SECURITIES AND EXCHANGE COMMISSION

 

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

 

AES Eastern Energy, L.P.

(Exact name of registrant as specified in its charter)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

Yes ý       No o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)

 

Yes o       No ý

 

Registrant is a wholly owned subsidiary of The AES Corporation. Registrant meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is filing this Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.

 

 

TABLE OF CONTENTS

 

PART I
Item 1.		Condensed Consolidated Financial Statements (Unaudited)
AES EASTERN ENERGY, L.P.
Condensed Consolidated Financial Statements:
	Consolidated Statements of Income for the three months ended September 30, 2003 and September 30, 2002
	Consolidated Statements of Income for the nine months ended September 30, 2003 and September 30, 2002
	Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2003 and September 30, 2002
	Statement of Changes in Partners’ Capital for the nine months ended September 30, 2003
	Notes to Condensed Consolidated Financial Statements
AES NY, L.L.C. (General Partner of AES Eastern Energy, L.P.)*
Condensed Consolidated Financial Statements:
	Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002
	Notes to Condensed Consolidated Balance Sheets

 

*	The condensed consolidated balance sheets of AES NY, L.L.C. contained in this Quarterly Report on Form 10-Q should be considered only in connection with its status as the general partner of AES Eastern Energy, L.P.
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations
		(a)  Results of Operations
		(b)  Liquidity and Capital Resources
Item 4.		Controls and Procedures
PART II
Item 1.		Legal Proceedings
Item 6.		Exhibits and Reports on Form 8-K
		(a)  Exhibits
		(b)  Reports on Form 8-K
Signatures

 

2

 

PART I - FINANCIAL INFORMATION

 

Item 1.  Condensed Consolidated Financial Statements (Unaudited)

 

AES Eastern Energy, L.P.

Condensed Consolidated Statements of Income

For the three months ended September 30, 2003 and September 30, 2002

(Amounts in Thousands)

 

Three months ended September 30,		2003			2002
Operating Revenues
Energy		$	109,302		$	87,241
Capacity		7,420			11,829
Transmission congestion contract		1,061			(14,730		)
Other		349			1,448
Total operating revenues		118,132			85,788
Operating Expenses
Fuel		41,597			36,833
Operations and maintenance		4,861			4,037
General and administrative		14,694			17,123
Depreciation and amortization		9,032			9,040
Total operating expenses		70,184			67,033
Operating Income		47,948			18,755
Other Income/(Expense)
Interest expense		(14,903		)	(15,596		)
Interest income		456			482
Loss on derivative valuation		(9		)	(362		)
Net Income		$	33,492		$	3,279

 

The notes are an integral part of the condensed consolidated financial statements.

 

3

 

AES Eastern Energy, L.P.

Condensed Consolidated Statements of Income

For the nine months ended September 30, 2003 and September 30, 2002

(Amounts in Thousands)

 

Nine months ended September 30,		2003			2002
Operating Revenues
Energy		$	303,692		$	222,356
Capacity		23,817			26,954
Transmission congestion contract		(5,364		)	4,239
Other		1,707			6,141
Total operating revenues		323,852			259,690
Operating Expenses
Fuel		112,471			100,833
Operations and maintenance		14,628			12,375
General and administrative		42,604			43,898
Depreciation and amortization		27,031			26,411
Total Operating Expenses		196,734			183,517
Operating Income		127,118			76,173
Other Income/(Expense)
Interest expense		(44,436		)	(44,398		)
Interest income		1,538			1,552
Gain(loss) on derivative valuation		179			(277		)
Net income before cumulative effect of change in accounting principle		84,399			33,050
Cumulative effect of change in accounting principle		(1,656		)	—
Net Income		$	82,743		$	33,050

 

The notes are an integral part of the condensed consolidated financial statements.

 

4

 

AES Eastern Energy, L.P.

Condensed Consolidated Balance Sheets

September 30, 2003 and December 31, 2002

(Amounts in Thousands)

 

		Sept. 30, 2003			Dec. 31, 2002
ASSETS
Current Assets
Restricted cash:
Operating - cash and cash equivalents		$	20,288		$	4,605
Revenue account		47,107			76,566
Accounts receivable - trade		36,051			35,233
Accounts receivable - affiliates		259			—
Accounts receivable - other		1,198			1,235
Inventory		27,111			26,982
Prepaid expenses		7,752			7,617
Total Current Assets		139,766			152,238
Property, Plant, Equipment and Related Assets Land		7,011			7,011
Electric generation assets (net of accumulated depreciation of $147,289 and $117,222)		908,792			929,654
Total property, plant, equipment and related assets		915,803			936,665
Other Assets
Deferred financing - net of accumulated amortization of $1,091 and $863		379			293
Derivative valuation		19,159			2,510
Transmission congestion contract		—			2,416
Rent reserve account		31,346			31,717
Total Assets		$	1,106,453		$	1,125,839
LIABILITIES
Current Liabilities
Accounts payable		$	2,013		$	1,195
Lease financing - current		8,118			1,665
Environmental remediation		—			20
Accrued interest expense		14,061			28,078
Due to The AES Corporation and affiliates		9,125			6,945
Accrued coal and rail expenses		8,751			8,492
Other liabilities and accrued expenses		11,570			9,311
Total Current Liabilities		53,638			55,706
Long-term liabilities
Lease financing - long term		629,815			637,660
Environmental remediation		5,056			9,192
Defined benefit plan obligation		17,016			17,439
Derivative valuation liability		19,896			20,996
Asset retirement obligation		9,747			—
Transmission congestion contract		836			—
Other liabilities		2,375			2,600
Total Long-term Liabilities		684,741			687,887
Total Liabilities		738,379			743,593
Commitments and Contingencies (Note 2)
PARTNERS’ CAPITAL		368,074			382,246
Total Liabilities and Partners’ Capital		$	1,106,453		$	1,125,839

 

The notes are an integral part of the condensed consolidated financial statements.

 

5

 

 

AES Eastern Energy, L.P.

Condensed Consolidated Statements of Cash Flows

For the nine months ended September 30, 2003 and September 30, 2002

(Amounts in Thousands)

 

		Nine months ended Sept. 30, 2003			Nine months ended Sept. 30, 2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income		$	82,743		$	33,050
Adjustments to reconcile net income to Net cash provided by operating activities:
Cumulative effect of change in accounting principle		1,656			—
Depreciation and amortization		27,031			26,622
Loss on disposal of asset		3
Asset retirement obligation accretion		536			—
Loss(Gain) on derivative valuation		3,073			(51		)
Write off of deferred financing		21			—
Net defined benefit plan cost		(423		)	(1,392		)
Changes in current assets and liabilities:
Accounts receivable		(1,040		)	(1,847		)
Inventory		(129		)	2,855
Prepaid expenses		(135		)	(845		)
Accounts payable		818			1,515
Accrued interest expense		(14,017		)	(14,255		)
Due to The AES Corporation and affiliates		2,180			896
Accrued expenses and other liabilities		2,293			(325		)
Net cash provided by operating activities		104,610			46,223
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for capital additions		(2,545		)	(6,556		)
Decrease in restricted cash		13,776			28,624
Net change in rent reserve account		371			378
Net cash provided by investing activities		11,602			22,446
CASH FLOWS FROM FINANCING ACTIVITIES:
Partners distribution paid		(114,600		)	(63,960		)
Principal payments on lease obligations		(1,392		)	(6,223		)
Partner’s contribution		115			1,514
Payments for deferred financing		(335		)	—
Net cash used in financing activities		(116,212		)	(68,669		)
CHANGE IN CASH AND CASH EQUIVALENTS		—			—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		—			—
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	—		$	—
Supplemental Disclosure of Cash Flow Information:
Interest paid		$	55,885		$	56,354
Supplemental Disclosure of Non-cash Flow Information:
Adoption of SFAS No. 143		$	3,396		$	—

 

The notes are an integral part of the condensed consolidated financial statements.

 

6

 

AES Eastern Energy, L.P.

Consolidated Statement of Changes in Partners’ Capital

For the nine months ended September 30, 2003

(Amounts in Thousands)

 

		General Partner			Limited Partner			Total			Accumulated Other Comprehensive Income (Loss)			Comprehensive Income
Balance, December 31, 2002		$	4,245		$	378,001		$	382,246		$	(18,432	)
Net income		827			81,916			82,743						82,743
Distributions paid		(1,146		)	(113,454		)	(114,600		)
Partner’s contribution (See Note 5)		—			115			115
Other comprehensive gain (See Note 3)		176			17,394			17,570			17,570			17,570
Comprehensive income (loss)											$	(862	)	$	100,313
Balance, September 30, 2003		$	4,102		$	363,972		$	368,074

 

The notes are an integral part of the condensed consolidated financial statements.

 

7

 

Notes to the Unaudited Condensed Consolidated Financial Statements

 

Note 1.   Unaudited Condensed Consolidated Financial Statements

 

The accompanying unaudited condensed consolidated financial statements of AES Eastern Energy, L.P. (the Partnership) reflect all adjustments which are necessary, in the opinion of management, for a fair presentation of the Partnership’s consolidated results for the interim periods. All such adjustments are of a normal recurring nature. The unaudited condensed consolidated financial statements should be read in conjunction with the Partnership’s consolidated financial statements and notes contained therein, as of December 31, 2002 and the year then ended, which are set forth in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2002.

 

Note 2.  Commitments and Contingencies

 

Coal Purchases - In connection with the acquisition of the Partnership’s four coal-fired electric generating stations (the Plants), the Partnership assumed from New York State Electric & Gas Corporation (NYSEG) an agreement to purchase the coal required by the Somerset and Cayuga Plants.  Each year either party can request renegotiation of the price of one-third of the coal supplied pursuant to this agreement. The supplier requested renegotiation during 2001 for the 2002 lot but the parties failed to reach agreement. The supplier requested renegotiation during 2002 for the 2003 lot plus the 2002 lot for which agreement was not reached. On September 11, 2002, the Partnership and the supplier reached agreement on both of the lots. Therefore, the commitment of the Partnership for 2003 is three lots for the Somerset Plant plus 70% of the anticipated coal usage for the Cayuga Plant.  The termination date for the contract is December 31, 2003. The parties were required to meet no later than June 30, 2003, to determine whether the agreement would be extended under mutually agreeable terms and conditions.  It has been determined that the agreement will not be extended. The Partnership can provide no assurances that it will be able to enter into other agreements on terms and conditions that are as favorable as the current contract.

 

As of the acquisition date of the Plants, the contract prices for the coal purchased through 2002 were above the market price, and the Partnership recorded a purchase accounting liability for approximately $15.7 million related to the fulfillment of its obligation to purchase coal under this agreement.  The purchase accounting liability was amortized as a reduction to coal expense over the life of the underlying contracts. As of December 31, 2002, the underlying contracts were fully amortized.

 

Based on the coal purchase commitments for the year ended December 31, 2003, the Partnership has expected coal purchases ranging between $90 and $100 million. Currently, the Partnership has expected coal purchase commitments ranging between $100 and $110 million for 2004.

 

As of September 30, 2003, the remaining anticipated coal purchase commitments for the year ending December 31, 2003 were between $20 and $25 million.

 

On September 4, 2003, the Partnership and AES Odyssey, L.L.C. (Odyssey) have amended their current contract to include management of the Partnership’s coal and emission inventories. The Partnership has also agreed to increase the fees paid to Odyssey by the Partnership to $400,000 per month from $300,000 per month.

 

Odyssey, in concert with the Partnership, is using a strategy of varying-term contracts with multiple suppliers to develop flexibility in the supply chain to meet the demands of a fleet of merchant Plants.

 

Transmission Agreements - On August 3, 1998, AES NY, L.L.C., the general partner of the Partnership (the General Partner), entered into an agreement with NYSEG for the purpose of transferring certain rights and obligations from NYSEG to the General Partner under an existing transmission agreement among Niagara Mohawk Power Corporation (NIMO), the New York Power Authority, NYSEG and Rochester Gas & Electric Corporation, and an existing transmission agreement between NYSEG and NIMO. This agreement provides for the assignment of rights to transmit energy from the Somerset Plant and other sources to remote load areas and other delivery points, and was assumed by the Partnership on the date of acquisition of the Plants. In accordance with its plan, as of the acquisition date, the Partnership discontinued using this service. The Partnership did not transmit over these lines but was required to pay the monthly fees until the effective cancellation date, November 19, 1999. These fees aggregated approximately $3.4 million over the six months ended December 31, 1999, and were recorded as a purchase accounting liability. Because the Partnership did not use the lines during this period, the Partnership received no economic benefit subsequent to the acquisition.

 

The Partnership was informed by NIMO that the Partnership would be responsible for the monthly fees of $500,640 under the existing transmission agreement to the originally scheduled termination date of October 1, 2004. On October 5, 1999, the Partnership filed a complaint against NIMO alleging that the Partnership has a right to non-firm transmission service upon six months prior notice without payment of $500,640 in monthly fees subsequent to the cancellation date of November 19, 1999.

 

8

 

On March 9, 2000, a settlement was reached between the Partnership and NIMO, which was approved by the Federal Energy Regulatory Commission (FERC) on May 10, 2000. According to the settlement, the Partnership will continue to pay NIMO a fixed rate of $500,640 per month during the period of November 20, 1999 to October 1, 2004, and, in turn, will receive a form of transmission service commencing on May 1, 2000, which the Partnership believes will provide an economic benefit over the period of May 1, 2000 to October 1, 2004.

 

The Partnership shall have the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 Megawatts (MW) over firm transmission lines from the Somerset Plant. The Partnership shall have the right to designate alternate points of delivery on NIMO’s transmission system provided that the Partnership shall not be entitled to receive any transmission service charge credit on the NIMO system.

 

The transmission congestion contract is accounted for as a derivative under SFAS No. 133. The transmission congestion contract was entered into because it provided a reasonable settlement for resolving a FERC issue. The agreement is essentially a swap between the congestion component of the locational prices posted daily by the New York Independent System Operator (NYISO) in western New York and the more heavily populated areas in eastern New York. The agreement is a financially settled contract since there is no requirement to flow power under this agreement. The agreement generates gains or losses from exposure to shifts or changes in market prices. The Partnership recorded a loss of approximately $5.4 million versus income of approximately $4.2 million in the first nine months of 2003 and 2002, respectively, related to this contract.

 

On June 25, 2003, the Somerset plant filed a complaint against NIMO with the FERC. The complaint involves outstanding station service charges for the period April 2000 to May 2003. The Plant has calculated that the outstanding charges owed are $290,000, while NIMO has calculated that the outstanding charges are $3.6 million. The Partnership is awaiting the FERC decision.

 

Line of Credit Agreement - On November 20, 2002, the Partnership signed an agreement with Union Bank of California, N.A. for a one-year extension of its current working capital and letter of credit facility. On April 16, 2003, the Partnership signed an amendment to its November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes another one-year extension of the current facility; the maturity date of the working capital and letter of credit facility is now January 2, 2005. The amendment also increases Union Bank of California’s commitment from $15 million to $20 million. On April 25, 2003, the Partnership further amended its November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes a commitment from Citibank, N.A. for the remaining $15 million of the facility. There have been two borrowings under the new facility. The first borrowing was for $9.7 million on January 10, 2003 at an interest rate of 5.75%. This borrowing was repaid in full on January 28, 2003. The second borrowing was for $9.7 million on July 9, 2003 at an interest rate of 5.5%. This borrowing was repaid in full on July 25, 2003. As of September 30, 2003, of the $35 million committed, the Partnership has issued letters of credit of $13 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

 

The AES Corporation on January 6, 2003 and February 25, 2003 authorized the Partnership to issue letters of credit to counterparties on its $350 million senior secured revolving credit facility to the amount of $25 million and $35 million for the years of 2003 and 2004, respectively. If required by the Partnership, The AES Corporation has authorized additional future use of its $350 million senior secured revolving credit facility. As of September 30, 2003, the Partnership has issued letters of credit of $9.7 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

 

On July 14, 2003, Mirant Corporation announced it and certain of its U.S. subsidiaries had filed voluntary petitions for reorganizations under Chapter 11 of the U.S. Bankruptcy Code. Mirant Corp., Mirant Americas Generation, LLC and substantially all of the companies’ wholly owned subsidiaries in the United States were included in the Chapter 11 filings. On August 8, 2003, the Partnership executed a Postpetition Assurance and Amendment Agreement with Mirant Americas Energy Marketing, LP (MIR). This Agreement gives the Partnership superpriority administrative claims status pursuant to Section 364(c)(1) of the Bankruptcy Code for amounts owed by MIR to the Partnership.  As of September 30, 2003, the Partnership has no outstanding receivables with MIR.  The Partnership’s current credit exposure is approximately $127,000 through December 31, 2003.

 

Environmental - The Partnership has recorded a liability for environmental remediation associated with the acquisition of the Plants. On an ongoing basis, the Partnership monitors its compliance with environmental laws. Because of the uncertainties associated with environmental compliance and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued.

 

The Partnership received an information request letter dated October 12, 1999 from the New York Attorney General, which sought detailed operating and maintenance history for the Westover and Greenidge Plants. On January 13, 2000, the Partnership received a subpoena from the New York State Department of Environmental Conservation (DEC) seeking similar operating and maintenance history from the Westover and Greenidge Plants. The Partnership has provided materials responding to the request from the Attorney General and the DEC. This information was sought in connection with the Attorney General’s and the DEC’s investigations of several electricity generating stations in New York that are suspected of undertaking modifications in the past without undergoing an air permitting review.

 

9

 

On April 14, 2000, the Partnership received a request for information pursuant to Section 114 of the Clean Air Act from the U.S. Environmental Protection Agency (EPA) seeking detailed operating and maintenance history data for the Cayuga and Somerset Plants. The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Clean Air Act associated with repairs, maintenance, modifications and operational changes made to coal-fired facilities over the years. The EPA’s focus is on whether the changes were subject to new source review permitting or new source performance standards, and whether best available control technology was or should have been used. The Partnership has provided the requested documentation.

 

By letter dated May 25, 2000, the DEC issued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Act and the Environmental Conservation Law at the Greenidge and Westover Plants related to NYSEG’s alleged failure to undergo an air permitting review for repairs and improvements made during the 1980s and 1990s, which was prior to the acquisition of the Plants by the Partnership. Pursuant to the purchase agreement relating to the acquisition of the Plants from NYSEG, the Partnership agreed to assume responsibility for environmental liabilities that arose while NYSEG owned the Plants. On September 12, 2000, the Partnership agreed with NYSEG that the Partnership will assume the defense of and responsibility for the NOV, subject to a reservation of its right to assert applicable exceptions to its contractual undertaking to assume preexisting environmental liabilities.

 

The Partnership is currently in negotiation with both the EPA and DEC. If the parties are unable to reach an agreement, the EPA and DEC could issue the Partnership a notice or notices of violations or file a complaint in court alleging violations of the Clean Air Act and New York Environmental Conservation Law. If the Attorney General, DEC or the EPA does file an enforcement action against the Somerset, Cayuga, Westover or Greenidge Plants, then penalties may be imposed and further emissions reductions might be necessary at these Plants which could require the Partnership to make substantial expenditures. The Partnership is unable to estimate the effect of such an enforcement action on its financial condition or results of future operations.

 

Nitrogen Oxide and Sulfur Dioxide Emission Allowances - The Plants emit nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of burning coal to produce electricity.

 

The Plants have been allocated allowances by the DEC to emit NOx during the ozone season, which runs from May 1 to September 30. Each NOx allowance authorizes the emission of one ton of NOx during the ozone season. New York State and the other states in the Mid-Atlantic and Northeast region are classified as the Ozone Transport Region in the federal Clean Air Act, which designates the Ozone Transport Region as not being in compliance with the ozone National Ambient Air Quality Standard. The states in the Ozone Transport Region have agreed to implement a three-phase process to reduce NOx emissions in the region in order to comply with the federal Clean Air Act Title I requirements for ozone non-compliance areas. Implementation of the Phase III emission rules commenced on May 1, 2003. The Phase III NOx regulations set forth a NOx allowance allocation program which gives the Partnership 2,516 NOx emission allowances for 2003.

 

The Plants are also subject to SO2 emission allowance requirements imposed by the EPA. Each SO2 allowance authorizes the emission of one ton of SO2 during the calendar year. All of the Plants are currently subject to SO2 allowance requirement, and are required to hold sufficient allowances to emit SO2.

 

Both NOx and SO2 allowances may be bought, sold or traded. If NOx and/or SO2 emissions exceed the allowance amounts allocated to the Plants, then the Partnership may need to purchase additional allowances on the open market or otherwise reduce its production of electricity to stay within the allocated amounts. It is expected that the Partnership may have a shortfall during 2003 of approximately 9,500 to 10,500 SO2 allowances and approximately 1,000 to 1,100 NOx allowances assuming the units are operated at forecasted capacities. At current market prices, the cost could range from $6.3 million to $7.4 million to purchase sufficient SO2 and NOx allowances for 2003.

 

In October 1999, New York State Governor Pataki announced an executive order mandating additional emission reductions from New York State power plants. The Governor’s initiative requires non-ozone season NOx emission reductions based on 0.15 lbs/Mmbtu starting in 2004, and a 50% reduction from the power plants’ Title IV SO2 emissions being phased in from 2005 to 2008. The program will be implemented through a market-based mechanism. The rules implementing the Governor’s initiative (NYCRR Parts 237 and 238) were adopted in March 2003. A number of entities have started legal actions to overturn these rules.

 

In September 2003, New York State determined the amount of NOx emissions allowances that would be allocated to the Plants. The allocation is several thousand tons short of the Partnership’s average historical NOx emissions for the Plants during the control period. The Partnership’s compliance plan cannot be finalized until NOx allowance market prices are determined.

 

The SO2 allocations are not scheduled to occur until January 2004. The impact of the SO2 rules on the Partnership cannot fully be determined until New York State makes its determination as to how many SO2 emission allowances will be allocated to each of the Plants and a market price is determined.

 

10

 

The Partnership voluntarily disclosed to the DEC and EPA on November 27, 2002 that NOx exceedances appear to have occurred on October 30 and 31 and November 1-8 and 10 of 2002. The exceedances were discovered through an audit by plant personnel of the Plants’ NOx Reasonably Available Control Technology (RACT) tracking system which monitors NOx emissions at all four Plants subject to the Partnership’s NOx RACT Plan. The Plants have taken all reasonable, good faith efforts to assess and correct the exceedances. Immediately upon the discovery of the calculation error, the Selective Catalytic Reduction System (SCR) at the Somerset Plant was activated to reduce NOx emissions. Emission data indicates that the Plants had already returned to a compliant operation by the time the error was discovered. The EPA has decided to defer to the DEC for review of the self-disclosure letter and technical issues. The Partnership is unable to predict any potential actions or fines the DEC may require, if any.

 

The Partnership voluntarily disclosed to the DEC in January 2003 that the Cayuga Plant had inadvertently burned synfuel (coal with a latex binder applied), which it is not permitted to burn.  The Cayuga Plant had entered into an agreement with a supplier to purchase coal. The Cayuga Plant received approximately one 9,000-ton train per month from April 24, 2001 to December 27, 2002. In January 2003, the Plant became aware that the product it had been receiving was synfuel. The Plants suspended all shipments from that supplier until a resolution could be reached. The Cayuga Plant has reviewed the emission and operation data that showed there was no adverse effect to air quality attributable to burning the material. The Partnership is unable to predict any potential actions or fines the DEC may require, if any. In July 2003, the Partnership reached an agreement with the supplier to resume shipment of coal in order to satisfy contractual obligations. As part of this agreement, the supplier has provided a written guarantee stating that all fuel shipments will be coal.

 

In April 2002, the EPA proposed to establish location, design, construction and capacity standards for cooling water intake structures at existing power plants. The EPA is developing these regulations under the terms of an Amended Consent Decree in Riverkeeper, Inc vs. Whitman, US District Court, Southern District of New York. The new scheduled finalization of the rules for existing facilities has been extended by six months to February 16, 2004. These new rules will impose new compliance requirements, with potentially significant costs, on operating plants across the nation with cooling water intake structures. Cost items include various environmental and engineering studies and potential capital and maintenance costs. The Partnership has not determined the effects, if any, of these regulations on its financial position or results of operations.

 

On July 24, 2003, Governor Pataki announced that ten Northeastern U.S. states (including New York) have agreed to work to develop a regional market-based emissions trading system to reduce power plants’ CO2 emissions. The goal is to reach an agreement by April 2005 on a cap and trade program. Until such time as the rules are developed to implement such a program the Partnership cannot determine what its impact would be on the Partnership’s financial position or results of operations.

 

Note 3.  Price Risk Management

 

Comprehensive Income (Loss) - The Partnership accounts for its derivative instruments in accordance with SFAS No. 133,” Accounting for Derivative Instruments and Hedging Activities”.  The Partnership utilizes derivative financial instruments to hedge commodity price risk. The Partnership utilizes electric derivative instruments, including swaps and forwards, to hedge the risk related to forecasted electricity sales over the next four years. The majority of the Partnership’s electric derivatives are designated and qualify as cash flow hedges. No significant amounts of hedge ineffectiveness were recognized in earnings during the nine months ended September 30, 2003.

 

Gains and losses on derivatives reported in accumulated other comprehensive income are reclassified into earnings when the hedged forecasted sale occurs. Amounts recorded in other comprehensive income (loss) during the nine months ended September 30, 2003, were as follows (in millions):

 

Balance as of December 31, 2002		$	(18.4	)
Reclassified to earnings		(41.5		)
Change in fair value		59.0
Balance, September 30, 2003		$	(0.9	)

 

In addition to the electric derivatives classified as cash flow hedge contracts, the Partnership has a Transmission Congestion Contract that is a derivative under the definition of SFAS No. 133, but does not qualify for hedge accounting.  This contract is recorded at fair value on the balance sheet with changes in the fair value recognized through earnings.

 

11

 

Note 4.  New Accounting Pronouncements

 

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which became effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred.  The new liability was recorded in the first quarter of 2003. The Partnership capitalized the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  Upon settlement of the liability, the Partnership will settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Partnership adopted SFAS No. 143 effective January 1, 2003.

 

The Partnership has completed a detailed assessment of the specific applicability and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily active ash landfills and water treatment basins. Upon adoption of SFAS No. 143, the Partnership recorded a liability of $9.2 million and a net asset of approximately $3.3 million, which are included in the electric generation assets, and reversed a $4.2 million environmental remediation liability it had previously recorded. The difference between the amounts previously recorded and the net SFAS No. 143 liability is a loss recorded as the cumulative effect of a change in accounting principle of $1.7 million. Reconciliation of asset retirement obligation liability for the nine months ending September 30, 2003 was as follows (in millions):

 

Balance as of January 1, 2003		$	9.2
Accretion		$	0.5
Balance, September 30, 2003		$	9.7

 

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure”. SFAS No. 148 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, SFAS No. 148 amends the disclosure requirements of SFAS No. 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 expects to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation.  All employee awards granted, modified or settled after January 1, 2003, were recorded using the fair value based method of accounting. (See Note 5). The Partnership’s adoption of the prospective method of accounting for stock-based employee compensation did not have any material impact on its financial position or results of operations.

 

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The adoption of SFAS No. 149 did not have a material impact on the Partnership’s financial position or results of operations.

 

The Partnership adopted the disclosure provisions of FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” in the fourth quarter of 2002.  The Partnership will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. In general, the Partnership enters into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent’s guarantee of its subsidiary’s debt to a third party (whether the parent is a corporation or an individual), a subsidiary’s guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor guarantees of a company’s own future performance.  Adoption of FIN 45 had no impact on the Partnership’s historical financial statements, as existing guarantees are not subject to the measurement provisions of FIN 45. The adoption of the liability recognition provisions of FIN 45 did not have a material impact on the Partnership’s financial position or results of operations.

 

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In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities”. This is an interpretation of Accounting Research Bulletin No. 51, “Consolidation of Variable Interest Entities”. FIN 46 requires certain variable interest entities (VIEs) to be consolidated by the primary beneficiary if the entity does not effectively disperse risks among the parties involved. The provisions of FIN 46 are effective immediately for those VIEs created after January 31, 2003. The provisions are effective for the first period beginning after June 15, 2003 for those variable interests held prior to February 1, 2003. The sales - leaseback transaction under which the Somerset and Cayuga Plants were acquired qualifies as a VIE. The sales - leaseback rules require that the leases be treated as financing leases for purposes of the Partnership’s financial statements, which they have been from the inception of the Partnership. The adoption of FIN 46 did not have a material impact on the Partnership’s financial position or results of operations.

 

Note 5. Long-term Incentive Program

 

Stock Option Plan - Employees of the Partnership participate in the AES Stock Option Plan (the SOP) that provides for grants of stock options to eligible participants. Prior to 2003, the Partnership accounted for the SOP under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations.  No stock-based employee compensation cost is reflected in 2002 net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.  Effective January 1, 2003, the Partnership adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation”, prospectively to all employee awards granted, modified or settled after January 1, 2003.  Awards under the SOP vest over periods ranging from two to five years.  Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards from the inception of the Partnership. The expense recognized under the prospective method for the nine months ended September 30, 2003 is approximately $115,000.

 

Note 6.   Reclassifications

 

Certain 2002 amounts have been reclassified on the condensed consolidated financial statements to conform with the 2003 presentation.

 

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Item 1.  Condensed Consolidated Financial Statements (Unaudited)

 

AES NY, L.L.C.

Condensed Consolidated Balance Sheets

September 30, 2003 and December 31, 2002

(Amounts in Thousands)

 

		September 30, 2003			December 31, 2002
ASSETS
Current Assets
Restricted cash:
Operating - cash and cash equivalents		$	20,288		$	5,116
Revenue account		47,427			76,566
Accounts receivable - trade		36,051			35,233
Accounts receivable - affiliates		3,007			2,935
Accounts receivable - other		1,227			1,264
Inventory		27,111			26,982
Prepaid expenses		7,809			7,726
Total current assets		142,920			155,822
Property, Plant, Equipment and Related Assets
Land		7,461			7,461
Electric generation assets (net of accumulated depreciation of $152,814 and $122,378)		908,792			929,654
Total property, plant, equipment and related assets		916,253			937,115
Other Assets
Deferred financing (net of accumulated amortization of $1,091 and $863)		379			293
Derivative valuation asset		19,159			2,510
Transmission congestion contract		—			2,416
Rent reserve account		31,346			31,717
Total Assets		$	1,110,057		$	1,129,873
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities
Accounts payable		$	2,016		$	1,195
Lease financing - current		8,118			1,665
Environmental remediation		—			35
Accrued interest expense		14,061			28,078
Due to The AES Corporation and affiliates		9,299			7,173
Accrued coal and rail expenses		8,751			8,492
Other liabilities and expenses		11,702			11,264
Total current liabilities		53,947			57,902
Long-term Liabilities
Lease financing - long-term		629,815			637,660
Environmental remediation		6,806			9,192
Defined benefit plan obligation		17,694			18,147
Derivative valuation liability		19,896			20,996
Asset retirement obligation		10,186			—
Transmission congestion contract		836			—
Other liabilities		2,375			2,600
Total long-term liabilities		687,608			688,595
Total Liabilities		741,555			746,497
Commitments and Contingencies (Note 3)
Minority Interest		364,817			379,542
Member’s Equity		3,685			3,834
Total Liabilities and Member’s Equity		$	1,110,057		$	1,129,873

 

The notes are an integral part of the condensed consolidated financial statements.

 

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Note 1.   Condensed Consolidated Balance Sheets

 

The consolidated balance sheets include the accounts of AES NY, L.L.C. (the Company), AES Eastern Energy, L.P. (AEE) and AES Creative Resources, L.P. (ACR) (including all subsidiaries). The balance sheets are presented on a consolidated basis because the Company, as general partner, controls the operations of AEE and ACR. The 99% limited partner ownerships of AEE and ACR are presented as minority interest.

 

The accompanying unaudited condensed consolidated balance sheets of the Company reflect all adjustments which are necessary, in the opinion of management, for a fair presentation of the Company’s consolidated financial position for the interim periods. All such adjustments are of a normal recurring nature. The unaudited condensed consolidated balance sheets should be read in conjunction with the Company’s consolidated balance sheet and notes contained therein, as of December 31, 2002, which are set forth in the Annual Report on Form 10-K of AEE for the year ended December 31, 2002.

 

Note 2.   Plants Placed on Long-Term Cold Standby

 

During the fourth quarter of 2000, ACR placed its AES Hickling and AES Jennison plants (ACR Plants) on long-term cold standby. The long-term cold standby designation means that these plants require more than 14 days to be brought on-line. The Company continues to evaluate the future of these plants.

 

Note 3.   Commitments and Contingencies

 

Coal Purchases - In connection with the acquisition by AEE of its four coal-fired electric generating stations (the AEE Plants), AEE assumed from New York State Electric & Gas Corporation (NYSEG) an agreement to purchase the coal required by the AEE Somerset and Cayuga plants. Each year either party can request renegotiation of the price of one-third of the coal supplied pursuant to this agreement. The supplier requested renegotiation during 2001 for the 2002 lot but the parties failed to reach agreement. The supplier requested renegotiation during 2002 for the 2003 lot plus the 2002 lot for which agreement was not reached. On September 11, 2002, AEE and the supplier reached agreement on both of the lots. Therefore, the commitment of AEE for 2003 is three lots for the Somerset Plant plus 70% of the anticipated coal usage for the Cayuga Plant.  The termination date for the contract is December 31, 2003. The parties were required to meet no later than June 30, 2003, to determine whether the agreement would be extended under mutually agreeable terms and conditions.  It has been determined that the agreement will not be extended. The Company can provide no assurances that AEE will be able to enter into other agreements on terms and conditions that are as favorable as the current contract.

 

As of the acquisition date of the AEE Plants, the contract prices for the coal purchased through 2002 were above the market price, and AEE recorded a purchase accounting liability for approximately $15.7 million related to the fulfillment of its obligation to purchase coal under this agreement. The purchase accounting liability was amortized as a reduction to coal expense over the life of the underlying contracts. As of December 31, 2002, the underlying contracts were fully amortized.

 

Based on the coal purchase commitments for the year ended December 31, 2003, AEE has expected coal purchases ranging between $90 and $100 million. Currently, AEE has expected coal purchase commitments ranging between $100 and $110 million for 2004.

 

As of September 30, 2003, the remaining anticipated coal purchase commitments for the year ending December 31, 2003 were between $20 and $25 million.

 

On September 4, 2003, AEE and AES Odyssey, L.L.C. (Odyssey) amended their current contract to include management of the Partnership’s coal and emission inventories. AEE has also agreed to increase their fees paid to Odyssey to $400,000 per month from $300,000 per month.

 

Odyssey, in concert with AEE, is using a strategy of varying-term contracts with multiple suppliers to develop flexibility in the supply chain to meet the demands of a fleet of merchant Plants.

 

Transmission Agreements - On August 3, 1998, the Company entered into an agreement with NYSEG for the purpose of transferring certain rights and obligations from NYSEG to the Company under an existing transmission agreement among Niagara Mohawk Power Corporation (NIMO), the New York Power Authority, NYSEG and Rochester Gas & Electric Corporation, and an existing transmission agreement between NYSEG and NIMO. This agreement provides for the assignment of rights to transmit energy from the Somerset Plant and other sources to remote load areas and other delivery points, and was assumed by AEE on the date of acquisition of the AEE Plants. In accordance with its plan, as of the acquisition date, AEE discontinued using this service. AEE did not transmit over these lines but was required to pay the monthly fees until the effective cancellation date, November 19, 1999. These fees aggregated approximately $3.4 million over the six months ended December 31, 1999, and were recorded as a purchase accounting liability. Because AEE did not use the lines during this period, AEE received no economic benefit subsequent to the acquisition.

 

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AEE was informed by NIMO that AEE would be responsible for the monthly fees of $500,640 under the existing transmission agreement to the originally scheduled termination date of October 1, 2004. On October 5, 1999, AEE filed a complaint against NIMO alleging that AEE has a right to non-firm transmission service upon six months prior notice without payment of $500,640 in monthly fees subsequent to the cancellation date of November 19, 1999.

 

On March 9, 2000, a settlement was reached between AEE and NIMO, which was approved by the Federal Energy Regulatory Commission (FERC) on May 10, 2000. According to the settlement, AEE will continue to pay NIMO a fixed rate of $500,640 per month during the period of November 20, 1999 to October 1, 2004 and, in turn, will receive a form of transmission service commencing on May 1, 2000, which AEE believes will provide an economic benefit over the period of May 1, 2000 to October 1, 2004. AEE shall have the right under a Remote Load Wheeling Agreement (RLWA) to transmit 298 megawatts (MW) over firm transmission lines from the Somerset Plant. AEE shall have the right to designate alternate points of delivery on NIMO’s transmission system provided that AEE shall not be entitled to receive any transmission service charge credit on the NIMO system.

 

The transmission congestion contract is accounted for as a derivative under SFAS No.133. The transmission congestion contract was entered into because it provided a reasonable settlement for resolving a FERC issue. The agreement is essentially a swap between the congestion component of the locational prices posted daily by the New York Independent System Operator (NYISO) in western New York and the more heavily populated areas in eastern New York. The agreement is a financially settled contract since there is no requirement to flow power under this agreement. The agreement generates gains or losses from exposure to shifts or changes in market prices. AEE recorded a loss of approximately $5.4 million versus income of approximately $4.2 million in the first nine months of 2003 and 2002, respectively, related to this contract.

 

On June 25, 2003, the Somerset Plant filed a complaint against NIMO with the FERC. The complaint involves outstanding station service charges for the period April 2000 to May 2003. The Plant has calculated that the outstanding charges owed are $290,000, while NIMO has calculated that the outstanding charges are $3.6 million. AEE is awaiting the FERC decision.

 

Line of Credit Agreement - On November 20, 2002, AEE signed an agreement with Union Bank of California, N.A. for a one-year extension of its current working capital and letter of credit facility. On April 16, 2003, AEE amended its November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes another one-year extension of the current facility; the maturity date of the working capital and letter of credit facility is now January 2, 2005. The amendment also increases Union Bank of California’s commitment from $15 million to $20 million. On April 25, 2003, AEE further amended its November 20, 2002 agreement with Union Bank of California, N.A. The amendment includes a commitment from Citibank, N.A. for the remaining $15 million of the facility. There have been two borrowings under the new facility. The first borrowing was $9.7 million on January 10, 2003 at an interest rate of 5.75%. This borrowing was repaid in full on January 28, 2003. The second borrowing was for $9.7 million on July 9, 2003 at an interest rate of 5.5%. This borrowing was repaid in full on July 25, 2003. As of September 30, 2003, of the $35 million committed, AEE had issued letters of credit of $13 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

 

The AES Corporation on January 6, 2003 and February 25, 2003 authorized AEE to issue letters of credit to counterparties on its $350 million senior secured revolving credit facility to the amount of $25 million and $35 million for the years of 2003 and 2004, respectively. If required by AEE, The AES Corporation has authorized additional future use of its $350 million senior secured revolving credit facility. As of September 30, 2003, AEE has issued letters of credit in the amount of $9.7 million, which have been provided as additional margin to support normal, ongoing hedging activities with a number of counterparties.

 

On July 14, 2003, Mirant Corporation announced it and certain of its U.S. subsidiaries had filed voluntary petitions for reorganizations under Chapter 11 of the U.S. Bankruptcy Code. Mirant Corp., Mirant Americas Generation, LLC and substantially all of the companies’ wholly owned subsidiaries in the United States were included in the Chapter 11 filings. On August 8, 2003, AEE executed a Postpetition Assurance and Amendment Agreement with Mirant Americas Energy Marketing, LP (MIR). This Agreement gives AEE superpriority administrative claims status pursuant to Section 364(c)(1) of the Bankruptcy Code for amounts owed by MIR to AEE.  As of September 30, 2003, AEE has no outstanding receivables with MIR.  AEE’s current credit exposure is approximately $127,000 through December 31, 2003.

 

Environmental - The Company has recorded a liability for environmental remediation associated with the acquisition of the AEE Plants and the ACR Plants. On an ongoing basis, the Company monitors its compliance with environmental laws. Because of the uncertainties associated with environmental compliance and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued.

 

16

 

AEE received an information request letter dated October 12, 1999 from the New York Attorney General, which sought detailed operating and maintenance history for the Westover and Greenidge Plants. On January 13, 2000, the Company received a subpoena from the New York State Department of Environmental Conservation (DEC) seeking similar operating and maintenance history from the AEE and ACR Plants. The Company has provided materials responding to the requests from the Attorney General and the DEC. This information was sought in connection with the Attorney General’s and the DEC’s investigations of several electricity generating stations in New York that are suspected of undertaking modifications in the past without undergoing an air permitting review.

 

On April 14, 2000, AEE received a request for information pursuant to Section 114 of the Clean Air Act from the U.S. Environmental Protection Agency (EPA) seeking detailed operating and maintenance history data for the Cayuga and Somerset Plants. The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Clean Air Act associated with repairs, maintenance, modifications and operational changes made to coal-fired facilities over the years. The EPA’s focus is on whether the changes were subject to new source review permitting or new source performance standards, and whether best available control technology was or should have been used. AEE has provided the requested documentation.

 

By letter dated May 25, 2000, the DEC issued a Notice of Violation (NOV) to NYSEG for violations of the Clean Air Act and the Environmental Conservation Law at the Greenidge and Westover Plants related to NYSEG’s alleged failure to undergo an air permitting review for repairs and improvements made during the 1980s and 1990s, which was prior to the acquisition of the AEE

Plants. Pursuant to the purchase agreement relating to the acquisition of the Plants from NYSEG, AEE agreed to assume responsibility for environmental liabilities that arose while NYSEG owned the Plants. On September 12, 2000, AEE agreed with NYSEG that AEE will assume the defense of and responsibility for the NOV, subject to a reservation of its right to assert applicable exceptions to its contractual undertaking to assume preexisting environmental liabilities.

 

AEE is currently in negotiation with both the EPA and DEC. If the parties are unable to reach an agreement, the EPA and DEC could issue AEE a notice or notices of violations or file a complaint in court alleging violations of the Clean Air Act and the New York Environmental Conservation Law. If the Attorney General, DEC or the EPA does file an enforcement action against the Somerset, Cayuga, Westover or Greenidge Plants, then penalties may be imposed and further emissions reductions might be necessary at these Plants which could require AEE to make substantial expenditures. AEE is unable to estimate the effect of such an enforcement action on its financial condition or results of future operations.

 

Nitrogen Oxide and Sulfur Dioxide Emission Allowances - The Plants emit nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of burning coal to produce electricity.

 

The AEE and ACR Plants have been allocated allowances by the DEC to emit NOx during the ozone season, which runs from May 1 to September 30. Each NOx allowance authorizes the emission of one ton of NOx during the ozone season. New York State and the other states in the Mid-Atlantic and Northeast region are classified as the Ozone Transport Region in the federal Clean Air Act, which designates the Ozone Transport Region as not being in compliance with the ozone National Ambient Air Quality Standard. The states in the Ozone Transport Region have agreed to implement a three-phase process to reduce NOx emissions in the region in order to comply with the federal Clean Air Act Title I requirements for ozone non-compliance areas. Implementation of the Phase III emission rules commenced on May 1, 2003. The Phase III NOx regulations set forth a NOx allowance allocation program which gives AEE 2,516 NOx emission allowances for 2003.

 

The AEE and ACR Plants are also subject to SO2 emission allowance requirements imposed by the EPA. Each SO2 allowance authorizes the emission of one ton of SO2 during the calendar year. All of the Plants are currently subject to SO2 allowance requirement, and are required to hold sufficient allowances to emit SO2.

 

Both NOx and SO2 allowances may be bought, sold or traded. If NOx and/or SO2 emissions exceed the allowance amounts allocated to the AEE Plants, then AEE may need to purchase additional allowances on the open market or otherwise reduce its production of electricity to stay within the allocated amounts. It is expected that AEE may have an allowance shortfall during 2003 of approximately 9,500 to 10,500 SO2 allowances and approximately 1,000 to 1,100 NOx allowances assuming the units are operated at forecasted capacities. At current market prices, the cost could range from $6.3 million to $7.4 million to purchase sufficient SO2 and NOx allowances for 2003. In 2002, ACR sold all its SO2 and NOx allocations for 2003.

 

In October 1999, New York State Governor Pataki announced an executive order mandating additional emission reductions from New York State power plants. The Governor’s initiative requires non-ozone season NOx emission reductions based on 0.15 lbs/Mmbtu starting in 2004, and a 50% reduction from the power plants’ Title IV SO2 emissions being phased in from 2005 to 2008.  The program will be implemented through a market-based mechanism. The rules implementing the Governor’s initiative (NYCRR Parts 237 and 238) were adopted in March 2003. A number of entities have started legal actions to overturn these rules.

 

17

 

In September 2003, New York State determined the amount of NOx emissions allowances that would be allocated to the Plants. The allocation is several thousand tons short of the AEE’s average NOx control period historical emissions. AEE’s compliance plan cannot be finalized until NOx market allowance prices are determined. ACR currently has NOx allowance surpluses since the Jennison and Hickling Plants were placed on long-term cold stand-by.

 

The SO2 allocations are not scheduled to occur until January 2004. The impact of the SO2 rules on the Company cannot fully be determined until New York State makes its determination as to how many SO2 emission allowances will be allocated to each of the Plants and a market price is determined.

 

AEE voluntarily disclosed to the DEC and EPA on November 27, 2002 that NOx exceedances appear to have occurred on October 30 and 31 and November 1-8 and 10 of 2002. The exceedances were discovered through an audit by plant personnel of the Plants’ NOx Reasonably Available Control Technology (RACT) tracking system which monitors NOx emissions at all the Plants subject to AEE’s NOx RACT Plan. The Plants have taken all reasonable, good faith efforts to assess and correct the exceedances. Immediately upon the discovery of the calculation error, the Selective Catalytic Reduction System (SCR) at the Somerset Plant was activated to reduce NOx emissions. Emission data indicates that the Plants had already returned to a compliant operation by the time the error was discovered. The EPA has decided to defer to the DEC for review of the self-disclosure letter and technical issues. AEE is unable to predict any potential actions or fines the DEC may require, if any.

 

AEE voluntarily disclosed to the DEC in January 2003 that the Cayuga Plant had inadvertently burned synfuel (coal with a latex binder applied), which it is not permitted to burn. The Cayuga Plant had entered into an agreement with a supplier to purchase coal. The Cayuga Plant received approximately one 9,000-ton train per month from April 24, 2001 to December 27, 2002. In January 2003, the Plant became aware that the product it had been receiving was synfuel. The Plants suspended all shipments from that supplier until a resolution could be reached. The Cayuga Plant has reviewed the emission and operation data that showed there was no adverse effect to air quality attributable to burning the material. AEE is unable to predict any potential actions or fines the DEC may require, if any. In July 2003, AEE reached an agreement with the supplier to resume shipment of coal in order to satisfy contractual obligations. As part of this agreement, the supplier has provided a written guarantee stating that all fuel shipments will be coal.

 

In April 2002, the EPA proposed to establish location, design, construction and capacity standards for cooling water intake structures at existing power plants. The EPA is developing these regulations under the terms of an Amended Consent Decree in Riverkeeper, Inc vs. Whitman, US District Court, Southern District of New York. The new rules for existing facilities have been extended by six months to February 16, 2004. These new rules will impose new compliance requirements, with potentially significant costs, on operating plants across the nation with cooling water intake structures. Cost items include various environmental and engineering studies and potential capital and maintenance costs. AEE has not determined the effects, if any of these regulations on its financial condition or results of operations.

 

ACR has reported that concentrations of a number of chemicals in a few groundwater wells increased in the year ending December 31, 2001, since the Jennison and Hickling Plants were placed on long-term cold standby. A consultant has been retained to help evaluate the source of the chemicals and suggest potential solutions.  ACR has notified the DEC. The Company is currently evaluating the data and a number of remedial actions. The Company cannot estimate if this will have a material effect on its financial position or results of operations.

 

ACR voluntarily disclosed to the DEC and EPA that ACR is conducting an investigation based on conflicting reports of suspected materials buried at the Hickling Plant. Field studies are on-going to determine if there are any materials on site, and the appropriate remedial plans will be developed if any are needed. The Company cannot estimate if this will have a material effect on its financial position or results of operations.

 

On July 24, 2003, Governor Pataki announced that ten Northeastern U.S. states (including New York) have agreed to work to develop a regional market-based emissions trading system to reduce power plants’ CO2 emissions. The goal is to reach an agreement by April 2005 on a cap and trade program. Until such time as the rules are developed to implement such a program the Company cannot determine what its impact would be on the Company’s financial position or results of operations.

 

Note 4.  Price Risk Management

 

AEE accounts for its derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. In the years prior to the adoption of SFAS No. 133, AEE did not have any items of other comprehensive income (loss).

 

AEE utilizes derivative financial instruments to hedge commodity price risk. AEE utilizes electric derivative instruments, including swaps and forwards, to hedge the risk related to forecasted electricity sales over the next four years. The majority of AEE’s electric derivatives are designated and qualify as cash flow hedges. No significant amounts of hedge ineffectiveness were recognized in earnings during the nine months ended September 30, 2003.

 

18

 

Gains and losses on derivatives reported in accumulated other comprehensive income are reclassified into earnings when the hedged forecasted sale occurs. Amounts recorded in other comprehensive income (loss) during the nine months ended September 30, 2003 were as follows (in millions):

 

Balance, January 1, 2003		$	(18.4	)
Reclassified to earnings		(41.5		)
Change in fair value		59.0
Balance, September 30, 2003		$	(0.9	)

 

In addition to the electric derivatives classified as cash flow hedge contracts, AEE has a Transmission Congestion Contract that is a derivative under the definition of SFAS No.133, but does not qualify for hedge accounting.  This contract is recorded at fair value on the balance sheet with changes in the fair value recognized through earnings.

 

Note 5. New Accounting Pronouncements

 

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which became effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred.  The new liability was recorded beginning in the first quarter of 2003. The Company capitalized the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.  Upon settlement of the liability, the Company will settle the obligation for its recorded amount or incur a gain or loss upon settlement. The Company adopted SFAS No. 143 effective January 1, 2003.

 

The Company has completed a detailed assessment of the specific applicability and implications of SFAS No. 143.  The scope of SFAS No. 143 includes primarily active ash landfills and water treatment basins. Upon adoption of SFAS No. 143, the Company recorded a liability of approximately $9.6 million and a net asset of approximately $3.3 million, which are included in electrical generation assets, and reversed a $4.2 million environmental remediation liability previously recorded. The difference of the amounts previously recorded and the net SFAS No. 143 liability is a loss recorded as the cumulative effect of a change in accounting principle of $2.2 million. Reconciliation of asset retirement obligation liability for the nine months ending September 30, 2003 was as follows (in millions):

 

Balance, January 1, 2003		$	9.6
Accretion		0.6
Balance, September 30, 2003		$	10.2

 

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure”.  SFAS No. 148 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, SFAS No. 148 amends the disclosure requirements of SFAS No. 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. AEE expects to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation.  All employee awards granted, modified or settled after January 1, 2003, will be recorded using the fair value based method of accounting.  (See Note 6). AEE’s adoption of the prospective method of accounting for stock-based employee compensation did not have any material impact on its financial position or results of operations.

 

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The adoption of SFAS No. 149 did not have a material impact on the Company’s financial position or results of operations.

 

19

 

The Company adopted the disclosure provisions of FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” in the fourth quarter of 2002.  The Company will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. In general, the Company enters into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent’s guarantee of its subsidiary’s debt to a third party (whether the parent is a corporation or an individual), a subsidiary’s guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor guarantees of a company’s own future performance.  Adoption of FIN 45 had no impact on the Company’s historical financial statements as existing guarantees are not subject to the measurement provisions of FIN 45. The Company does not expect adoption of the liability recognition provisions of FIN 45 to have a material impact on its financial position or results of operations.

 

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities”. This is an interpretation of Accounting Research Bulletin No. 51, “Consolidation of Variable Interest Entities”. FIN 46 requires certain variable interest entities (VIEs) to be consolidated by the primary beneficiary if the entity does not effectively disperse risks among the parties involved. The provisions of FIN 46 are effective immediately for those VIEs created after January 31, 2003. The provisions are effective for the first period beginning after June 15, 2003 for those variable interests held prior to February 1, 2003. The sales - leaseback transaction under which the Somerset and Cayuga Plants were acquired qualifies as a VIE. The sales - leaseback rules require that the leases be treated as financing leases for purposes of the Company’s financial statements, which they have been from the inception of the Company. Therefore the adoption of FIN 46 did not have a material impact on the Company’s financial position or results of operations.

 

Note 6. Long-term Incentive Program

 

Stock Option Plan - Employees of the Company participate in the AES Stock Option Plan (the SOP) that provides for grants of stock options to eligible participants. Prior to 2003, the Company accounted for the SOP under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations.  No stock-based employee compensation cost is reflected in 2002 net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS No. 123,” Accounting for Stock-Based Compensation,” prospectively to all employee awards granted, modified or settled after January 1, 2003.  Awards under the SOP vest over periods ranging from two to five years.  Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards from the inception of the Company. The expense recognized under the prospective method for the nine months ended September 30, 2003 is $115,000.

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The information in this Management’s Discussion and Analysis should be read in conjunction with the accompanying condensed consolidated financial statements and the related Notes to the Financial Statements. Forward looking statements in this Management’s Discussion and Analysis are qualified by the cautionary statement in the Forward Looking Statements section of the Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Critical Accounting Policies

 

General

 

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America.  As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The significant accounting policies which we believe are most critical to understanding and evaluating our reported financial results include the following:  Revenue Recognition; Property, Plant and Equipment; Contingencies; and Derivatives.

 

Revenue Recognition

 

Revenues from the sale of electricity are recorded based upon output delivered and rates specified under contract terms. Revenues generated from the hedging of future sales using commodity forwards, swaps and options are recorded based on settlement accounting with the net amount received recognized as revenue. Revenues for ancillary and other services are recorded when the services are rendered. The Transmission Congestion Contract is not deemed to be a hedge based on the definitions in SFAS No. 133. Therefore, this contract is marked to market at the end of every period.  The mark-to-market value is computed based on a regression of historical eastern and western locational prices. This regression is used with forecasted eastern and western locational prices to calculate the forward congestion for the remainder of the contract term. This accounting treatment contributes to the income statement volatility of this contract.

 

20

 

Property, Plant and Equipment

 

Electric generation assets that existed at the date of acquisition were recorded at fair market value. Somerset and Cayuga, which represent $650 million of the electric generation assets, are subject to a leasing arrangement accounted for as a financing lease. Additions or improvements thereafter are recorded at cost. Depreciation is computed using the straight-line method over the 34-year and 28.5-year lease terms for Somerset and Cayuga, respectively, and over the estimated useful lives for the other fixed assets, which range from 7 to 35 years. Maintenance and repairs are charged to expense as incurred.

 

Contingencies

 

We accrue for loss contingencies when the amount of the loss is probable and estimable.  We are subject to various environmental regulations, and we are involved in certain legal proceedings.  If our actual environmental and/or legal obligations are materially different from our estimates, the recognition of the actual amounts may have a material impact on our operating results and financial condition.

 

Derivatives

 

On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” which, as amended, established new accounting and reporting standards for derivative instruments and hedging activities. SFAS No. 133 requires that all derivatives (including derivatives embedded in other contracts) be recorded as either assets or liabilities at fair value on the balance sheet. Changes in the derivative’s fair value are to be recognized in earnings in the period of change, unless hedge accounting criteria are met. Hedge accounting allows the derivative’s gains or losses in fair value to offset the related results of the hedged item. We utilize derivative financial instruments to manage commodity price risk. Although the majority of our derivative instruments qualify for hedge accounting, the adoption of SFAS No. 133 results in more variation to our results of operations from changes in commodity prices. We have chosen to use the hypothetical derivative methodology for testing whether our hedges meet the criteria to qualify for hedge accounting treatment. A historical regression is performed between the Plants’ delivery points into the New York Independent System Operator (NYISO) market and the NYISO zones in which the hedges are settled. Comparing the results of the historical regression and the actual changes in the market value of the hedges determines if the hedges qualify for hedge accounting treatment.  For the nine months ended September 30, 2003 and September 30, 2002, we recognized $5.4 million of loss and $4.2 million of income, respectively, pursuant to SFAS No. 133 related to derivatives which did not qualify for hedge accounting.

 

Results of Operations for the Three Months ended September 30, 2003

 

Results of Operations

 

(Amounts in Millions)

 

For the Three Months Ended September 30,		2003			2002			% Change
Energy revenue		$	109.3		$	87.2		25.3
Capacity revenue		7.4			11.8			(37.3	)
Transmission congestion contract		1.1			(14.7		)	—
Other		0.3			1.5			(80.0	)

 

Energy revenues for the three months ended September 30, 2003 were $109.3 million, compared to $87.2 million for the comparable period of the prior calendar year, an increase of 25.3%. The increase in energy revenues is primarily due to higher market prices offset in part by lower demand. Market prices for peak and off-peak electricity were approximately 6.3% and 27.4% higher than the comparable period of the prior calendar year. Demand for peak and off-peak electricity was 2.9% and 3.2% lower than the comparable period of the prior calendar year. The market price and demand numbers were based on statistics obtained from the NYISO.

 

Capacity revenues for the three months ended September 30, 2003 were $7.4 million, compared to $11.8 million for the comparable period of the prior calendar year, a decrease of 37.3%. The decrease in capacity revenue is primarily due to lower prices for capacity sales on the open market for the summer capacity period (May - October) versus the comparable period of the prior calendar year.

 

Transmission congestion contract gain for the three months ended September 30, 2003 was $1.1 million, compared to a loss of $14.7 million for the comparable period of the prior calendar year. This agreement is essentially a swap between the congestion component of the locational prices posted by the NYISO in western New York and the more populated areas in eastern New York.  The transmission contract was entered into because it provided a reasonable settlement for resolving a FERC dispute between us and Niagara Mohawk Power Corporation.

 

21

 

Operating Expenses

 

For the Three Months Ended September 30,		2003			2002			% Change
Fuel expense		$	41.6		$	36.8		13.0
Operations and maintenance		4.9			4.0			22.5
General and administrative		14.7			17.1			(14.0	)
Depreciation and amortization		9.0			9.0			—

 

Fuel expense for the three months ended September 30, 2003 was $41.6 million, compared to $36.8 million for the comparable period of the prior calendar year, an increase of 13.0%. The increase in Fuel expense is primarily due to higher operating levels and higher coal, NOx allowance, ammonia and limestone pricing.

 

Operations and maintenance expense for the three months ended September 30, 2003 was $4.9 million, compared to $4.0 million for the comparable period of the prior calendar year, an increase of 22.5%. This increase is primarily due to maintenance expenses incurred because of higher operating factors during the year and a scheduled maintenance outage at the Somerset Plant. Lower utilities and contract service expenses offset the increased maintenance expenses.

 

General and administrative expense for the three months ended September 30, 2003 was $14.7 million, compared to $17.1 million for the comparable period of the prior calendar year, a decrease of 14.0%. This decrease is primarily due to one-time postretirement costs incurred in the third quarter of 2002. The decrease in postretirement expense was offset by increases in property taxes and property and medical insurance costs.

 

Depreciation and amortization expense for the three months ended September 30, 2003 was $9.0 million, compared to $9.0 million for the comparable period of the prior calendar year.

 

Other Expenses

 

For the Three Months Ended September 30,		2003			2002			% Change
Interest expense		$	14.9		$	15.6		(4.5	)
Interest income		0.5			0.5			—
Gain(loss) on derivative valuation		—			(0.3		)	—

 

Other Income/Expenses for the three months ended September 30, 2003 were net expenses of $14.4 million, compared to net expenses of $15.4 million for the comparable period of the prior calendar year, a decrease of 6.5%.

 

Results of Operations for the Nine Months ended September 30, 2003

 

Results of Operations

 

(Amounts in Millions)

 

For the Nine Months ended September 30,		2003			2002			% Change
Energy revenue		$	303.7		$	222.4		36.6
Capacity revenue		23.8			27.0			(11.9	)
Transmission congestion contract		(5.4		)	4.2			—
Other		1.7			6.1			(72.1	)

 

Energy revenues for the nine months ended September 30, 2003 were $303.7 million, compared to $222.4 million for the comparable period of the prior calendar year, an increase of 36.6%. The increase in energy revenues is primarily due to higher market prices and demand. Market prices for peak and off-peak electricity were 59% and 62.6% higher than the comparable period of the prior calendar year. Demand for peak and off-peak electricity was 0.3% and 1.1% higher than the comparable period of the prior calendar year. The market price and demand numbers were based on statistics obtained from the NYISO.

 

Capacity revenues for the nine months ended September 30, 2003 were $23.8 million, compared to $27.0 million for the comparable period of the prior calendar year, a decrease of 11.9%. The decrease in capacity revenue is primarily due to lower prices for capacity sales on the open market for the summer capacity period (May - October) offset by higher prices for capacity sales on the open market for the winter capacity period (November - April) versus the comparable period of the prior calendar year.

 

22

 

Transmission congestion contract loss for the nine months ended September 30, 2003 was $5.4 million compared to income of $4.2 million for the comparable period of the prior calendar year. This agreement is essentially a swap between the congestion component of the locational prices posted by the NYISO in western New York and the more populated areas in eastern New York.  The transmission contract was entered into because it provided a reasonable settlement for resolving a FERC dispute between us and Niagara Mohawk Power Corporation.

 

Operating Expenses

 

For the Nine Months ended September 30,		2003			2002			% Change
Fuel expense		$	112.5		$	100.8		11.6
Operations and maintenance		14.6			12.4			17.7
General and administrative		42.6			43.9			(3.0	)
Depreciation and amortization		27.0			26.4			2.3

 

Fuel expense for the nine months ended September 30, 2003 was $112.5 million, compared to $100.8 million for the comparable period of the prior calendar year, an increase of 11.6%. The increase in Fuel expense is primarily due to higher operating levels and higher coal, NOx allowance, ammonia and limestone pricing.

 

Operations and maintenance expense for the nine months ended September 30, 2003 was $14.6 million, compared to $12.4 million for the comparable period of the prior calendar year, an increase of 17.7%. This increase is primarily due to maintenance expenses incurred during scheduled outages at the Somerset, Cayuga, Greenidge and Westover Plants combined with higher Railroad, raw material and contract services expense offset by lower utility expense.

 

General and administrative expense for the nine months ended September 30, 2003 was $42.6 million, compared to $43.9 million for the comparable period of the prior calendar year, a decrease of 3.0%. This decrease is primarily due to one-time postretirement costs incurred in 2002. The decrease in postretirement expense was offset by increases in property taxes and property and medical insurance expenses. In addition, in the comparable period of the prior calendar year, general and administrative expenses were partially offset by a reversal of accruals for potential environmental liabilities that were resolved at a lower cost than estimated.

 

Depreciation and amortization expense for the nine months ended September 30, 2003 was $27.0 million, compared to $26.4 million for the comparable period of the prior calendar year, an increase of 2.3%. The primary reason for the increase is the depreciation of the additional assets recorded under SFAS No. 143, as well as the capital expenditures of the prior year.

 

Other Expenses

 

For the Nine Months Ended September 30,		2003			2002			% Change
Interest expense		$	44.4		$	44.4		—
Interest income		1.5			1.6			(6.3	)
Gain(loss) on derivative valuation		0.1			(0.3		)	—

 

Other Income/Expenses for the nine months ended September 30, 2003 were net expenses of $42.8 million, compared to net expenses of $43.1 million for the comparable period of the prior calendar year, a decrease of 0.7%.

 

Liquidity and Capital Resources

 

Operating Activities

 

Net cash provided by operating activities of $104.6 million for the nine months ended September 30, 2003, reflects the increase in net income due to increased energy prices offset in part by an increase in working capital. The working capital increase is primarily due to a decrease in accrued interest expense.

 

23

 

Investing Activities

 

Net cash provided by investing activities of $11.6 million for the nine months ended September 30, 2003 reflects a decrease in our restricted cash accounts of $13.8 million and a decrease in the rent reserve account of $371,000 offset by approximately $2.5 million in capital expenditures. The capital expenditures include the Westover Over-fire Air Project, which was completed in May, 2003. Net cash provided by investing activities for the nine months ended September 30, 2002 was $22.4 million, reflecting a decrease in our restricted cash accounts of $28.6 million and a decrease in the rent reserve account of $378,000 offset by approximately $6.6 million in capital expenditures. We make capital expenditures according to the maintenance program for our Plants.  In addition to capital requirements associated with the ownership and operation of our Plants, we will have significant fixed charge obligations in the future, principally with respect to the leases.

 

Compliance with environmental standards will continue to be reflected in our capital expenditures. Based on the current status of regulatory requirements, we do not anticipate that any capital expenditures associated with our compliance with current laws and regulations will have a material effect on our results of operations or our financial condition, other than the expenditures for the SCRs at Somerset and Cayuga, including the construction of new landfill space to manage ash from Somerset’s SCR system operations and expenditures for possible installation of a SCR system on Cayuga Unit 2 and the U.S. Department of Energy Power Plant Improvement project on Greenidge Unit 4.

 

Financing Activities

 

Net cash used in financing activities for the nine months ended September 30, 2003 of $116.2 million reflects principal payments on our leases of $1.4 million, payment of a distribution to our partners of $114.6 million and payments for deferred financing of $335,000 offset by a Partner’s contribution of $115,000. Net cash used in financing activities for the nine months ended September 30, 2002 of $68.7 million reflects principal payments on our leases of $6.2 million, payment of a distribution to our partners of $63.9 million offset by a Partner’s contribution of $1.5 million. Cash flow from operations in excess of the aggregate rental payments under our leases is permitted, if certain criteria are met, to be paid in the form of distribution payments to our partners.

 

We are obligated to make payments under the Coal Hauling Agreement with Somerset Railroad Corporation (SRC), an affiliated company, in an amount sufficient, when added with funds available from other sources, to enable SRC to pay, when due, all of its operating expenses and other expenses, including interest on and principal of outstanding indebtedness. As of September 30, 2003, we had recorded $2.9 million as operating expenses and other accrued liabilities under this agreement. On August 14, 2000, SRC entered into a $26 million credit facility with Fortis Capital Corp. which replaced in its entirety a credit facility for the same amount previously provided to SRC by an affiliate of CIBC World Markets. The new credit facility provided by Fortis Capital Corp. consists of a 14-year term note (maturing on May 6, 2014), with principal and interest payments due quarterly. The current interest rate on the loans under this credit facility is equal to a Base Rate plus 0.750% for the Base Rate loans and LIBOR plus 1.500% for LIBOR loans. The Base Rate was 1.50% on September 30, 2003 and LIBOR was 1.14% on that date. The principal amount of SRC’s outstanding indebtedness under this credit facility was approximately $19.9 million as of September 30, 2003.

 

On November 20, 2002, we signed an agreement with Union Bank of California, N.A. for a one-year extension of our current working capital and letter of credit facility. On April 16, 2003, we amended our November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes another one-year extension of our current facility; the maturity date of our working capital and letter of credit facility is January 2, 2005. The amendment also increases Union Bank of California’s commitment from $15 million to $20 million. On April 25, 2003, we further amended our November 20, 2002 credit agreement with Union Bank of California, N.A. The amendment includes a commitment from Citibank, N.A. for the remaining $15 million of our facility. There have been two borrowings under the new facility. The first borrowing was for $9.7 million on January 10, 2003 at an interest rate of 5.75%. This borrowing was repaid in full on January 28, 2003. The second borrowing was for $9.7 million on July 9, 2003 at an interest rate of 5.5%. This borrowing was repaid in full on July 25, 2003. As of September 30, 2003, of the $35 million committed, we had issued letters of credit of $13 million, which have been provided as additional margin to support normal ongoing hedging activities with a number of counterparties.

 

The AES Corporation on January 6, 2003 and February 25, 2003 authorized us to issue letters of credit to counterparties on its $350 million senior secured revolving credit facility to the amount of $25 million and $35 million, respectively. If required by us, The AES Corporation has authorized additional future use of its $350 million senior secured revolving credit facility. As of September 30, 2003, we have issued letters of credit in the amount of $9.7 million, which have been provided as additional margin to support normal ongoing hedging activities with a number of counterparties.

 

24

 

On July 14, 2003, Mirant Corporation announced it and certain of its U.S. subsidiaries had filed voluntary petitions for reorganizations under Chapter 11 of the U.S. Bankruptcy Code. Mirant Corp., Mirant Americas Generation, LLC and substantially all of the companies’ wholly owned subsidiaries in the United States were included in the Chapter 11 filings. On August 8, 2003, we executed a Postpetition Assurance and Amendment Agreement with Mirant Americas Energy Marketing, LP (MIR). This Agreement gives the Partnership superpriority administrative claims status pursuant to Section 364(c)(1) of the Bankruptcy Code for amounts owed by MIR to us.  As of September 30, 2003, we have no outstanding receivables with MIR.  Our current credit exposure is approximately $350,000 through December 31, 2003.

 

Credit Rating Discussion

 

Credit ratings affect our ability to execute our commercial strategies in a cost-effective manner. In determining our credit rating, the rating agencies consider a number of factors. Quantitative factors that appear to have significant weight include, among other things, earnings before interest, taxes and depreciation and amortization (EBITDA); operating cash flow; total debt outstanding; fixed charges such as interest expense and lease payments; liquidity needs and availability and various ratios calculated from these factors. Qualitative factors appear to include, among other things, predictability of cash flows, business strategy, industry position and contingencies. In addition, Standard and Poor’s links our credit rating to the credit rating of The AES Corporation in accordance with their standard policy of linking the credit rating of a wholly owned subsidiary to that of its parent. Our Standard and Poor’s credit rating is currently BB+, three notches higher than the credit rating of The AES Corporation.

 

Trigger Events

 

Our commercial agreements typically include adequate assurance provisions relating to trade credit and some agreements have credit rating triggers. These trigger events typically would give counterparties the right to request additional collateral if our credit ratings were downgraded. Under such circumstances, we would need to post collateral within three days or the counterparties would have the right to suspend or terminate credit. The cost of posting collateral would have a negative effect on our profitability. If such collateral were not posted, our ability to continue transacting business as before the downgrade would be impaired. On October 8, 2002, one of our counterparties made a $1 million margin call on us because of Standard and Poor’s downgrade of our credit rating from BBB- to BB+. We provided a letter of credit for approximately $1 million.

 

New Accounting Pronouncements

 

Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143, which became effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The new liability was recorded in the first quarter 2003. We capitalized the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we will settle the obligation for its recorded amount or incur a gain or loss upon settlement. We adopted SFAS No. 143 effective January 1, 2003.

 

We have completed a detailed assessment of the specific applicability and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily active ash landfills and water treatment basins. Upon adoption of SFAS No. 143, we recorded a liability of approximately $9.2 million and a net asset of approximately $3.4 million, which are included in electric generation assets, and reversed a $4.2 million environmental remediation liability we had previously recorded. The difference of the amounts previously recorded and the net SFAS No. 143 liability is a loss recorded as the cumulative effect of a change in accounting principle of $1.7 million. Reconciliation of our asset retirement obligation liability for the nine months ended September 30, 2003 was as follows (in millions):

 

Balance, January 1, 2003		$	9.2
Accretion		0.5
Balance, September 30, 2003		$	9.7

 

25

 

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure”.  SFAS No. 148 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, SFAS No. 148 amends the disclosure requirements of SFAS No. 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.  We expect to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation.  All employee awards granted, modified or settled after January 1, 2003 will be recorded using the fair value based method of accounting.  The expanded disclosures required by SFAS No. 148 are included in our quarterly financial reports beginning in the first quarter of 2003. Our adoption of the prospective method of accounting for stock-based employee compensation did not have any material impact on our financial position or results of operations.

 

On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The adoption of SFAS No. 149 did not have a material impact on our financial position or results of operations.

 

We adopted the disclosure provisions of FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” in the fourth quarter of 2002.  We will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. In general, we enter into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent’s guarantee of its subsidiary’s debt to a third party (whether the parent is a corporation or an individual), a subsidiary’s guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor does it apply to guarantees of a company’s own future performance. Adoption of FIN 45 had no impact on our historical financial statements as existing guarantees are not subject to the measurement provisions of FIN 45.  The adoption of the liability recognition provisions of FIN 45 did not have a material impact on our financial position or results of operations.

 

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities”. This is an interpretation of Accounting Research Bulletin No. 51, “Consolidation of Variable Interest Entities.” FIN 46 requires certain variable interest entities (VIEs) to be consolidated by the primary beneficiary if the entity does not effectively disperse risks among the parties involved. The provisions of FIN 46 are effective immediately for those VIEs created after January 31, 2003. The provisions are effective for the first period beginning after June 15, 2003 for those VIES held prior to February 1, 2003. The sales - leaseback transaction under which Somerset and Cayuga  were acquired qualifies as a VIE. The sales - leaseback rules require that the leases be treated as financing leases for our financial statements, which they have been from our inception. Therefore the adoption of FIN 46 did not have a material impact on our financial position or results of operations.

 

Forward-looking Statements

 

Certain statements contained in this Form 10-Q are forward-looking statements as that term is defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements speak only as of the date hereof. Forward-looking statements can be identified by the use of forward-looking terminology such as “believe,” “expects,” “may,” “intends,” “will,” “should” or “anticipates” or the negative forms or other variations of these terms or comparable terminology, or by discussions of strategy. Future results covered by the forward-looking statements may not be achieved. Forward-looking statements are subject to risks, uncertainties and other factors, which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements. The most significant risks, uncertainties and other factors are discussed under the heading “Business (a) General Development of Business” in our Annual Report on Form 10-K, and you are urged to read this section and carefully consider such factors.

 

Item 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures. The principal executive officer and principal financial officer of our General Partner, based on the evaluation of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) or 15d-15(e)) as required by paragraph (b) of Exchange Act Rules 13a-15 or 15d-15, have concluded that as of September 30, 2003, our disclosure controls and procedures were effective and designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

 

26

 

Changes in Internal Control Over Financial Reporting. There have been no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II - - OTHER INFORMATION

 

Item 1.   Legal Proceedings

 

See Note 2 to our Condensed Consolidated Financial Statements in Part I.

 

Item 6.   Exhibits and Reports on Form 8-K

 

(a)  Exhibits

 

31.1		Certification by Chief Executive Officer Required by Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
31.2		Certification by Chief Financial Officer Required by Rule 13a-14(a) or 15d- 14(a) of the Securities Exchange Act of 1934
32		Certification Required by Rule 13a-14(b) or 15d-14(b) of the Securities Exchange Act of 1934

 

(b)  Reports on Form 8-K

 

None

 

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Signatures

 

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.

 

	AES EASTERN ENERGY, L.P.
	By:  AES NY, L.L.C., as General Partner
	By:	/s/ Daniel J. Rothaupt
		Daniel J. Rothaupt
		President
Date:  November 12, 2003		(principal executive officer)
	By:	/s/ Amy Conley
		Amy Conley
		Vice President
		(principal financial officer)
Date:  November 12, 2003

 

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