Dyne Therapeutics 8K/A Financial Statements and Exhibits | SEC 2 May 07

EXHIBIT 99.1

POWER GENERATION BUSINESS OF

LS POWER DEVELOPMENT, LLC AND AFFILIATES

Combined Financial Statements

December 31, 2006 and 2005

(With Independent Auditors’ Report Therein)

Report of Independent Registered Public Accounting Firm

The Members

LS Power Development, LLC:

We have audited the accompanying combined balance sheets of the Power Generation Business of LS Power Development, LLC and Affiliates as of December 31, 2006 and 2005, and the related combined statements of operations, owners’ equity and comprehensive loss, and cash flows for the years then ended. These combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Power Generation Business of LS Power Development, LLC and Affiliates as of December 31, 2006 and 2005, and the results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Philadelphia, Pennsylvania

April 13, 2007

POWER GENERATION BUSINESS OF

LS POWER DEVELOPMENT, LLC AND AFFILIATES

Combined Balance Sheets

December 31, 2006 and 2005

(In thousands of dollars)


	2006		2005
Assets
Current assets:
Cash and cash equivalents	$	63,681	$	6,554
Restricted cash		234,273		27,089
Accounts receivable-trade, net of allowance for doubtful accounts of $0 and $436, respectively		49,778		8,082
Accounts receivable-other		10,895		654
Inventory		35,898		5,184
Prepaid expenses		11,257		2,092
Derivative instruments		24,028		—
Prepaid income taxes		1,796		—
Other current assets		392		296

Total current assets		431,998		49,951

Property, plant and equipment, net		2,143,985		349,329
Acquired intangible assets, net		263,930		253,847
Goodwill		610		—
Derivative instruments		14,235		—
Restricted cash		225,044		—
Other non-current assets		29,599		1,255
Deferred financing costs, net		62,843		10,175

Total assets	$	3,172,244	$	664,557


Liabilities and Owners’ Equity
Current liabilities:
Current portion of long-term debt	$	31,733	$	19,835
Short-term debt		—		125,000
Accounts payable		11,423		2,911
Accounts payable-affiliate		280		1,640
Accrued interest payable		1,763		811
Accrued expenses		55,357		7,412
Deferred revenue		9,130		—

Total current liabilities		109,686		157,609
Long-term debt		2,121,200		401,110
Bonds payable		100,000		—
Note payable-affiliate, including accrued interest		3,322		1,376
Derivative instruments		43,839		95
Asset retirement obligations		32,577		—
Deferred income taxes		1,402		—
Other long-term liabilities		31,782		11,666

Total liabilities		2,443,808		571,856

Commitments and contingencies (notes 7 and 14)
Minority interest		80		—
Owners’ equity		728,356		92,701

Total liabilities and owner’s equity	$	3,172,244	$	664,557

See accompanying notes to combined financial statements.

POWER GENERATION BUSINESS OF

LS POWER DEVELOPMENT, LLC AND AFFILIATES

Combined Statements of Operations

Years ended December 31, 2006 and 2005

(In thousands of dollars)


	2006			2005
Energy and capacity revenues	$	969,654		$	65,537
Ancillary revenues		19,502			373

Total revenues		989,156			65,910

Operating expenses:
Fuel and transportation		659,189			23,753
Operations and maintenance expenses		117,897			20,232
Depreciation		52,140			6,573
Project development expenses		22,400			16,097
General and administrative expenses		28,186			5,215

Total operating expenses		879,812			71,870

Income (loss) from operations		109,344			(5,960	)

Interest expense		(150,968	)		(57,160	)
Interest income		20,405			1,121
Other income, net		33,676			12,786
Minority interest		8,689			—

Income (loss) before income taxes		21,146			(49,213	)

Income tax provision		(8,190	)		—

Net income (loss)	$	12,956		$	(49,213	)

See accompanying notes to combined financial statements.

POWER GENERATION BUSINESS OF LS

POWER DEVELOPMENT, LLC AND AFFILIATES

Combined Statements of Owners’ Equity and Comprehensive Income (Loss)

Years ended December 31, 2006 and 2005

(In thousands of dollars)


	Owners’ interests			Accumulated deficit			Accumulated other comprehensive loss			Total owners’ equity
Balance at December 31, 2004	$	26,370		$	(25,882	)	$	—		$	488
Net loss		—			(49,213	)		—			(49,213	)
Change in unrealized loss on derivatives		—			—			(95	)		(95	)

Total comprehensive loss											(49,308	)
Distributions		(144,939	)		—			—			(144,939	)
Capital contributions		286,460			—			—			286,460

Balance at December 31, 2005	$	167,891			(75,095	)		(95	)		92,701
Net income		—			12,956			—			12,956
Change in unrealized loss on derivatives		—			—			(7,500	)		(7,500	)

Total comprehensive income											5,456
Distributions		(97,736	)		—			—			(97,736	)
Capital contributions		727,935			—			—			727,935

Balance at December 31, 2006	$	798,090		$	(62,139	)	$	(7,595	)	$	728,356

See accompanying notes to combined financial statements.

POWER GENERATION BUSINESS OF

LS POWER DEVELOPMENT, LLC AND AFFILIATES

Combined Statements of Cash Flows

Years ended December 31, 2006 and 2005

(In thousands of dollars)


	2006			2005
Cash flows from operating activities:
Net income (loss)	$	12,956		$	(49,213	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Increase in accrued interest income receivable on deposits for electrical transmission service		2			(67	)
Increase in accrued interest expense-affiliate loans		5			72
Non cash interest expense		1,368			—
Depreciation		52,140			6,573
Deferred income taxes		1,402			—
Amortization of intangible assets		38,297			29,998
Amortization of debt discount		—			27,116
Amortization of deferred financing costs		6,411			366
Bad debt expense		3,348			436
Gain on sale of assets		(29,909	)		—
Gain on derivative instruments		(2,019	)		(7,979	)
Accretion of asset retirement obligations		2,350			—
Realized gain on option		—			(667	)
Swap breakage costs		—			(5,452	)
Minority interest in net loss of subsidiary		(8,689	)		—
Change in assets and liabilities:
Increase in accounts receivable-trade		(26,162	)		(1,422	)
Increase in accounts receivable-other		(132	)		(64	)
Decrease (increase) in inventory		316			(506	)
Increase in prepaid expenses		(6,019	)		(1,073	)
Increase in prepaid income taxes		(1,796	)		—
(Increase) decrease in other current assets		288			206
Increase in other non-current assets		(152	)		—
(Decrease) increase in accounts payable		(15,172	)		733
(Decrease) increase in accounts payable-affiliates		(1,222	)		1,639
Increase in accrued interest payable		858			761
Increase in accrued expenses		2,858			567
Increase in deferred revenue		9,130			—
Decrease in other long-term liabilities		(699	)		(704	)

Cash provided by operating activities		39,758			1,320

Cash flows from investing activities:
Acquisitions of assets and liabilities assumed, net of cash acquired		(1,712,608	)		(212,548	)
Capital expenditures		(2,767	)		(1,340	)
Purchases of land		(5,382	)		—
Proceeds from sale of assets		41,965			—
Payments on construction in progress		(96,636	)		—
Deposits for electrical transmission service		(1,943	)		—
Change in restricted cash		(432,228	)		9,367

Cash used in investing activities		(2,209,599	)		(204,521	)

Cash flows from financing activities:
Principal payments on long-term debt		(213,958	)		(467,578	)
Principal payments on short-term debt		(236,500	)		—
Debt issuance costs and deferred financing costs		(60,584	)		(11,308	)
Proceeds from issuance of long-term debt		1,887,450			547,000
Proceeds from issuance of working capital loans		111,500			—
Proceeds from issuance of affiliate loans		1,940			—
Proceeds from issuance of bonds		100,000			—
Premium payment on option contract		(45,500	)		—
Proceeds from sale of option contract		40,152			—
Proceeds from minority interest		8,769			—
Increase in deferred revenue		3,500			—
Capital contributions		727,935			286,460
Distributions		(97,736	)		(144,939	)

Cash provided by financing activities		2,226,968			209,635

Increase in cash and cash equivalents		57,127			6,434
Cash and cash equivalents:
Cash and cash equivalents, beginning of year		6,554			120

Cash and cash equivalents, end of year	$	63,681		$	6,554

Supplemental disclosure of cash flow information:
Cash paid for interest	$	135,954		$	28,828
Cash paid for income taxes	$	8,584		$	—

See accompanying notes to combined financial statements.

POWER GENERATION BUSINESS OF

LS POWER DEVELOPMENT, LLC AND AFFILIATES

Notes to Combined Financial Statements

December 31, 2006 and 2005

(1)

Basis of Presentation and Organization

LS Power Development, LLC and affiliates (the “LS Power Group”) is a group of integrated development, investment and management companies focusing on the power generation industry. LS Power Development, LLC (“Development”), a Delaware limited liability company, is the general partner of LS Power Associates, LP (“LS Associates”), a Delaware limited partnership, through which the LS Power Group develops, manages and invests in power generation projects. In addition, Development is the general partner of LS Power Partners, L.P. (“LS Power”), a Delaware limited partnership. LS Power is the general partner of LS Power Equity Partners, L.P. (“LS Equity Partners”) and LS Power Equity Partners PIE I, LP (“PIE”), both Delaware limited partnerships. LS Equity Partners and PIE co-invest in companies engaged in the power industry.

The accompanying combined financial statements include the financial statements of: LSP Kendall Blocker, Inc.; LSP Kendall Holding, LLC and its wholly owned subsidiaries of LSP-Kendall Energy, LLC and LSP Equipment, LLC; LSP Services Kendall, LLC; LSP ONT Blocker, Inc.; LSP Ontelaunee Holding, LLC and its wholly owned subsidiary of Ontelaunee Power Operating Company, LLC; LSP Plum Point Blocker, Inc.; LSP Plum Point Holdings, LLC and its subsidiaries; LSP Services Plum Point, LLC; and LSP Moss Blocker, Inc; LSP Morro Blocker, Inc.; LSP Oakland Blocker, Inc.; LSP SB Blocker, Inc.; LSP Arlington Blocker, Inc.; LSP Griffith Blocker, Inc.; LSP Bridgeport Blocker, Inc.; LSP Casco Blocker, Inc.; (collectively the “Blockers”); LSP Generation Holdings, LLC and its subsidiaries; and certain power generation development projects, which are in early stages of development and are owned directly or indirectly by LS Associates. Each of the aforementioned entities is owned directly or indirectly by LS Associates. As of December 31, 2006, only one of the power generation development projects (the “Plum Point Project”), had reached the construction phase of development. No power generation project had reached the construction phase of development at December 31, 2005. The entities listed in this paragraph, excluding LS Associates, are collectively referred to within the accompanying combined financial statements as the “Company.”

On December 1, 2004, LSP Kendall Holding, LLC (“Kendall Holding”), a wholly owned subsidiary of LS Associates acquired 100% of the outstanding membership interests of LSP-Kendall Energy, LLC (“Kendall”) and LSP Equipment, LLC (“Equipment”) (the “Kendall Acquisition”). Kendall Holding was formed to acquire 100% of the outstanding membership interests of Kendall and Equipment. The acquisition was accounted for under the purchase method of accounting and the results of Kendall’s operations have been included in the combined financial statements since the date of acquisition. The current members of Kendall Holding are LS Associates, LS Equity Partners and LSP Kendall Blocker, Inc. (“Kendall Blocker”). LS Equity Partners and Kendall Blocker were admitted as members in October 2005.

On October 6, 2005, LSP Ontelaunee Holding, LLC (“Ont Holding”), acquired 100% of the outstanding membership interests of Ontelaunee Power Operating Company, LLC (“Ontelaunee”) (the “Ontelaunee Acquisition”). Ont Holding was formed to acquire 100% of the outstanding membership interests in Ontelaunee. The acquisition was accounted for under the purchase method of accounting and the results of Ontelaunee’s operations have been included in the combined financial statements since the date of acquisition. The members of Ont Holding are LS Equity Partners and LSP ONT Blocker, Inc. (“ONT Blocker”).

On May 4, 2006, LSP Generation Holdings, LLC (“Gen Holdings”), through its subsidiary LS Power Generation, LLC (“LSP Gen”), acquired 100% of Duke Energy North America’s ownership interests in eight power generation facilities located in the western and northeastern United States (the “Generation Acquisition”) (see note 3). At the time of the acquisition, 50% of one of the power generation facilities was owned by PP&L Corporation. LSP Gen purchased the remaining ownership interest from PP&L Corporation on June 30, 2006. The members of Gen Holdings are LS Equity Partners and the Blockers. The members of LSP Gen are Gen Holdings and LSP Gen Investors, LP which owns approximately 1.7%.

As of December 31, 2006, the LS Power Group controlled the following power generation facilities:


Facility	Location	Year Operational	Size in MW
Moss Landing	California	1967-2002	2,529
Morro Bay	California	1963	650
South Bay	California	1960-71	706
Oakland	California	1978	165
Arlington Valley	Arizona	2002	585
Griffith	Arizona	2002	558
Bridgeport	Connecticut	1998	527
Casco Bay	Maine	2000	540
Ontelaunee	Pennsylvania	2002	580
Kendall	Illinois	2002	1,200
Plum Point	Arkansas	In Construction	665

(2)

Summary of Significant Accounting Policies

(a)

Basis of Combination

The combined financial statements include the financial statements of Kendall Blocker; Kendall Holding and its wholly owned subsidiaries of Kendall and Equipment; LSP Services Kendall, LLC; ONT Blocker; Ont Holding and its wholly owned subsidiary of Ontelaunee; LSP Plum Point Blocker, Inc.; LSP Plum Point Holding, LLC and its subsidiaries; LSP Services Plum Point, LLC; and LSP Moss Blocker, Inc; LSP Morro Blocker, Inc.; LSP Oakland Blocker, Inc.; LSP SB Blocker, Inc.; LSP Arlington Blocker, Inc.; LSP Griffith Blocker, Inc.; LSP Bridgeport Blocker, Inc.; LSP Casco Blocker, Inc.; LSP Generation Holdings, LLC and its subsidiaries; and certain power generation development projects, which are in early stages of development and are owned directly or indirectly by LS Associates. Each of the aforementioned entities is owned directly or indirectly by LS Associates, LS Equity Partners or PIE. The Company is under common control of Development by virtue of Development’s direct and indirect ownership

interests and management control of the entities. Minority interest represents minority members’ proportionate share of the membership interests in LSP Gen and a subsidiary of LSP Plum Point Holdings, LLC. All significant intercompany transactions and balances have been eliminated in combination.

(b)

Use of Estimates

Management makes estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities and reported amounts of revenues and expenses to prepare the combined financial statements in conformity with U.S. generally accepted accounting principles. The most significant of these estimates and assumptions relate to the recoverability of reported amounts of acquired property, plant and equipment and intangible assets, valuation of deferred tax assets, valuation of derivative instruments and valuation of assets acquired and liabilities assumed in purchase business combinations. Actual results could differ from those estimates.

(c)

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(d)

Restricted Cash

Restricted cash consists of amounts that are restricted under the terms of the Company’s financing agreements from transfer or dividend until such time as certain conditions are met. Such restricted cash is used primarily for construction costs, operating and maintenance expenses and debt service. A portion of restricted cash used for construction costs and debt service is classified as noncurrent at December 31, 2006 in the accompanying 2006 combined balance sheet.

(e)

Allowance for Doubtful Accounts

Management establishes reserves on accounts receivable if it becomes probable that the Company will not collect part of the outstanding accounts receivable balance. Management reviews collectibility and establishes or adjusts its allowance using the specific identification method.

(f)

Inventory

Inventory consists of spare parts and fuel oil. Spare parts inventory is stated at the lower of weighted average cost or market and fuel oil inventory is stated at the lower of cost or market.

(g)

Property, Plant and Equipment

Property, plant and equipment are stated at cost (fair value at the acquisition dates) less accumulated depreciation. Depreciation is computed on a straight line basis over the estimated remaining useful lives of individual assets or classes of assets. The useful lives for office equipment and furniture and fixtures are 7 years, software is 3 years, computer hardware is 5

years and plant and equipment is 30-35 years, except for the leased South Bay facility which is 4 years. Additions and improvements extending asset lives are capitalized, while repairs and maintenance, including planned major maintenance, are charged to expense as incurred. Depreciation expense for the years ended December 31, 2006 and 2005 was $52.1 million and $6.6 million, respectively.

(h)

Construction in Progress

All costs directly related to the acquisition and construction of long lived assets are capitalized. A portion of interest costs (including amortization of debt issuance and financing costs) from loans and bonds has been capitalized during the ongoing construction of a 665 megawatt coal fired electric generating facility (the “Plum Point Project”), near the city of Osceola, Arkansas. As of December 31, 2006, cumulative capitalized interest including amortization of debt issuance and financing costs was approximately $5.4 million. Interest cost was approximately $44.2 million for the year ended December 31, 2006.

(i)

Impairment of Long Lived Assets and Acquired Intangible Assets

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144,Accounting for the Impairment or Disposal of Long Lived Assets, long lived assets and intangible assets with determinable useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future undiscounted net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets and would be charged to earnings. Assets to be disposed of are reported at the lower of the carrying amount or fair value less the costs to sell. Intangible assets are amortized over their respective estimated useful lives.

(j)

Investment in Unconsolidated Subsidiary

The Company had an investment in an unconsolidated subsidiary representing its 50% ownership in such subsidiary from May 4, 2006 through June 30, 2006. The investment resulted in equity in loss of approximately $1.8 million for the aforementioned period, which is reflected in the Company’s income from operations.

(k)

Goodwill

Goodwill represents, at the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. In connection with the Company’s June 2006 acquisition of the remaining 50% of the electric generating facility from PPL Corporation, the Company recognized goodwill of $610,000. In accordance with SFAS No. 142,Goodwill and Other Intangible Assets, the Company will evaluate goodwill for impairment on an annual basis and when events warrant an assessment.

(l)

Asset Retirement Obligations

The Company recognizes the fair value of the liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted through charges to operating expenses. If the obligation is settled for other than the carrying amount of the liability a gain or loss is recognized on settlement. In connection with the Generation Acquisitions in May and June 2006, the Company recognized liabilities of $30.2 million for asset retirement obligations to provide for the future removal of asbestos from certain of its electric generating facilities, pond closures and dismantling of an electric generating facility. Accretion expense related to the asset retirement obligations during 2006 was approximately $2.4 million and the liability as of December 31, 2006 totaled $32.6 million.

(m)

Leases

Due to the criteria set forth in SFAS No. 13,Accounting for Leases, certain agreements or leases are classified as capital leases. The individual agreements or leases are identified in note 8.

(n)

Debt Issuance and Financing Costs

Debt issuance and financing costs are amortized over the term of the related debt using the effective interest method. The amortization of these costs is reflected as a component of interest expense on the accompanying statements of operations. For the years ended December 31, 2006 and 2005, amortization of these costs totaled $6.4 million and $0.4 million, respectively.

(o)

Revenue Recognition

Revenue from sales of electricity are recorded upon delivery to customers based upon the output delivered and capacity provided at the lesser of amounts billable under the power purchase agreements, or the average estimated contract rates over the initial term of the power purchase agreements. When a long-term power purchase agreement conveys the right to use the generating capacity of the Company’s facility to the buyer of the electric power, that agreement is evaluated to determine if it is a lease of the generating unit rather than a sale of electric power. Operating lease revenue for the Company’s generating units is recorded as capacity revenue and included in energy and capacity revenues in the combined financial statements. Revenues from sales of electricity not covered under power purchase agreements are recorded as delivered at current market prices.

(p)

Power Purchase Agreements

In connection with the acquisitions described in notes 1 and 3, the Company recorded the fair value of long-term power purchase agreements as intangible assets and liabilities. The intangible assets and liabilities are amortized over the term of the respective contracts as a reduction or increase in energy and capacity revenues in the combined statements of operations for the years ended December 31, 2006 and 2005.

(q)

Derivative Financial Instruments

The Company enters into interest rate swaps and other contracts to reduce its exposure to market risks from changing interest, commodity, and energy rates. In accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended, all derivative instruments are recorded on the balance sheet as either an asset or liability and are measured at fair value regardless of the purpose or intent for holding them. On the date a derivative contract is entered into, the Company may designate hedging relationships.

The Company documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy. This process includes linking all derivatives that are designated as hedges to specific assets or liabilities on the balance sheet or to forecasted transactions. The Company also assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively. This could occur when: (1) it is determined that a derivative is no longer effective in offsetting changes in the cash flows of a hedged item; (2) the derivative expires or is sold, terminated or exercised; or (3) the derivative is discontinued as a hedging instrument, because it is unlikely that a forecasted transaction will occur. When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective hedge of the cash flows, the derivative will continue to be carried at fair value in the statement of financial position, and gains and losses that were accumulated in other comprehensive income are either recognized immediately or over the remaining term of the forecasted transaction.

Changes in the fair value of derivative instruments are either recognized in income or owners’ equity as a component of accumulated other comprehensive income or loss (“AOCI”), depending upon their use and designation. Gains and losses related to transactions that qualify for cash flow hedge accounting are recorded in AOCI and reflected in income in the period the hedged items affect earnings. Otherwise any gains and losses resulting from changes in the market value of the contracts are recorded in income in the current period.

The interest rate swap agreements are used to convert the floating interest rate component of a portion of our long term debt obligations to fixed rates. Changes in the fair value of the interest rate swap agreements that qualify as cash flow hedges are recorded in other comprehensive income; otherwise, such changes are recorded in other income, net. In addition, the Company has entered into heat rate call option contracts on generating capacity of a number of its electric generating facilities. Changes in the fair value of the heat rate call option contracts are recorded in energy and capacity revenues.

As of December 31, 2006 and 2005, the net fair value of derivative instruments totaled a net liability of $5.6 million and a liability of $95,000, respectively (see note 9).

(r)

Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued expenses equals or approximates fair values due to the short term maturity of those instruments. The fair value of long term debt approximated its book value at December 31, 2006 and December 31, 2005 as the interest rates are variable.

(s)

Project Development Costs

Project development costs consisting of start up and organization costs are expensed as incurred. Project development costs directly related to the acquisition or construction of long lived assets are capitalized when it is determined that it is probable that such project development costs will be realized through the ultimate construction of a power generation plant. These costs are primarily funded and paid for by LS Associates.

(t)

Income Taxes

The majority of the entities comprising the Company have been organized as limited liability companies or limited partnerships. Therefore, federal and state income taxes are assessed at the member or partner level. However, the Blockers, LSP Plum Point Blocker, Inc, Kendall Blocker and ONT Blocker are Delaware corporations and any related income tax is accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities and their respective tax bases and operating loss carryforwards. A valuation allowance is provided when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to be applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date.

(u)

Concentrations of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of restricted cash and accounts receivable. Restricted cash accounts are generally held in federally insured banks. Accounts receivable are concentrated within entities engaged in the energy industry and the Company’s operations are concentrated in California and the northeastern United States. These industry and geographic concentrations may impact the Company’s overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry, weather or other conditions. For the year ended December 31, 2006, three customers, California ISO, ISO New England and PJM ISO, accounted for 30%, 26% and 8%, respectively, of the Company’s revenues. For the year ended December 31, 2005, three customers accounted for all of the Company’s revenues. The loss of any of these customers could result in an adverse impact on the Company’s results of operations, financial position and cash flows.

The Company is exposed to credit losses in the event of noncompliance by counterparties on its derivative financial instruments. The counterparties to these transactions are major financial institutions. The Company does not require collateral or other security to support the financial instruments with credit risk.

(v)

Risks and Uncertainties

The Company believes there are many development and investment opportunities to pursue. However, development and investment opportunities are dependent upon a variety of factors, including the economy, the regulatory environment, the electricity markets, and the availability of capital resources.

As with any power generation facility, operation and construction of the Company’s electric generating facilities involves risk, including the performance of the facility below expected levels of efficiency and output, shut downs due to the breakdown or failure of equipment or processes, violations of permit requirements, operator error, labor disputes, weather interferences or catastrophic events such as fires, earthquakes, floods, explosions, or other similar occurrences affecting a power generation facility or its power purchasers. The occurrence of any of these events could significantly reduce or eliminate revenues generated by the facilities or significantly increase the expenses of each of the facilities, adversely impacting the Company’s ability to make payments of principal and interest on its debt when due.

(w)

Commitments and Contingencies

The Company is a party to a number of claims and proceedings arising in the normal course of business. Management assesses each matter and determines the probability that a gain or loss has been incurred and the amount of such gain or loss if it can be reasonably estimated. Management reviews such matters on an ongoing basis. Any gain or loss contingencies are based on estimates and judgments made by management with respect to the likely outcome of such matters. Management’s estimates could change based on new information.

The Company follows the guidance of Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 45Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others for disclosing and accounting of guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject to FIN No. 45 is entered into the estimated fair value of the guarantee or indemnification is assessed. Some guarantees and indemnifications could have financial impact under certain circumstances. Management considers the probability of such circumstances occurring when estimating fair value.

(x)

Reclassifications

Certain reclassifications have been made to the 2005 combined financial statements to conform to the 2006 presentation.

(y)

Recent Accounting Pronouncements

In June 2006, FASB issued FIN No. 48,Accounting for Uncertainty in Income Taxes. The Interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109,Accounting for Income Taxes. The

Interpretation prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Interpretation also provides guidance on the related recognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The Interpretation is effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. The Company does not expect this pronouncement to have a material impact on its combined financial statements.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements. SFAS 157 provides a definition of fair value as well as a framework for measuring fair value. In addition, SFAS 157 expands the fair value measurement disclosure requirements of other accounting pronouncements to require, among other things, disclosure of the methods and assumptions used to measure fair value as well as the earnings impact of certain fair value measurement techniques. SFAS 157 does not expand the use of fair value in existing accounting pronouncements. The Company will adopt the provisions of SFAS 157 prospectively and must adopt SFAS 157 no later than January 1, 2008. The potential impact of adoption is not yet determinable.

(3)

Generation Acquisition

Generation Acquisitions

On May 4, 2006, Gen Holdings, through its subsidiary LSP Gen, acquired 100% of Duke Energy North America’s ownership interests in eight power generation facilities located in the western and northeastern United States. At the time of the acquisition, 50% of one of the power generation facilities was owned by PP&L Corporation. On June 30, 2006, a subsidiary of LSP Gen purchased the remaining 50% ownership interest from PPL Corporation for approximately $112 million. The assets acquired in the June 30 acquisition consisted primarily of property, plant and equipment and a receivable (see note 5 (a)).

The two acquisitions include eight power generation facilities (the “Generation Facilities”) in four states in the western and northeastern United States with a nominal net operating capacity of 6,260 MW as follows:

(1) Natural gas fired combined cycle facilities located in Moss Landing (units 1 and 2), California; Griffith, Arizona; Arlington Valley, Arizona; Bridgeport, Connecticut and Casco Bay, Maine representing 51% of total net operating capacity;

(2) Natural gas fired conventional steam facilities located in Moss Landing (units 6 and 7), California; Morro Bay, California and San Diego, California representing 46% of total net operating capacity; and

(3) An oil fired, simple cycle facility located in Oakland, California representing 3% of total net operating capacity.

The cost of the Generation Acquisition was approximately $1,610 million, consisting of $1,604 million of cash and $6 million of direct acquisition costs. There was a subsequent

adjustment of approximately $8.2 million reducing the purchase price that is reflected in the following table. The $8.2 million is reflected in accounts receivable-other on the combined balance sheet. The acquisition was partially funded by the issuance of debt (see note 8) and capital contributions from the current owners. The cost of the acquisition was allocated to the assets acquired and liabilities assumed based on estimates of their fair values at the date of acquisition. Fair values were determined primarily by an independent third party valuation.

The following table summarizes the estimated fair value of assets acquired and liabilities assumed at the date of acquisition (May 4, 2006).


	(in thousands)
Current assets	$	65,493
Property, plant and equipment		1,660,989
Acquired intangible assets		48,380
Other non-current assets		582

Total assets acquired		1,775,444

Current liabilities		66,662
Capital lease obligation		55,909
Asset retirement obligations		29,942
Other long-term liabilities		13,135

Total liabilities assumed		165,648

Net assets acquired	$	1,609,796

The acquired intangible assets represent the above market portion of a number of power purchase agreements. In addition, the Company also recognized a power purchase contract as an out-of-market contract liability with a fair value of $2.4 million. Such agreements have a weighted average term of four and one half years. At December 31, 2006, the gross carrying value, accumulated amortization and net carrying value of the power purchase agreements was approximately $46.0 million, $8.4 million and $37.6 million, respectively. The estimated annual amortization expense for each of the next five years is approximately $11.4 million for 2007, $8.7 million for 2008, $8.7 million for 2009 and $8.8 million for 2010.

Current liabilities included a $32 million reserve for major maintenance. Such maintenance was completed and paid for and the capital lease obligation of $55.9 million was deemed repaid as the result of the defeasance of a related bond obligation prior to December 31, 2006.

(4)

Property, Plant and Equipment

Property, plant and equipment at December 31, 2006 and 2005 consisted of the following:


	2006			2005
	(In thousands)
Land and improvements	$	55,843		$	6,295
Computer software and hardware		714			282
Office furniture and equipment		128			74
Plant and equipment		2,047,874			348,603
Construction in progress		98,526			1,035

		2,203,085			356,289
Accumulated depreciation		(59,100	)		(6,960	)

Property, plant and equipment, net	$	2,143,985		$	349,329

(5)

Other Non Current Assets

As of December 31, 2006, other noncurrent assets consisted primarily of the following:

(a) a $26 million prepaid related to an interconnection agreement with the Western Area Power Administration (“WAPA”). WAPA provides for the interconnection of the Griffith facility to WAPA’s transmission system. The prepaid represents amounts paid by the Company in connection with the construction of improvements to the WAPA transmission system that were necessary to enable transmission of electricity from the Griffith facility. The amount paid is refunded in the form of a monthly credit of $252,000 to Griffith’s transmission service charge through June 2018; and

(b) refundable cash deposits of $3 million. The deposits were paid to electric utilities in connection with applications for firm point to point electric transmission service. The deposits are refundable, with interest, upon the occurrence of certain events, including among others, withdrawal of the application for transmission service by the Company, or inability of the transmission provider to complete new facilities needed to provide the transmission service. Interest income on the deposit is computed from the date the deposit is received by the utility until the date a refund is made, compounded quarterly, in accordance with the Federal Energy Regulatory Commission’s guidelines. Such guidelines require the use of monthly prime interest rates published by the Federal Reserve Board. Accrued interest income on deposits aggregated approximately $154,000 and $156,000 as of December 31, 2006 and 2005, respectively and has been included in the related deposits on the combined balance sheets.

(6)

Accrued Expenses

Accrued expenses at December 31, 2006 and 2005 consisted of the following:


	2006		2005
	(In thousands)
Property taxes	$	5,579	$	5,894
Construction in progress		10,749		—
RMR contract reserve (see note 14)		8,000		—
Option contract settlements		4,840		—
Other		26,189		1,518

Total accrued expenses	$	55,357	$	7,412

(7)

Facility and Project Development Contract Commitments

(a)

Power Purchase Agreements

Kendall

Under the terms of a Power Purchase Agreement (the “DPM PPA”), with Dynegy Power Marketing, Inc. (“DPM”), Kendall is obligated to sell and DPM is obligated to purchase approximately 550 MW of electric generating capacity and associated energy from two of the four electric generating units (the “Units”) at the Kendall facility at prices set forth in the DPM PPA. The initial term of the DPM PPA is ten years, beginning on June 1, 2001. DPM has the option of extending the DPM PPA for two additional five-year terms by providing Kendall written notice at least two years prior to the expiration of the initial term and the first additional five-year extension. Kendall may, if DPM does not extend the DPM PPA prior to the end of the initial term, extend the DPM PPA for a period of five years.

The terms of the DPM PPA require DPM to make payments to Kendall including a reservation payment, an energy payment, a guaranteed heat rate payment and a system upgrade payment.

The DPM PPA is a tolling arrangement, whereby DPM is obligated to arrange, procure, supply, nominate, balance, transport, pay for and deliver the amount of natural gas necessary for each DPM Unit to generate its net electrical output. DPM’s obligations under the DPM PPA are guaranteed by DPM’s parent company, Dynegy Inc. In November 2004, DPM entered into a back to back power purchase agreement (the “Dynegy/Constellation PPA”) with Constellation Energy Commodities Group, Inc. (“Constellation”) with respect to the DPM Units. Under the terms of the Dynegy/Constellation PPA, DPM paid Constellation to assume its fixed obligations under the Dynegy PPA through November 2008.

Under the terms of a Power Purchase Agreement (the “Rainy River PPA”) with Rainy River Energy Corporation (“Rainy River”), Kendall was obligated to sell and Rainy River was obligated to purchase approximately 275 MW of electric generating capacity and associated energy from one of the four Units at the Kendall facility at prices set forth in the Rainy River PPA. On April 1, 2005, Rainy River assigned its interest to Constellation. Constellation thereby assumed all of Rainy River’s rights and obligations arising under the Rainy River PPA, restating the agreement to the Constellation PPA (the “Constellation PPA”). In connection with this assignment, Kendall received a consent fee of $4.1 million which has been recorded in other income, net in the accompanying combined statements of operations for the year ended December 31, 2005. The initial term of the Constellation PPA expires on September 16, 2017. Constellation may extend the term of the agreement for additional one year periods under certain circumstances.

The terms of the Constellation PPA require Constellation to make payments to Kendall including a reservation payment, an energy payment, a guaranteed heat rate payment and a system upgrade payment.

The Constellation PPA is a tolling arrangement, whereby Constellation is obligated to arrange, procure, supply, nominate, balance, transport, pay for and deliver the amount of natural

gas necessary for the Constellation Unit to generate its net electrical output. Constellation’s obligations under the Constellation PPA are guaranteed by Constellation’s parent company, Constellation Energy Group, Inc.

Plum Point

During 2006, PPEA entered into 30-year power purchase agreements (each a “PPA” or together the “PPAs”) with Empire District Electric Company (“Empire”), Municipal Energy Agency of Mississippi (“MEAM”), South Mississippi Electric Power Association (“SMEPA”), the Missouri Joint Municipal Electric Utility Commission (“MJMEUC”) and Southwestern Electric Cooperative, Inc. (“SWECI”) for the sale of 50 MW, 40 MW, 200 MW, 50MW and 78MW, respectively, of capacity and associated energy from the Plum Point Project. Pursuant to the PPAs, PPEA will receive capacity payments, fixed and variable payments, a fuel payment and a capital expense payment. The fuel charge under the PPAs will be based on the delivered cost of coal (inclusive of transportation costs) and an assumed heat rate.

The Empire and MEAM PPA provide both Empire and MEAM with a buyout option. Upon exercising these options, the PPA counterparties would become Project Co Owners.

Under the terms of the Empire PPA, Empire originally agreed to purchase an amount in MW equal to fifteen percent (15%) of the total net electrical capacity of Plum Point Project (the “Contract Capacity”). On March 14, 2006, Empire exercised its buyout option to purchase a percentage ownership in the Plum Point Project equal to 7.5% of the unit capacity. Empire has assumed all ongoing costs associated with the construction and operation of its portion of the Plum Point Project. The Empire PPA continues in effect for a period ending 30 years after the Plum Point Project’s commercial operations date. However, the Empire PPA is subject to termination at an earlier date on or after the fifth anniversary of the Plum Point Project’s commercial operations date for the 7.5% unit capacity or 50MW that has remained subject to the Empire PPA. Empire has the option to acquire another 7.5% ownership interest in the Plum Point Project and reduce the Contract Capacity to zero on the fifth anniversary of the Plum Point Project’s commercial operation date (the “Purchaser Second Buyout Option”).

If Empire fails to close on the Purchaser Second Buyout Option, the Empire PPA stays in full force and Empire is precluded thereafter from exercising such buyout option. Exercising the Purchaser Second Buyout Option terminates the Empire PPA.

The Empire PPA is subject to specified construction and energy delivery milestone deadlines.

If PPEA fails to meet any of the construction milestones, PPEA would be responsible to deliver to Empire completion security that shall be limited to an amount not to exceed $3 million, the product of $30 per kW and 100MW.

In the event the commercial operations date is delayed beyond August 1, 2010, PPEA may be responsible for replacement power or liquidated damages during the period of delay, subject to a maximum of $3 million, the product of $30 per kW and 100 MW.

Empire may terminate the Empire PPA and draw down the entire amount of any completion security posted if the delay period is longer than 365 days.

The commercial operations date and construction milestone dates may be extended by a force majeure or a delivery excuse.

In June 2006, MEAM exercised its buy out option of the entire MEAM PPA and acquired a 6% undivided interest in the Plum Point Project from PPEA and the MEAM PPA was terminated. MEAM has assumed all ongoing costs associated with the construction and operation of its portion of the Plum Point Project.

The MJMEUC PPA is subject to termination if the commercial operations date is delayed more than 365 days beyond June 1, 2010. The scheduled commercial operations date may be extended by a force majeure or a delivery excuse. MJMEUC has the option to extend the agreement for an additional five contract years (the “Extension Term”) by providing written notice to PPEA at least 24 months prior to the end of the initial term or any extension term. MJMEUC has a one-time option to purchase the contract capacity at the end of the first Extension Term at fair market value.

The SMEPA PPA is subject to termination if the commercial operations date is delayed more than 365 days beyond August 14, 2010. The scheduled commercial operations date may be extended by a force majeure or a delivery excuse. SMEPA has the option to purchase the contract capacity at fair market value or to extend the agreement for an additional ten contract years (the “SMEPA Extension Term”) by providing written notice to PPEA at least one contract year prior (two contract years prior notification to determine fair market value) to the end of the initial term.

At the end of the SMEPA Extension Term, SMEPA has the option to purchase the contract capacity at the same purchase terms as at the end of the initial term.

The SWECI PPA is subject to termination if the commercial operations date is delayed more than 365 days from the schedule commercial operations date of August 14, 2010. The scheduled commercial operations date may be extended by a force majeure or a delivery excuse.

Generation Facilities

The Company entered into two consecutive (May 1, 2006 until December 31, 2006 and January 1, 2007 until December 31, 2010) tolling agreements for the two electric generation units at Moss Landing 6&7 with Pacific Gas and Electric Company (“PG&E”). The unit contingent contracts include energy conversion, capacity and ancillary services with a price tied to a guaranteed availability rate and an expected heat rate. These contracts are on a unit contingent basis whereby if the unit is not operational, it is not expected to deliver power or make the contractor whole. These tolling agreements also provide for the reimbursement by PG&E of gas transportation costs. PG&E has exclusive full dispatch rights to the applicable generating units, limited by the rules of the California ISO, the contracted capacity and other operating restrictions.

The Company has provided letters of credit in the aggregate amount of $55.1 million as security for its obligations under the Moss Landing 6&7 tolling agreement. In addition, the Company is required to post additional security to PG&E to the extent PG&E’s mark-to-market exposure exceeds the amount of the posted letter credit. In order to be in a position to satisfy these potential additional security posting requirements, LSP Moss Landing, LLC and Gen Finance entered into an agreement with an investment grade financial institution, under which the financial institution has agreed to provide credit support in the form of cash deposits, up to a specified maximum amount. In the event PG&E were to utilize such cash deposits to satisfy Moss Landings’ obligations under the tolling agreement, Gen Finance would have an obligation to reimburse the financial institution. Gen Finance has provided a $30 million letter of credit to the financial institution as well as a lien on the collateral securing the Gen Finance credit facilities (see note 8).

Several capacity contracts were entered into by LSP Moss Landing, LLC, with various counterparties for the sale of resource adequacy capacity to load serving entities for delivery in 2007. The average monthly volume of the contracts is 147 MW. The contracts provide for the plant to bid the contracted capacity into the California ISO markets for the counterparties to have the right to claim contracted capacity resources to the California ISO in exchange for fixed monthly payments.

The Company’s Morro Bay electric generating facility has a three-year tolling agreement with PG&E for two of the facility’s units which is effective through December 31, 2007. Under this tolling agreement, PG&E pays Morro Bay a fixed capacity payment as well as a reimbursement for variable O&M expenses. The tolling agreement contracts the plant on a unit contingent basis. Under the contract, PG&E has the right to ancillary services as well as the contracted capacity of the plant. Security in the form of a $32.5 million letter of credit has been provided to PG&E.

On December 7, 2006, Griffith Energy, LLC entered into a unit contingent tolling agreement with Nevada Power Company for 50% of the output of the Griffith generating plant. The contract includes energy conversion with a price tied to a guaranteed availability rate. Nevada Power is responsible for providing fuel to the plant. The term of the contract is for the months of June through September 2007. LSP Gen provided a performance guarantee on behalf of Griffith Energy, LLC. The potential liability under this guarantee is capped at $5 million.

The Company’s South Bay and Oakland electric generating facilities operate under renewable Reliability Must Run (“RMR”) agreements with the California ISO which may be renewed by the ISO on a year-by-year and unit basis. Bridgeport operates under an RMR agreement with the ISO NE, which is subject to modification by the Federal Energy Regulatory Commission (“FERC”). The ISOs rely upon must run resources to ensure reliability in areas where the supply of electricity may be constrained due to transmission congestion and to maintain the voltage power and stability of the overall power grid. The purpose of the RMR agreements is to maintain sufficient power generation that can be dispatched by the ISO to ensure the reliability of the electricity transmission grid. Under an RMR agreement, the ISO, for certain fixed and variable payments, has the right to call on the generation facility to generate energy or provide ancillary services when required to ensure the reliability of the power grid.

The Bridgeport facility operates under a cost of service agreement to provide the ISO NE with the required reliability services. The Bridgeport RMR agreement was accepted but remains subject to ongoing proceedings before FERC. Unless terminated, the RMR agreement will be in place until May 31, 2010 (see note 14).

In connection with the Company’s Kendall Acquisition and Generation Acquisition, the Company recognized certain of these power purchase contracts as intangible assets with a fair value totaling $279.2 million and $48.4 million, respectively. In addition, Gen Finance recognized a power purchase contract as an out-of-market contract liability with a fair value of $2.4 million. As a result of the Kendall purchase price allocation adjustment made in 2005, the value of these power sales agreements was increased by $7.1 million. At December 31, 2006 and December 31, 2005, the gross carrying value, accumulated amortization and net carrying value of the power purchase agreements was approximately $332.3 million and $286.2 million, $70.8 million and $32.4 million and $261.5 million and $253.8 million, respectively. The estimated annual amortization expense for each of the next five years is approximately $41.3 million for 2007, $38.6 million for 2008, $38.6 million for 2009, $38.7 million for 2010 and $23.4 for 2011.

(b)

Heat Rate Options

Generation Facilities

The Company has entered into several heat-rate call option contracts with respect to energy from its electric generating units at Moss Landing 1 and 2, Arlington Valley, Griffith and Casco Bay. These contracts were entered into with high quality, investment grade counterparties.

The counterparties to such agreements pay a monthly fixed fee to the Company and receive payments based on the prevailing energy price based on certain energy price indices and the sum of the applicable facility’s fuel costs based on a specified price and a strike price for each hour of generation actually called for. The heat rate at which the contracts are priced incorporates start up costs, variable operating costs, including transmission losses, if any, gas taxes and certain adjustments to gas prices to reflect basis differentials. The contracts are settled between the parties on a monthly basis. The Company retains dispatch control over all of the contracted units and receives all proceeds from the physical sale of energy, capacity (including resource adequacy) and ancillary services.

The Company’s counterparties received letters of credit in the aggregate amount of $179.3 million and a first priority lien on the same collateral as the Gen Finance credit agreements for a portion of the mark to market exposure under the call options. In addition, they also received a third priority lien on the same collateral as the Gen Finance credit agreements to secure the remaining portion of the mark to market exposure under the call options that is not secured under the first lien. Also, the Company has the right to substitute lien collateral for letters of credit, investment grade guaranties or liens on other assets.

The options expire as follows: Arlington Valley and Griffith on September 30, 2008, Moss Landing 1&2 on September 30, 2010 and Casco Bay on December 31, 2010.

Ontelaunee

Ontelaunee and a third party entered into a heat-rate call option agreement effective for the period January 1, 2006 through December 31, 2008. The counterparty pays Ontelaunee a monthly charge during the term and the counterparty receives payments based on the prevailing energy price based on certain energy price indices and the sum of the facility’s fuel costs based on a specified price and a strike price for each hour of generation actually called for. The heat rate at which the contracts are priced incorporates start up costs, variable operating costs, including transmission losses, if any, gas taxes and certain adders to gas prices to reflect basis differentials. The Company retains dispatch control over the facility and receives all proceeds from the physical sale of energy, capacity (including resource adequacy) and ancillary services. As of December 31, 2006, the Company had issued a $13.6 million ($11.5 million at December 31, 2005) letter of credit for the benefit of the counterparty as security under this agreement.

The Company realized income of approximately $21.7 million related to the heat rate options for the period ended December 31, 2006. The fair value of all the heat rate options at December 31, 2006 totaled a net asset $1.4 million (see note 9).

(c)

Energy and Fuel Services Agreements

Generation Facilities

The Company has an Energy Management and Marketing Agreement with Bear Energy, LP (the “Bear EMA”). Under the terms of the Bear EMA, Bear Energy, LP (“Bear”) provides energy, ancillary services, fuel and risk management services for the Generation Facilities. Among other things, Bear markets power and capacity, schedules dispatch and supplies the natural gas required to operate the facilities. Each of the managed facilities retains the ability to sell power, capacity or ancillary services to third parties. Bear’s obligations under this agreement are guaranteed by The Bear Stearns Companies. The Company has the right to terminate the Bear EMA upon 30 days’ notice.

Each month during the term of the Bear EMA, Bear is required to issue to the Company monthly invoices setting forth for the prior month all related revenues earned and costs incurred. The invoice is paid on a net basis. Bear receives a monthly management fee equal to a percentage of the value created above each of the Generation Facilities’ indexed spark spread margin. The management fee has a floor calculated over a 12-month period. The Company has issued letters of credit in the aggregate amount of $10 million for the benefit of Bear as security under this agreement.

Kendall

During 2005, Kendall had an Energy Management and Marketing Agreement with Progress Ventures, Inc. (the “EMA”). Under the terms of the EMA, Progress Ventures, Inc. (“Progress”) provided energy, fuel and risk management services for one of the units at the Kendall facility. Progress received a monthly management fee equal to a fixed percentage of the gross margin of the Unit subject to a minimum fee.

During the term of the EMA, Kendall was required to provide Progress security for Kendall’s obligations under the EMA. To satisfy this obligation, in 2005, the Company funded an escrow account in the amount of $2 million from its restricted cash. Under the terms of the escrow agreement, Progress was the beneficiary of the escrow account.

The EMA expired on February 28, 2006. At that time the EMA expired, the escrow agreement was terminated and the related funds were then released to Kendall.

On February 28, 2006, an Energy Management Agreement (the “Cinergy EMA”) with Cincinnati Gas & Electric Company (“Cinergy”) became effective. This agreement expired on December 31, 2006. In accordance with the terms of the agreement, Cinergy provided power management, fuel management and risk management services. Cinergy received a monthly management fee equal to a fixed percentage of the gross margin of the Unit subject to a minimum fee. As security for its obligations under the Cinergy EMA, the Company issued to Cinergy a standby letter of credit in the amount of $1 million. Effective November 1, 2006, the Cinergy EMA was assigned to Fortis Energy Marketing & Trading GP (“Fortis”). The agreement expired on March 31, 2007 but was extended for an additional three months. The Cinergy letter of credit was replaced with a $1 million letter of credit issued to Fortis.

Ontelaunee

Ontelaunee had an Energy Services Agreement (the “ESA”) with Calpine Energy Services, L.P. (“CES”). Under the terms of the ESA, CES provided energy and risk management services for the Ontelaunee facility. CES received a monthly management fee equal to a fixed percentage of the monthly generation margin subject to a minimum fee. The ESA expired on August 31, 2006.

On August 31, 2006, Ontelaunee and Eagle Energy Partners I, L.P. (“Eagle”) entered into an agreement that requires Eagle to provide energy and risk management services for the Ontelaunee facility. Eagle receives a fee comprised of fixed and variable components. The agreement was amended and restated on December 1, 2006 to include fuel management services for the Ontelaunee facility. As security, funds owed to Ontelaunee from PJM for power sold during the prior month are sent directly to Eagle on a monthly basis. Eagle forwards any remaining funds to Ontelaunee after any outstanding invoices to Ontelaunee have been paid. The term of the agreement expires on August 31, 2007, unless the parties mutually agree to an extension of one additional year.

Ontelaunee had a natural gas supply management contract with Cinergy Marketing and Trading LP (“CMT”) that expired on May 31, 2006. A natural gas supply management contract with BG Energy Merchants, LLC (“BG”) was in effect from June 1, 2006 to November 30, 2006. Under the agreement, BG provided fuel management services for the Ontelaunee facility.

The Company has incurred costs of $6.3 million and $0.3 million for the years ended December 31, 2006 and 2005, respectively, under all these energy and fuel services agreements.

(d)

Transportation Agreements

Generation Facilities

The Company has several firm natural gas transportation contracts for firm reserved service to a number of the Company’s facilities. The Company is required to pay rates per decatherm of natural gas delivered based on current gas tariffs.

Bridgeport Energy has two 20-year transportation agreements, one with Iroquois Gas Transmission System (‘Iroquois’) and one with Southern Connecticut Gas (‘SCGC’) and CNE Energy Services, Inc. (‘CNE’). Iroquois constructed an approximately 1 mile-long natural gas pipeline to connect Iroquois’ transmission system to SCGC’s gas lateral which in turn connects with the Bridgeport Facility. Bridgeport Energy pays Iroquois monthly demand charges of approximately $50,000 plus a per decatherm charge to transport natural gas on the pipeline and pays SCGC and CNE $625,000 per month for the transportation of up to 187,000 decatherms of natural gas per day. The Company issued letters of credit in the aggregate amount of $6.5 million as security under these agreements.

Arlington Valley had a 5-year transportation agreement, with automatic one year extensions, dated May 7, 2001, with El Paso Natural Gas Company (“El Paso”). El Paso constructed a natural gas pipeline to connect El Paso’s transmission system to the facility. Arlington Valley pays El Paso on a per decatherm basis at a rate equal to El Paso’s Natural Gas Rate Schedule FT-1 to transport up to 83,000 decatherms of natural gas per day on the pipeline. In June 2006, Arlington Valley entered into an amended agreement with El Paso for deliveries beginning June 1, 2006 thru October 31, 2008. The transportation contract provides for 45,500 MMBTU/day during the months of April through October. The Company issued a letter of credit in the amount of $2.5 million as security under this agreement.

Casco Bay has a 20-year transportation agreement, dated September 17, 1998, with Maritimes & Northeast Pipeline, LLC (“Maritimes”), Maritimes constructed a 1.1 mile-long natural gas pipeline to connect to the Casco Bay facility. Casco Bay pays Maritimes a demand charge of approximately $73,000 per month plus a per decatherm rate for the transportation of natural gas on the pipeline. Duke Capital issued a guaranty to Maritimes as security under this agreement. The Company issued a letter of credit in the amount of $12.3 million to Duke Capital that will remain in place until the earlier of the expiration of the contract or the date that Duke Capital’s guaranty is released.

Griffith has a 20-year transportation agreement, dated April 30, 1999, with Citizens Utility Company (“CUC”). CUC constructed, owns and operates pipeline, metering and interconnection facilities between two interstate natural gas pipelines and the Griffith generating plant. The transportation agreement provides for 121,000 decatherms of natural gas per day. Griffith pays CUC a demand charge of approximately $78,000 per month for the transportation of natural gas on the pipeline.

Costs incurred under these agreements totaled $28.4 million for the year ended December 31, 2006.

(e)

Operations and Maintenance Agreements

Generation Facilities

The Company has entered into operations and maintenance contracts with three counterparties which provide for the operation and maintenance of the Generation Facilities (the “Generation O&M”). Several of these contracts have five year terms expiring in 2011, with the earliest contract term set to expire in 2010, but can be automatically extended for up to five years. The Company pays a fixed monthly management fee and reimburses the operator for all labor costs, including payroll and taxes, and other costs.

Kendall

Under the terms of a long-term operations and maintenance agreement with respect to the Kendall facility (“Kendall O&M Agreement”), the Company is required to pay the operator a fixed annual fee to operate the Kendall facility. Kendall is also required to reimburse the operator for all labor costs, including payroll and taxes, subcontractor costs and other costs. The annual fee is adjusted annually based on specified indices published by the United States Government. The Kendall O&M Agreement expires on March 28, 2012.

Ontelaunee

Under the terms of an operations and maintenance agreement with respect to the Ontelaunee facility (the “Ont O&M Agreement”), the Company is required to pay the operator a fixed monthly fee to operate the Ontelaunee facility. The Company is also required to reimburse the operator for all labor costs, including payroll and taxes, subcontractor costs and other costs. The monthly fee is adjusted annually based on specified indices. The initial term of the Ont O&M Agreement is 5 years commencing on October 6, 2005. The Ont O&M Agreement was assigned to Worley Parsons on September 15, 2006.

The Company incurred costs of $35.6 million and $4.6 million under all of the operations and maintenance agreements for the years ended December 31, 2006 and 2005, respectively.

(f)

Long Term Parts and Service Agreements

Generation Facilities

The Company has five Long-Term Service Agreements (the “Gen LTSAs”) with two counterparties which provide for planned and unplanned major maintenance services including parts, repairs, and other services to a number of the Generation Facilities. The majority of the costs incurred under these agreements vary, and are based on factored hours and starts. Fixed and variable payments consist of fees and performance related bonuses, as well as specified amounts paid upon the occurrence of certain maintenance events. The Company issued letters of credit in the aggregate amount of $94 million for the benefit of one counterparty as security under these agreements.

Kendall

Pursuant to the terms of a Long-Term Service Agreement with respect to the Kendall facility (the “Kendall LTSA”) the service provider provides long-term parts and services for each of the four combustion turbine Units located at the Kendall facility. The term of the Kendall LTSA will expire on a Unit by Unit basis after the later of (i) the date on which a Unit has attained either 96,000 factored hours or 5,400 factored starts, as defined in the Kendall LTSA, whichever occurs first, or (ii) the date on which the service provider has completed the second major inspection, as defined in the Kendall LTSA, for such Unit. In no event shall the term of the Kendall LTSA extend beyond the 21st anniversary of the effective date.

Fees for the Kendall LTSA are comprised primarily of (i) a variable quarterly payment based upon each Unit’s operational parameters and (ii) a fixed payment based upon each Unit’s actual hours and starts incurred. All payments are adjusted annually based upon specified indices published by the United States Government.

Ontelaunee

Pursuant to the terms of a Long Term Service Agreement with respect to the Ontelaunee facility, the service provider provided long term parts and services for each of the two combustion turbine units located at the Ontelaunee facility. The contract was terminated on December 8, 2006 and was not replaced.

The Company incurred costs of approximately $17.6 million and $4.4 million under all these long term parts and service agreements for the years ended December 31, 2006 and 2005, respectively.

(g)

Electric Interconnection Agreements

Generation Facilities

The Company has an interconnection agreement with the WAPA which provides for the interconnection of the Griffith facility to WAPA’s transmission system. The Company was required to pay for certain improvements to the WAPA transmission system to enable transmission of electricity from the Griffith facility. The amount paid is refunded to the Company in the form a monthly credit of $252,000 to Griffith’s transmission service charge through June 2018. At December 31, 2006 the Company had a current asset and a noncurrent asset of $2 million and $26 million, respectively, for such reimbursement.

Ontelaunee

The Company has an Interconnection Agreement with Metropolitan Edison Company (“GPU”) to transmit the electricity generated by the Ontelaunee facility to the transmission grid so that it may be sold in the open market. The agreement is in effect for the life of the Ontelaunee facility. In order to bring the transmission lines up to capacity, GPU had to upgrade the lines and network. GPU recovers its cost of the upgrades through a monthly fee of approximately $112,000 that is fixed for 25 years, at which time the rate will be renegotiated. If Ontelaunee terminates the contract prior to its expiration, it will be responsible for an early termination charge as outlined in the agreement. The Company issued a letter of credit of approximately $5.7 million for the benefit of GPU as security under this agreement.

Upon termination of this agreement, Ontelaunee may be required to pay for the removal of the upgrades, less salvage. The upgrades are critical to Ontelaunee’s ability to transmit energy and are integral to the operations of GPU’s transmission network. As a result, Ontelaunee does not believe it will be required to remove the upgrades upon termination. Accordingly, Ontelaunee has not recognized an asset retirement obligation related to this provision of the agreement as of December 31, 2006 and 2005.

(h)

Project Development and Construction Agreements

The Company entered into an option agreement pursuant to which the Company acquired an option to acquire all or a portion of an interest in a certain transmission line and related facilities. Under the terms of the agreement, the Company is obligated to make fixed payments over a two year period totaling $1.5 million. For the years ended December 31, 2006 and 2005, the Company made payments of $400,000 and $600,000, respectively, under such agreement.

Pursuant to an Asset Purchase Agreement (the “Asset Purchase Agreement”), dated March 14, 2006, PPEA sold 37.15% of its ownership interest in the Plum Point Project to the three unaffiliated investors (the “Project Co-Owners”). The Company recognized a gain of approximately $30 million in connection with such sale. The gain is recorded in other income, net on the combined statement of operations. Each Project Co-Owner owns an undivided tenancy in common interest in the Plum Point Project and participates in the construction and operation of the Plum Point Project with PPEA. Each Project Co-Owner is separately financing its pro rata share of the total construction cost of the project.

PPEA, the City of Osceola, Arkansas (the “City”), Mississippi County, Arkansas, the Osceola School District No. 1 of Mississippi County and the Mississippi County Community College District entered into an agreement (the “PILOT Agreement”) whereby the City agreed to issue Industrial Development Revenue Bonds for the purpose of acquiring, constructing and equipping certain industrial facilities within or near the City that make up the Plum Point Project. Pursuant to the PILOT Agreement, the City agreed to enter into a lease agreement (the “Pilot Lease”) whereby the Plum Point Project would be leased from the City to PPEA. In return, PPEA agreed to make (i) a one time donation to the City, the School District and the Community College and (ii) payments in lieu of certain ad valorem taxes over the term of the Pilot Lease or any extension term of the Pilot Lease.

Prior to the sale of its interests in the Plum Point Project to the Project Co-Owners, PPEA transferred its interest in the Plum Point Project (including the project site) to the City, and the City and PPEA entered into the PILOT Lease pursuant to which the City leased-back such interest to PPEA. After the transfer and lease-back of the Plum Point Project, PPEA sold undivided tenancy-in-common interests in the Plum Point Project to the Project Co-Owners. Such undivided, tenancy-in-common interests included an assignment of such interests in the PILOT Lease, excluding certain of the Project Co-Owners’ obligations to pay rent. The rent obligations will be excluded from obligations because only PPEA and Empire will use an industrial development bond structure to fund their share of the Plum Point Project’s costs and

rent payments will be used by the City to provide debt service on the industrial development bonds issued by the City to PPEA. The bond documents permit PPEA and Empire to satisfy their obligations to make rent payments under the PILOT Lease by way of netting the amount of each rent payment against the equal amount otherwise payable at such time to PPEA as holder of the bonds.

On March 1, 2006, the City and PPEA entered into a Lease Agreement, Trust Indenture and Guaranty Agreement and other ancillary documents (collectively, the “Taxable Bond Documents”). Pursuant to the Trust Indenture, the City issued the City of Osceola, Arkansas Taxable Industrial Development Revenue Bonds, Series 2006, in the aggregate principal amount of up to $980 million (the “Taxable Bonds”) for the purpose of acquiring, constructing and equipping certain industrial facilities that make up the Plum Point Project. Pursuant to the Lease Agreement, the City leased the project to PPEA for a term to match the maturity of the Taxable Bonds (March 1, 2036).

Under the PILOT Lease, PPEA is required to pay, as rent, amounts equal to any amounts payable from time to time as principal and accrued interest on the Taxable Bonds. Under the Trust Indenture, the Taxable Bonds are not full recourse obligations of the City but are rather limited recourse obligations that are payable only out of amounts received as rent under the Pilot Lease. PPEA is the sole holder of the Taxable Bonds. Consequently, PPEA is both the payor and the ultimate payee of the amounts payable by PPEA as rent under the Pilot Lease. In recognition of this fact: (i) the Taxable Bond Documents permit PPEA to satisfy its obligation to make rent payments by way of netting the amount of each rent payment against the equal amount otherwise payable at such time to PPEA as holder of the Taxable Bonds, and (ii) as a result of such netting, PPEA is not expected to have any obligation to make any cash payments under the Pilot Lease.

On June 8, 2006, PPEA sold 6% of its ownership in the Plum Point Project to MEAM. The Company recognized a gain of approximately $5.6 million in connection with such sale. The gain is recorded in other income, net in the combined statement of operations. MEAM has assumed all of the ongoing costs associated with the construction and operation of its portion of the Plum Point Project.

As of December 31, 2006, PPEA held a 56.85% undivided interest in the Plum Point Project.

PPEA and the Project Co-owners are parties to a Participation Agreement (the “Participation Agreement”) that provides for sharing, in proportion to their respective interests, in the construction costs, the capital expenses and the fixed operating expenses reflected of the Plum Point Project. The purpose of this agreement is to set forth the manner in which the significant contracts and undertakings for the Plum Point Project shall be managed and administered. The Participation Agreement also establishes a management committee composed of a representative of PPEA and each Project Co-Owner.

The term of the Participation Agreement is from the date of signing until retirement from service of the Plum Point Project and the applicable windup events have been completed (including the distribution of proceeds from the sale of the Plum Point Project).

On December 1, 2005, PPEA entered into a $880.8 million fixed price Turnkey Engineering, Procurement and Construction Agreement (the “Plum Point EPC”), as amended, with Plum Point Power Partners (the “Contractor”), a joint venture of Zachry Construction Corporation, Overland Contracting Inc., and Gilbert Central Corporation, which provides for the Contractor to design, engineer, procure, construct, start-up and test the Plum Point Project on a turnkey, total cost basis. The contract price includes the Plum Point Project, the transmission line to the proposed Entergy Arkansas, Inc. (“Entergy”) switchyard and the railroad facilities to be interconnected with the BNSF Railway Company (“BNSF”) mainline switch. Construction of the Plum Point Project began in March 2006. During 2006, PPEA assigned an undivided tenancy in common interest in the Plum Point EPC to the Project Co Owners.

In completing the Plum Point Project, the Contractor shall be solely responsible for the engagement and management of subcontractors and is responsible for all related costs, whether incurred by the Contractor or its hired subcontractors. Contractor shall also secure and pay for all necessary approvals, permits, and licenses; and pay all taxes levied in connection with the performance of the work.

If Substantial Completion, as defined in the Plum Point EPC, has not occurred before or on the Guaranteed Completion Date of August 14, 2010, the Contractor must pay to PPEA and the Project Co-Owners delay liquidated damages. If Substantial Completion is not achieved by 180 days after August 14, 2010, PPEA and the Project Co-Owners may terminate the Plum Point EPC. The Contractor is required to achieve final completion within 9 months of Substantial Completion.

Performance liquidated damages and performance bonuses will be payable to the extent that the results of the performance test for the Plum Point Project differ from the performance guarantees. Availability liquidated damages shall be payable to the extent the result of the availability test is less than the availability guarantee. Liquidated damages for reagents tests are also available if reagents tests do not demonstrate that all reagents guarantees (maximum usage rates) have been complied with.

The aggregate liability of the Contractor to pay liquidated damages will not be greater than 25% of the contract price, plus the full amount received by the Contractor in respect of bonuses.

As of December 31, 2006, total costs incurred by PPEA under the Plum Point EPC were $89.4 million, including contract retainage payable of $4.2 million. Contract retainage payable is recorded as a non-current liability in the accompanying combined balance sheet.

PPEA and Entergy Arkansas, Inc. (“Entergy”) are parties to the Entergy Interconnection and Operating Agreement (the “Entergy Interconnection Agreement”) which provides for the interconnection of the Plum Point Project to Entergy’s electric transmission system. The Entergy Interconnection Agreement binds the parties until the termination by mutual consent of the parties, not to exceed the date on which the Plum Point Project ceases commercial operations. During 2006, PPEA assigned an undivided tenancy in common interest in the Entergy Interconnection Agreement to the Project Co-Owners.

Entergy is responsible for performing system upgrades, as necessary to accept electrical energy from the Plum Point Project at the point of interconnection, which shall include a new 500 kV substation and two 500 kV transmission line segments approximating 1.5 miles. PPEA and the Project Co-Owners shall be responsible for paying for the cost of the interconnection system upgrades but will receive certain transmission service credits. PPEA and the Project Co-Owners agree to reimburse Entergy for all interconnection costs reasonably incurred by Entergy under the Entergy Interconnection Agreement in connection with the testing, metering and upgrade of the Interconnection facilities.

An agreement for the Engineering, Procurement and Construction for the Sans Souci Switchyard (“Entergy EPC Agreement”) dated November 10, 2006 was executed between PPEA, the Project Co-Owners and Entergy. For the purposes of executing the Entergy EPC Agreement, LSP Services Plum Point, LLC, (“LSP Services”), an affiliate of PPEA, was identified as the duly authorized representative for PPEA and the other Project Co-Owners.

For purposes of the Entergy EPC Agreement, PPEA and the Project Co-Owners have retained LSP Services as its project management company for the switchyard project and has delegated to LSP Services authority to act for and on their behalf with respect to the administration of the Entergy EPC Agreement.

LSP Services executed a $10.7 million fixed-price date certain Switchyard Turnkey Engineering, Procurement, and Construction Agreement (“Switchyard EPC Agreement”) dated November 13, 2006 with National Conductor Contractors (“NCC”) for the design, engineering, procurement, construction, training, commissioning, and testing services for the Sans Souci Switchyard.

The Guaranteed Completion Date is identified as March 1, 2008. The NCC warranty period ends eighteen (18) months after March 1, 2008. The San Souci Switchyard is schedule to be energized by August 2008 which should provide about one year to verify the equipment reliability.

If Substantial Completion, as defined in the Switchyard EPC Agreement, has not occurred on or prior to the Guaranteed Completion Date, NCC is required to pay delay liquidated damages. The aggregate liability of Contractor to pay delay liquidated damages is not to exceed an amount equal to twenty five percent (25%) of the contract price.

As of December 31, 2006, PPEA had incurred costs of approximately $274,000 under the Switchyard EPC Agreement, including contract retainage of approximately $14,000. Contract retainage payable is recorded as a non-current liability in the accompanying combined balance sheet.

PPEA paid a $45.5 million upfront option premium in connection with a 5-year gas option agreement (the “Option Agreement”). The Option Agreement economically hedged gas volumes equivalent to 84% of the on peak output of the future net capacity of the Plum Point Project after giving effect to the sale of undivided interests and to the power purchase agreements described above. In October 2006 and November 2006, PPEA unwound such option and received $40.2 million. PPEA recorded a loss of $5.4 million on the transactions which is

recorded in other income, net in the combined statements of operations. Proceeds of approximately $34.4 million were used to repay a portion of the outstanding principal and related interest on First Lien Term Loans and Second Lien Term Loans.

The contracts discussed in this footnote resulted in the Company having various long-term firm commitments with the approximate contractual obligations, excluding obligations under the Plum Point EPC and Switchyard EPC Agreement, for the next five years at December 31, 2006 as follows:


	2007		2008		2009		2010		2011
	(In thousands)
Interconnection agreements	$	7,744	$	7,746	$	7,748	$	7,750	$	7,752
Gas transportation agreements		9,884		9,884		9,884		9,884		9,884
Energy and fuel services agreements		2,359		—		—		—		—
O&M and long-term service agreements		24,995		25,590		18,689		41,139		76,707

Total contractual obligations	$	44,982	$	43,220	$	36,321	$	58,773	$	94,343

(8)

Financing Arrangements

As of December 31, 2006 and 2005, outstanding principal balances under the Company’s financing agreements described below are as follows:


	2006		2005		Maturity Date
	(In thousands)
Plum Point term loans	$	499,652	$	—	2014
Plum Point bonds		100,000		—	2036
Generation Facilities first lien term loans		951,628		—	2013
Generation Facilities second lien term loans		150,000		—	2014
Kendall loans		401,653		420,945	2013
Ontelaunee loans		150,000		125,000	2009

Total outstanding principal	$	2,252,933	$	545,945

As of December 31, 2006, minimum principal payments under the Company’s financing agreements described below for the next five years are as follows:


	2007		2008		2009		2010		2011		Thereafter
	(In thousands)
Plum Point	$	—	$	—	$	—	$	2,115	$	4,230	$	593,307
Generation Facilities		9,895		9,895		9,895		9,895		9,895		1,052,153
Kendall		4,220		4,220		4,220		4,220		4,220		380,553
Ontelaunee		—		—		150,000		—		—		—

Total principal payments	$	14,115	$	14,115	$	164,115	$	16,230	$	18,345	$	2,026,013

(a)

Plum Point

Effective March 14, 2006, PPEA closed its financing for the Plum Point Project with a consortium of financial institutions (the “PPEA Lenders”). The financing consists of (1) (a) a $423 million term loan, (b) a $50 million revolver and (c) a $102 million letter of credit facility (collectively, the “First Lien Facility”) and (2) a $175 million term loan (the “Second Lien Facility”), (and collectively with the First Lien Facility, the “PPEA Credit Facility”).

On March 14, 2006, PPEA borrowed $423 million under the First Lien Facility and $175 million under the Second Lien Facility. The proceeds of the loans issued under the PPEA Credit Facility will be used to fund PPEA’s pro rata portion of the construction costs for the development of the Plum Point Project, fund interest expense during construction, provide for a six-month debt service reserve when commercial operations are achieved and provide PPEA’s pro rata portion of working capital for the operations of the Plum Point Project.

As a result of the MEAM buy-in (see note 7), PPEA repaid $66.8 million of outstanding term loans to align its borrowing under such term loans to its proportionate share of total construction costs. In addition, the letters of credit issued under an Equity Contribution Agreement (the “Equity Agreement”) were reduced by $14.6 million (see below).

In October 2006 and November 2006, the Option Agreement was unwound and PPEA received approximately $40.2 million. Proceeds of approximately $34.1 million were used to repay a portion of the outstanding loans under the First Lien Facility and Second Lien Facility.

For the year ended December 31, 2006, PPEA made principal payments on outstanding loans under the First Lien Facility and the Second Lien Facility of $71.3 million and $29.6 million, respectively. Outstanding loans under the First Lien Facility and Second Lien Facility at December 31, 2006 totaled $351.7 million and $148 million, respectively. The interest rates in effect on loans under the First Lien Facility and Second Lien Facility at December 31, 2006 was 8.61% and 10.61%, respectively. The additional 2% interest charge is paid-in-kind interest which is capitalized to the outstanding principal balance at the end of each quarter. Total paid-in-kind interest for the year ended December 31, 2006 was approximately $2.6 million.

In addition, a funded letter of credit in the amount of approximately $101 million was issued under the letter of credit facility for the benefit of the owners of the Tax Exempt Bonds. The letter of credit facility is unfunded by PPEA. The letter of credit facility is secured by a cash deposit funded by the participating Lenders and held by the bank that issued the letter of credit. PPEA is required to pay fees on a quarterly basis equal to 0.125% plus 3.25% per annum on the entire letter of credit facility amount.

Concurrent with the financing under the PPEA Credit Facility, PPEA entered into two interest rate swap agreements. The terms of the swaps require PPEA to pay a fixed rate and receive a floating rate. The swaps mature in March 2014. The fixed rate is 5.15% while the floating rate is based on 3 month LIBOR rate (see note 9).

The loans are secured by all of the assets and contract rights of PPEA. In addition, PPEA Holding Company, LLC (“PPEA Holding”), the sole member of PPEA, has pledged its ownership interest in PPEA as security for these loans. The PPEA Credit Facility and the Depositary Agreement (the “Depositary Agreement”), (collectively, the “Credit Documents”) set forth, among other things: (a) terms and conditions upon which loans and disbursements are to be made under the PPEA Credit Facility; (b) the mechanism for which loan proceeds, operating revenues, equity contributions and other amounts received by PPEA are disbursed to pay construction costs, operations and maintenance costs, debt service and other amounts due from PPEA; (c) the conditions that must be satisfied prior to making distributions from PPEA; and (d) the covenants and reporting requirements PPEA is required to be in compliance with during the terms of the loans.

The Credit Documents require compliance with covenants, including, among other things, compliance with reporting requirements, limitations on the use of the proceeds under the PPEA Credit Facility, additional indebtedness, and disposition of assets. The Credit Documents also describe events of default which include, among others, failure to make payments in accordance with the terms of the PPEA Credit Facility and failure to comply with agreements entered into by PPEA.

Principal payments of the loans under the First Lien Facility and Second Lien Facility are not due until the Plum Point Project achieves commercial operations (“COD”), currently projected to be in the summer of 2010. At COD, annual mandatory amortization of the term loan under the First Lien Facility is 1.0%, payable quarterly. Subject to the priority allocation of cash described in the Credit Documents, after the payment of, among other things, operating expenses, repayment of borrowings under the revolver, funding of certain reserve accounts, and payment of mandatory interest and principal, all excess cash generated is applied to pay down principal on outstanding loans under the First Lien Facility. The term loan and letter of credit facility under the First Lien Facility mature in March 2014. The revolver matures in March 2012. The term loan under the Second Lien Facility matures in September 2014.

Under the terms of the Equity Agreement, PPEA Holding is required to make an aggregate equity contribution to PPEA in the amount of $210 million prior to the completion of construction of the Plum Point Project. As security for this obligation, each member of PPEA Holding or its affiliate has issued separate letters of credit in favor of the PPEA Lenders. Letters of credit in the amount of $118 million, $17 million and $75 million were issued by LSP Plum Point Holding, LLC, LS Associates, and the unaffiliated member, EIF Plum Point, LLC (“EIF”), respectively.

Effective March 29, 2007, PPEA refinanced the Credit Facility. The financing consists of a $700 million term loan facility (the “Bank Loan”), a $17 million revolving credit facility (the “Revolver”) and a $102 million letter of credit facility (the “LC Facility”). The LC Facility will be utilized to back-up the $101 million letter of credit issued under the existing L/C Facility until alternative facilities can be put in place. PPEA will also enter into interest rate hedging agreements for a portion of the outstanding loans under the Bank Loan. The Tax Exempt Bonds will continue under the proposed refinancing.

Interest rates on outstanding loans will either be the prime rate or LIBO plus .35%. In addition, PPEA will pay commitment fees equal to .125% per annum on the undrawn Bank Loan, Revolver and LC Facility commitments.

The payment obligations of PPEA in respect of the Bank Loan, the Revolver, the LC Facility, the Tax Exempt Bonds, and the interest rate hedging agreements are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation. The insurer also provided an unconditional commitment to issue a debt service reserve surety at closing in an amount equal to the debt service reserve requirement.

The credit facilities and insurance policy are secured by a security interest (subject to permitted liens) in all of PPEA’s assets, contract rights and PPEA’s undivided tenancy in common interest in the Project.

On March 29, 2007, PPEA borrowed $185.1 million under the Bank Loan. Approximately $172.7 million of such proceeds were used to repay all the outstanding loans under the First Lien Facility and Second Lien Facility of $499.7 million, net of available restricted cash of $361.1 million, payment of a call premium of $8 million in respect to the First Lien Facility and Second Lien Facility, accrued interest and commitment fees of $12.4 million under the First Lien Facility and Second Lien Facility, termination fees of $6.2 million on the existing interest rate swap agreements and debt issuance and financing fees of $7.6 million related to the Bank Loan, Revolver and LC Facility.

On April 1, 2006, the City and PPEA entered into a loan agreement authorizing that the proceeds of the City of Osceola, Arkansas Solid Waste Disposal Revenue Bonds (Plum Point Energy Associates, LLC Project) in the aggregate amount of $100 million (the “Tax Exempt Bonds”) will be loaned by the City to PPEA. The Tax Exempt Bonds are issued pursuant to and secured by a Trust Indenture dated April 1, 2006 between the City, PPEA and Regions Bank as Trustee. The purpose of the Tax Exempt Bonds is to finance certain of PPEA’s undivided interests in various sewage and solid waste collection and disposal facilities. These systems are eligible for tax exempt financing. Interest expense on the Tax-Exempt Bonds is based on a weekly variable rate and is payable monthly. The interest rate in effect at December 31, 2006 was 3.95% and total interest expense incurred during 2006 was approximately $2.5 million. To support the payment of principal and interest on the Tax Exempt Bonds, an irrevocable letter of credit in the amount of $101 million was issued under the PPEA Credit Facility for the benefit of the owners of the Tax Exempt Bonds.

(b)

Generation Facilities

A portion of the purchase price of the Generation Acquisition was funded through the issuance of term loans by Gen Finance, a wholly owned subsidiary of LSP Gen, under two credit agreements, the First Lien Loan Facility and the Second Lien Loan Facility (collectively, the “Gen Finance Credit Facilities”). The Gen Finance Credit Facilities consist of:

(1) a $950 million 7-year first lien term loan, a $40 million 7 year first lien delayed draw term loan, and a $150 million 8-year second lien term loan; all used to (i) fund a portion of the Generation Acquisition and (ii) pay a portion of the fees and expenses associated with the transaction;

(2) a $100 million 5-year first lien revolving and letter of credit facility that is used for general corporate, liquidity and working capital purposes (the “Working Capital Facility”);

(3) a $500 million 7-year first lien funded letter of credit facility (the “Special LC Facility”). The Special LC Facility is used to (i) support obligations under certain agreements and (ii) satisfy certain collateral requirements with respect to maintenance, operations, fuel purchase, transportation and transmission services; and

(4) a $150 million 5-year incremental letter of credit facility, which may be used to provide support to permitted project related agreements and other uses which are necessary for the operation of the business.

As of December 31, 2006, approximately $13.9 million in letters of credit were outstanding under the Working Capital Facility, approximately $470.3 million in letters of credit were outstanding under the Special LC Facility and $30 million in letters of credit were outstanding under the five-year letter of credit facility. There were no outstanding working capital loans at December 31, 2006.

The interest rate on loans under the Gen Finance Credit Facilities adjusts for each interest period based on the adjusted LIBOR rate. The interest rates in effect at December 31, 2006 for the first lien term loans and second lien term loans were 7.11% and 8.86%, respectively.

Annual mandatory amortization of the term loans under the First Lien Loan Facility is 1.0%, payable quarterly. Subject to the priority allocation of cash described in the Gen Finance Credit Facilities after the payment of, among other things, operating expenses, repayment of borrowings under the Working Capital Facility, funding of certain reserve accounts, and payment of mandatory interest and principal, between 75% and 95% of excess cash generated, depending on attainment of certain debt amortization targets, is applied to pay down principal. The term loans under the First Lien Loan Facility mature in May 2013. The term loans under the Second Lien Loan Facility mature in May 2014. The Working Capital Facility matures in May 2011.

In connection with the Gen Finance Credit Facilities, Gen Finance entered into three interest rate swap agreements. The terms of the swaps require Gen Finance to pay a fixed rate and receive a floating rate. The floating rate is based on three-month LIBOR rate (see note 9).

The Gen Finance Credit Facilities require that proceeds from borrowings, the receipt of revenues, debt service payments and the payments for certain categories of expenses each be segregated into separate bank accounts. Under the terms of a security deposit agreement (the “Security Deposit Agreement”), Gen Finance has established the required bank accounts and has pledged all its rights, title and interest in the bank accounts as security for its payment obligations under the Gen Finance Credit Facilities. Gen Finance has also established a liquidity reserve account which may be funded at Gen Finance’s option with cash, equity commitments or through commitments under the Working Capital Facility. The liquidity reserve is to be in an amount equal to the lesser of (A) $50 million and (B) an amount equal to the sum of (i) six months of scheduled debt service plus (ii) a portion of certain projected major maintenance costs.

All obligations of Gen Finance under the Gen Finance Credit Facilities are guaranteed by all of the wholly owned existing subsidiaries and certain other affiliates of Gen Finance.

In August 2006, LSP Moss Landing, LLC and Gen Finance entered into an agreement with an investment grade financial institution, under which the financial institution has agreed to provide credit support in the form of cash deposits, up to a specified maximum amount. In the event PG&E were to utilize such cash deposits to satisfy Moss Landings’ obligations under the tolling agreement, Gen Finance would have an obligation to reimburse the financial institution. Gen Finance has provided a $30 million letter of credit to the financial institution as well as a

lien on the collateral securing the Gen Finance Credit Facilities. The agreement expires on December 31, 2010 unless terminated earlier in accordance with the terms of the agreement. Gen Finance has already paid $6 million in commitment fees to the financial institution and is required to pay two remaining commitment fee payments of approximately $2.6 million on each of August 1, 2007 and February 1, 2008.

In April 1999, the California Maritime Infrastructure Authority (“CMIA”) issued $115 million of Taxable Lease Revenue Bonds (the “South Bay Bonds”) due November 1, 2009 and loaned the proceeds to the San Diego Unified Port District (“SDUPD”) to acquire the South Bay facility. Simultaneous with the purchase of the facility, SDUPD entered into a lease agreement with Duke Energy South Bay, LLC (“South Bay”). South Bay’s obligations under the lease, which expires on February 1, 2010, include the payment of rent in an amount sufficient to cover principal and interest under the South Bay Bonds. In connection with the Generation Acquisition, the Company assumed the remaining lease obligation of $55.9 million. Effective August 1, 2006, the Company defeased the lease through the purchase and deposit of $55.9 million of United States Treasury securities into an escrow account. These funds will be used by the escrow agent to pay, when due, interest and principal on the South Bay Bonds. The remaining lease obligation was removed from the Company’s books as it was deemed repaid and South Bay was relieved of its obligation to make future lease payments. The Company will continue to operate the facility through February 1, 2010 and is in the process of negotiating a new arrangement with SDUPD.

(c)

Kendall

The Company refinanced Kendall’s credit facility on October 7, 2005 with a new 8-year $422 million Senior Secured Term Loan Facility (the “Term Loan Facility”) and a 6-year $10 million Senior Secured Liquidity Facility (the “Liquidity Facility” and collectively with the Term Loan Facility, the “Credit Facility”). The interest rate for the Term Loan Facility adjusts each interest period based on an adjusted LIBO rate. The interest rates in effect at December 31, 2006 and 2005 were 7.364% and 6.527%, respectively. The proceeds were used to retire outstanding debt of $440.9 million, pay interest rate swap breakage fees of $5.5 million, pay accrued interest of approximately $600,000 and pay debt issuance costs of $10.5 million.

The terms of the Credit Facility require Kendall to hedge a minimum of 50% of the Term Loan Facility. Accordingly, concurrent with the refinancing, the Company entered into an interest rate swap agreement. The terms of the swap require the Company to pay a fixed rate and receive a floating rate. The floating rate is based on the three month LIBO rate (see note 9).

The interest rate swap agreements that were outstanding at December 31, 2004 had a termination date of September 29, 2006. Swap breakage costs of $5.5 million were paid in connection with the termination of the interest rate swap agreements on October 7, 2005.

For the years ended December, 2006 and 2005, Kendall made principal payments of approximately $19.3 million and $26.7 million, respectively. Interest payments of $29.7 million and $21.7 million were made for the years ended December 31, 2006 and 2005, respectively.

Kendall may, at its option, prepay the outstanding term loan in whole or in part at any time, subject to payment of a premium equal to 3.00% of the amount being prepaid if the prepayment occurs during the first year of the Kendall Credit Facility (which has passed) and 1.00% of the amount being prepaid if the prepayment occurs during the second year of the Kendall credit facility, with no premium required thereafter. Mandatory principal payments are payable quarterly at the rate of 1% per annum of the original outstanding principal amount of the Term Loan Facility of $422 million. If the outstanding principal amount of the Term Loan Facility exceeds the Targeted Principal Outstanding (defined below), (i) 100% of the amount, if any, of Excess Cash Flow (as defined) for the quarter up to the amount required for the outstanding principal amount of the Term Loan Facility to equal the Targeted Principal Outstanding, and (ii) 50% of the amount, if any, of the Excess Cash Flow (as defined) for the quarter remaining after the application of (i) shall be used to prepay the outstanding principal amount of the Term Loan Facility. The Targeted Principal Outstanding refers to the aggregate principal amount of Term Loans specified to be outstanding as of a certain date, as detailed below.


	Mandatory Principal		Principal Outstanding
	Payments		Minimum		Targeted
	(In thousands)
2007	$	4,220	$	397,433	$	380,595
2008		4,220		393,213		350,946
2009		4,220		388,993		310,396
2010		4,220		384,773		256,349
2011		4,220		380,553		188,894
Thereafter		380,553		—		—

In addition to the $4.2 million mandatory principal payments, the Company estimates that additional principal payments of $17.6 million will be made from Excess Cash Flow (as defined) during the next twelve months and has included such amount in current portion of long-term debt in the accompanying combined balance sheet as of December 31, 2006.

There were no amounts outstanding under the Liquidity Facility as of December 31, 2006 and December 31, 2005. A commitment fee of 0.50% per annum is payable on the average daily unused amount of the Liquidity Facility. Letter of credit fees are payable on a quarterly basis at a rate of .675% per annum for the $20 million letter of credit issued by Holding and 1% per annum for the $1 million Fortis letter of credit.

All of the assets and contract rights of Kendall are collateral for outstanding loans.

The Credit Facility requires that proceeds from borrowings, the receipt of revenues, debt service payments and the payments for certain categories of expenses each be segregated into separate bank accounts. Under the terms of a depositary agreement dated October 7, 2005, Kendall has established the required bank accounts and has pledged all its rights, title and interest in the bank accounts as security for its payment obligations under the Credit Facility. The Credit Facility requires Kendall to maintain a $20 million debt service reserve account. Initially, Kendall cash funded this account. On December 28, 2005, Kendall replaced the cash balance with a $20 million letter of credit issued by Kendall Holding. In accordance with the terms of the Credit Facility, Kendall distributed the $20 million of cash to Kendall Holding.

The Credit Facility requires compliance with certain covenants, relating to among other things, financial ratios, certain reporting requirements, additional indebtedness, certain new and existing agreements and other activities.

(d)

Ontelaunee

On December 7, 2005, Ontelaunee entered into a $125 million term loan agreement (the “Credit Agreement”) with a financial institution. The proceeds were used to refinance a portion of the debt incurred in connection with the Ontelaunee Acquisition. At December 31, 2005, $125 million was outstanding under the Credit Agreement, bearing interest at a variable rate of 7.83%.

On May 5, 2006, Ontelaunee refinanced its existing Credit Agreement with a new 3-year $100 million term loan (the “First Lien Term Loan”) and a 3-year $50 million term loan (the “Second Lien Term Loan”). Proceeds from the new loans of approximately $22 million were distributed to the owners. The loans are due on May 4, 2009. There were no principal paydowns during 2006. Substantially all of Ontelaunee’s assets and contract rights are pledged as collateral on the First Lien Term Loan and Second Lien Term Loan. The interest rates in effect at December 31, 2006 for First Lien Term Loan and Second Lien Term Loan were 7.36% and 9.36%, respectively.

The First Lien Term Loan and Second Lien Term Loan require compliance with certain covenants, including among other things, compliance with certain reporting requirements, additional indebtedness, certain new and existing agreements and other activities.

(9)

Derivative Instruments and Hedging Activities

The Company enters into interest rate swaps and other contracts to reduce its exposure to market risks from changing interest, commodity, and energy rates. Interest rate swap agreements are used to convert the floating interest rate component of a portion of the Company’s long term debt obligations to fixed rates (see note 8). Such interest rate swap agreements qualify as cash flow hedges.

The following table summarizes the Company’s outstanding interest rate swap agreements as of December 31, 2006 and 2005:


	Notional Amount		Fair Value			Fixed Rate		Termination Date
	(In thousands)
Entity
2006
Plum Point	$	150,675	$	(3,476	)	5.15	%	March 2014
Generation Facilities		964,710		(6,730	)	5.19	%	March 2016
Kendall		382,024		3,216		4.80	%	September 2015

Total	$	1,497,409	$	(6,990	)

2005
Kendall	$	398,191	$	(95	)

The Company expects $2.2 million of deferred net gains on interest rate swaps accumulated in OCI to be recognized in earnings during the next twelve months. The Company

recognized $604,000 of ineffectiveness on the interest rate swaps that qualify as hedges during the year ended 2006. No ineffectiveness was recognized on interest rate swaps that qualify as hedges during the years ended December 31, 2005.

In addition, the Company has entered into heat rate call option contracts for a number of its electric generating facilities (see note 7). Such option contracts do not qualify for hedge accounting and therefore the Company records any changes in the fair value of the heat rate call option contracts in current period earnings. The fair value of all the heat rate call option contracts at December 31, 2006 and 2005 totaled $1.4 million and zero, respectively. For the year ended December 31, 2006, the Company recorded income of $1.4 million in energy and capacity revenues in the combined statement of operations.

(10)

Other Long Term Liabilities

As of December 31, 2006 and 2005, other long term liabilities consisted primarily of the following:

(a) approximately $11.0 million and $11.7 million, respectively, of accrued state sales tax. Equipment purchased certain generating equipment used in the construction of the Kendall facility totaling approximately $225.1 million. State sales tax on these equipment purchases was deferred and estimated annual sales tax payments for the next five years will approximate $696,000 per year;

(b) approximately $9.2 million for the removal of the tank farm at the Moss Landing facility as required under a facility environmental permit; and

(11)

Related Party Transactions

The Company has notes payable to an affiliate (LS Associates) in the amount of $3.3 million and $1.2 million at December 31, 2006 and 2005, respectively. The notes bear interest at the prime interest rates published by the Federal Reserve Board as adjusted quarterly. The average interest rates at December 31, 2006 and 2005 on the notes were 8.25% and 6.23%, respectively. The notes are unsecured and amounts are due in 2010.

Project development costs, including salaries and general and administrative costs, are primarily funded and paid for by LS Associates. Such fundings are reflected as capital contributions in the combined financial statements.

(12)

Income Taxes

Income tax expense for the years ended December 31, 2006 and 2005 consisted of:


	(in thousands)
	2006		2005
Current:
U.S. Federal	$	5,282	$	—
State and local		1,506		—

Total current		6,788		—

Deferred:
U.S. Federal		1,115		—
State and local		287		—

Total deferred		1,402		—

Total income tax expense	$	8,190	$	—

At December 31, 2006 gross deferred tax assets totaled $7.7 million which consisted of federal and state net operating losses and a gross deferred tax liability of $1.4 million related to an investment basis difference. The Company recorded no net tax expense for 2005. As of December 31, 2005, the Company recorded a deferred tax asset of $1.1 million for federal and state loss carryforwards and an offsetting deferred tax liability of $1.1 million related to an investment basis difference.

The majority of the entities comprising the Company have been organized as limited liability companies or limited partnerships and are not subject to income tax at the entity level. The Blockers, LSP Plum Point Blocker, Inc., Kendall Blocker and ONT Blocker are organized as Delaware corporations and are subject to income tax. Each of these entities is subject to income tax on a stand-alone basis with some entities generating positive taxable income and other generating net operating losses.

The Company assesses the realization of its deferred tax assets to determine whether a valuation allowance is required on its deferred tax assets. Based on all available evidence, both positive and negative, and the weight of that evidence, the Company determines whether it is more likely than not that all or a portion of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the period in which those temporary differences become deductible. The Company considers the scheduled reversals of deferred tax liabilities, projected taxable income, and tax planning strategies in making the assessment of the amount of valuation allowance.

At December 31, 2006, the Company established a $7.7 million valuation allowance for a portion of the federal and state net operating losses due to the uncertainty of future earnings of certain entities included in the combined financial statements and management’s inability to affect a tax planning strategy to utilize such net operating losses due to the merger agreement with Dynegy Inc. (see note 14).

At December 31, 2006 the Company had available net federal and state operating loss carry forwards available to offset future taxable income of approximately $17.9 million. The net operating loss carry forwards, if unutilized, will expire in the years 2011 through 2026.

Prepaid income taxes and income taxes payable at December 31, 2006 totaled $1.8 million. Estimated income tax payments of $8.6 million were paid during the years ended December 31, 2006. No income tax payments were made in 2005.

(13)

Owners’ Equity

Profits, losses and distributions are allocated in accordance with the provisions of the applicable organizational documents.

In October 2005, Holding issued 610 Class A preferred units (the “Class A Units”) and 610 Class B preferred units (the “Class B Units”) to Equity LP for approximately $9.2 million and $12.2 million, respectively, and 390 Class A preferred units and 390 Class B preferred units to Blocker for approximately $5.8 million and $7.8 million, respectively. Proceeds from the issuance of the Class B Units were used to temporarily fund a debt service reserve account at Kendall. In December 2005, Kendall Holding issued a $20 million letter of credit to satisfy such debt service reserve requirement. As a result, the Class B Units were redeemed by Kendall Holding and $12.2 million and $7.8 million was paid to Equity LP and Blocker, respectively.

The Class A Units earn a 12% per annum preferred return. Such preferred return is required to be paid prior to any other distributions. Preferred return distributions totaled $1.3 million in 2006. In addition, $10.9 million of Class A Units were redeemed by Kendall Holdings during 2006. During the first quarter of 2007, Kendall Holdings made preferred return distributions of approximately $286,000 and redeemed approximately $2.8 million of Class A Units. No applicable distributions were paid as of December 31, 2005.

In addition, during the first quarter of 2007, approximately $50.5 million was distributed by the Company to the owners.

(14)

Commitments and Contingencies

Kendall

Concurrent with the Kendall Acquisition, a receivable in the amount of $12 million had been recorded which represented management’s estimate of the fair value related to claims for (i) reservation payments under the DPM PPA due Kendall for the periods from July 21, 2001 through March 26, 2002 and from July 21, 2001 through April 4, 2002 for Unit 1 and Unit 2, respectively; and (ii) an adjustment to prior invoices for replacement power obligations for the months of July and August 2001. In addition, Kendall invoiced DPM for reservation payments under the DPM PPA based upon Kendall’s interpretation of the start date of the initial contract year. DPM has disputed these claims. In 2005, management revised its estimate for these claims to be $2 million which was reflected as an adjustment to the purchase price allocation. In February 2005, DPM issued a notice of default under the DPM PPA claiming that Kendall has failed to construct the plant in order to provide power that could be dispatched in accordance with the DPM PPA. Kendall has disputed this claim. In May 2005, DPM filed a demand for arbitration claiming (i) Kendall breached and is in breach of the DPM PPA by failing to construct, operate and maintain the plant and dedicated units in accordance with prudent industry practices and the terms of the DPM PPA and (ii) the payments demanded by Kendall are not due or payable under the terms of the DPM PPA. Kendall has filed an answering statement and counterclaim in the arbitration denying DPM’s claims and seeking payment for the claims identified above. In light of the execution of an agreement on September 14, 2006 to enter into a merger with Dynegy Inc. (as described below), Kendall and DPM entered into a letter agreement

dated October 31, 2006 regarding the arbitration whereby the claims and counterclaims have been dismissed voluntarily without prejudice. All applicable periods of limitations regarding the claims and defenses are tolled through the date of the closing of the merger transaction or June 30, 2007, whichever occurs first. DPM and Kendall have agreed to execute final and mutual releases within seven days of the merger transaction closing. As a result, Kendall charged to expense the $2 million receivable for claims under the DPM PPA as of December 31, 2006.

During the development of the Kendall facility, Kendall entered into a tax agreement (the “Tax Agreement”) with Kendall County, Illinois and Seward Township, Illinois. The Tax Agreement specified an allocation of 10-20% of the direct construction costs of the Kendall facility to be treated as real property, and thus taxed as such, and the remainder to be treated as personal property, and not subject to real estate taxes. Two local school districts (the “School Districts”) that were not parties to the Tax Agreement filed an appeal of Kendall’s 2001 and 2002 tax assessments at the county level. The School Districts argue that the entire Kendall facility, including all construction costs and generating equipment, is assessable. Kendall contends that only the land, buildings and site improvements are assessable. The School Districts’ 2001 appeal at the county level was unsuccessful. The School Districts’ appeal of the Kendall 2002 assessment at the county level was successful and, as a result, the assessments for 2002, 2003 and 2004 were increased and the related taxes were expensed and paid by Kendall. Kendall’s assessment for all years (2001-2004) is currently under appeal at the state level in front of the Illinois Property Tax Appeal Board (the “PTAB”). In April 2005, the PTAB held a hearing in connection with Kendall’s 2001 real estate taxes. In February 2006, PTAB ruled in favor of Kendall for the 2001 tax year. The School Districts appealed the 2001 case to the Illinois Appellate Court. In response to PTAB’s February 2006 decision, the county set the 2005 tax assessment at a number that was reduced from prior years. The 2005 assessed value is also being appealed at the PTAB by Kendall and the School Districts. On June 30, 2006, the PTAB declared that the refund due to Kendall for 2001 taxes needed to be held in an escrow account until further court review.

National Energy Production Corporation (“NEPCO”) and Dick Corporation (“DC”) (collectively, the “Kendall Contractor”) had entered into an Engineering Procurement and Construction contract (the “Kendall EPC”) to design, engineer and construct the Kendall facility. In 2002, Kendall filed a proof of claim against Enron Corp. (“Enron”) with respect to a guaranty of the contractor’s obligations to Kendall under the EPC Agreement and a proof of claim against NEPCO relating to the EPC Agreement. Pursuant to a Stipulation and Consent Order entered on January 25, 2006, Kendall’s claims with Enron and NEPCO were settled in the amount of $6.5 million and $6.5 million, respectively. Enron and certain of its affiliates, including NEPCO had filed voluntary petitions for relief under bankruptcy laws. Accordingly, the settlement was approved by the bankruptcy court on February 7, 2006. Effective March 30, 2006, Kendall Holding assigned all rights in future distributions from Kendall arising under the claims with Enron and NEPCO to a third party for approximately $3.1 million. Such amount is reflected in other income, net in the statement of operations. In October 2006, Kendall received $835,000 under these claims and such proceeds were paid to the third party. As of December 31, 2006 and December 31, 2005, no receivable had been recorded related to this matter.

Generation Facilities

On February 18, 2005, Bridgeport filed an unexecuted Reliability Must Run Agreement (“RMR Agreement”) between itself and ISO-New England with the Federal Energy Regulatory Commission (“FERC”). The Bridgeport RMR Agreement provides for an annual fixed revenue requirement (the “AFRR”) of $57.7 million and certain variable operating costs re imbursements (the “VOM”). On July 19, 2005, FERC conditionally accepted the application subject to refund, hearing and settlement judge procedures. Bridgeport has been operating under that contract since June 1, 2005. Bridgeport also filed a petition for review of FERC’s order with the U.S. Court of Appeals, D.C. Circuit, which challenges FERC’s application of a new cost test. That appeal is still pending.

On April 19, 2006, Bridgeport, ISO-New England, the Connecticut Department of Public Utility Control (the “CDPUC”), and the Connecticut Office of Consumer Counsel (the “CT OCC”) (collectively, the “Settling Parties”) filed a Partial Settlement Agreement (“Partial Settlement”) resolving all outstanding issues, with the exception of the level of Bridgeport’s cost-of-service. The Defined Cost of Service Settlement Agreement will reduce the current AFRR of $57.7 million over the remaining term of the RMR Agreement.

The Attorney General for the State of Connecticut and the Connecticut Municipal Electric Cooperative filed comments opposing some aspects of the settlements.

Bridgeport continues to receive revenues based upon the higher AFRR pending final resolution at FERC and is currently reserving approximately $0.6 million per month toward an eventual refund. As of December 31, 2006, Bridgeport has reserved $8 million for such refund.

On March 23, 2007, FERC issued an order approving in part, subject to conditions, and rejecting in part the Partial Settlement and Defined COS Settlement Agreement (collectively, the “Settlement Agreements”). First, FERC found that the Partial Settlement Agreement did not resolve the factual issue of whether Bridgeport is economically eligible for an RMR agreement under the facility costs test, and remanded the issue to the presiding judge for hearing. In remanding the issue, FERC directed the administrative law judge to consider not only Bridgeport’s eligibility based on application of the facility costs test to the period before Bridgeport filed its RMR Application, but to all subsequent periods, including the period after which Bridgeport became eligible for transition payments under the 2006 ISO-NE Forward Capacity Market (“FCM”) Settlement. If, after the hearing, FERC determines that Bridgeport was/is not eligible for an RMR Agreement, Bridgeport would be required to refund all RMR payments in excess of its energy and capacity market revenues (including transition payments earned after of December 1, 2006).

Second, assuming Bridgeport is eligible in the first instance, FERC provisionally accepted the Defined COS Settlement on the conditions that the Settling Parties: (A) remove language which would have allowed Bridgeport to unilaterally terminate the RMR Agreement with 30 days notice; and (B) modify the Settlement Agreements and the RMR Agreement so that the Mobile-Sierra public interest standard of review would not apply to future modifications of the RMR agreement sought by third-parties or FERC. On March 29, 2007, an order was issued by the administrative law judge scheduling a pre-hearing conference for April 26, 2007, and stating that the hearing would commence on August 20, 2007.

On or before April 22, 2007, Bridgeport and the other Settling Parties will have to notify FERC whether they agree to accept FERC’s conditions and remain bound by the Settlement Agreements, in which case they are required to submit a compliance filing.

The Company estimates that the range of potential refund for the period from contract inception through March 2007, dependent upon the outcome of future events, would be between approximately $9.8 million, the amount reserved based upon the Settlement Agreements, and $28.9 million, in the event Bridgeport fails to establish eligibility for an RMR Agreement in the first instance. For any refund relating to the period prior to May 4, 2006, Bridgeport would have a claim against Duke Energy Americas, LLC (“Duke”) for amounts in excess of the first $10 million of any refund obligation pursuant to indemnification provisions under the purchase and sale agreement for the Generation Acquisition. Approximately $6.4 million is included in the above range of potential refund. This estimated refund will continue to increase on a monthly basis until the outstanding issues are resolved. As stated above, at December 31, 2006, Bridgeport has reserved $8 million for such refund and is increasing such reserve by approximately $0.6 million per month in 2007.

The Company is currently evaluating its options and due to the uncertainties surrounding this matter the ultimate outcomes cannot be determined.

During 2006, Bear, based on their interpretation of the RMR agreement, submitted daily bid prices to ISO-New England in a manner to help minimize certain gas costs of the Bridgeport facility. ISO-New England did not settle the bids consistent with Bear’s interpretation which resulted in the project receiving $8.8 million less than it believed it was entitled to under the RMR agreement. Settlement discussions with Bear regarding the reimbursement of such lost revenue are ongoing. As of December 31, 2006, no amounts have been recorded for the potential recovery of such amount.

South Bay is party to a Lease Agreement (the “South Bay Lease”) with SDUPD pursuant to which South Bay is currently leasing the existing South Bay facility from SDUPD. The South Bay Lease will terminate on February 1, 2010 (or, if later, the date on which South Bay is no longer subject to a reliability must run contract with the California ISO). Upon termination of the South Bay Lease, South Bay will be obligated, at its sole cost and expense, to decommission, dismantle and remove the existing power plant facility. In addition, pursuant to a separate Environmental Remediation Agreement (the “ERA”) between South Bay and SDUPD, South Bay is responsible for remediation of any contamination that may have been released at the existing South Bay facility site after commencement of the lease, as well as remediation of certain parcels in the vicinity of the South Bay facility site. Pursuant to the asset purchase agreement under which SDUPD purchased the South Bay facility and related properties from SDG&E, SDG&E indemnified SDUPD for certain types of pre existing contamination, including certain types of pre closing contamination at the South Bay facility, and South Bay is a beneficiary of these SDG&E indemnities.

South Bay’s decommissioning, dismantling and removal obligations under the South Bay Lease, as well as its environmental cleanup obligations under the related ERA, are guaranteed by Duke Capital, LLC (“Duke Capital”). In the event Duke Capital was required to perform under such guaranties, Duke Capital would be permitted to draw upon letters of credit issued to Duke Capital pursuant to the Gen Finance credit facilities totaling $45 million. In addition, LSP Gen has agreed to indemnify Duke Capital for any losses Duke Capital may incur as a result of the existing guaranties. As of December 31, 2006, the Company has recorded a $24.5 million liability for its decommissioning, dismantling and removal obligations.

South Bay is also a party to an agreement with the SDUPD under which South Bay is obligated to use commercially reasonable efforts to develop and construct a new power generating facility that will replace the existing South Bay power plant and which shall have a generating capacity at least as sufficient to cause the California ISO to terminate the must-run designation of the South Bay power plant. Under the agreement South Bay’s obligation to incur development costs is capped. South Bay believes it has incurred costs and expenses in excess of the cap amount and therefore has fulfilled its obligation to incur such costs.

Each of the Morro Bay, Moss Landing and Oakland facilities were purchased from PG&E in 1997. Each of the current owners of these plants agreed under the purchase and sale agreements with PG&E to indemnify PG&E for liabilities arising out of post closing environmental contamination and certain other types of claims caused by the current owners. These entities obligations under the purchase and sale agreements, including such indemnification obligations, are guaranteed by Duke Capital. In the event Duke Capital were required to perform under such guaranties, Duke Capital would be permitted to draw upon letters of credit issued to Duke Capital pursuant to the Gen Finance credit facilities totaling $15 million (capped at $5 million per project). In addition, LSP Gen has agreed to indemnify Duke Capital for any losses Duke Capital may incur as a result of the existing guaranties. The current owners of the Morro Bay, Moss Landing and Oakland facilities are also beneficiaries of indemnities provided by PG&E for certain matters, including certain types of preexisting environmental contamination.

As noted above, Gen Finance issued letters of credit to Duke Capital. As long as the Duke Capital guarantees remain in place, Gen Finance is required to pay Duke Capital a fee equal to 1% per annum on $21 million of such letters of credit which increases by 0.5% per annum every six months up to a maximum fee of 3%.

The Morro Bay, Moss Landing and South Bay facilities have obligations, upon termination of operations of the facilities, for the closure of the waste water ponds located at each site. As of December 31, 2006, Morro Bay and Moss Landing have recorded asset retirement liabilities in the amount of $404,000 and $135,000 for such future obligations. South Bay’s pond closure asset retirement liability is a component of the $24.5 million liability stated above. As security for such future obligations, Gen Finance issued a $22.9 million letter of credit to the California Department of Toxic Substance Control.

In connection with the execution of certain long-term service agreements, by certain of its direct and indirect subsidiaries, LSP Gen has provided performance and payment guarantees for a portion of such obligations. The potential liability under these guarantees is capped on a project

by project basis with an aggregate limit of $55 million. In addition, Gen Finance has issued $94 million of letters of credit to the counterparties of these contracts, respectively, as security for its obligations under such long-term service agreements (see note 7).

The Company enters into contracts that contain various representations, warranties, indemnifications and guarantees. Some of the agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event the Company effectively indemnifies the other party. While there is the possibility of a loss related to such representations, warranties, indemnifications and guarantees in the contracts and such loss could be significant, the Company considers the probability of loss to be remote.

To satisfy certain of the Company’s contractual obligations described in notes 7, 8 and 14 the Company has issued letters of credit in favor of counterparties totaling approximately $797.4 million and $38.2 million as of December 31, 2006 and 2005, respectively.

The Company is a party to certain other claims arising in the ordinary course of business. The Company is of the opinion that final disposition of these claims will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Merger

On September 15, 2006, the LS Power Group announced that LS Associates, LS Power, LS Equity Partners, PIE and LSP Gen Investors, L.P. (collectively, the “LS Entities”) had entered into a Plan of Merger, Contribution and Sale Agreement dated as of September 14, 2006 (the “Dynegy Merger Agreement”) with Dynegy Inc. (“Dynegy”), Dynegy Acquisition Inc. (“New Dynegy”) and Falcon Merger Sub Co. (“Merger Sub”), a wholly owned subsidiary of New Dynegy. Pursuant to the Dynegy Merger Agreement, (a) Merger Sub will be merged (the “Merger”) with and into Dynegy and Dynegy will become a wholly owned subsidiary of New Dynegy (b) the LS Entities will contribute certain interests in power generation entities to New Dynegy in exchange for (i) 340 million shares of New Dynegy Class B common stock, par value $0.01 per share, and (ii) $163 million in aggregate principal amount of notes to be issued by New Dynegy; and (c) the LS Entities will sell Kendall Holding and LSP Kendall Blocker, Inc. to New Dynegy in exchange for (i) $100 million in cash and (ii) $112 million in aggregate principal amount of notes to be issued by New Dynegy. Each share of Dynegy’s common stock outstanding at the time of the Merger will be converted into the right to receive one share of New Dynegy Class A common stock, par value $0.01 per share, following the Merger. The transaction was approved by Dynegy’s shareholders on March 29, 2007 and was finalized on April 2, 2007.

Effective April 2, 2007, the Company issued termination notices to the counterparties under certain operations and maintenance contracts and Gen LTSA contracts of the Contributed Entities. In addition, Bear issued a notice to the Company terminating the Bear EMA effective May 1, 2007. The Company will either enter into new agreements with third party service providers or with New Dynegy.

On April 2, 2007, GE made a draw on a letter of credit in the amount of $15 million for a purported non-payment of an invoice under the Casco Bay LTSA. The Company is disputing

such draw. In addition, on April 12, 2007, the Company received a $29.7 million termination invoice under the Arlington Valley LTSA. The Company is disputing the full amount of the invoice. The parties are currently negotiating new arrangements which would include a full release from the obligations allegedly claimed by GE pursuant to this invoice.

Dyne Therapeutics Inactive 8-K/AFinancial Statements and Exhibits