FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

For the quarter ended September 30, 2005

OR

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

For the transition period from              to             

Commission file number 1-10877

TERRA NITROGEN COMPANY, L.P.

(Exact name of registrant as specified in its charter)

Delaware	73-1389684
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer 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:

(712) 277-1340

At the close of business on October 31, 2005, there were 18,501,576 Common Units and 184,072 Class B Common Units outstanding.

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.    x  Yes    ¨  No

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

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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TERRA NITROGEN COMPANY, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(unaudited)

	September 30, 2005			December 31, 2004			September 30, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	38,627		$	78,192		$	42,377
Accounts receivable		36,131			21,079			21,587
Inventory		25,108			15,729			15,780
Prepaid insurance and other current assets		35,184			4,244			12,112
Total current assets		135,050			119,244			91,856
Property, plant and equipment, net		74,250			80,425			80,027
Other assets		11,258			14,284			7,408
Total assets	$	220,558		$	213,953		$	179,291
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	43,123		$	18,816		$	12,685
Customer prepayments		17,370			52,871			11,315
Pension liabilities due to affiliate		—			—			2,931
Current portion of long-term debt and capital lease obligations		28			63			62
Total current liabilities		60,521			71,750			26,993
Long-term debt due to affiliates		—			8,200			8,200
Capital lease obligations		—			12			28
Other long-term liabilities		174			7			501
Total liabilities		60,695			79,969			35,722
Partners’ capital:
Limited partners’ interests – common unitholders		164,888			150,850			147,837
General partner’s interest		(10,503	)		(10,791	)		(10,852	)
Accumulated other comprehensive income (loss)		5,478			(6,075	)		6,584
Total partners’ capital		159,863			133,984			143,569
Total liabilities and partners’ capital	$	220,558		$	213,953		$	179,291

See Accompanying Notes to the Condensed Consolidated Financial Statements.

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TERRA NITROGEN COMPANY, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Revenues	$	111,462		$	100,479		$	337,175		$	337,436
Other income		277			251			624			620
Total revenues		111,739			100,730			337,799			338,056
Cost of goods sold		92,387			90,791			267,943			297,062
Gross profit		19,352			9,939			69,856			40,994
Operating expenses		1,770			3,366			5,939			8,200
Operating income		17,582			6,573			63,917			32,794
Interest expense		(184	)		(2	)		(598	)		(6	)
Interest income		314			185			1,037			569
Net income	$	17,712		$	6,756		$	64,356		$	33,357
Net income allocable to limited partners’ interest	$	17,357		$	6,621		$	63,068		$	32,690
Net income per limited partnership unit	$	0.94		$	0.36		$	3.41		$	1.77

See Accompanying Notes to the Condensed Consolidated Financial Statements.

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TERRA NITROGEN COMPANY, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine Months Ended September 30,
	2005			2004
Operating activities:
Net income	$	64,356		$	33,357
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation		11,045			7,020
Changes in operating assets and liabilities:
Receivables		(15,052	)		15,025
Inventories		(9,379	)		3,584
Accounts payable, accrued liabilities and customer prepayments		(11,194	)		(25,912	)
Other assets and liabilities		(19,813	)		(4,481	)
Net cash flows from operating activities		19,963			28,593
Investing activities:
Capital expenditures		(5,141	)		(1,482	)
Plant turnaround expenditures		(1,113	)		(688	)
Proceeds from the sale of property, plant and equipment		4,991			—
Net cash used in investing activities		(1,263	)		(2,170	)
Financing activities:
Repayment of long-term debt and capital lease obligations		(8,235	)		(43	)
Partnership distributions paid		(50,030	)		(23,599	)
Net cash flows used in financing activities		(58,265	)		(23,642	)
Net (decrease) increase in cash and cash equivalents		(39,565	)		2,781
Cash and cash equivalents at beginning of year		78,192			39,596
Cash and cash equivalents at end of period	$	38,627		$	42,377

See Accompanying Notes to the Condensed Consolidated Financial Statements.

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TERRA NITROGEN COMPANY, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except for units)

(unaudited)

(in thousands, except for Units)	Limited Partners’ Interests			General Partner’s Interests			Accumulated Other Comprehensive Income (Loss)			Total Partners’ Capital			Comprehensive Income
Partners’ capital at January 1, 2005	$	150,850		$	(10,791	)	$	(6,075	)	$	133,984
Net income		63,068			1,288			—			64,356		$	64,356
Change in fair value of derivatives		—			—			11,553			11,553			11,553
Comprehensive income		—			—			—			—		$	75,909
Distributions		(49,030	)		(1,000	)		—			(50,030	)
Partners’ capital at September 30, 2005	$	164,888		$	(10,503	)	$	5,478		$	159,863

Limited partner units issued and outstanding at September 30, 2005:
Common Units	18,501,576
Class B Common Units	184,072
Total Units Outstanding at September 30, 2005	18,685,648

(in thousands, except for Units)	Limited Partners’ Interests			General Partner’s Interest			Accumulated Other Comprehensive Income (Loss)		Total Partners’ Capital			Comprehensive Income
Partners’ capital at January 1, 2004	$	138,274		$	(11,047	)	$	5,050	$	132,277
Net income		32,690			667			—		33,357		$	33,357
Change in fair value of derivatives		—			—			1,534		1,534			1,534
Comprehensive income		—			—			—		—		$	34,891
Distributions		(23,127	)		(472	)		—		(23,599	)
Partners’ capital at September 30, 2004	$	147,837		$	(10,852	)	$	6,584	$	143,569

Limited partner units issued and outstanding at September 30, 2004:
Common Units	18,501,576

See Accompanying Notes to the Condensed Consolidated Financial Statements.

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TERRA NITROGEN COMPANY, L.P.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Financial Statement Presentation

Basis of Presentation

The condensed consolidated financial statements contained herein should be read in conjunction with the consolidated financial statements and notes thereto contained in the Terra Nitrogen Company, L.P. (“TNCLP”) Annual Report on Form 10-K for the year ended December 31, 2004. TNCLP and its operating partnership subsidiary, Terra Nitrogen, Limited Partnership (the “Operating Partnership”), are referred to herein, collectively, as the “Partnership”.

The accompanying unaudited condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for the fair statement of the results for the periods presented. All of these adjustments are of a normal and recurring nature. Results for the quarter are not necessarily indicative of future financial results of the Partnership.

Revenue Recognition

Revenue is recognized when title and risk of loss passes to the customer. Revenue is recognized as the net amount to be received after deducting estimated amounts for discounts and trade allowances. Revenues include amounts paid by customers for shipping and handling.

Cost of Sales

During the 2005 third quarter the Partnership identified and made corrections to natural gas costs related to previously reported quarters of fiscal 2004 and 2005 totaling $1.8 million and $1.5 million, respectively.

Had the adjustment related to 2004 been recorded as of December 31, 2004, the impact on the consolidated statement of operations and comprehensive loss would have been an approximate $1.8 million decrease in operating income and net income for the year ending December 31, 2004 and an approximate $1.8 million decrease to Partners’ Capital Equity as of December 31, 2004. The adjustment had no impact on cash flows.

Management does not believe that the combined impact of the corrections for the adjustments discussed above is material to the financial statements as of and for the year ended December 31, 2004; for the three-month period ended March 31, 2005; for the three- and six-month periods ended June 30, 2005; and for the three- and nine-month periods ended September 30, 2005; nor is the cumulative adjustment of $3.3 million recorded in the third quarter of 2005 expected to be material, in aggregate, to the financial statements as of and for the year ended December 31, 2005. The adjustments had no impact on cash flows.

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Hedging Transactions

Realized gains and losses from hedging activities and premiums paid for option contracts are deferred and recognized in the month in which the hedged transactions closed. Swaps, options and other derivative instruments that do not qualify for hedge accounting treatment are marked to fair value each accounting period. Costs associated with settlement of natural gas purchase contracts and costs for shipping and handling are included in cost of sales. Cash flows related to natural gas hedging are reported as cash flows from operating activities.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected future cash flows expected to result from the use of the asset (undiscounted and without interest charges) is less than the carrying amount of the asset, an impairment loss is recognized based on the difference between the carrying amount and the fair value of the asset.

Natural Gas Futures, Swaps, Options and Basis Swaps

The estimated fair value of each class of derivatives is based on published referenced prices and quoted market prices from brokers.

Use of Estimates in Preparation of the Financial Statements

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

2. Changes to the Organizational Structure

On September 1, 2005, Terra Nitrogen Corporation (“TNC”), which prior to such time was the general partner of the Partnership, completed a restructuring of its organizational structure and certain contractual relationships. The purpose of the restructuring was to further reinforce the structural independence of the Partnership from Terra Industries Inc. (“Terra”).

Prior to the restructuring, TNC owned, as General Partner, a consolidated 2.0% interest in the Partnership. In the restructuring transactions, TNC exchanged 1.95% of its General Partnership interests for limited partnership interests comprised of 184,072 Class B Common Units of TNCLP and a 0.98% limited partnership interest in the Operating Partnership. The Class B Common Units, which are identical to Common Units with respect to distributions and allocations of income, gain, loss or deductions, have no voting rights on any matter. The Class B Common Units are not listed for trading.

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TNC subsequently transferred the remaining 0.05% General Partner interest in the Partnership to Terra Nitrogen GP Inc., an indirect wholly-owned subsidiary of Terra Industries Inc.

3. Agreement of Limited Partnership

The Partnership makes quarterly cash distributions to Unitholders and the General Partner in an amount equal to 100% of its “Available Cash” (as defined in the Partnership Agreement).

In the first nine months of 2005, the Partnership paid cash distributions in the amount of $50.0 million. In the first nine months of 2004 the Partnership paid cash distributions in the amount of $23.6 million.

At September 30, 2005, the General Partner and its affiliates owned 75.3% of the Partnership’s outstanding units. When less than 25% of the issued and outstanding units are held by non-affiliates of the General Partner, the Partnership, at the General Partner’s sole discretion, may call, or assign to the General Partner or its affiliates, its right to acquire all such outstanding units held by non-affiliated persons. If the General Partner elects to acquire all outstanding units, the Partnership is required to give at least 30 but not more than 60 days’ notice of its 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 as described therein.

4. Net Income per Limited Partnership Unit

Basic income per unit data is based on the weighted-average number of Partnership Units outstanding during the period. Diluted income per unit data is based on the weighted-average number of Partnership Units outstanding and the effect of all dilutive potential common units.

The following table provides a reconciliation between basic and diluted income per unit for the three- and nine-month periods ended September 30, 2005 and 2004:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except per-share amounts)	2005		2004		2005		2004
Basic income per limited Partnership unit computation:
Net income allocable to limited Partnerships’ interest	$	17,357	$	6,621	$	63,068	$	32,690
Weighted average units outstanding		18,562		18,522		18,502		18,502
Net income per limited Partnership unit	$	0.94	$	0.36	$	3.41	$	1.77

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On September 1, 2005, 184,072 Class B Common Units were issued to TNC (see Note 2).

There were no dilutive Partnership units outstanding for the three- and nine-months ended September 30, 2005 and 2004.

5. Inventories

Inventories consisted of the following:

(in thousands)	September 30, 2005		December 31, 2004		September 30, 2004
Materials and supplies	$	6,361	$	7,053	$	7,150
Finished goods		18,747		8,676		8,630
Total	$	25,108	$	15,729	$	15,780

Inventory is valued at actual first in – first out cost. Costs include raw material, labor and overhead.

6. Derivative Financial Instruments

The Partnership manages 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, the Partnership enters into derivative transactions only with counter-parties who are currently rated as BBB or better or equivalent as recognized by a national rating agency. The Partnership 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.

The Partnership classifies a derivative financial instrument as a hedge if all of the following conditions are met:

1. The item to be hedged must expose the Partnership to currency or price risk.

2. It must be probable that the results of the hedge position substantially offset the effects of currency or price changes on the hedged item (e.g., there is a high correlation between the hedge position and changes in market value of the hedge item).

3. The derivative financial instrument must be designated as a hedge of the item at the inception of the hedge.

Natural gas supplies to meet production requirements at the Partnership’s production facilities are purchased at market prices. Natural gas market prices are volatile and the Partnership effectively fixes prices for a portion of its natural gas production requirements and inventory through the use of futures contracts, swaps and options. These contracts reference physical natural gas prices or appropriate 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, natural gas supplies for the Partnership’s

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production facilities are purchased 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 change in the price of physical gas. 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 the Partnership 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 futures contracts require maintenance of cash balances generally 10% to 20% of the contract value and option contracts require initial premium payments ranging from 2% to 5% of contract value. Basis swap contracts require payments to or from the Partnership 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.

The Partnership will also use a collar structure where it will enter into a swap, sell a call at a higher price and buy a put. The collar structure allows for greater participation in a decrease to natural gas prices and protects against moderate price increases. However, the collar exposes the Partnership to large price increases.

The following summarizes open natural gas derivative contracts at September 30, 2005 and 2004:

	2005
(in thousands)	Realized Contract MMBtu	Realized Gain (Loss)			Unrealized Contract MMBtu	Unrealized Gain (Loss)
Swaps	1,842	$	8,112		3,577	$	22,869
Basis swaps	2,047		(3,410	)	3,014		(2,416	)
Purchased put options	1,228		(393	)	3,577		(1,783	)
Sold call options	819		(3,728	)	3,577		(13,774	)
	5,936	$	581		13,745	$	4,896
	2004
(in thousands)	Realized Contract MMBtu	Realized Gain (Loss)			Unrealized Contract MMBtu	Unrealized Gain (Loss)
Swaps	2,322	$	(1,110	)	9,797	$	10,170
Basis swaps	—		—		—		—
Purchased put options	871		160		8,819		(4,005	)
Sold call options	726		107		8,461		1,987
	3,919	$	(843	)	27,077	$	8,152

Gains and losses on settlement of these contracts and premium payments on option contracts are credited or charged to cost of sales in the month in which the hedged transaction closes. 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. Realized gains on contracts settled in October 2005 were $0.6 million.

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Compared with spot prices, natural gas derivative activities decreased the Partnership’s 2005 third quarter natural gas costs by $5.3 million and increased 2004 third quarter natural gas costs by $0.9 million.

Compared with spot prices, natural gas derivative activities decreased the Partnership’s 2005 first nine-month natural gas costs by $2.9 million and reduced 2004 first nine-month natural gas costs by $5.2 million.

The following table presents the carrying amounts and estimated fair values of the Partnership’s derivative financial instruments as of September 30, 2005 and 2004. SFAS 107, “Disclosures about Fair Value of Financial Instruments” defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties.

	2005					2004
(in millions)	Carrying Amount			Fair Value		Carrying Amount			Fair Value
Natural gas	$	(0.8	)	$	5.9	$	(1.0	)	$	7.3

The Partnership’s accumulated comprehensive income is comprised solely of hedging transactions. The activity to other comprehensive income (loss) for the three- and nine-month periods ended September 30, 2005 and 2004 follows:

	Three Months Ended September 30						Nine Months Ended September 30
(in thousands)	2005			2004			2005			2004
Beginning accumulated gain (loss)	$	3,249		$	(110	)	$	(6,075	)	$	5,050
Reclassification into earnings		(5,337	)		930			(2,888	)		(5,165	)
Net change associated with current period hedging transactions		7,566			5,764			14,441			6,699
Ending accumulated gain (loss)	$	5,478		$	6,584		$	5,478		$	6,584

Approximately $2.3 million of the accumulated gain at September 30, 2005 will be reclassified into earnings during 2005.

Derivative Financial Instruments not Accounted for as Hedges

The Partnership also uses forward derivative instruments to fix or set floor prices for a portion of its nitrogen sales volumes. At September 30, 2005, the Partnership had open swap contracts covering 20,000 tons of nitrogen solutions. The nitrogen solution contracts do not qualify for hedge treatment due to inadequate trading history to demonstrate effectiveness. Consequently, the contracts are marked-to-market and unrealized gains or losses are reflected in cost of sales in the statement of operations. For the three- and nine-month periods ending September 30, 2005, the Partnership recognized losses of $0.2 million and $1.7 million, respectively, on these forward derivative instruments. The open nitrogen solution contracts expire during 2005.

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7. Long-Term debt and capital lease obligations

Long-term debt and capital lease obligations consisted of the following:

(in thousands)	September 30, 2005		December 31, 2004
Capitalized lease obligations	$	28	$	75
Long-term debt due to affiliate		—		8,200
		28		8,275
Less current maturities		28		63
Total	$	—	$	8,212

During the third quarter of 2005, $8.2 million of debt was repaid to an affiliate in connection with the reorganization of the Partnership (see Note 2).

8. Disposal of property, plant and equipment

During the second quarter of 2003, due to expectations that the Blytheville facility would not cover its future cash costs and required capital improvements because of continuing competition from urea imports from regions with much lower gas costs, the Partnership decided to permanently close the facility following the 2004 planting season. In accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” a $40.7 million charge was recorded during the 2003 second quarter. During the second quarter of 2004, the Blytheville production facility was permanently shutdown. During the third quarter of 2005, the Blytheville facility was disposed. There were no gains or losses related to this disposal.

9. Commitments and contingencies

At September 30, 2005 the Partnership had fixed price sales orders for approximately 23% of its annual nitrogen production capacity. The Partnership expects to fulfill these sales commitments through product shipments during the next six to eight months. Based on the September 30, 2005 NYMEX natural gas future prices for the four-month period from October 2005 to January 2006 of $14.03 per MMBtu and excluding any impact related to outstanding derivative instruments at September 30, 2005, the estimated production costs of these sales orders would exceed the fixed sales price by approximately $14.4 million. A $1 per MMBtu change in the NYMEX quoted natural gas cost would be expected to increase or decrease the estimated loss from these sale orders by approximately $8.8 million. Since September 30, 2005, management has taken, and continues to take, steps to mitigate and cap the potential losses on these transactions.

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

Introduction

The Partnership produces and markets nitrogen products for use in agricultural and industrial markets. Nitrogen is a commodity chemical and prices are established based on global supply and demand conditions. The nitrogen products industry has cycles of oversupply, resulting in lower prices and idled capacity, followed by supply shortages, resulting in high selling prices and higher industry-wide production rates. To be viable under these market conditions, a producer must be among the low-cost producers to markets it serves and have a financial position that can sustain it during periods of oversupply.

Natural gas is the most significant raw material in the production of nitrogen products. North American natural gas costs have increased substantially since 1999. Since the Partnership competes with nitrogen products imported from regions with lower natural gas costs, the oversupply situation during most of the three years ending December 31, 2003 did not permit the Partnership to increase selling prices to levels necessary to cover the natural gas cost increases. This resulted in curtailments of North American nitrogen production. These curtailments contributed to reductions in global nitrogen product supplies.

The cost of natural gas has recently increased to unprecedented levels due to supply disruptions caused by Hurricanes Katrina and Rita. These increases, if sustained, will significantly increase the Partnership’s production costs. The ability of the Partnership to recover these cost increases through higher prices for its finished goods is uncertain. Consequently, future gross profits realized by the Partnership may be lower than realized during the first nine months of 2005. In addition, the Partnership may curtail or shut down its production facilities if finished goods prices do not increase, or natural gas costs do not decline, to levels allowing the Partnership to cover variable production costs.

Imports, most of which are produced at facilities with access to fixed-price natural gas supplies, account for a significant portion of U.S. nitrogen product supply. Imported products’ natural gas costs have been and could continue to be substantially lower than the delivered cost of natural gas to our facilities. Offshore producers are most competitive in regions close to the point of entry for imports, including the Gulf Coast and East Coast.

The Partnership’s sales volumes are primarily dependent upon the operating rates for its plants. The Partnership may purchase product from other manufacturers or importers for resale, however, gross margins on those volumes are rarely significant. Profitability and cash flows from the operations are affected by the ability to manage costs and expenses (other than natural gas), most of which do not materially change for different levels of production or sales. Other factors affecting operating results include the level of planted acres, transportation costs, weather conditions (particularly during the planting season), grain prices and other variables described in Items 1 and 2 in the “Business and Properties” section of the Partnership’s most recent Form 10-K filing with the Securities and Exchange Commission.

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Dependence on Terra Industries

The Partnership is dependent on Terra Industries Inc. (“Terra”) in a number of respects. Terra provides all of the Partnership’s management, natural gas purchasing and hedging, selling and administrative services and operates its 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 the Partnership. Although Terra is affected by most of the factors that affect the Partnership, its higher level of debt could put a greater risk on Terra in the event of adverse business conditions. The Partnership’s 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 Form 8-K.

Three months ended September 30, 2005 compared with

three months ended September 30, 2004

Volumes and prices for the three-month periods ended September 30, 2005 and 2004 follow:

	2005			2004
	Volumes (000 tons)	Unit Price ($/ton)*		Volumes (000 tons)	Unit Price ($/ton)*
Ammonia	45	$	329	76	$	265
UAN	578		150	586		119

* After deduction of outbound freight costs

Revenues for the quarter ended September 30, 2005 increased $11.0 million, or 11%, compared with the same 2004 quarter primarily due to increased ammonia and UAN prices, offset by decreased ammonia production. The increase in ammonia and UAN prices are primarily due to higher demand and lower nitrogen supplies caused by industry-wide production curtailments since mid-2003. Price increases also reflected increased manufacturing costs, primarily related to natural gas and higher imported product costs as the result of U.S. currency declines relative to other currencies and increased international freight rates.

Gross profits for the third quarter were $19.4 million and increased $9.4 million from 2004. Higher 2005 unit prices contributed about $20.8 million to gross profits, but were offset by higher natural gas costs and a $3.3 million charge to correct natural gas costs. Third quarter natural gas costs increased 20%, from $5.59/MMBtu in 2004 to $6.73/MMBtu in 2005 (net of forward pricing gains or losses.) As a result of forward price contracts, third quarter 2005 natural gas costs for the Partnership were $5.8 million lower than spot prices.

Operating expenses of $1.8 million in 2005 declined $1.6 million, or 47%, from 2004 as the result of lower management, selling and administrative expense allocations from Terra to the Partnership, reflecting recent acquisitions that expanded Terra’s base of operations over which its expenses are allocated. Interest income, net of interest expense, in 2005 approximated prior year levels.

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Nine months ended September 30, 2005 compared with

nine months ended September 30, 2004

Volumes and prices for the nine-month periods ended September 30, 2005 and 2004 follow:

	2005			2004
	Volumes (000 tons)	Unit Price ($/ton)*		Volumes (000 tons)	Unit Price ($/ton)*
Ammonia	207	$	310	274	$	266
UAN	1,655		148	1,679		118
Urea	—		—	212		181

* After deducting outbound freight costs

Revenues for the nine months ended September 30, 2005 decreased $0.3 million, compared with the same period in 2004. The constant level of revenues was due to increased unit prices, offset by a decrease in production, primarily attributable to the closure of the Blytheville production facility in May 2004. The ammonia and UAN prices increased as the result of higher demand and lower nitrogen supplies caused by industry-wide production curtailments since mid-2003. Price increases also reflected higher imported product costs as the result of U.S. currency declines relative to other currencies and increased international freight rates.

Gross profits during the 2005 first nine months increased $28.9 million from 2004. Higher selling prices contributed $58.8 million to the increase in 2005 gross profits, but were offset by increased natural gas costs and a $1.8 million charge to correct prepaid natural gas inventories. Nine-month natural gas costs increased 21%, from $5.39/MMBtu in 2004 to $6.52/MMBtu in 2005 (net of forward pricing gains or losses.) As a result of forward price contracts, the first nine months of 2005 natural gas costs for the Partnership were $3.5 million lower than spot prices.

Operating expenses of $5.9 million in 2005 declined $2.3 million, or 28%, from 2004 as the result of lower management, selling and administrative expense allocations from Terra to the Partnership, reflecting recent acquisitions that expanded Terra’s base of operations over which its expenses are allocated. Net interest income in 2005 approximated prior year levels.

Capital resources and liquidity

Operating activities for the first nine months of 2005 generated $20.0 million of cash, comprised of $75.4 million of cash from operations less $55.4 million of cash used to fund changes to current assets and liabilities. The funding needs for current assets and liabilities included a $35.5 million seasonal reduction in customer prepayments from December 31, 2004, a $15.1 million increase to accounts receivable and a $9.4 million increase to inventories. Increases to accounts receivable and inventory balances reflect the effects of higher selling prices and natural gas costs as well as the timing of shipments.

Capital expenditures of $5.1 million during the first nine months of 2005 were primarily to fund replacement and stay-in-business additions to plant and equipment. The Partnership expects 2005 capital expenditures to approximate $8.0 million for replacement and stay-in-business additions to plant and equipment.

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At September 30, 2005 the Partnership had fixed price sales orders for approximately 23% of its annual nitrogen production capacity. The Partnership expects to fulfill these sales commitments through product shipments during the next six to eight months. Based on the September 30, 2005 NYMEX natural gas future prices for the four-month period from October 2005 to January 2006 of $14.03 per MMBtu and excluding any impact related to outstanding derivative instruments at September 30, 2005, the estimated production costs of these sales orders would exceed the fixed sales price by approximately $14.4 million. A $1 per MMBtu change in the NYMEX quoted natural gas cost would be expected to increase or decrease the estimated loss from these sale orders by approximately $8.8 million. Since September 30, 2005, management has taken, and continues to take, steps to mitigate and cap the potential losses on these transactions.

The Partnership’s principal funding needs are to support its working capital and capital expenditures. The Partnership intends to fund its needs primarily from cash provided by operating activities and, to the extent required, from funds borrowed under the Partnership’s $50 million revolving bank credit facility.

During the third quarter of 2005, $8.2 million of debt was repaid to an affiliate in connection with the reorganization of the Partnership (See Note 2 and Note 7 to the Condensed Consolidated Financial Statements).

Under the credit facility, the Partnership 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. The Partnership’s borrowings under the credit facility are secured by substantially all of its working capital. At September 30, 2005, borrowing availability exceeded $50 million and the Partnership had no outstanding borrowings or letters of credit under the facility. Management expects the facility to be adequate to meet the Partnership’s operating cash needs.

Under the credit facility, the Partnership is subject to covenants which impose 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. In addition, if Partnership’s aggregate borrowing availability falls below $10 million, it is 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 credit facility) for the preceding four quarters.

The Partnership’s ability to continue to meet the covenants under the credit 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 a default by the Partnership such that all amounts outstanding could become immediately due and payable and the Partnership would be unable to borrow additional amounts under the credit facility. Because access to adequate bank facilities may be critical to funding the Partnership’s operating cash needs and the General Partner’s purchase of financial derivatives to manage the Partnership’s exposure to natural gas commodity price risk, any default or termination of the joint revolving bank credit facility could have a material adverse effect on the Partnership.

Quarterly distributions to TNCLP’s partners are based on Available Cash for the quarter as defined in the TNCLP 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. Distributions paid to the partners in the first nine months of 2005 and 2004 were $50.0 and $23.6 million, respectively.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Partnership’s operations are significantly affected by the price of natural gas. It employs derivative commodity instruments related to a portion of its natural gas requirements (primarily futures, 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 have a high correlation to changes in the spot price of natural gas. For more information about how the Partnership manages specific risk exposures, refer to its 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 13 – Derivative Financial Instruments contained in Item 8.

The volume of natural gas hedged varies from time to time based on management’s judgment of market conditions, particularly natural gas prices and prices for nitrogen products. Contracts were in place at September 30, 2005 to cover approximately 12% of its natural gas requirements for the succeeding twelve months (see Note 6 to the Condensed Consolidated Financial Statements). The General Partner’s ability to manage the Partnership’s exposure to commodity price risk in the purchase of natural gas through the use of financial derivatives may be affected by limitations imposed by its 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 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms.

During 2005 third quarter and subsequent to that date, the Partnership implemented additional processes that enhanced internal controls over the accounting for natural gas purchasing and derivative instruments. The Partnership believes these enhancements will improve internal controls over financial reporting. Aside from such enhancements, there were significant changes in the Partnerships’ internal control over financial reporting that occurred during the most recent quarter that have materially affected, or are reasonably likely to materially affect, the Partnerships’ internal control over financial reporting.

FORWARD LOOKING PRECAUTIONS

Information contained in this report, other than historical information, may be considered forward looking. Forward-looking information reflects Management’s current views of future events and financial performance that involve a number of risks and uncertainties. The factors that could cause actual results to differ materially include, but are not limited to the following: Changes in the 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 agricultural regulations, and other risks detailed in the Partnership’s Securities and Exchange Commission filings, in particular the “Factors that Affect Operating Results” section of its most recent Form 10-K.

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

(a) Exhibits:

Exhibit 3.1	First Amended and Restated Agreement of Limited Partnership of Terra Nitrogen Company, L.P., dated September 1, 2005. Incorporated by reference to Terra Nitrogen Company, L.P.’s Form 8-K filed on September 7, 2005.
Exhibit 3.2	Certificate of Incorporation of Terra Nitrogen GP Inc. Incorporated by reference to Terra Nitrogen Company, L.P.’s Form 8-K filed on September 7, 2005.
Exhibit 3.3	Bylaws of Terra Nitrogen GP Inc. Incorporated by reference to Terra Nitrogen Company, L.P., dated September 1, 2005. Incorporated by reference to Terra Nitrogen Company, L.P.’s Form 8-K filed September 7, 2005
Exhibit 3.4	Certification of Amendment to Certificate of Limited Partnership of Terra Nitrogen Company, L.P., dated September 1, 2005. Incorporated by reference to Terra Industries Inc.’s Form 10-Q for the quarterly period ended September 30, 2005.
Exhibit 4.1	Certificate of Amendment to Certificate of Limited Partnership of Terra Nitrogen, Limited Partnership, dated September 1, 2005. Incorporated by reference to Terra Industries Inc.’s Form 20-Q for the quarterly period ended September 30, 2005.
Exhibit 4.2	Amendment No. 1 to the Credit Agreement dated July 29, 2005, among Terra Nitrogen, Limited Partnership (“Borrower”), Terra Nitrogen Company, L.P., the Lenders party hereto, and Citicorp USA, Inc. as administrative agent and collateral agent for the Lenders and Issuers. Incorporated by reference to Terra Nitrogen Company, L.P.’s Form 8-K filed on September 7, 2005.
Exhibit 10.1	Reorganization Agreement, by and among Terra Nitrogen Company, L.P., Terra Nitrogen, Limited Partnership and Terra Nitrogen Corporation, dated September 1, 2005. Incorporated by reference to Terra Nitrogen Company, L.P.’s Form 8-K filed on September 7, 2005.

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Exhibit 10.2	Conveyance, Assignment and Assumption Agreement, by and between Terra Nitrogen Corporation and Terra Nitrogen GP Inc., dated September 1, 2005. Incorporated by reference to Terra Nitrogen Company, L.P.’s Form 8-K filed on September 7, 2005.
Exhibit 10.3	First Amended and Restated Agreement of Limited Partnership of Terra Nitrogen, Limited Partnership, dated September 1, 2005. Incorporated by reference to Terra Nitrogen Company, L.P.’s Form 8-K filed on September 7, 2005.
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	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* filed herewith

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 CORPORATION
	as General Partner
By:	/s/ Francis G. Meyer
	Francis G. Meyer
	Vice President (Principal Accounting Officer)

Date: November 10, 2005

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