Form 10-Q

At the close of business on July 31, 2003, there were 18,501,576 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. Yes x No ¨

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

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, 2002. 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.

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 market each accounting period. Costs associated with settlement of natural gas purchase contracts and costs for shipping and handling are included in cost of sales.

Net income per limited partnership unit is computed by dividing net income, less a 2% share allocable to the General Partner for the six months ended June 30, 2003 and 2002, respectively, by 18,501,576 limited partner units. According to the Agreement of Limited Partnership of TNCLP, net income is allocated to the General Partner and the Limited Partners in each taxable year in the same proportion as Available Cash for such taxable year was distributed to the General Partner and the Limited Partners. If there is no cash distribution, net income is allocated to the Limited Partners and the General Partner generally based on their respective ownership percentages. Distributions of Available Cash are made 98% to the Limited Partners and 2% to the General Partner, except that the General Partner is entitled, as an incentive, to larger percentage interests (up to 50%) to the extent that distributions of Available Cash exceed specified amounts.

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). The Partnership paid a $4.7 million cash distribution ($0.25 per common unit) on February 7, 2003. No cash distributions were paid in the first six months of 2002.

The Partnership has an arrangement for demand deposits and notes with an affiliate to allow for excess Partnership cash to be deposited with or funds to be borrowed from Terra Capital, Inc., the parent of the General Partner. The amount of the demand note was $7.0 million at June 30, 2003

and bore interest at 4.0%, the rate paid by Terra Capital on its short-term borrowings. At June 30, 2002, $11.1 million was deposited with Terra Capital, Inc. and earned interest at the rate received on its commingled investments.

Natural gas is the principal raw material used in the Partnership’s production of nitrogen products. Natural gas prices are volatile and we manage this volatility through the use of derivative commodity instruments. The Partnership’s normal policy is to hedge 20-80% of its natural gas requirements for the upcoming 12 months and up to 50% of the requirements for the following 24-month period, provided that such arrangements would not result in costs greater than expected selling prices for our finished products. Deviations from this policy are permitted by notification of Terra Industries’ Board of Directors. The financial derivatives are traded in months forward and settlement dates are scheduled to coincide with gas purchases during those future periods. These contracts reference physical natural gas prices or approximate NYMEX futures contract prices. Contract prices are frequently based on prices at the most common and financially liquid location of reference for financial derivatives related to natural gas. However, natural gas supplies for our facilities are purchased for each plant at locations other than reference points, which often creates a location basis differential between the contract price and the physical price of natural gas. Accordingly, use of financial derivatives may not exactly offset the change in the price of physical gas.

The Partnership has entered into forward pricing positions for a portion of its natural gas requirements for the remainder of 2003, consistent with its policy. As a result of its policies, the Partnership has reduced the potential adverse financial impact of natural gas increases during the forward pricing period, but conversely, if natural gas prices were to fall, the Partnership will incur higher costs. Contracts were in place at June 30, 2003 to cover 19% of natural gas requirements for the succeeding twelve months.

Unrealized losses from forward pricing positions totaled $2.1 million as of June 30, 2003. The amount ultimately recognized by the Partnership will be dependent on published prices in effect at the time of settlement. The Partnership also had $0.4 million of realized losses on closed North America contracts relating to future periods that have been deferred to the respective period.

On June 30, 2003, the fair value of the derivatives resulted in a $2.3 million decrease in other current assets and a $2.5 million increase in current liabilities to reclassify deferred losses on closed contracts relating to future periods.

On February 27, 2003, the Partnership suspended production of ammonia and urea at its Blytheville, Arkansas plant and placed one of the two Verdigris, Oklahoma ammonia plants on standby due to the high natural gas prices. On March 13, 2003, the Partnership announced the restart of production at both facilities.

On June 26, 2003, the Partnership suspended production at its Blytheville, Arkansas facility due to expectations that the facility would not cover its cash costs because of continuing high natural gas costs and the seasonal decline in nitrogen fertilizer demand and prices. In response to this action

and as required by Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” Terra commenced a review to determine if the Blytheville facility’s carrying value was impaired. This review led Terra management to conclude that future market conditions may not justify the ongoing investment in maintenance and replacement capital necessary to extend operations for the remainder of the facility’s useful life. Accordingly a $40.7 million charge was recorded during the second quarter as an “Impairment of long-lived assets”. Terra currently plans to keep the Blytheville facility in a mothballed condition and may operate the facility from time to time as market conditions allow.

Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” became effective for the Partnership’s fiscal year beginning January 1, 2003. This standard requires the Partnership to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The adoption of this standard did not have a material effect on the Partnerships’ financial position or results of operations.

SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure” amends SFAS No. 123 “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Partnership believes that the adoption of this standard will not have an impact to our financial position.

SFAS No. 149, “Amendments of Statement 133 on Derivative Instruments and Hedging Activities”, amends and clarifies financial accounting for derivative instruments. This standard becomes effective in the Partnerships’ third quarter. The adoption of this standard is not expected to have a material effect on the Partnerships’ financial position or results of operations.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”, establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. This standard became effective for the Partnership contracts entered into after May 31, 2003. The adoption of this standard did not have a material effect on the Partnerships’ financial position or results of operations.

FASB Interpretation (“FIN”) No. 45, “Guarantor’s Accounting and Disclosure Requirements, Including Indirect Guarantees of Indebtedness of Others”, clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing certain guarantees. FIN 45 also expands the disclosure to be made by a guarantor in its financial statements about its obligations under certain guarantees that it has issued. The provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 became effective for the Partnership in 2003. FIN 45 did not have an impact to our financial position.

FASB Interpretation (“FIN”) No. 46, “Consolidation of Variable Interest Entities”, explains how to identify variable interest entities and how an enterprise assesses its interest in a variable interest entity to decide whether to consolidate that entity. The provisions of FIN 46 applied to the Partnership on June 15, 2003. FIN 46 did not have an impact to our financial position.

FASB Emerging Issues Task Force (“EITF”) issue 02-9, “Accounting for Changes that Result in a Transferor Regaining Control of Financial Assets Sold”, was effective for the Partnership on April 2, 2003 and did not have an impact on the Partnerships’ financial position.

FASB EITF issue 01-8, “Determining Whether an Arrangement Contains a Lease”, was assessed and did not have an impact on the Partnerships’ financial position.

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America for interim reporting purposes. The preparation of these financial statements requires us to make estimates and judgments that affect the amount of assets, liabilities, revenues and expenses at the date of our financial statements. Actual results may differ from these estimates under different assumptions or conditions.

Critical accounting policies are defined as those that are reflective of significant judgments and uncertainties, and potentially result in materially different results under different assumptions and conditions. Our critical accounting policies are described below.

Impairments of long-lived assets – We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of these items. Our cash flow estimates are based on historical results adjusted to reflect our best estimate of future market and operating conditions. The net carrying value of assets not recoverable is reduced to fair value. Our estimates of fair value represent our best estimate based on industry trends and reference to market rates and transactions. The recoverability of these assets is highly dependent upon the accuracy of certain underlying assumptions, such as future product prices and costs. During the 2003 second quarter, events occurred that necessitated an evaluation of recoverability of assets at our Blytheville facility.

On June 26, 2003, we suspended production at our Blytheville facility due to expectations that the facility would not cover its cash costs because of continuing high natural gas costs and the seasonal decline in nitrogen fertilizer demand and prices. In response to this action and as required by Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” Terra commenced a review to determine if the Blytheville facility’s carrying value was impaired. This review led Terra management to conclude that future market conditions may not justify the ongoing investment in maintenance and replacement capital necessary to extend operations for the remainder of the facility’s useful life. Accordingly a $40.7 million charge was recorded during the second quarter as an “Impairment of long-lived assets”. Terra currently plans to keep the Blytheville facility in a mothballed condition and may operate the facility from time to time as market conditions allow.

Revenue recognition – Revenue is recognized when title to finished product passes to the customer. Revenue is recognized as the net amount to be received after deducting estimated amounts for discounts and trade allowances. Revenue includes amounts paid by customers for shipping and handling.

Inventory valuation – Inventories are stated at the lower of cost or estimated net realizable value. The average cost of inventories is determined using the first-in, first-out method. The nitrogen industry is characterized by rapid change in both demand and pricing. Rapid declines in demand could result in temporary or permanent curtailment of production, while rapid declines in price could result in a lower of cost or market adjustment.

Volumes and prices for the three-month periods ended June 30, 2003 and 2002 follow:

Revenues for the quarter ended June 30, 2003 increased $13.2 million, or 11.1%, compared with the same quarter in 2002 as the result of higher sales prices partly offset by lower sales volumes. Lower nitrogen supplies were the primary factor causing the increased prices as compared to the 2002 second quarter. Sales volumes during the 2003 second quarter were impacted by lower production rates and reduced demand in response to high prices and increased competition from imports.

Second quarter gross profits declined $7.4 million from 2002. Higher 2003 sales prices contributed $35 million to gross profits, but were more than offset by higher natural gas costs and lower sales volumes. Second quarter natural gas costs increased almost 73%, or $28.0 million, $3.11/MMBtu in 2002 to $5.37/MMBtu in 2003 (net of forward pricing gains or losses.) As a result of forward price contracts, second quarter 2003 natural gas costs for the Partnership were $.8 million higher than spot prices.

Operating expenses were essentially unchanged in 2003 from 2002. Net interest income was $.1 million higher than the 2002 second quarter due to higher cash balances and lower short-term borrowings during the 2003 second quarter.

We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those asset are less that the carrying amount of these items. Our cash flow estimates are based on historical results adjusted to reflect our best estimate of future market and operating conditions. The net carrying value of assets not recoverable is reduced to fair value. Our estimates of fair value represent our best estimate based on industry trends and reference to market rates and transactions. The recoverability of these assets is highly dependent upon the accuracy of certain underlying assumptions, such as future product prices and natural gas costs. During our 2003 second quarter, events occurred that necessitated an evaluation of recoverability of assets at our Blytheville facility.

Impairment or Disposal of Long-Lived Assets,” a $40.7 million charge was recorded during the second quarter as discussed more fully above under “Critical Accounting Policies”.

Volumes and prices for the six-month periods ended June 30, 2003 and 2002 follow:

Revenues for the six months ended June 30, 2003 increased $26.8 million, or 16.5%, compared with the same period in 2002. Sales prices were higher as the result of decreased supplies of nitrogen fertilizer caused by high natural gas costs that resulted in industry-wide production curtailments.

Gross profits during the 2003 first six months declined $16.8 million from 2002. Higher 2003 sales priced contributed about $54 million to gross profits, but were more than offset by higher natural gas costs. First half natural gas costs increased almost $62 million over the 2002 first half as unit costs, net of forward pricing games and losses increased to $5.38/MMBtu during the 2003 first half compared to $2.86/MMBtu during the same 2002 period. Natural gas costs in the 2003 first half were $3.9 million lower than spot prices as the result of forward price contracts.

Operating expenses were essentially unchanged in 2003 from 2002. Net interest income was $.2 million higher than the 2002 first half due to higher cash balances and lower short-term borrowing during the first half of 2003.

We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those asset are less that the carrying amount of these items. Our cash flow estimates are based on historical results adjusted to reflect our best estimate of future market and operation conditions. The net carrying value of assets not recoverable is reduced to fair value. Our estimates of fair value represent our best estimate based on industry trends and reference to market rates and transactions. The recoverability of these assets is highly dependent upon the accuracy of certain underlying assumptions, such as future product prices and natural gas costs. During our 2003 second quarter, events occurred that necessitated an evaluation of recoverability of assets at our Blytheville facility.

Net cash used in operations for the first half of 2003 was $31.1 million composed of $4.5 million of cash used for operating activities and $26.5 million of increases to working capital balances. The increase in working capital primarily consisted of increases to inventory and accounts receivable and lower customer prepayments.

Capital expenditures of $6.9 million during the first half of 2003 were primarily to fund replacement and stay-in-business additions to plant and equipment. The Partnership expects 2003 capital expenditures to approximate $7.5 million to fund replacement and stay-in-business additions to plant and equipment.

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). The Partnership paid a $4.7 million cash distribution ($0.25 per common unit) on February 7, 2003. The Partnership paid no cash distributions in the first six months of 2002.

The Partnership, along with Terra Industries Inc. (“Terra”), Terra Capital, Inc. and other affiliates, has a revolving credit facility that expires in June 2005. Borrowing availability under the credit facility is generally based on eligible cash balances, 85% of eligible accounts receivable and 65% of eligible finished goods inventory, less outstanding letters of credit. At June 30, 2003, the Partnership had no outstanding revolving credit borrowings or outstanding letters of credit, resulting in remaining borrowing availability of approximately $38.2 million under the facility. Management expects the facility to be adequate to meet the Partnership’s operating cash needs. The credit facility also requires that we 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. In addition, if Terra’s borrowing availability falls below $60 million, Terra is required to have generated $60 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 amount of operating cash flows to measure credit facility compliance is different than amounts that can be derived from Terra’s financial statements. For the 12 months ended June 30, 2003, Terra’s operating cash flows as defined in the credit facility was $82.6 million.

The Partnership’s principal needs for funds are for support of its working capital and capital expenditures. The Partnership intends to fund its needs primarily from net cash provided by operating activities, and, to the extent required, from funds borrowed from others, including borrowings from Terra Capital, Inc., the parent of the General Partner.

Since June 30, Terra has experienced cash needs arising from margin calls on its forward natural gas positions as a result of declining prices, tightened terms by trade creditors and other operating requirements. As a result, Terra’s ability to meet its bank covenants will depend on future operating cash flows, working capital needs, receipt of customer prepayments and trade credit terms. Failure to meet these covenants could require additional costs and fees to amend the bank facilities or could result in termination of the Partnership’s bank facilities. Access to adequate bank facilities is critical to funding our operating cash needs. Terra currently anticipates that it will be able to meet its covenants through the end of this year, but that it will be close to the limits imposed by the

covenants. While natural gas prices have recently declined, if product margins in the second half of 2003 were to be as depressed as during portions of the first half, or if there were to be any adverse changes in the other factors discussed above, Terra may need a waiver of its bank covenants to meet its 2004 seasonal working capital needs. There can be no assurance Terra could obtain a bank waiver.

Because Terra expects to be close to the limits imposed by its bank agreement covenants, 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 limited.

At June 30, 2003, the General Partner and its affiliates owned 75.1% 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 of 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 are restricted under the terms of Terra’s bank credit agreement as described therein.

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.

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 and methanol. Contracts were in place at June 30, 2003 to cover 19% of its natural gas requirements for the succeeding twelve months (see Note 4). Because Terra expects to be close to the limits imposed by its bank agreement covenants, 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 limited.

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.

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

Exhibit 4.7		Amendment No. 1 to Amended and Restated Credit Agreement dated as of June 27, 2002 among Terra Capital, Inc., Terra Nitrogen (U.K.) Limited, and Terra Nitrogen, Limited Partnership, certain guarantors, certain lenders, certain issuing banks and Citicorp USA, Inc., previously filed as Exhibit 4.4 to Terra Industries Form 10-K dated March 11, 2003, and incorporated by reference herein

Exhibit 4.8		Amendment No. 2 to Amended and Restated Credit Agreement dated as of May 12, 2003, previously filed as Exhibit 4.5 to Terra Industries’ Form 10-Q dated August 11, 2003, and incorporated by reference herein

Exhibit 31		Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Exhibit 32		Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Form 8-K dated June 23, 2003 announcing closing of the Blytheville, Arkansas manufacturing plant

Form 8-K dated July 31, 2003 announcing second quarter results

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)

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

	June 30, 2003		December 31, 2002		June 30, 2002
ASSETS
Current assets:
Cash and cash equivalents	$	10	$	35,738	$	11,125
Accounts receivable		30,519		26,760		28,781
Inventory – finished products		18,537		10,411		12,137
Inventory – materials and supplies		5,983		9,692		9,754
Prepaid expenses and other current assets		2,282		6,659		2,744

Total current assets		57,331		89,260		64,541

Net property, plant and equipment		95,495		126,056		130,849
Other assets		5,144		10,708		7,593

Total assets	$	157,970	$	226,024	$	202,983

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Short-term note payable to affiliates		7,040	$	—	$	—
Accounts payable and accrued liabilities		27,266		21,520		14,131
Customer prepayments		328		21,314		741
Current portion of long-term debt and capital lease obligations		56		53		53

Total current liabilities		34,690		42,887		14,925

Long-term debt and capital lease obligations		8,304		8,333		8,362
Long-term payable to affiliates		5,316		5,316		5,316
Other long-term liabilities		1,500		—		—
Partners’ capital		108,160		169,488		174,380

Total liabilities and partners’ capital	$	157,970	$	226,024	$	202,983

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Revenues	$	117,977		$	104,529		$	188,832		$	161,638
Other income		172			364			254			655

Total revenues		118,149			104,893			189,086			162,293
Cost of goods sold		119,890			99,198			195,851			152,264

Gross profit (loss)		(1,741	)		5,695			(6,765	)		10,029
Operating expenses		2,476			2,649			4,495			4,644
Impairment of long-lived assets		40,655			—			40,655			—

Operating income (loss)		(44,872	)		3,046			(51,915	)		5,385
Interest expense		(3	)		(22	)		(6	)		(125	)
Interest income		59			1			72			1

Net income (loss)	$	(44,816	)	$	3,025		$	(51,849	)	$	5,261

Net income (loss) allocable to limited partners’ interest	$	(43,920	)	$	2,965		$	(50,812	)	$	5,156

Net income (loss) per limited partnership unit	$	(2.37	)	$	0.16		$	(2.75	)	$	0.28

	Six Months Ended June 30,
	2003			2002
Operating activities:
Net income from operations	$	(51,849	)	$	5,261
Adjustments to reconcile net income to net cash flows from operating activities:
Impairment of long-lived assets		40,655			—
Depreciation and amortization		6,620			6,547
Changes in operating assets and liabilities:
Receivables		(3,759	)		3,530
Inventories		(8,612	)		6,528
Prepaid expenses		4,377			2,814
Accounts payable, accrued liabilities and customer prepayments		(20,003	)		(235	)
Change in other assets		1,449			1,811

Net cash flows from operating activities		(31,122	)		26,256
Net cash flows from investing activities:
Capital expenditures		(6,903	)		(1,062	)
Financing activities:
Net changes in short-term borrowings		7,040			(14,293	)
Issuance (repayment) of long-term debt and capital lease obligations		(23	)		214
Partnership distributions paid		(4,720	)		—

Net cash flows from financing activities		(2,297	)		(14,079	)

Net increase (decrease) in cash and cash equivalents		(35,728	)		11,115
Cash and cash equivalents at beginning of period		35,738			10

Cash and cash equivalents at end of period	$	10		$	11,125

(in thousands, except for Units)	Limited Partners’ Interests			General Partners’ Interests			Accumulated Other Comprehensive Income (loss)			Total Partners’ Capital
Partners’ capital at January 1, 2003	$	177,463		$	(10,248	)	$	2,273		$	169,488
Net loss		(50,812	)		(1,037	)		—			(51,849	)
Change in fair value of derivatives		—			—			(4,759	)		(4,759	)

Comprehensive loss		—			—			—			(56,608	)
Distributions		(4,626	)		(94	)		—			(4,720	)

Partners’ capital at June 30, 2003	$	122,025		$	(11,379	)	$	(2,486	)	$	108,160

Limited partner units issued and outstanding at June 30, 2003					18,501,576

(in thousands, except for Units)	Limited Partners’ Interests		General Partners’ Interest			Accumulated Other Comprehensive Income (loss)			Total Partners’ Capital
Partners’ capital at January 1, 2002	$	178,808	$	(10,221	)	$	(1,087	)	$	167,500
Net income		5,156		105			—			5,261
Change in fair value of derivatives		—		—			1,619			1,619

Comprehensive income		—		—			—			6,880

Partners’ capital at June 30, 2002	$	183,964	$	(10,116	)	$	532		$	174,380


Limited partner units issued and outstanding at June 30, 2002				18,501,576

	2003			2002
	Volumes (000 tons)	Unit Price ($/ton)*		Volumes (000 tons)	Unit Price ($/ton)*
Ammonia	82	$	253	129	$	159
UAN	638		102	825		71
Urea	135		171	122		114