,889			2,065			62,797			—			211,751		$	211,751
Change in fair value of derivatives		—			—			—			36,934			36,934			36,934
Comprehensive income																$	248,685
Distributions		(160,040	)		(1,669	)		(9,516	)		—			(171,225	)
Partners’ capital at June 30, 2008	$	208,002		$	969		$	43,353		$	32,235		$	284,559
Limited partner units issued and outstanding June 30, 2008:
Common Units								18,501,576
Class B Common Units								184,072
Total units outstanding at June 30, 2008								18,685,648

See Accompanying Notes to the Consolidated Financial Statements.

6

TERRA NITROGEN COMPANY, L.P.

Notes to Consolidated Financial Statements (Unaudited)

1. Background and Basis of Presentation

Terra Nitrogen Company, L.P. (TNCLP, our, we, or us) is a leading producer and marketer of wholesale nitrogen products made from natural gas. TNCLP and its operating partnership subsidiary, Terra Nitrogen, Limited Partnership (Operating Partnership), are referred to herein, collectively, as the “Partnership”. Our principal products are anhydrous ammonia (ammonia) and urea ammonium nitrate solutions (UAN), which we manufacture at our facility in Verdigris, Oklahoma. We operate in one principal industry segment — Nitrogen Products, which is based upon the guidance provided in Statement of Financial Accounting Standards (SFAS) 131, Disclosures about Segments of an Enterprise and Related Information (SFAS 131). As a wholesale nitrogen producer, we do not report industry segments in a separate disclosure because our only reportable industry segment is nitrogen.

The accompanying unaudited consolidated financial statements and notes thereto have been prepared in accordance with the requirements of the U.S. Securities and Exchange Commission (SEC) for interim reporting. They do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. Therefore, these financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended December 31, 2008, included in our 2008 Annual Report on Form 10-K.

Our significant accounting policies are described in the notes to consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2008. Management is responsible for the unaudited consolidated financial statements included in this document. The consolidated financial statements included in this document are unaudited; however, they contain all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods presented.

Because of the seasonal nature of our operations and effects of weather-related conditions in several of its marketing areas, results of any interim reporting period should not be considered as indicative of results for future quarters or the full year.

2. New Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141R, Business Combinations (SFAS 141R), which changes the way we account for business acquisitions. SFAS 141R requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction and establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed in a business combination. Certain provisions of SFAS 141R will, among other things, impact the determination of acquisition-date fair value of consideration paid in a business combination (including contingent consideration); exclude transaction costs from acquisition accounting; and change accounting practices for acquired contingencies, acquisition-related restructuring costs, in-process research and development, indemnification assets, and tax benefits. SFAS 141R became effective for the Partnership on January 1, 2009 and the adoption did not have an impact on our financial statements.

7

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161). SFAS 161 is an amendment of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). To address concerns that the existing disclosure requirements of SFAS 133 do not provide adequate information, SFAS 161 requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. SFAS 161 became effective for the Partnership on January 1, 2009 and we have included the additional disclosure information required by SFAS 161 within Note 6, Derivative Financial Instruments, of the Notes to the Consolidated Financial Statements.

The FASB has issued Draft Abstract Emerging Issues Task Force (EITF) Issue 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (EITF 07-4). EITF 07-4 specifies the treatment of earnings per unit calculations when incentive distribution rights exist. EITF 07-4 became effective for the Partnership on January 1, 2009 and did not have an impact on our financial statements.

In April 2009, the FASB issued FASB Staff Position (FSP) FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identify Transactions That Are Not Orderly (FSP FAS 157-4), which provides additional guidance in accordance with FASB Statement No. 157, Fair Value Measurements, when the volume and level of activity for the asset or liability has significantly decreased. FSP FAS 157-4 became effective for the Partnership on April 1, 2009 and the adoption did not have an impact on our financial statements.

In April 2009, the FASB issued FASB Staff Position FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2). This FSP amends the other-than-temporary impairment guidance in U.S. generally accepted accounting principles (U.S. GAAP) for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in a company’s financial statements. This FSP does not amend the existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP FAS 115-2 and FAS 124-2 became effective for the Partnership on April 1, 2009 and the adoption did not have an impact on our financial statements.

In April 2009, the FASB issued FASB Staff Position FSP 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and APB 28-1). FSP FAS 107-1 and APB 28-1 enhance consistency in financial reporting by increasing the frequency of fair value disclosures. This FSP relates to fair value disclosures for any financial instruments that are not currently reflected in a company’s balance sheet at fair value. Prior to the effective date of this FSP, fair values for these assets and liabilities were only been disclosed once a year. This FSP will now require these disclosures to be made on a quarterly basis, providing qualitative and quantitative information about fair value estimates for all those financial instruments not measured on the balance sheet at fair value. FSP FAS 107-1 and APB 28-1 became effective for the Partnership on April 1, 2009 and we have included the additional information required by FSP FAS 107-1 and APB 28-1 within Note 7, Fair Value Measurements, of the Notes to the Consolidated Financial Statements.

8

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (SFAS 165), to be effective for interim or annual financial periods ending after June 15, 2009. SFAS 165 does not materially change the existing guidance but introduces the concept of financial statements being “available to be issued”. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. This disclosure is intended to alert all users of financial statements that an entity has not evaluated subsequent events after that date in the set of financial statements being presented. SFAS 165 became effective for the Partnership on April 1, 2009 and the adoption did not have an impact on our financial statements. We have evaluated subsequent events through July 24, 2009, which is the date of our Form 10-Q filing.

In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets (SFAS 166), which amends the derecognition guidance in SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (SFAS 140). SFAS 166 addresses concerns expressed by the SEC, members of Congress, and financial statement users about the accounting and disclosures required by SFAS 140 in the wake of the subprime mortgage crisis and the deterioration of the global credit markets. This guidance is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009. We are currently assessing the impact SFAS 166 will have on our financial statements.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R) (SFAS 167), which amends the consolidation guidance applicable to variable interest entities under FASB Interpretation No. 46 (R), Consolidation of Variable Interest Entities. SFAS 167 is intended to improve financial reporting by enterprises involved with variable interest entities. This guidance is effective as of the beginning of the first fiscal year that begins after November 15, 2009. We are currently assessing the impact SFAS 167 will have on our financial statements.

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (SFAS 168), which amends SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS 168 will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. On the effective date, SFAS 168 will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in SFAS 168 will become nonauthoritative. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We are currently assessing the impact SFAS 168 will have on our financial statements.

9

3. Agreement of Limited Partnership

We make quarterly distributions to our partners based on Available Cash (as defined in our Agreement of Limited Partnership) for the quarter. Available Cash is defined generally as all cash receipts less all cash disbursements, adjusted for changes in certain reserves established as Terra Nitrogen GP Inc. (the General Partner) determines in its reasonable discretion to be necessary. We paid distributions of $154.7 million to our partners in the first six months of 2009 and $171.2 million for the same period in 2008.

We receive 99% of the Available Cash from the Operating Partnership and 1% is distributed to its general partner (who is also our General Partner). Cash distributions from the Operating Partnership generally represent the Operating Partnership’s Available Cash from operations. Our cash distributions are made 99.975% to Common Unitholders and Class B Common Unitholders and 0.025% to our General Partner except when cumulative distributions of Available Cash exceed specified target levels above the Minimum Quarterly Distributions (“MQD”) of $0.605 per unit. Under such circumstances, our General Partner is entitled, as an incentive, to larger percentage interests.

On July 23, 2009, we announced a $2.22 cash distribution per common limited partnership unit, payable on August 27, 2009 to holders of record as of August 7, 2009. We have exceeded the cumulative MQD amounts and will distribute Available Cash as summarized in the following table:

	Income and Distribution Allocation
								Class B
	Target		Target		Common			Common			General
	Limit		Increment		Units			Units			Partner			Total
Minimum Quarterly Distribution	$	0.605	$	0.605		98.990	%		0.985	%		0.025	%		100.000	%
First Target		0.715		0.110		98.990	%		0.985	%		0.025	%		100.000	%
Second Target		0.825		0.110		85.859	%		0.985	%		13.156	%		100.000	%
Third Target		1.045		0.220		75.758	%		0.985	%		23.257	%		100.000	%
Final Target and Beyond		1.045		—		50.505	%		0.985	%		48.510	%		100.000	%

The General Partner is required to remit the majority of cash distributions it receives from the Partnership, in excess of its 1% Partnership equity interest, to an affiliated company.

At June 30, 2009, the General Partner and its affiliates owned 75.3% of our outstanding units. When not more than 25% of our issued and outstanding units are held by non-affiliates of the General Partner, we, at the General Partner’s sole discretion, may call, or assign to the General Partner or its affiliates, our right to acquire all such outstanding units held by non-affiliated persons. If the General Partner elects to acquire all outstanding units, we are required to give at least 30 but not more than 60 days’ notice of our decision to purchase the outstanding units. The purchase price per unit will be the greater of (1) the average of the previous 20 trading days’ closing prices as of the date five days before the purchase is announced and (2) the highest price paid by the General Partner or any of its affiliates for any unit within the 90 days preceding the date the purchase is announced. Additional purchases of common units by the General Partner may be restricted under the terms of Terra Industries Inc.’s bank credit agreement as described therein.

10

4. Net Income per Common Unit

Basic and diluted income per Common Unit is based on the weighted-average number of Common Units outstanding during the period. The following table provides a reconciliation for basic and diluted income per Common Unit for the three and six month periods ended June 30, 2009 and 2008:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands, except per-unit amounts)	2009			2008			2009			2008
Basic income per Common Unit:
Net income	$	60,778		$	130,155		$	104,120		$	211,751
Less: Net income allocable to Class B Common Units		(593	)		(1,269	)		(1,016	)		(2,065	)
Less: Net income allocable to General Partner		(22,184	)		(54,701	)		(37,607	)		(62,797	)
Net income allocable to Common Units		38,001			74,185			65,497			146,889
Weighted average units outstanding		18,502			18,502			18,502			18,502
Net income per Common Unit	$	2.05		$	4.01		$	3.54		$	7.94

There were no dilutive Common Units outstanding for the three and six month periods ended June 30, 2009 and 2008.

5.	Inventories, net
	Inventories consisted of the following:

	June 30,		December 31,		June 30,
(in thousands)	2009		2008		2008
Materials and supplies	$	9,464	$	10,708	$	9,038
Finished goods		19,893		46,499		27,922
Total	$	29,357	$	57,207	$	36,960

Production costs include the cost of direct labor and materials, depreciation and amortization, and overhead costs related to manufacturing activities. We allocate fixed production overhead costs based on the normal capacity of our production facilities and unallocated overhead costs are recognized as expense in the period incurred. We determine the cost of inventories using the first-in, first-out method.

11

Inventories are stated at the lower of cost or market. Market is defined as current replacement cost, except that market should not exceed the net realizable value and should not be less than net realizable value reduced by an allowance for an approximately normal profit margin. We perform a monthly analysis of our inventory balances to determine if the carrying amount of inventories exceeds our net realizable value. Our determination 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 estimate a reserve for obsolescence and excess of materials and supplies inventory. Inventory is stated net of the reserve.

6. Derivative Financial Instruments

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161). SFAS 161 is an amendment of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). SFAS 161 requires enhanced disclosures of an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. SFAS 161 became effective for the Partnership on January 1, 2009 and we have incorporated the additional disclosure information for SFAS 161 below.

We enter into derivative financial instruments, including swaps, basis swaps, purchased put and call options and sold call options, to manage the effect of changes in natural gas costs and the price of our nitrogen products. We report the fair value of the derivatives on our balance sheet. If the derivative is not designated as a hedging instrument, changes in fair value are recognized in earnings in the period of change. If the derivative is designated as a cash flow hedge, and to the extent such hedge is determined to be effective, changes in fair value are reported as a component of accumulated other comprehensive income (loss) in the period of change, and subsequently recognized in our statement of operations in the period the offsetting hedged transaction occurs. If an instrument or the hedged item is settled early, we evaluate whether the hedged forecasted transaction is still probable of occurring when determining whether to reclassify any gains or losses immediately in cost of sales or wait until the forecasted transaction occurs.

Until our derivatives settle, we test derivatives for ineffectiveness. This includes assessing the correlation of New York Mercantile Exchange (NYMEX) pricing, which is commonly used as an index in natural gas derivatives, to the natural gas pipelines’ pricing at our manufacturing facilities. This assessment requires management judgment to determine the statistically and industry appropriate analysis of prior operating relationships between the NYMEX prices and the natural gas pipelines’ prices at our facilities.

To the extent possible, we base our market value calculations on third party data. Due to multiple types of settlement methods available, not all settlement methods for future period trades are available from third party sources. In the event that a derivative is measured for fair value based on a settlement method that is not readily available, we estimate the fair value based on forward pricing information for similar types of settlement methods.

12

We manage risk using derivative financial instruments for changes in natural gas supply prices and changes in nitrogen prices. Derivative financial instruments have credit risk and market risk.

To manage credit risk, we enter into derivative transactions only with counter-parties who are currently rated as BBB or better or equivalent as recognized by a national rating agency. We will not enter into transactions with a counter-party if the additional transaction will result in credit exposure exceeding $20 million. The credit rating of counter-parties may be modified through guarantees, letters of credit or other credit enhancement vehicles. As of June 30, 2009, we did not have any credit risk related contingent features that would require us to settle the derivative instruments or to post collateral upon the occurrence of a credit event.

We classify a derivative financial instrument as a hedge if all of the following conditions are met:

1.	The item to be hedged must expose us to currency, interest or price risk;
2.	It must be probable that the results of the hedge position substantially offset the effects of currency, interest or price changes on the hedged item (i.e., there is a high correlation between the hedge position and changes in market value of the hedge item); and
3.	The derivative financial instrument must be designated as a hedge of the item at the inception of the hedge.

We purchase natural gas at market prices to meet production requirements at our manufacturing facility. Natural gas market prices are volatile and we effectively hedge a portion of our natural gas production requirements and inventory through the use of swaps and options. These contracts reference physical natural gas prices or approximate NYMEX futures contract prices. Contract physical prices are frequently based on prices at the Henry Hub in Louisiana, the most common and financially liquid location of reference for financial derivatives related to natural gas. However, we purchase natural gas for our manufacturing facility at locations other than Henry Hub, which often creates a location basis differential between the contract price and the physical price of natural gas. Accordingly, the use of financial derivatives may not exactly offset the changes in the price of physical gas. Natural gas derivatives are designated as cash flow hedges, provided that the derivatives meet the conditions discussed above. The contracts are traded in months forward and settlement dates are scheduled to coincide with gas purchases during that future period.

A swap is a contract between us and a third party to exchange cash based on a designated price. Option contracts give the holder the right to either own or sell a futures or swap contract. The option contracts require initial premium payments ranging from 2% to 5% of contract value. Basis swap contracts require payments to or from us for the amount, if any, that monthly published gas prices from the source specified in the contract differ from the prices of a NYMEX natural gas futures during a specified period. There are no initial cash requirements related to the swap and basis swap agreements; however, the counterparties require maintenance of cash margin balances generally 10% to 20% of the contract value.

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As of June 30, 2009 and 2008, we had open derivative contracts for 5.2 million MMBtus and 17.4 million MMBtus, respectively, of natural gas.

The gross fair market value of all derivative instruments and their location in our Consolidated Balance Sheet are shown by those in an asset or liability position and are all categorized as commodity derivatives.

Asset Derivatives (a)
		June 30,		December 31,		June 30,
Derivative Instrument	Location	2009		2008		2008
Commodity Derivatives	Other current assets	$	3,255	$	9,456	$	42,425

Liability Derivatives (a)
		June 30,			December 31,			June 30,
Derivative Instrument	Location	2009			2008			2008
Commodity Derivatives	Derivative hedge liabilities	$	(2,350	)	$	(43,315	)	$	(5,503	)

(a) Amounts are disclosed at gross fair value in accordance with SFAS 161 requirements. All of our commodity derivatives are designated as cash flow hedging instruments under SFAS 133. See footnote 1 and 6 of our 2008 Annual Report Form 10-K for additional information on our overall risk management strategies.

Certain derivatives outstanding at June 30 2009 and 2008, which settled during July 2009 and July 2008, respectively, are included in the position of open natural gas derivatives in the table above. The July 2009 derivatives settled for an approximate $0.7 million loss compared to the July 2008 derivatives which settled for an approximate $7.4 million gain. All material open derivatives at June 30, 2009 will settle during the next 12 months.

At June 30, 2009 and 2008, we determined that a portion of certain derivative contracts were ineffective for accounting purposes and, as a result, recorded a $1.1 million charge and a credit of $4.4 million to cost of sales for the six month periods ending June 30, 2009 and 2008, respectively. At June 30, 2009 and 2008, we excluded a portion of the loss on certain derivative contracts from the effectiveness assessment and, as a result, reported a $0.8 million credit and $0.3 million charge, respectively, to cost of sales.

The effective portion of gains and losses on derivative contracts that qualify for hedge treatment are carried as accumulated other comprehensive income (loss) and credited or charged to cost of sales in the month in which the hedged transaction settles. Gains and losses on the contracts that do not qualify for hedge treatment are credited or charged to cost of sales based on the positions of fair value. The risk and reward of outstanding natural gas positions are directly related to increases or decreases in natural gas prices in relation to the underlying NYMEX natural gas contract prices.

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All of our commodity derivatives are designated as cash flow hedging instruments under SFAS 133. See footnote 1 and 6 of our 2008 Annual Report Form 10-K for additional information on our overall risk management strategies. The following table presents the effect of our commodity derivative instruments on the Consolidated Statement of Operations for the three and six months ended June 30, 2009 and 2008.

Three Months Ended
						Amount of Gain (Loss)
Amount of Gain (Loss)					Location of Gain	Reclassified from AOCI						Amount of Gain (Loss)
Recognized in OCI					(Loss) Reclassified	into Income						Recognized in Income (b)
June 30,			June 30,		from AOCI into	June 30,			June 30,		Location of Gain (Loss)	June 30,			June 30,
2009			2008		Income (a)	2009			2008		Recognized in Income (b)	2009			2008
$	(1,335	)	$	37,528	Cost of Sales	$	(10,596	)	$	19,744	Cost of Sales	$	(287	)	$	4,098

Six Months Ended
						Amount of Gain (Loss)
Amount of Gain (Loss)					Location of Gain	Reclassified from AOCI						Amount of Gain (Loss)
Recognized in OCI					(Loss) Reclassified	into Income						Recognized in Income (b)
June 30,			June 30,		from AOCI into	June 30,			June 30,		Location of Gain (Loss)	June 30,			June 30,
2009			2008		Income (a)	2009			2008		Recognized in Income (b)	2009			2008
$	(14,622	)	$	59,181	Cost of Sales	$	(44,305	)	$	22,247	Cost of Sales	$	(287	)	$	4,098

(a)	Effective portion of gain (loss).
(b)	The amount of gain or (loss) recognized in income represents ($1.1) million and $4.4 million related to the ineffective portion of the hedging relationships and $0.8 million and ($0.3) million related to the amount excluded from the assessment of hedge effectiveness.

Approximately $1.1 million of the net accumulated loss at June 30, 2009 will be reclassified into earnings during the next twelve months as compared to $32.2 million of the net accumulated income at June 30, 2008.

At times, we also use forward derivative instruments, such as nitrogen solution contracts, to fix or set floor prices for a portion of our nitrogen sales volumes. At June 30, 2009, we had open nitrogen solutions contracts. When outstanding, the nitrogen solution contracts do not qualify for hedge treatment due to inadequate trading history to demonstrate effectiveness. Consequently, these contracts are marked-to-market and unrealized gains or losses are reflected in revenue in the statement of operations. For both the three and six month periods ending June 30, 2009, we recognized a gain of $0.1 million respectively, on nitrogen forward derivative instruments. For the three and six month periods ending June 30, 2008, there were no gains or losses on nitrogen forward derivative instruments.

7. Fair Value Measurements

SFAS 157 establishes a three level hierarchal disclosure framework that prioritizes and ranks the level of market price observability used in measuring assets and liabilities at fair value. Market price observability is impacted by a number of factors, including the type of asset or liability and their characteristics. Assets and liabilities with readily available active quoted prices or for which fair value can be measured from actively quoted prices generally will have a higher degree of market price observability and a lesser degree of judgment used in measuring fair value.

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The three levels are defined as follows:

• Level 1 — inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets.

• Level 2 — inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3 — inputs to the valuation methodology are observable and significant to the fair value measurement.

We evaluated our assets and liabilities to determine which items should be disclosed according to SFAS 157. We currently measure our derivative contracts on a recurring basis at fair value. The inputs included in the fair value measurement of our derivative contracts use adjusted quoted prices from an active market, which are classified at level 2, as a significant other observable input in the disclosure hierarchy framework as defined by SFAS 157. The Partnership’s gas derivative contracts, which are classified as a level 2 input, are comprised of swaps, basis swaps and options. The valuation techniques for these contracts are observable market data for inputs, including prices quoted on the New York Mercantile Exchange, prices quoted in spot markets and commonly referenced industry publications and prices quoted by market makers. There have been no changes in valuation techniques during the half ending June 30, 2009.

The following table summarizes the valuation of our assets and liabilities in accordance with SFAS 157 fair value hierarchy levels as of June 30, 2009:

	Quoted Market		Significant Other			Significant
	Prices in Active		Observable			Unobservable
	Markets		Inputs			Inputs
(in thousands)	(Level 1)		(Level 2)			(Level 3)
Assets
Derivative contracts	$	—	$	3,255		$	—
Total	$	—	$	3,255		$	—
Liabilities
Derivative contracts	$	—	$	(2,350	)	$	—
Total	$	—	$	(2,350	)	$	—

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The following table summarizes the valuation of our assets and liabilities in accordance with SFAS 157 fair value hierarchy levels as of December 31, 2008:

	Quoted Market		Significant Other			Significant
	Prices in Active		Observable			Unobservable
	Markets		Inputs			Inputs
(in thousands)	(Level 1)		(Level 2)			(Level 3)
Assets
Derivative contracts	$	—	$	9,456		$	—
Total	$	—	$	9,456		$	—
Liabilities
Derivative contracts	$	—	$	(43,315	)	$	—
Total	$	—	$	(43,315	)	$	—

The following table summarizes the valuation of our assets and liabilities in accordance with SFAS 157 fair value hierarchy levels as of June 30, 2008:

	Quoted Market		Significant Other			Significant
	Prices in Active		Observable			Unobservable
	Markets		Inputs			Inputs
(in thousands)	(Level 1)		(Level 2)			(Level 3)
Assets
Derivative contracts	$	—	$	42,425		$	—
Total	$	—	$	42,425		$	—
Liabilities
Derivative contracts	$	—	$	(5,503	)	$	—
Total	$	—	$	(5,503	)	$	—

Fair values of financial instruments: We use the following methods and assumptions in estimating our fair value disclosures for financial instruments:

• Cash and cash equivalents — The carrying amounts approximate fair value due to the short maturity of these instruments.

• Demand deposits with affiliate — The carrying amounts approximate fair value due to the short maturity of these instruments.

• Financial instruments — Fair values for the Partnership’s natural gas swaps and options are based on contract prices in effect at June 30, 2009 and 2008. The unrealized loss on these contracts is disclosed on Note 6, Derivative Financial Instruments, of the Notes to the Consolidated Financial Statements.

Concentration of credit risk: We are subject to credit risk through trade receivables and short-term investments. Although a substantial portion of our debtors’ ability to pay depends upon the agribusiness economic sector, credit risk with respect to trade receivables is minimized due to a large customer base and our geographic dispersion.

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8. Turnaround Costs

The following represents a summary of the deferred plant turnaround costs for the six months ended June 30, 2009 and 2008:

			Turnaround
	Beginning		Costs		Turnaround			Ending
(in thousands)	Balance		Capitalized		Amortization			Balance
Periods ended:
June 30, 2009	$	5,255	$	389	$	(3,751	)	$	1,893
June 30, 2008	$	16,841	$	116	$	(6,693	)	$	10,264

9. Revolving Credit Facility

We have a $50 million revolving credit facility available that expires January 31, 2012. The revolving credit facility bears interest at a variable rate plus a margin (London Interbank Offer Rate (LIBOR) plus 175 basis points, or 2.07% at June 30, 2009). Under the credit facility, we may borrow an amount generally based on eligible cash balances, 85% of eligible accounts receivable and 60% of eligible finished goods inventory, less outstanding letters of credit. Our borrowings under the credit facility are secured by substantially all of our working capital. The agreement also requires us to adhere to certain limitations on additional debt, capital expenditures, acquisitions, liens, asset sales, investments, prepayments of subordinated indebtedness, changes in lines of business and transactions with affiliates. At June 30, 2009, we had $50 million of borrowing availability and there were no outstanding borrowings or letters of credit under the facility.

10. Unsolicited Exchange Offer

On January 15, 2009, CF Industries Holdings, Inc. (CF) presented a letter to the Board of Directors of Terra Industries Inc. (Terra or Company) proposing CF’s acquisition of Terra in an all-stock transaction. Terra’s Board rejected the proposal on the grounds that it was not in the best interest of Terra or its stockholders and substantially undervalued the Company. CF subsequently announced that they remained committed to the proposal, and on February 3, 2009, announced that they would nominate three director candidates to Terra’s Board of Directors and commence an exchange offer for all of Terra’s outstanding common shares.

On February 23, 2009, CF announced that it had commenced an unsolicited exchange offer to acquire all of the outstanding common shares of Terra at a fixed exchange ratio of 0.4235 CF shares for each Terra common share. In response, Terra’s Board of Directors announced on February 23, 2009 that it would review and consider CF’s exchange offer and make a formal recommendation to shareholders within ten business days, and further advised Terra’s shareholders to take no action pending the review of the proposed exchange offer by Terra’s Board of Directors. On March 3, 2009, Terra’s Board of Directors unanimously concluded that CF’s offer did not present a compelling case to create additional value for the stockholders of either Terra or CF, substantially undervalues Terra on an absolute basis and relative to CF and is not in the best interests of Terra and its stockholders.

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On March 9, 2009, CF sent a letter to Terra’s Board of Directors stating CF would be prepared to enter into a negotiated merger agreement with Terra on the basis of an exchange ratio based on $27.50 for each Terra common share, with an exchange ratio of not less than 0.4129 of a CF common share and not more than 0.4539 of a CF common share. On March 11, 2009, Terra’s Board of Directors unanimously concluded that CF’s proposal continues to run counter to Terra’s strategic objectives, substantially undervalues Terra both absolutely and relative to CF, and would deliver less value to our shareholders than would owning Terra on a stand-alone basis.

On March 23, 2009, CF sent a letter to Terra’s Board of Directors stating CF would be prepared to enter into a negotiated merger agreement with Terra on the basis of an exchange ratio based on $30.50 for each Terra share, with an exchange ratio of not less than 0.4129 of a CF common share and not more than 0.4539 of a CF common share, the same collar as CF’s proposal of March 9, 2009. On March 24, 2009, Terra’s Board of Directors unanimously concluded that CF’s proposal continues to run counter to Terra’s strategic objectives, substantially undervalues Terra both absolutely and relative to CF, and would deliver less value to our shareholders than it would owning Terra on a stand-alone basis.

As of the date of this Form 10-Q, CF’s unsolicited exchange offer to acquire all of the outstanding common shares of Terra is still outstanding and is set to expire on August 7, 2009, unless further extended.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

You should read the following discussion and analysis in conjunction with our Unaudited Condensed Consolidated Financial Statements and the related Notes thereto contained in Part I, Item 1 of this report. The information contained in this Quarterly Report on Form 10-Q is not a complete description of our business or the risks associated with an investment in our common shares. We urge you to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2008 and subsequent reports on Form 8-K, which discuss our business in greater detail.

The section entitled “Risk Factors” contained in Part II, Item 1A of this report, and similar discussions in our other SEC filings, describe some of the important risk factors that may affect our business, financial condition, results of operations and/or liquidity. You should carefully consider those risks, in addition to the other information in this report and in our other filings with the SEC.

Dependence on Terra Industries

We are dependent on Terra Industries Inc. (Terra) in a number of respects. Terra provides all of our management, natural gas purchasing and hedging, selling and administrative services and operates our facilities through its wholly-owned subsidiary Terra Nitrogen GP Inc., the Partnership’s General Partner. Terra and its wholly-owned subsidiaries have more debt and debt service requirements than us. Although Terra is affected by most of the factors that affect us, its higher level of debt could put a greater risk on Terra in the event of adverse business conditions. Our results of operations and financial condition might be materially adversely affected by financial difficulties at Terra, default by it or its subsidiaries on their debt or their bankruptcy. For additional information concerning Terra, refer to Terra’s filings with the Securities and Exchange Commission on Form 10-K, Forms 10-Q and current reports on Forms 8-K.

Introduction

In this discussion and analysis, we explain our business in the following areas:

• Business Strategy;

• Recent Business Environment;

• Results of Operations;

• Liquidity and Capital Resources; and

• Various Quantitative and Qualitative Disclosures.

Business Strategy

We are a leading producer and marketer of wholesale nitrogen products, serving agricultural and industrial markets. The nitrogen products industry has periods of oversupply during industry downturns that lead to capacity shutdowns at the least cost-effective plants. These shutdowns are followed by supply shortages, which result in higher selling prices and higher industry-wide production rates during industry upturns. The higher selling prices encourage capacity additions until we again start to see an oversupply, and the cycle repeats itself.

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To succeed in this business, a producer must have the financial strength to weather industry downturns and the ability to serve its markets cost-effectively during every phase of the cycle. A nitrogen producer will also benefit from having one or more nitrogen products that operate in non-agricultural markets to balance the cyclicality of those markets.

We base our business strategies on these concepts. In practice, this means we:

• Manage our assets to reap the highest returns through the cycle by maintaining our facilities to be safe and reliable, cultivating relationships with natural customers who due to their physical location can receive our product most economically, and closely managing the supply chain to keep storage, transportation and other costs down.

• Develop higher-return product markets, such as that for UAN, our primary nitrogen fertilizer product.

In every case, we invest our capital judiciously to realize a return above the cost of capital over the industry cycle.

Recent Business Environment

The following factors are the key drivers of our profitability: nitrogen products selling prices, as determined primarily by the global nitrogen demand/supply balance, and natural gas costs, particularly in North American markets.

Demand

Short term demand for nitrogen products may remain constrained into the fall as retailers are anticipated to maintain low inventory levels. Dealers appear to be returning to the pre-2007 practice of utilizing all available inventory and clearing on-site material by the end of the planting season. Estimated ending corn stock levels as of the end of the 2009 planting season support an expected strong demand for corn in the spring of 2010. In addition, nitrogen demand is expected to benefit from the enactment of the 2010 Emission Standards of the 1990 Amendments to the Clean Air Act which requires diesel powered vehicles to achieve near-zero emissions of nitrogen oxides on January 1, 2010.

An expected increase in long term demand for nitrogen products is supported by the global grain supply. The ending corn stock ratio for the 2009 planting season was estimated to be 15.8% by the USDA World Agriculture Supply and Demand Estimates (WASDE) June 2009 report, which is the second lowest level in 35 years. Historically, the expected increased corn stock ratio is approximately 30%. Pursuant to its June 2009 report, WASDE expects corn prices for 2009-2010 to increase to $3.90 - $4.70 per bushel, from $4.10 — $4.30 per bushel in 2008-2009. The expected increased demand for corn is supported by the expected increased demand for food, seed and industrial markets, increased ethanol demand and higher expected exports.

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Supply

In an effort to maintain nitrogen inventory at acceptable levels, certain North American production has been curtailed. Imports have declined as a result of the sluggish demand due to poor import economics during the second quarter of 2009, removing 1.2 million tons of nitrogen from the U.S. supply system.

Natural Gas Costs

As a result of the depressed economy, natural gas consumption has declined in the utility and industrial sectors, driving prices below $4 per MMBtu as of June 30, 2009.

The following is an average NYMEX forward natural gas price for the succeeding twelve month period noted for the respective dates:

	June 30,		September 30,		December 31,		March 31,		June 30,
(in $ per MMBtu)	2008		2008		2008		2009		2009
	$	13.22	$	7.90	$	6.09	$	4.69	$	5.09

During the first half of 2009, natural gas prices decreased 61% from June 30, 2008. Generally, as customers place advance orders we secure the prices for the natural gas required to produce the inventory to satisfy these orders.

RESULTS OF OPERATIONS

Consolidated Results

We reported for the first half of 2009 net income of $104.1 million on revenues of $308.1 million, compared with the first half of 2008 net income of $211.8 million on revenues of $431.2 million. The decrease in net income and revenue for the first half of 2009 is due to lower ammonia and UAN sales volumes and sales prices. Net income per Common Unit for the six months ended June 30, 2009 was $3.54 compared with $7.94 for the six months ended June 30, 2008.

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The following table shows the results of operations for the three and six month periods ended June 30, 2009 and 2008:

	Three Months Ended						Quarter to Date						Six Months Ended						Year to Date
	June 30,						2009-2008						June 30,						2009-2008
(in millions except per unit data)	2009			2008			Change			Percent			2009			2008			Change			Percent
Net sales	$	142.8		$	256.7		$	(113.9	)		-44	%	$	308.1		$	431.2		$	(123.1	)		-29	%
Cost of goods sold		78.0			121.9			(43.9	)		-36	%		195.0			213.8			(18.8	)		-9	%
Gross margin		64.8			134.8			(70.0	)		-52	%		113.1			217.4			(104.3	)		-48	%
Gross margin percentage		45.4	%		52.5	%		-7.1	%		-14	%		36.7	%		50.4	%		-13.7	%		-27	%
Selling, general and administrative expenses		4.1			6.1			(2.0	)		-33	%		9.4			9.6			(0.2	)		-2	%
Operating earnings		60.7			128.7			(68.0	)		-53	%		103.7			207.8			(104.1	)		-50	%
Interest income, net		0.1			1.5			(1.4	)		-93	%		0.4			4.0			(3.6	)		-90	%
Net income	$	60.8		$	130.2		$	(69.4	)		-53	%	$	104.1		$	211.8		$	(107.7	)		-51	%
Net income allocable to Common Units	$	38.0		$	74.2		$	(36.2	)		-49	%	$	65.5		$	146.9		$	(81.4	)		-55	%
Net income per Common Unit	$	2.05		$	4.01			(1.96	)		-49	%	$	3.54		$	7.94		$	(4.40	)		-55	%

Sales Volumes and Prices

The following table shows North American ammonia and UAN volumes and prices and natural gas cost for the three month periods ended June 30, 2009 and 2008:

	2009				2008
	Volumes		Unit Price		Volumes		Unit Price
	(000 tons)		($/ton) 2		(000 tons)		($/ton) 2
Ammonia		82	$	444		116	$	555
UAN 1		412	$	226		521	$	336
Natural gas cost 3		—	$	4.26		—	$	7.59

1.	The nitrogen content of UAN is 32% by weight.
2.	After deducting $13.0 million and $16.9 million outbound freight costs for the second quarter of 2009 and 2008, respectively.
3.	Excluding the impact of hedge costs, natural gas cost was $3.05 per MMBtu for the 2009 second quarter.

The following table shows North American ammonia and UAN volumes and prices and natural gas cost for the six month periods ended June 30, 2009 and 2008:

	2009				2008
	Volumes		Unit Price		Volumes		Unit Price
	(000 tons)		($/ton) 2		(000 tons)		($/ton) 2
Ammonia		187	$	440		154	$	546
UAN 1		778	$	255		1,023	$	309
Natural gas cost 3		—	$	5.68		—	$	7.37

1.	The nitrogen content of UAN is 32% by weight.
2.	After deducting $25.4 million and $29.8 million outbound freight costs for the first half of 2009 and 2008, respectively.
3.	Excluding the impact of hedge costs, natural gas cost was $3.31 per MMBtu for the 2009 first half.

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RESULTS OF OPERATIONS — QUARTER ENDED JUNE 30, 2009 COMPARED WITH
QUARTER ENDED JUNE 30, 2008

Our net sales for the second quarter of 2009 were $142.8 million, a decline of $113.9 million or 44% from the second quarter of 2008 net sales of $256.7 million. The decline was primarily due to a decline in UAN and ammonia sales prices of 33% and 20% and a decline in UAN and ammonia sales volumes of 21% and 29%, respectively. During the second quarter of 2009, growers faced inclement weather early in the quarter which limited pre-plant fertilizer application. Demand recovered for side-dressing ammonia application at the end of the quarter. The supply channel also maintained the carryover of inventory from purchases made in the prior year. The significant decrease in volumes as compared to the second quarter of 2008 is also partially due to dealers purchasing for application and future fill during the second quarter of 2008. As the market has corrected for this, the sales volumes decreased in the current quarter. As a result of decreased demand in the second quarter, production rates were reduced to 89%.

Our gross margin was $64.8 million in the second quarter of 2009 compared to $134.8 million in the second quarter of 2008. The gross margin decreased slightly as a percentage of sales to 45.4% from 52.5%. The gross margin percentage includes a 44% decrease in natural gas costs for the second quarter of 2009. The second quarter natural gas unit costs, net of forward pricing gains and losses, declined from $7.59 per MMBtu in 2008 to $4.26 per MMBtu in 2009. The decrease in natural gas cost was offset by aggregate reductions in product pricing of $54.8 million and a margin impact of $30.4 million due to the decrease in sales volumes.

We enter into forward sales commitments by utilizing forward pricing and prepayment programs with customers. We use derivative instruments to hedge a portion of our natural gas requirements. The use of these derivative instruments is designed to hedge exposure to natural gas price fluctuations for production required for forward sales estimates. The net cost of derivatives for the second quarter of 2009 was $10.6 million as compared to the net benefit of derivatives for the second quarter of 2008 of $19.7 million. Excluding the impact of the hedge cost, natural gas cost was $3.05 per MMBtu in the second quarter of 2009.

Selling, General and Administrative Costs

Selling, general and administrative costs were $4.1 million in the second quarter of 2009, a decrease of $2.0 million from the second quarter of 2008. The decrease is primarily due to a decrease in short term performance based incentive compensation expense, long term share-based compensation expense and a reduction in self-insurance costs.

Interest Income

Interest income has decreased in the second quarter of 2009 due to declining interest rates and a reduction of the average investment balance as compared to the second quarter of 2008.

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RESULTS OF OPERATIONS — SIX MONTHS ENDED JUNE 30, 2009 COMPARED WITH
SIX MONTHS ENDED JUNE 30, 2008

Our net sales for the first half of 2009 were $308.1 million, a decline of $123.1 million or 29% from the first half of 2008 net sales of $431.2 million. The decline was primarily due to a 19% and 17% decline in ammonia and UAN sales prices, respectively, and a 24% decline in UAN sales volumes, offset by a 21% increase in ammonia sales volumes as compared to the first half of 2008.

Our gross margin was $113.1 million in the first half of 2009 compared to $217.4 million in the first half of 2008, and decreased as a percentage of sales to 36.7% from 50.4%. The gross margin percentage movement reflects a 23% decrease in natural gas costs. The first half of 2009 natural gas unit costs, net of forward pricing gains and losses, decreased 23% from $7.37 per MMBtu in 2008 to $5.68 per MMBtu in 2009. The decrease in natural gas cost was offset by aggregate reductions in product pricing of $58.4 million and a margin impact of $38.2 million due to the decrease in sales volumes.

We enter into forward sales commitments by utilizing forward pricing and prepayment programs with customers. We use derivative instruments to hedge a portion of our natural gas requirements. The use of these derivative instruments is designed to hedge exposure to natural gas price fluctuations for production required for forward sales estimates. The net cost of derivatives for the first half of 2009 was $44.3 million as compared to the net benefit of derivatives for the first half of 2008 of $22.2 million. Excluding the impact of the hedge cost, natural gas cost was $3.31 per MMBtu in the first half of 2009.

Selling, General and Administrative Costs

Selling, general and administrative costs were $9.4 million in the first half of 2009, a decrease of $0.2 million as compared to the first half of 2008. This is primarily due to a decrease in short-term performance based incentive compensation expense, long-term share-based compensation expense and a reduction in self-insurance costs.

Interest Income

Interest income has decreased in the first half of 2009 due to declining interest rates and a reduction of the average investment balance as compared to the first half of 2008.

CAPITAL RESOURCES AND LIQUIDITY

Our principal funding needs are to support working capital requirements, make payments for plant turnaround and capital expenditures, and quarterly distributions. Cash and cash equivalents were $95.2 million at June 30, 2009. During the first half of 2009, cash and cash equivalents decreased by $59.5 million from December 31, 2008.

Our cash receipts are generally received by Terra. Cash receipts, net of cash payments made by Terra, are transferred to us from Terra weekly. Because of this cash collection and distribution arrangement, Terra is a creditor to us.

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Cash Flows

The following table summarizes our cash flows from operating, investing and financing activities for the six months ended June 30, 2009 and 2008 ($ in thousands):

Total cash provided by (used in)	2009			2008
Operating activities	$	107.4		$	93.1
Investing activities		(12.2	)		(6.7	)
Financing activities		(154.7	)		(171.2	)
Increase (decrease) in cash and cash equivalents	$	(59.5	)	$	(84.8	)

Operating Activities

Net cash provided by operating activities for the first half of 2009 represented $113.0 million from operations offset by $5.6 million used in working capital changes. The $113.0 million includes $104.1 million of net income, adjusted for non-cash expenses of $8.9 million of depreciation of plant, property and equipment and amortization of deferred plant turnaround costs.

Investing Activities

Our investing activities used cash of $12.1 million for the first half of 2009. This includes $8.0 million of capital expenditures, $0.3 million of plant turnaround expenditures and a $3.8 million change in our demand deposits with an affiliate.

Financing Activities

Our financing activities used cash of $154.7 million related to the distributions paid to our unitholders. The distributions paid are based on the “Available Cash”, as defined in our Agreement of Limited Partnership. See Note 3, Agreement of Limited Partnership, of the Notes to the Consolidated Financial Statements, included herein.

Revolving Credit Facility

We have a $50 million revolving credit facility (facility) through January 31, 2012. A portion of this facility is available for swing loans and for the issuance of letters of credit. At June 30, 2009, there were no revolving credit borrowings and there were no outstanding letters of credit. The facility requires us to maintain certain financial ratio covenants relating to minimum earnings, maximum capital expenditures and minimum liquidity. We must also adhere to certain limitations on additional indebtedness, capital expenditures, acquisitions, liens, investments, asset sales, prepayments or subordinated indebtedness, changes in lines of business, restricted payments and transactions with affiliates, among others. Terra and its other domestic subsidiaries have guaranteed our obligations on an unsecured basis. For additional information regarding our facility, see Note 9, Revolving Bank Credit Facility, of the Notes to the Consolidated Financial Statements included in Item 8, Financial Statements and Supplementary Data, of our 2008 Annual Report on Form 10-K.

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Under the facility, we may borrow an amount generally based on eligible cash balances, 85% of eligible accounts receivable and 60% of eligible finished goods inventory, less outstanding letters of credit. Our borrowings under the facility are secured by substantially all of our working capital.

In addition, if our aggregate borrowing availability falls below $10 million, we are required to have generated $25 million of operating cash flows or earnings before interest, income taxes, depreciation, amortization and other non-cash items as defined in the facility for the preceding four quarters. We are also required to maintain a minimum aggregate unused borrowing availability of $5 million at all times.

Our ability to continue to meet the covenants under the facility in the future will depend on market conditions, operating cash flows, working capital needs, receipt of customer prepayments and trade credit terms. Failure to meet these covenants, or to obtain a waiver from the lenders, would result in our default such that all outstanding amounts could become immediately due and payable and we would be unable to borrow additional amounts under the facility. Access to adequate bank facilities may be required to fund operating cash needs. Therefore, any default or termination of the facility could have a material adverse effect on our business.

The facility also requires that there be no change of control related to Terra, such that no individual or group (within the meaning of the Securities Exchange Act of 1934, as amended) beneficially owns more than 35% of the outstanding voting shares of Terra. Such a change of control would constitute an event of default under the facility. On February 23, 2009, CF Industries Holdings, Inc. (CF) commenced an exchange offer to acquire all of the outstanding Terra common stock. Such a business combination, if consummated, would constitute a change of control under the facility. See Note 10, Unsolicited Exchange Offer by CF Industries Holdings, Inc., to the Notes to the Consolidated Financial Statements for additional information with respect to CF’s unsolicited proposal.

We expect the facility to be adequate to meet our operating needs.

Debt

The General Partner is an indirect, wholly-owned subsidiary of Terra. Under the General Partner’s governing documents, neither we nor the General Partner may make any bankruptcy filing (or take similar action) without the approval of the General Partners’ independent directors.

Partnership Distributions

We make quarterly distributions to our partners based on “Available Cash” for the quarter, as defined in our Agreement of Limited Partnership. Available Cash is defined generally as all cash receipts less all cash disbursements, adjusted for changes in certain reserves established as the General Partner determines in its reasonable discretion to be necessary. We paid distributions of $154.7 million and $171.2 million for the six months ended June 30, 2009 and 2008, respectively.

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We receive 99% of the Available Cash from Terra Nitrogen, Limited Partnership (“the Operating Partnership”) and 1% is distributed to its general partner, (who is also our General Partner). Cash distributions from the Operating Partnership generally represent our Available Cash from operations. Our cash distributions are made 99.975% to Common Unitholders and 0.025% to our General Partner, except when cumulative distributions of Available Cash exceed specified target levels above the Minimum Quarterly Distributions (“MQD”) of $0.605 per unit. Under such circumstances, our General Partner is entitled, as an incentive, to larger percentage interests. Pursuant to our Agreement of Limited Partnership, income allocable to the Limited Partner and General Partner is based upon the distributions of Available Cash for the year. Therefore, earnings per unit reflect an annualized allocation rate.

On July 23, 2009, we announced a $2.22 cash distribution per common limited partnership unit, payable on August 27, 2009 to holders of record as of August 7, 2009. We have exceeded the cumulative MQD amounts and will distribute Available Cash as summarized in the following table:

	Income and Distribution Allocation
								Class B
	Target		Target		Common			Common			General
	Limit		Increment		Units			Units			Partner			Total
Minimum Quarterly Distribution	$	0.605	$	0.605		98.990	%		0.985	%		0.025	%		100.000	%
First Target		0.715		0.110		98.990	%		0.985	%		0.025	%		100.000	%
Second Target		0.825		0.110		85.859	%		0.985	%		13.156	%		100.000	%
Third Target		1.045		0.220		75.758	%		0.985	%		23.257	%		100.000	%
Final Target and Beyond		1.045		—		50.505	%		0.985	%		48.510	%		100.000	%

The General Partner is required to remit the majority of cash distributions it receives from the Partnership, in excess of its 1% Partnership equity interest, to an affiliated company.

General Partner Option to Effect Mandatory Redemption of Partnership Units

At June 30, 2009, the General Partner and its affiliates owned 75.3% of our outstanding units. When not more than 25% of the issued and outstanding units are held by non-affiliates of the General Partner, as was the case at June 30, 2009, we, at the General Partner’s sole discretion, may call, or assign to the General Partner or its affiliates, our right to acquire all such outstanding units held by non-affiliated persons. If the General Partner elects to acquire all outstanding units, we are required to give at least 30 but not more than 60 days’ notice of our decision to purchase the outstanding units. The purchase price per unit will be the greater of (1) the average of the previous 20 trading days’ closing prices as of the date five days before the purchase is announced and (2) the highest price paid by the General Partner or any of its affiliates for any unit within the 90 days preceding the date the purchase is announced. Additional purchases of common units by the General Partner may be restricted under the terms of Terra’s bank credit agreement.

Our cash receipts are generally received by Terra on our behalf. Cash receipts, net of cash payments made by Terra, are transferred to us from Terra on a weekly basis. As a result of this cash collection and distribution arrangement, Terra is a creditor to us.

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There were no material changes outside the ordinary course of business to the Partnership’s contractual obligations, critical accounting policies or off-balance sheet arrangements presented in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Annual Report on Form 10-K for the period ended December 31, 2008.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our operations are significantly affected by the price of natural gas. We employ derivative commodity instruments related to a portion of our natural gas requirements (primarily swaps and options) for the purpose of managing exposure to commodity price risk in the purchase of natural gas. Changes in the market value of these derivative instruments are expected to have a high correlation to changes in the spot price of natural gas. For more information about how we manage specific risk exposures, refer to our most recent Annual Report on Form 10-K (which is on file with the Securities and Exchange Commission), Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” and Note 6 — Derivative Financial Instruments contained in Item 8 of our 2008 Form 10-K. There were no material changes in our use of financial instruments during the quarter ended June 30, 2009.

Natural gas is the principal raw material used to manufacture nitrogen. Natural gas prices are volatile and we mitigate some of this volatility through the use of derivative commodity instruments. Our current policy is to hedge natural gas provided that such arrangements would not result in costs greater than expected selling prices for our finished products. Estimated North American natural gas requirements for 2009 are approximately 38 billion cubic feet (BCF). We have hedged 16% of our expected North American requirements for the next twelve months. The fair value of these instruments is estimated based, in part, on quoted market prices from brokers, realized gains or losses and or computations. These instruments and other natural gas positions fixed natural gas prices at $1.4 million (includes $1.1 million related to accumulated other comprehensive loss) more than published prices for June 30, 2009 forward markets.

The General Partner’s ability to manage our exposure to commodity price risk in the purchase of natural gas through the use of financial derivatives may be affected by limitations imposed by our bank agreement covenants.

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by this report, that our disclosure controls and procedures are effective to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 are recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There were no significant changes in our internal control over financial reporting that occurred during the most recent quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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FORWARD-LOOKING INFORMATION IS SUBJECT TO RISK AND UNCERTAINTY

Certain statements in this report may constitute “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon assumptions as to future events that may not prove to be accurate. These statements are not guarantees of future performance and involve risks, uncertainties and assumptions that are difficult to predict. Actual outcomes and results may differ materially from what is expressed or forecasted in these forward-looking statements. As a result, these statements speak only as of the date they were made and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as otherwise required by law.

Words such as “expects,” “intends,” “plans,” “projects,” “believes,” “estimates,” and similar expressions are used to identify these forward-looking statements. These include, among others, statements relating to:

• changes in financial markets,

• general economic conditions within the agricultural industry,

• competitive factors and price changes (principally, sales prices of nitrogen products and natural gas costs),

• changes in product mix,

• changes in the seasonality of demand patterns,

• changes in weather conditions,

• changes in environmental and other government regulations,

• changes in agricultural regulations, and

• other risks detailed in the section entitled “Risk Factors” in our 2008 Annual Report on Form 10-K.

Additional information as to these factors can be found in our 2008 Annual Report on Form 10-K in the sections entitled Business and Management’s Discussion and Analysis of Financial Condition and Results of Operations and in the Notes to our Consolidated Financial Statements included as part of this report.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are involved in various claims, disputes, administrative proceedings and legal actions arising in the ordinary course of business. We do not believe that the matters in which we are currently involved, either individually or in the aggregate, will have a material adverse effect on our consolidated financial position, results of operations or liquidity.

ITEM 1A. RISK FACTORS

There were no significant changes in our risk factors during the first half of 2009 as compared to the risk factors identified in our 2008 Annual Report on Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

(a) Exhibits:

Exhibits 31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Exhibits 31.2	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Exhibit 32.1	Certification of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 32.2	Certification of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURE

Pursuant to the requirements 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.

TERRA NITROGEN COMPANY, L.P.
By:	TERRA NITROGEN GP INC.
	as General Partner
By:	/s/ DANIEL D. GREENWELL Daniel D. Greenwell
	Vice President and
	Chief Financial Officer
	(Principal Financial Officer and
	Principal Accounting Officer)

Date: July 24, 2009

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EXHIBIT INDEX

Exhibit
Number	Description
Exhibits 31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Exhibits 31.2	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Exhibit 32.1	Certification of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 32.2	Certification of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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