FORM S-1

As filed with the Securities and Exchange Commission on August 12, 2008

No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

US Power Generating Company

(Exact name of Registrant as specified in its charter)


Delaware	4911	26-0165545
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

505 Fifth Avenue, 21st Floor

New York, NY 10017

(212) 792-0800

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

Belinda Foxworth

Executive Vice President and General Counsel

US Power Generating Company

505 Fifth Avenue, 21st Floor

New York, NY 10017

(212) 792-0800

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:


Dennis M. Myers, P.C. Kirkland & Ellis LLP 200 East Randolph Drive Chicago, Illinois 60601 Telephone: (312) 861-2000 Telecopy: (312) 861-2200		Robert B. Williams Milbank, Tweed, Hadley & McCloy LLP 1 Chase Manhattan Plaza New York, New York 10005 Telephone: (212) 530-5516 Telecopy: (212) 822-5516

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), check the following box: o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).


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

CALCULATION OF REGISTRATION FEE


	Proposed Maximum		Amount of
Title of Each Class of	Aggregate		Registration
Securities to be Registered	Offering Price(1)(2)		Fee(1)
Common Stock, par value $0.00001 per share	$	500,000,000	$	19,650


(1)		Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(o) under the Securities Act.

(2)		Includes offering price of additional shares which the underwriters have the option to purchase.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

SUBJECT TO COMPLETION, DATED AUGUST 12, 2008

US Power Generating Company

Common Stock

This is our initial public offering of shares of our common stock. We and the selling stockholders are offering shares and shares, respectively, of common stock.

We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders. Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $ and $ per share. We have applied to list our common stock on the New York Stock Exchange under the symbol “UPR.”

The underwriters have an option to purchase from the selling stockholders a maximum of additional shares to cover over-allotments of shares.

Investing in our common stock involves risks. See “Risk Factors” beginning on page 13.

Underwriting

Discounts and

Proceeds to us

Proceeds to the Selling

Price to Public

Commissions

before expenses

Stockholders

Per Share

Total

Delivery of the shares of common stock will be made on or about , 2008.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse

Goldman, Sachs & Co.

Merrill Lynch & Co.

Morgan Stanley

The date of this prospectus is , 2008.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. Before investing in our common stock, you should read the entire prospectus carefully, including the section entitled “Risk Factors,” our financial statements and the related notes included elsewhere in this prospectus. Unless the context requires otherwise: (i) the terms “we,” “us,” “our,” “our company” and “our business” refer to US Power Generating Company and its consolidated subsidiaries and their respective predecessors; (ii) the term “USPowerGen” refers only to US Power Generating Company and not to any of its subsidiaries; (iii) the term “Astoria” refers to Astoria Generating Company Holdings, L.L.C. and its consolidated subsidiaries; and (iv) the term “EBG” refers to EBG Holdings LLC and its consolidated subsidiaries. USPowerGen became the parent holding company of Astoria and EBG on June 1, 2007. See “— Our Corporate Structure.” Certain differences in the numbers in the tables and text throughout this prospectus may exist due to rounding.

Company Overview

We are a wholesale power generation company that owns and operates electric power generation facilities located in New York City and the Boston metropolitan area. We have a portfolio of fifty-eight generating units at six facilities, with seasonally adjusted generation capacity of approximately 5,223 megawatts (“MW”). We can generate sufficient power to serve approximately 20% of the summer peak load in New York City and approximately 31% of the summer peak load in eastern Massachusetts. We believe that we have a competitive advantage due to our strategic urban locations that have high costs of entry, favorable siting within these urban locations, access to well-developed capacity markets and an asset portfolio consisting primarily of clean burning natural gas-fired generating units with significant dual fuel capability.

Set forth below is information regarding our power generation portfolio as of June 30, 2008:


											Dual Fuel Capability
									No. of		No. of		% of Net
			Generation Capacity (MW)						Generating		Generating		Generating
Name of Facility	Location		Winter		Summer		Average⁽¹⁾		Units		Units		Capacity

New York Facilities:
Astoria		Queens, NY		1,314		1,312		1,313		5		3		85	%
Gowanus		Brooklyn, NY		745		556		651		32		16		52	%
Narrows		Brooklyn, NY		391		297		344		16		16		100	%
Boston Facilities:
Mystic 8&9		Everett, MA		1,658		1,360		1,558		2		0		0	%
Mystic Station:
Mystic 7		Everett, MA		560		578		566		1		1		100	%
Mystic Jet		Everett, MA		12		7		10		1		0		0	%
Fore River		North Weymouth, MA		831		682		781		1		1		100	%⁽²⁾

Total				5,511		4,792		5,223		58		37		60	%


(1)		Seasonally adjusted generating capacity. NYISO uses a May to October summer and November to April winter; ISO-NE uses a June to September summer and October to May winter.

(2)		Our Fore River generating unit’s capacity is limited to 635 MW when it operates using ultra-low sulfur diesel versus 831 MW when it operates using natural gas. Due to air permit restrictions, this unit can only operate using ultra-low sulfur diesel for approximately 45 days during the non-ozone season from October 1 to April 30.

Electric Energy Sales. We sell electric energy generated by our facilities in centralized electric energy markets administered by two independent system operators (“ISOs”): the New York Independent System Operator, Inc. (“NYISO”) and ISO New England Inc. (“ISO-NE”). As administrators for their respective markets, the ISOs are responsible for ensuring the reliability, adequacy and security of the electric transmission system as well as providing generators with fair and non-discriminatory access to the transmission grid.

Capacity Sales. We sell capacity to NYISO and ISO-NE for purchase by load-serving entities (entities that provide electric service to end-users and wholesale customers) in our markets. Load-serving entities are required to purchase sufficient capacity to demonstrate their ability to provide electric energy in an amount equal to the peak load forecast for the relevant period plus a reserve. Due to this requirement, NYISO and ISO-NE have capacity markets separate from the electric energy market. Capacity sales provide us with a relatively predictable and recurring source of revenues.

Ancillary Services. We sell ancillary services to the ISOs in our respective markets, including automatic generation control, operating reserves, reactive supply and voltage support and black-start capability.

New York Facilities

Our generation facilities located in New York City (the “New York Facilities”) operate in and generate electric energy for New York City’s power market, which is administered by NYISO. Our New York Facilities include the Astoria Generating Station (“Astoria facility”), the Gowanus Gas Turbine facility (“Gowanus facility”) and the Narrows Gas Turbine facility (“Narrows facility”). The Astoria facility consists of five operating units (Units 20, 30, 40, 50 and GT-1) located in Queens, New York. The five operating units have an average summer capacity of 1,312 MW. Units 30, 40 and 50 operate as intermediate units, which run frequently during the peak load (daytime and evening hours during working days) and ramp down or shut off during most off-peak periods. Unit 20 operates primarily as a peaking facility, running only during peak-load periods and shutting off during other periods. Unit GT-1 is a 17 MW natural gas-fired combustion turbine that operates as a peaking facility. The generating units at our Gowanus and Narrows facilities are peaking units located in Brooklyn, New York. Our Gowanus facility has 32 units, 16 of which are dual fuel, with a summer capacity rating of 556 MW and our Narrows facility has 16 units, all of which are dual fuel, with a summer capacity rating of 297 MW.

Peak demand for energy within the New York City power market has grown from 9.6 gigawatts in 1997 to 11.0 gigawatts in 2007, representing a compound annual growth rate of approximately 1.3%. NYISO forecasted in April 2008 that the summer peak-load in New York City would increase to 13.0 gigawatts in 2017, representing a compound annual growth rate of approximately 1.7% from 2007. In June 2008, peak demand was 700 MW higher than the previous record for the month of June, which was set in June 2007.

NYISO currently requires that all load serving entities operating in New York City purchase at least 80% of their capacity from in-city power generators, due to significant transmission constraints that limit generators’ ability to deliver electric energy into and within New York City. As a result of these constraints, energy prices in New York City reflect a premium over other parts of the NYISO market. For the three-year period ended December 31, 2007, on-peak prices at our Gowanus and Narrows facilities were approximately $32 higher per megawatt hour (“MWh”), or approximately 36% higher than the average on-peak prices for all of NYISO. Similarly, for the three-year period ended December 31, 2007, on-peak prices at our Astoria facility were approximately $11 higher per MWh, or approximately 13% higher than the average on-peak prices for all of NYISO. Additionally, as a result of transmission constraints within New York City, sub-load pockets exist in which energy prices often reflect a premium over prices in other parts of New York City. All of our New York Facilities are located within these sub-load pockets, and we have generally sold the energy generated by these facilities at prices higher than average prices in the other parts of New York City.

The table below outlines annual output and key operating statistics for our New York Facilities for the years ended December 31, 2007, 2006 and 2005 and for the twelve months ended March 31, 2008.


	Twelve Months
	Ended March 31,			Year Ended December 31,
New York Facilities	2008			2007			2006			2005

Net Generation (MWh)⁽¹⁾		2,463,407			2,348,699			2,774,756			5,249,090
Net Capacity Factor (%)⁽²⁾		12.4	%		11.8	%		14.1	%		25.7	%
Equivalent Availability Factor (%)⁽³⁾		87.1	%		88.8	%		87.9	%		81.2	%
Equivalent Forced Outage Rate Demand (%)⁽⁴⁾		2.7	%		2.2	%		1.3	%		8.7	%
Net Heat Rate (Btu/kWh)⁽⁵⁾		12,546			12,714			11,868			11,003


(1)		Net generation is the total amount of electric energy (as measured by the generating unit) generated during the specified period, minus the electrical energy consumed by the generating units.

(2)		Net capacity factor is the ratio of the actual output of our generating units during the specified period over their output if they had operated at full capacity during that period.

(3)		Equivalent availability factor of our generating units is the percentage of time that they are able to generate electricity over a given period, adjusted to account for partial outage time of equivalent generating units.

(4)		Equivalent forced outage rate demand is the historical percentage of the generating units’ maximum output lost to forced outages when such output is demanded.

(5)		Net heat rate is a measure of generating unit thermal efficiency, and is the amount of fuel energy required by our generating units to generate one kilowatt-hour (“kWh”) of electrical output. It is computed by dividing the total British Thermal Unit (“Btu”) content of fuel burned for electric generation by the resulting net kWh generation.

Boston Facilities

Our generation facilities located in the Boston metropolitan area (the “Boston Facilities”) operate in and generate electric energy for the Boston metropolitan area power market, which is administered by ISO-NE. The Boston Facilities include Mystic Generating Station Units 8&9, a natural gas combined cycle plant with a seasonally adjusted capacity of 1,558 MW (“Mystic 8&9”), Fore River Generating Station, a 781 MW natural gas-fired combined cycle plant (“Fore River”) and Mystic Generating Station Unit 7 and Mystic Jet, a 566 MW oil/natural gas-fired steam turbine and 10 MW oil-fired gas turbine peaking unit, respectively (collectively, “Mystic Station”). Mystic 8&9 operate as intermediate units, have a strategic location within the Boston metropolitan area and receive natural gas from a dedicated pipeline to the liquified natural gas terminal facility of Distrigas of Massachusetts, LLC (“Distrigas”). Fore River is an intermediate unit substantially similar to each unit of Mystic 8&9, with the added capability of dual fuel operation, located outside of Boston in Weymouth, Massachusetts. Mystic Station is a two unit, substantially dual fuel, power generating facility located adjacent to Mystic 8&9. Mystic 7 has the ability to operate at a minimum output level of 90 MW. This dual fuel flexibility, combined with its location inside the Boston area, provides Mystic Station with the ability to follow the regional load patterns.

Peak demand for energy within the New England market has grown from 21.2 gigawatts in 1997 to 27.5 gigawatts in 2007, representing a compound annual growth rate of approximately 2.6%. ISO-NE forecasted in April 2008 that the summer peak-load in New England would increase to 31.3 gigawatts in 2017, representing a compound annual growth rate of approximately 1.3% from 2007.

Most of the generating capacity of our Boston Facilities is less than six years old and we believe it to be among the most cost and environmentally efficient fossil fuel power-generating capacity in New England. As a result of changes to the ISO-NE capacity market rules that became effective December 1, 2006, the revenues we receive for providing capacity to that market have increased significantly. These market rules provide that power generators supplying capacity will receive payments at set, escalating prices until May 2010, following which capacity prices will be set by annual auctions. The first auction, covering the 2010 capacity year (beginning June 1, 2010), was held during the first quarter of 2008. The second auction, covering the 2011 capacity year (beginning June 1, 2011), will be held in December 2008.

The table below outlines annual output and key operating statistics for our Boston Facilities for the years ended December 31, 2007, 2006 and 2005 and for the twelve months ended March 31, 2008.


	Twelve Months
	Ended March 31,			Year Ended December 31,
Boston Facilities	2008			2007			2006			2005

Net Generation (MWh)⁽¹⁾		13,211,310			12,909,479			12,266,894			9,985,007
Net Capacity Factor (%)⁽²⁾		51.2	%		50.1	%		47.8	%		38.9	%
Equivalent Availability Factor (%)⁽³⁾		87.5	%		87.4	%		87.7	%		83.3	%
Equivalent Forced Outage Rate demand (%)⁽⁴⁾		1.3	%		1.9	%		3.1	%		7.9	%
Net Heat Rate (BTU/kWh)⁽⁵⁾		7,818			7,799			7,518			7,941


(1)		Net generation is the total amount of electric energy (as measured by the generating unit) generated during the specified period minus the electrical energy consumed by the generating unit.

(2)		Net capacity factor is the ratio of the actual output of our generating units during the specified period over their output if they had operated at full capacity during that period.

(3)		Equivalent availability factor of our generating units is the percentage of time that they are able to generate electricity over a given period, adjusted to account for partial outage time of equivalent generating units.

(4)		Equivalent forced outage rate demand is the historical percentage of the generating units’ maximum output lost to forced outages when such output is demanded.

(5)		Net heat rate is a measure of generating unit thermal efficiency, and is the amount of fuel energy required by our generating units to generate one kilowatt-hour of electrical output. It is computed by dividing the total BTU content of fuel burned for electric generation by the resulting net kWh generation.

Business Strengths

We believe that the key strengths of our company are the following:

Located in Attractive Competitive Power Markets. Our facilities are located in well-developed markets with mature regulatory frameworks. NYISO and ISO-NE focus on providing open-access transmission services on a non-discriminatory basis and administering competitive electric power markets. Aggregate electric energy demand in our markets is high, and our urban locations are subject to transmission constraints, resulting in electric energy prices that are higher than the nationwide average. Capacity markets in New York and New England are designed so that constraints in supply and increases in construction costs will typically result in higher capacity prices. The market for ancillary services provides an additional revenue stream while supporting the reliability of the transmission system by providing critical system functions such as black-start capability, automatic generation control and reserves.

Favorable Locations within the Markets. Our New York Facilities benefit from the current NYISO requirement that all load serving entities operating in New York City purchase at least 80% of their peak load from in-city power generators, which results in premium capacity prices for existing in-city generation resources compared to the rest of NYISO. Transmission constraints within New York City further limit the ability to transmit electricity freely throughout the zone, creating sub-load pockets (in which our facilities are located), resulting in higher energy prices for generation located within these sub-load pockets compared to elsewhere in the New York City market. In Boston, the proximity of our Mystic 8&9 facility to the liquified natural gas terminal facility of Distrigas enables this facility to receive natural gas through a dedicated pipeline at a market price while reducing transportation costs and interruptions.

Growing Markets with Inherent Development Opportunities. NYISO forecasted in April 2008 that the summer peak-load in New York City would increase by a compound annual growth rate of approximately 1.7% from 2007 through 2017. In April 2008, ISO-NE forecasted that the summer peak-load in New England would increase by a compound annual growth rate of approximately 1.3% from 2007 through 2017. We believe that additional generating capacity will be required in these markets to meet this expected growth, and potential new entrants into these markets will face challenges associated with limited site availability, difficult permitting processes, high construction costs and long development times. We believe that we are well

positioned to provide future generating capacity since we currently have the available land, infrastructure and market and regulatory knowledge to support expansion at our existing sites.

Proven and Reliable Technology. All of the generating units at our facilities were built by well-established manufacturers, using proven technologies from industry-leading suppliers. As a result of the maintenance plan we implemented in 2006, the average forced outage rate at our New York Facilities in 2007 was reduced to its lowest point in the last 10 years, from an average rate of nearly 9% in 2005 to approximately 2% in 2007, and the average forced outage rate for our Boston Facilities was reduced from 8% in 2005 to 2% in 2007. The resulting increase in availability has had a favorable impact on both our power sales and capacity revenues.

Favorable Emission Profile. Approximately 93% of our generating capacity can operate using natural gas as a primary fuel, which has a significantly lower emissions profile than other fossil fuels used to operate generation plants. As a result, we expect that we will have significantly lower capital investment requirements to comply with environmental regulations than those potentially faced by generators using other fossil fuels. In addition, the combination of state-of-the-art gas turbine technology with dry, low nitrogen oxide (“NO_x”) combustion systems makes our Mystic 8&9 and Fore River units among the lowest cost and cleanest natural gas-fired generating facilities in the ISO-NE control area.

Business Strategy

Our business strategy includes the following elements:

Expand and Develop Facilities. We intend to enhance and/or expand our existing generation capabilities to meet growing electricity demand by developing economic, reliable and environmentally responsible generating capacity. Recently, we announced the addition of approximately 100 MW of peaking capacity at our Gowanus facility, which is tentatively scheduled to be completed by 2010 to 2011. Our Mystic Station and Fore River facilities have considerable undeveloped land and infrastructure support systems that may allow us to add generation capacity in a cost-efficient manner. Additionally, we are currently evaluating the feasibility of a repowering at our Astoria facility and are actively exploring additional “brownfield” (sites previously used for industrial activities) and “greenfield” (sites not previously used for industrial activities) development opportunities. We intend to identify and pursue attractive projects through applying a rigorous set of criteria, including projected returns, environmental impacts and community relations.

Pursue Selective Mergers and Acquisitions. We intend to evaluate and pursue selective joint venture, merger and acquisition opportunities with both strategic and financial owners of electric generation assets and portfolios. We will primarily focus on acquiring generating assets in competitive markets with well-developed

or developing regulatory structures where we believe we can apply our existing market and technical knowledge to maximize contribution from these assets.

Improve Financial Flexibility and Liquidity. Pursuant to the terms of our credit agreements at both Astoria and EBG, we will continue to use a significant portion of the cash we generate from operations to service our indebtedness. We may consider refinancing our debt for either or both of Astoria and EBG in the future, which may provide us with greater financial flexibility to pursue our strategic initiatives. In addition, we plan to continue to pursue the most cost-efficient means of providing collateral to secure our fuel purchase commitments and our risk management activities, with an emphasis on lien-based structures as opposed to cash-based collateral.

Mitigate Market and Industry Risks. We intend to continue to use derivative instruments and explore other opportunities to mitigate our risk and exposure to the uncertainties of the energy markets in which we operate. We also intend to enter into interest rate swaps so that we pay a fixed interest rate on a portion of our outstanding floating rate borrowings. We intend to continue our current risk management policy, which is designed to stabilize our revenue by managing our exposure to market price risks, particularly those related to changing electric energy and capacity prices. As part of this policy, we recently entered into energy-related derivative instruments at Astoria which were designed to provide favorable energy margins. We will continue to focus primarily on opportunistically entering into derivative contracts when we deem market conditions are favorable for such a strategy.

Our History

USPowerGen, the issuer of the common stock being sold in this offering, is a Delaware corporation formed in February 2007 to facilitate the combination of the operations of Astoria and EBG as wholly-owned subsidiaries of USPowerGen. We refer to this combination throughout this prospectus as the “Combination.” The Combination was effected on June 1, 2007, and resulted in each of the entities that own our New York Facilities and Boston Facilities becoming wholly-owned subsidiaries of USPowerGen, and provided us with significant scale in the Northeast U.S. with opportunity for further expansion. The Combination was effected to leverage the complementary nature of the two asset portfolios, including each being located in markets that we believe are characterized by expected high demand growth, well-established capacity markets, significant costs for new entry and each portfolio having significant dual fuel capability.

In 2003, Mr. Jacob Worenklein, our Chief Executive Officer, formed an acquisition and management company to acquire and manage domestic power generation facilities. In 2004, Hunt Generation Investments, L.P. (“Hunt Generation”) joined as an investor in this acquisition and management company. On February 23, 2006, a newly formed entity owned by Madison Dearborn Partners, LLC (“Madison Dearborn”), certain other equity investors and officers of this acquisition and management company acquired our New York Facilities from Reliant Energy, Inc. (“Reliant”). We refer to this acquisition throughout this prospectus as the “MDP Acquisition.”

Risk Factors

For information on risks relating to our business and an investment in our common stock, see “Risk Factors” beginning on page 13.

Recent Regulatory Developments

On March 7, 2008, the Federal Energy Regulatory Commission (“FERC”) approved most of NYISO’s previously proposed market power mitigation plan that sought to prevent sellers of electric energy and capacity in the NYISO market with market power from artificially raising capacity prices and also to prevent net purchasers of capacity, including local load serving entities that provide electricity to end-users, from artificially depressing capacity prices by building uneconomic generation facilities. These measures will apply to market participants, such as us, that own or control more than 500 MW of New York in-city capacity (which are considered to be “pivotal suppliers” by NYISO). Under the terms of the approved plan, the bid cap and revenue cap, previously imposed on our New York Facilities as a result of our status as a “Divested Generation Owner” (“DGO”), or an owner of facilities divested in 1999 by Consolidated Edison, Inc. (“Con

Ed”), have been removed. However, the approved plan imposes a new bid cap on our New York Facilities. The new bid cap is equal to the higher of: (i) the market clearing price on NYISO’s administratively set installed capacity demand curve on the basis of which all qualified in-city capacity is sold, and (ii) the marginal generating unit’s net avoided costs achieved by removing the unit from operations but maintaining the unit in operating condition. Additionally, NYISO implemented market power mitigation measures to discourage future construction of uneconomic generation capacity that artificially reduces capacity prices below just and reasonable prices. The revised market rules are being implemented prospectively, without refunds to market participants.

In the near term, as a result of the reference price mechanism described above and the fact that the new market rules ignore the 1,000 MW of recently constructed facilities with uneconomic characteristics, we believe the market changes may substantially reduce capacity prices in Zone J, which is comprised of New York City. However, we also believe the expected retirement in 2010 of the 885 MW New York Power Authority Poletti power generation station is likely to reduce the current surplus of capacity, leading to an increase in Zone J capacity prices at that time. We believe the market changes are likely to produce a more predictable capacity market, and that the removal of the DGO revenue caps will increase the prices at which capacity is permitted to be sold by our New York Facilities. See “Business — Regulatory Matters — Recent Regulatory Developments.”

Corporate and Other Information

Our principal executive offices are located at 505 Fifth Avenue, New York, New York, 10017, and our telephone number is (212) 792-0800. Our website is www.uspowergen.com. The information contained in, or that can be accessed through, our website is not a part of this prospectus and should not be relied upon in determining whether to make an investment in our common stock.

For financial reporting purposes, Astoria is considered the acquiring entity in the Combination. As a result, the historical operating results of Astoria and its accounting predecessor are set forth in this prospectus for all periods presented prior to the Combination. Unless the context requires otherwise, we use the terms: “Predecessor” to refer to Astoria’s results of operations for periods prior to the MDP Acquisition; and “Successor” to collectively refer to (i) Astoria for the periods subsequent to the MDP Acquisition and prior to the Combination and (ii) USPowerGen and its consolidated subsidiaries for periods following the Combination.

This prospectus refers to brand names, trademarks, service marks and trade names of us and other companies and organizations, and these brand names, service marks and trade names are the property of their respective holders.

The Offering


Common stock offered by us		shares

Common stock offered by the selling stockholders		shares

Common stock to be outstanding after this offering		shares

Over-allotment option		shares

Use of proceeds		We intend to use the net proceeds from this offering to finance capital expenditures, including planned capital improvements and generation capacity expansions and for other general corporate purposes. In addition, we may, if circumstances warrant, use a portion of the net proceeds in lieu of the foregoing to repay a portion of our indebtedness. We will not receive any proceeds from the sale of shares by the selling stockholders. See “Use of Proceeds.”

Dividend policy		We currently intend to retain all future earnings, if any, for use in the operation and expansion of our business and repayment of debt and do not anticipate paying any cash dividends in the foreseeable future.

Proposed New York Stock Exchange symbol		UPR

Risk factors		You should carefully read and consider the information set forth under “Risk Factors” and all other information set forth in this prospectus before investing in our common stock.

Selling stockholders		The selling stockholders include several former owners of EBG and their transferees and New Astoria Generating Company Holdings, L.L.C. (“New Astoria”). Members of our senior management hold equity interests in New Astoria. See “Principal and Selling Stockholders.”

Except as otherwise indicated, the number of shares of our common stock to be outstanding after this offering, including the amounts set forth above, excludes 650,000 shares of our common stock issuable upon the exercise of outstanding warrants at a weighted average exercise price of $11.88 per share.

Except as otherwise indicated, all information in this prospectus reflects:


	•	no exercise of the underwriters’ over-allotment option;

	•	the effectiveness of the -for-1 stock split, which will occur immediately prior to this offering;

	•	the conversion of all of our Class B common stock into Class A common stock pursuant to our existing certificate of incorporation, and the effectiveness of our amended and restated certificate of incorporation which will, in part, reclassify our Class A common stock as common stock; and

	•	an initial public offering price of $ per share, the midpoint of the range set forth on the cover page of this prospectus.

Summary Historical and Pro Forma Financial Data

The following table sets forth our summary consolidated financial data as of and for the periods indicated. We derived the summary historical financial data as of and for the years ended December 31, 2007 and 2006 from the audited consolidated financial statements of the Successor included elsewhere in this prospectus. We have derived the summary historical financial data as of and for the year ended December 31, 2005 and for the period from January 1, 2006 to February 23, 2006 from the Predecessor’s audited consolidated financial statements included elsewhere in this prospectus. We derived the unaudited consolidated statement of operations data for the quarters ended March 31, 2008 and 2007 and the unaudited consolidated balance sheet data as of March 31, 2008 from our unaudited consolidated financial statements for such periods included elsewhere in this prospectus, and such financial data contains all adjustments, consisting solely of normal recurring adjustments, that, in the opinion of management, are necessary for their fair statement. Historical results are not necessarily indicative of the results expected in the future and results for an interim period are not necessarily indicative of results for a full year.

Prior to the MDP Acquisition, the Predecessor operated as a business unit of Reliant during the periods presented. As a result, the historical financial information of the Predecessor included in this prospectus does not necessarily reflect what our financial position or results of operations would have been had we operated the business as a separate, stand-alone entity during those periods. In addition, the results of operations of EBG have only been included in the Successor’s results of operations since the effective date of the Combination, which was June 1, 2007.

The unaudited pro forma statement of operations data for the year ended December 31, 2007 gives effect to the Combination, the effectiveness of the -for-1 stock split, which will occur immediately prior to this offering, and the sale of the shares in this offering by us and the application of the net proceeds therefrom as if each had occurred on January 1, 2007. The pro forma financial information is for informational purposes only and should not be considered indicative of actual results that would have been achieved had the specified transactions actually been consummated on the dates indicated and does not purport to indicate balance sheet information, results of operations or other financial data as of any future date or future period.

The unaudited pro forma consolidated balance sheet data as of March 31, 2008 has been prepared to give pro forma effect to the sales of shares in this offering by us and the application of the net proceeds therefrom as if such transactions had been completed as of March 31, 2008. The results for the quarter ended March 31, 2008 reflect the Combination; therefore, pro forma statement of operations data have not been presented.

The following summary historical and pro forma financial data should be read together with “Unaudited Pro Forma Consolidated Financial Statements,” “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the accompanying notes thereto elsewhere in this prospectus.


	Successor									Predecessor⁽¹⁾
										January 1,
					Year Ended			Year Ended		2006 to		Year Ended
	Three Months Ended March 31,				December 31, 2007⁽²⁾			December 31,		February 23,		December 31,
	2008		2007		Actual		Pro Forma	2006⁽³⁾		2006		2005
	(Unaudited)		(Unaudited)				(Unaudited)
	($ in millions, other than share data)
Statement of Operations Data:
Revenues	$	489.3	$	112.4	$	1,182.7	$	$	480.5	$	104.7	$	1,014.0
Operating expenses:
Fuel		333.9		60.3		779.0			258.9		50.7		555.2
Operations and maintenance		29.7		15.0		106.2			63.1		21.7		94.0
General and administrative		14.6		8.8		64.4			26.0		1.4		6.6
Taxes, other than income		12.6		7.2		41.6			35.8		5.7		33.8


	Successor													Predecessor⁽¹⁾
														January 1,
							Year Ended				Year Ended			2006 to			Year Ended
	Three Months Ended March 31,						December 31, 2007⁽²⁾				December 31,			February 23,			December 31,
	2008			2007			Actual			Pro Forma	2006⁽³⁾			2006			2005
	(Unaudited)			(Unaudited)						(Unaudited)
	($ in millions, other than share data)
Depreciation		30.4			7.1			82.3				22.9			5.9			38.8
Impairment of goodwill		250.1			—			—				—			—			—

Operating (loss) income		(181.9	)		14.0			109.3				73.7			19.4			285.6
Other expense (income):
Interest expense (income), net		87.0			15.8			203.5				55.2			0.2			(2.1	)
Other		(0.7	)		—			3.9				0.9			—			—

Total other expenses		86.3			15.8			207.4				56.1			0.2			(2.1	)

(Loss) income before income taxes		(268.2	)		(1.8	)		(98.1	)			17.6			19.2			287.7
Income tax expense (benefit)		(4.3	)		—			(35.9	)			0.7			0.7			11.5

Net (loss) income	$	(264.0	)	$	(1.8	)	$	(62.3	)	$	$	16.9		$	18.4		$	276.2

(Loss) income per common share⁽⁴⁾:
Basic and diluted	$	(0.48	)	$	(0.01	)	$	(0.15	)	$	$	0.07		$	0.07		$	1.10
Shares used to compute (loss) income per share⁽⁴⁾:
Basic and diluted		545.4			252.2			423.2				252.2			252.2			252.2
Other Financial Data:
Capital expenditures	$	13.8		$	14.4		$	49.0		$	$	39.4		$	5.5		$	17.6
Cash flows provided by (used in):
Operating activities		1.6			20.9			141.6				120.0			24.7			230.8
Investing activities		(10.0	)		(14.4	)		(94.0	)			(1,039.7	)		(5.5	)		(17.6	)
Financing activities		(14.6	)		(23.5	)		(57.7	)			964.2			(18.8	)		(214.7	)


	As of
	March 31,					As of		As of		As of
	2008		2008			December 31,		February 23,		December 31,
	Actual		Pro Forma	2007		2007		2006		2006		2005
	(Unaudited)
	($ in millions)
Balance Sheet Data:
Cash and cash equivalents	$	11.3	$	$	27.6	$	34.4	$	0.5	$	44.5	$	—
Total assets		4,715.2			1,068.6		5,004.5		2,097.8		1,104.6		2,082.6
Total debt		2,528.8			670.7		2,531.7		—		691.8		—
Total equity		1,136.8			323.9		1,409.0		2,025.8		326.8		2,006.7

Footnotes continued on next page.

RISK FACTORS

The purchase of our common stock involves significant investment risks. You should carefully consider the risks set forth below, as well as other information contained in this prospectus, before making a decision to invest in our common stock. If any of the following risks actually materialize, then our business, financial condition and results of operations may suffer. In addition, there may be risks of which we are currently unaware or that we currently regard as immaterial based on the information available to us that later prove to be material. These risks may adversely affect our business, financial condition and operating results. As a result, the price of our common stock could decline, and you could lose some or all of your investment. You should read the section entitled “Forward-Looking Statements” immediately following these risk factors for a discussion of what types of statements are forward-looking statements, as well as the significance of such statements in the context of this prospectus.

Risks Related to Our Business

Our financial performance may be impacted by significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond our control.

Our cash flows are significantly affected by wholesale prices of energy. We sell energy in day-ahead and hourly markets administered by NYISO and ISO-NE, and prices in these markets often fluctuate substantially due to many factors outside of our control, including:


	•	regulations and actions of regulatory bodies, including federal and state power market and environmental regulation and legislation;

	•	oversupply or undersupply of generation capacity;

	•	changes in power transmission or fuel transportation capacity constraints or inefficiencies;

	•	electric supply disruptions, including plant outages and transmission disruptions;

	•	availability and market prices for natural gas and oil;

	•	seasonality and weather conditions;

	•	changes in demand for power or patterns of power usage including as a result of changes in the macro-economic environment;

	•	additional supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or the repowering of non-operating plants;

	•	development of new fuels and new technologies for the production of power;

	•	availability of competitively priced alternative power sources; and

	•	natural disasters, wars, embargoes, terrorist attacks and other catastrophic events.

If prices decline, we may not be able to sell any or all of the energy from our facilities at commercially attractive rates or operate profitably, and our financial condition, results of operations and cash flows may be materially adversely affected.

Our business is subject to substantial market and governmental regulation, and we may be adversely affected by changes to market rules, legislation or regulations.

Our business is subject to extensive federal, state and local laws and regulations. Compliance with these various regulations may cause us to incur significant costs and may impact almost every aspect of our business. Future changes to rules governing wholesale power markets or other regulatory changes in our markets may have an adverse effect on our business. For example, interested parties have recently proposed material market design changes that would affect our markets, including the elimination of a single market clearing price mechanism (the price at which the final increment of demand has been met that sets the price for all transactions in that particular auction), as well as proposals to re-regulate the markets or require divestiture by generating companies to reduce their market share. Other proposals to re-regulate may be made

and legislative or other attention to the electric power market restructuring process may delay or reverse the movement towards competitive markets. If restructuring of the electric energy markets is reversed, discontinued, or delayed, our business prospects and financial results could be negatively affected.

We are also affected by other legislative and regulatory changes in addition to the changes to the NYISO market described below. For example, FERC adopted new policies in 2007 to determine whether a seller possesses market power. “Market power” includes the ability of a supplier of electricity, such as us, to profitably raise the price of electric energy at a sustained level above a competitive price. Generally, the presence of market power exists in a specific geographic area when sufficient competition is lacking. We filed a revised market power analysis relating to our New York and Boston Facilities with FERC in June 2008 and we believe that, unless modified, FERC’s new policies could result in a rebuttable presumption of market power with respect to both our New York and Boston Facilities. Any additional mitigation or revocation of market-based rate authority by FERC may, by virtue of such assumption, adversely impact our ability to operate profitably. At the same time, FERC has adopted a rebuttable presumption that market monitoring and mitigation in ISO power markets is adequate to mitigate any market power that a seller may possess in such markets. Motions to intervene and comments relating to our revised market power analysis were required to be filed by July 15, 2008. No filings were timely submitted. We cannot predict at this time whether a late intervenor might be able to rebut this presumption as to the effect of ISO mitigation in one or both of the NYISO or ISO-NE markets and, if so, whether FERC would conclude that additional mitigation or revocation of market-based rate authority is appropriate.

We are affected by changes to market design, market rules, tariffs, cost allocations and bidding rules in the existing ISOs in which we sell electric energy. The rules governing sales of capacity and energy in New York City and in New England may again change, and it is not possible to predict how such changes would impact us. The ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, market power mitigation measures, including price limitations, offer and revenue caps and other mechanisms to mitigate high price levels and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of our generation facilities that sell energy and capacity into the ISO power markets. For example, NYISO has implemented specific restrictions on the sale of capacity and energy in New York City which cover our New York Facilities. There is a limit on capacity bids that our New York Facilities and other “pivotal suppliers” may make. Additionally, in June 2005, Connecticut policy-makers enacted legislation requiring the Connecticut Department of Public Utility Control to develop and issue a request for proposals (“RFP”) to solicit the development of long-term projects to reduce federally mandated transmission congestion charges. This RFP may result in projects or arrangements that cause additional energy or capacity to be available in our markets and effectively reduce the price of energy and capacity, which could have an adverse affect on the profitability of our Boston Facilities. Furthermore, other states may choose to enact similar measures or measures that would also result in a decrease in the price of energy and capacity. Similarly, recent market changes contained in the March, 2008 FERC order approving the changes to the NYISO market, as discussed below, may cause a significant near-term decline in our capacity revenues and cash flows.

Our market-based sales are subject to certain ISO-imposed market behavior rules enforceable by NYISO, ISO-NE and FERC. If we are deemed to have violated these rules, we will be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of our market-based rate authority, as well as potential criminal and civil penalties. If our generating companies were to lose market-based rate authority, we would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and could become subject to, among other things, the burdensome accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules. Loss of market-based rate authority could have an adverse effect on the rates we charge for power from our facilities and our cost of regulatory compliance.

A substantial portion of our revenues come from sales of capacity, and therefore our financial performance may be impacted by structural changes and price fluctuations in capacity markets.

We rely on revenues from capacity sales for a substantial portion of our total revenues. For example, capacity revenues represented 18.8% of our revenues on a pro forma basis (giving effect to the Combination as if it had occurred on January 1, 2007) for the year ended December 31, 2007, and 14.4% of our revenues for the three months ended March 31, 2008. Since the structure of the capacity markets in ISO-NE and NYISO continues to evolve, we cannot predict the effect that future changes will have on the prices at which we sell our capacity.

On March 7, 2008, FERC approved most of NYISO’s previously proposed market power mitigation plan that sought to prevent sellers of electric energy and capacity in the NYISO market with market power from artificially raising capacity prices and also to prevent net purchasers of capacity, including the local load serving entities that provide electricity to end-users, from artificially depressing capacity prices by building uneconomic generation facilities. Under the terms of the approved plan, our New York Facilities will be subject to a bid cap equal to the higher of (i) the market clearing price on NYISO’s administratively set installed capacity demand curve on the basis of which all qualified in-city capacity is sold, and (ii) the marginal generating unit’s net avoided costs achieved by removing the unit from operations but maintaining the unit in operational condition. The legacy “bid and revenue cap” (the predecessor to the new bid cap) on DGOs, such as us, of $105 per kW-year, has been removed. However, the approved plan imposes a new bid cap on our New York Facilities. Currently, the NYISO capacity market has excess capacity caused by the approximate 1,000 MW of prior uneconomic entry. The FERC order, which only addresses uneconomic entry by net purchasers of electric energy and capacity on a going forward basis, will likely result in lower market clearing prices for capacity we sell until the excess capacity is absorbed through load growth and generator retirements.

We are party to a capacity swap (a form of derivative instrument as hereinafter explained) that effectively exchanges a substantial portion of our New York City installed capacity spot market auction payments for a fixed payment. In a “spot” auction, capacity is purchased immediately prior to the month of delivery for a term of one month at a fixed-price. This contract has a stated maturity of April 30, 2009 and contains provisions that provide for modification or early termination upon certain significant regulatory changes. On May 7, 2008, we received notification from the counterparty that it interprets recent regulatory developments to trigger modification of the pricing provisions within the contract, and the counterparty has adjusted its payments to Astoria accordingly. These modifications expose us to the NYISO market clearing price for capacity. As a result, we expect this price to be lower than the fixed price of $7.07 per kW-month we had been receiving under the contract. This could lead to a significant decline in revenues if those prices drop. A significant decline in revenues could trigger a financial covenant default under the Astoria credit facilities. In addition, early termination of the contract and failure to replace the contract with another contract containing at least as favorable terms within 60 days would constitute a default under the Astoria credit facilities.

Due to regulatory changes to the ISO-NE capacity market that became effective December 1, 2006, power generators in that market such as EBG can sell capacity as part of a FERC-approved Forward Capacity Market (“FCM”) settlement. The settlement provides for capacity to be sold at fixed prices through May 2010 and at auctions within price collars for a period of time thereafter. We cannot predict the prices at which capacity will be sold in future auctions. Capacity prices in the first auction, held in February, 2008, for the 2010 capacity year, were set at the regulatory floor of $4.50 per kW-month. More capacity was bid into the auction than was required. This resulted in downward pressure on the final price set by the auction. We will therefore receive less capacity revenues for the 2010 period than we could have if there had not been an oversupply of capacity in the auction.

We have been required to recognize an impairment charge against our goodwill, and we may be required to recognize additional impairment charges against goodwill in the future.

We had approximately $579.0 million and $78.1 million of goodwill and other intangible assets, respectively, recorded as assets on our balance sheet as of March 31, 2008. We account for goodwill in

accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS 142”) and are required to test such goodwill for impairment at least annually and whenever an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We recorded an impairment of our goodwill of $250.1 million in our results of operations for the three months ended March 31, 2008 principally due to lower than expected capacity prices in the ISO-NE capacity market established in the recent FCM auction covering the 2010 capacity year (beginning June 1, 2010). This impairment charge contributed to our net loss of $264 million for the three months ended March 31, 2008. We may experience additional goodwill impairment charges in the future, and any such charges could adversely affect our results of operations and financial condition.

Competition in wholesale power markets or efforts to reduce peak demand may have a material adverse effect on our results of operations, cash flows and the market value of our assets.

We have numerous competitors in all aspects of our business. Our existing competitors may expand their presence and additional competitors may enter our markets. If generating capacity in our markets is added at a greater rate than existing generating capacity is retired and/or demand for electric energy increases, prices for our energy and capacity products may decrease. Periods of excess capacity have occurred in our markets and long-term industry cycles, including periods of oversupply, are typical of commodity-based industries like ours.

Some of our plants were built prior to 1975, and newer plants owned by our competitors often can generate energy more efficiently than our older plants. Our competitors may construct new plants capable of producing energy more efficiently than ours, or they may upgrade existing plants or add additional capacity to existing plants in a manner which allows them to generate energy more efficiently than us. Our competitors may also use or develop alternative technologies to produce power, including fuel cells, clean coal and coal gasification, micro-turbines, photovoltaic (solar) cells, tidal current based generators and improvements in traditional technologies and equipment, such as more efficient gas turbines and nuclear or coal power plants, with simplified and safer designs, and coal-fired integrated gasification combined-cycle power plants, among others. Advances in these or other technologies used by our competitors could reduce the costs of power production, and/or could enable our competitors to receive assistance through renewable resource subsidies, tax incentives, loan guarantees or favorable regulatory requirements or tradable credits. Competitors may be able to bid into our markets at lower prices, decreasing the hours during which our older units can be economically dispatched. Our Astoria facility, which was originally constructed in the 1950s, has recently experienced a decrease in both operating hours and energy production as a result of newer, more efficient facilities coming online in the New York market. Over time, our plants may be unable to compete with these more efficient plants unless we invest in substantial upgrades.

Our competitors may have greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures, more effective risk management policies and procedures and/or greater ability than us to withstand losses. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or devote greater resources to the construction, expansion or refurbishment of their power generation facilities than we can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties, including load servicing entities. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share to our detriment. We may not be able to compete successfully against current and future competitors, and any failure to do so could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Competition in the form of businesses or government-subsidized programs that are designed to reduce peak demand or energy consumption could adversely impact our business. Demand response technologies and real-time pricing programs are growing in effectiveness and are succeeding in enlisting customers to reduce energy consumption at times of peak demand. This could ultimately have a significant effect on the need for peaking generation capacity, including energy provided by many of our units. Additionally, energy efficiency programs may reduce the total amount of energy used by customers which could reduce overall demand.

Concentration of our business in the New York City and Boston metropolitan areas limits our ability to protect against geographic market concentration risks.

We are subject to geographic market concentration risk because our business is limited to the metropolitan areas of New York City and Boston. Many of our competitors have diversified their operations in markets across the United States, and may be better able to absorb adverse changes to our markets. Changes in the structure, operation or regulation of our markets may adversely affect the prices at which we can sell our electric energy, capacity or ancillary service products or otherwise adversely affect our business, financial condition or results of operations. Any disruptions or similar events affecting the supply of energy in our markets (including the supply of fuels that we use to generate energy) may increase our costs or prohibit us from generating electric energy on a cost effective basis, or at all.

Improvements to certain transmission systems or new transmission lines could permit more electric energy and capacity sales in our markets, which could reduce our revenues.

Our New York Facilities operate in the New York City Zone J market, which is one of the most transmission constrained power markets in the United States. We receive premium electric energy and capacity prices as a result of this transmission congestion. Enhancements of the transmission and distribution systems to reduce or eliminate these transmission constraints may permit more electric energy and capacity to be purchased from generators outside of New York City, or may permit energy to be more easily transported within New York City, either of which would negatively impact the value or profitability of our New York Facilities.

Additionally, the Boston metropolitan area has historically been transmission constrained. A newly constructed 345 kilovolt (“kV”) transmission line which enters Boston from the south has relieved a significant portion of the historical transmission constraints in that region. The first phase of this construction was completed in the spring of 2007 adding approximately 850 MW of transmission capacity and the second phase is scheduled to be complete in 2009, adding an additional 250 MW of transmission capacity. The new transmission lines have resulted in the convergence of prices for energy generated at our Mystic facility and Fore River facility (prices were historically higher at our Mystic facility due to transmission constraints). If prices of electric energy decline, we could experience a material adverse effect on our financial condition, results of operations or cash flows.

We have significant leverage and require a significant amount of cash to service our indebtedness, which reduces the cash available for other activities, and our credit facilities contain covenants that restrict our ability to take certain actions.

As of March 31, 2008, our total indebtedness was approximately $2.5 billion. Our substantial leverage could have important consequences, including the following:


	•	our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, refinancings, acquisitions and general corporate or other purposes may be limited;

	•	a substantial portion of our cash flows from operations must be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities;

	•	the debt service requirements of our indebtedness could make it more difficult for us to satisfy our other financial obligations;

	•	our borrowings under our senior credit facilities are at variable rates of interest, exposing us to the risk of increased interest rates;

	•	our ability to adjust to changing market conditions may be limited, which would place us at a competitive disadvantage compared with our competitors that have less debt;

	•	we may be more vulnerable in a downturn in general or regional economic conditions or in our business; and


	•	certain portions of our indebtedness will be paid-in-kind and not in cash, and we therefore will incur additional debt due through the accrual of paid-in-kind interest.

Our ability to service our indebtedness will depend on our future performance, which will be affected by prevailing economic conditions, market prices for our energy products and regulatory and other factors. Some of these factors are beyond our control. If we cannot generate sufficient cash flow from operations to service our indebtedness and to meet our other obligations and commitments, we might be required to refinance our debt or to dispose of assets to obtain funds for such purpose. We cannot assure you that refinancings or asset dispositions could be effected on a timely basis or on satisfactory terms, if at all, or would be permitted by the terms of our debt instruments. In addition, our senior credit facilities contain covenants that may restrict our and our subsidiaries’ ability to make payments or distributions (including dividends) with respect to our capital stock or otherwise restrict payments or distributions to our equity holders, prepay other debt, encumber our assets, incur additional indebtedness, make capital expenditures above specified levels, engage in business combinations or undertake various other corporate activities. Our senior credit facilities also limit the type and value of affiliated transactions that we can undertake, which may limit our ability to realize synergies resulting from the Combination.

Our existing senior credit facilities require us to comply with certain financial covenants and any failure to comply with such covenants could have a material adverse effect on our financial condition, results of operations or cash flows.

Our senior credit facilities contain covenants that require each of the respective borrowers under such facilities to maintain certain specified financial ratios relating to total leverage and interest coverage. We were in compliance with such covenants as of March 31, 2008. With respect to our credit facilities at Boston Generating, LLC (“BG”) (collectively, the “BG credit facilities”), a wholly-owned subsidiary of EBG, however, we released approximately $2.5 million from a post-closing contingency reserve account established at the initial closing of these facilities to remain in compliance with BG’s financial covenants at March 31, 2008. We expect that we will need to use additional amounts from this contingency account over the next several quarters to remain in compliance with the covenants under the BG credit facilities due in part to required step downs in our leverage ratio during this period pursuant to the agreements governing these credit facilities. Each of our credit facilities contains an equity cure provision whereby any financial covenant default can be cured with the investment of additional capital by the relevant borrower’s respective parent company. Any net proceeds from this offering that are contributed to BG will be available for purposes of the equity cure provision of the BG credit facilities. With respect to our credit facilities at Astoria, we expect our leverage ratio will significantly increase over the next several quarters due primarily to recent developments in the New York City (Zone J) capacity markets. We expect to remain in compliance with Astoria’s leverage ratio covenant for the foreseeable future. See “Use of Proceeds” and “Description of Principal Indebtedness — Representation and Warranties, Covenants and Events of Default.”

Our ability to remain in compliance with the financial covenants contained in our existing senior credit facilities may be affected by events beyond our control, including prevailing economic conditions, market prices for our energy products and regulatory and other factors. As a result, we cannot assure you that the borrowers will remain in compliance with the respective financial covenants. In the event we do not remain in compliance, we would either have to seek a waiver of such covenant compliance from the respective lenders under such senior credit facilities or seek to refinance the outstanding indebtedness under such senior credit facilities. We cannot assure you that we will be successful in either obtaining any such waiver or refinancing or, if we are successful, what the ultimate terms and conditions of any such waiver or refinancing will be.

Our failure to comply with any of these covenants could result, among other things, in the imposition of default interest rates or the acceleration of our outstanding indebtedness. If acceleration occurs, we would not be able to repay our accelerated indebtedness and it is unlikely that we would be able to borrow sufficient additional funds to refinance such indebtedness. Even if new financing is made available to us, it may not be available on acceptable or reasonable terms and will likely not be available on terms as favorable as our existing senior credit facilities. If we were unable to refinance our indebtedness on acceptable terms, or at all, we might be forced to dispose of assets on disadvantageous terms or otherwise restructure such indebtedness.

If interest rates or other factors at the time of the refinancing result in higher interest rates upon refinancing, our interest expense would increase, which could have a material adverse effect on our financial condition, results of operations or cash flows. Any acceleration of our existing indebtedness may create substantial doubt about our ability to continue as a going concern. See “Description of Principal Indebtedness.”

Our use of derivative instruments or our failure to fully implement risk management activities could result in financial losses that negatively impact our results of operations and result in volatility in our cash flows.

We use derivative instruments to reduce the risks inherent in our business, including the volatility of our revenues from our electric energy generation and capacity obligations and the borrowing costs associated with our variable rate debt. This risk and volatility can be attributed to many factors in our day-to-day business, including changes in interest rates and fluctuations in prices of electric energy, capacity, natural gas and fuel oil. These derivative instruments are types of “hedges,” and are generally in the form of “swap” or “index” contracts with counterparties willing to assume certain risks or volatility that are inherent in our business. By using these contracts, we seek to obtain more predictable cash flows.

We have obligations under our electric energy and fuel purchase derivative instruments designed to approximate net profits that we earn from our generation plants. However, net revenues from generating operations often do not match payment obligations under these instruments. Unforeseen changes in governmental regulation, fuel costs, environmental compliance, plant outages or a wide range of other factors may in the future cause our net revenues to deviate from our payment obligations under our derivative contracts. As a result, we could be required to pay amounts to our derivative instrument counterparties in excess of the net revenue stream that we actually realize. These payments could materially adversely affect our financial condition and operating results. In addition, if we experience unplanned outages at our generating units, we may incur significant obligations under the derivative instruments that are not offset by other revenues from plant operations. To further mitigate such risks, in certain periods we may purchase unit outage insurance products designed to replace lost plant revenues due to unplanned outages. We typically purchase outage insurance for our combined cycle plants at our Boston Facilities, which have a high expectation of running. For our Astoria facility, we have typically in the past, and may in the future, purchase outage insurance for certain months depending on the amount of plant output that we have sold. We may be unable to purchase enough outage insurance at desirable costs, or our policies may not cover every contingency.

EBG has entered into energy-related derivative instruments relating to approximately 100% of the seasonally adjusted generating capabilities of the Mystic 8&9 and Fore River facilities through 2010 and Astoria has entered into derivative instruments relating to between 300 to 600 MW (varying by month) of its summer generation capacity in 2008 and 2009. Since a portion of our generation is not subject to derivative instruments, our risk management activities will not fully protect us from exposure to commodity price risks, and we will still have exposure to changes in electric energy and fuel prices. Our energy-related derivative instruments have had and are expected to have in the future a material impact on our operating results. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosure About Market Risk — Energy and Capacity Price Risk.”

In the future we may not be able to obtain replacement derivative instruments on similar or better terms than the derivative instruments we currently are a party to, and the failure to do so could materially adversely affect our financial condition and operating results. We prefer to enter into highly structured long-term derivative instruments that mirror our cash flows earned in market sales from plant operations. The ability and willingness of counterparties to take on long-term structured positions at prices that we would find attractive will depend on liquidity in local capacity and energy markets and the willingness of such counterparties to take on commodity price risk. As a result, in the future we may be required to manage the risks inherent in our business with shorter term derivative instruments or with instruments that do not match variability in our plant cash flow as well as our current derivative instruments. This could lead to increased volatility in our cash flows in the future.

We may not have sufficient liquidity to effectively address market risks.

In connection with entering into derivative instruments to manage certain of our risks, we must provide credit support for these derivative instruments in the form of liens, letters of credit or cash collateral. The amount of credit support that must be provided is typically based on an estimation of the expected or potential adverse exposure between the price of the derivative instruments and the current market value that the specific contracts represent. Significant movements in market prices may require us to provide cash collateral and letters of credit in potentially significant sums. The effectiveness of our derivative instrument strategy may be dependent on the amount of collateral available that we may be required to provide or maintain for these contracts, and these requirements may be greater than we anticipated or have adequate collateral capacity to meet. If we do not have a sufficient amount of working capital to post collateral in support of performance guarantees or a cash margin, we may not be able to implement our strategy for managing price risk exposure. An increase in the amount of letters of credit or cash collateral required to be provided to our counterparties may negatively affect our liquidity and financial condition. The inability to maintain adequate collateral posted to counterparties could result in a contract counterparty prematurely closing out of a contract position in the derivative instrument, which could expose us to significant liability.

We cannot fully eliminate the risk associated with our commodity risk management activities.

Our ongoing commodity purchases, including electrical energy and fuel, expose us to risks of unexpected price movements. We attempt to manage these exposures through enforcement of established risk limits and risk management policies and activities. However, these risk limits and risk management policies may not work as planned and cannot eliminate all risks associated with these policies and activities. Even when policies and procedures are followed, and decisions regarding commodities are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions turn out to be incorrect. The further into the future estimations are made, the more difficult it becomes to predict market conditions. As a result, we cannot predict the impact that the decisions related to our commodity risk management policies and activities may have on our business, operating results, earnings or financial position.

Additionally, we expect to have unhedged generation (generation for which we have not entered into derivative instruments). To the extent we do not hedge our generation, fluctuating commodity prices can adversely affect our financial results and financial position. Furthermore, the risk management procedures we have in place may require exceptions that may not always work as planned and limits and controls might be ineffective. Unauthorized derivative instruments and related activities by our employees could result in significant penalties and financial losses. As a result of these and other factors, we cannot predict the outcome that our risk management policies regarding commodity purchasing, the sale of electric energy and fuel procurement activities may have on our business, operating results or financial condition.

Accounting for derivative instruments will increase the volatility in our quarterly and annual financial results.

Certain of our derivative instruments are accounted for in accordance with Statement of Financial Accounting Standards 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS 133”), which requires us to record all derivatives on our balance sheet at fair value, with changes in the fair value resulting from fluctuations in the underlying commodity prices and interest rates immediately recognized in earnings, unless the derivative instrument qualifies for “cash flow hedge” accounting treatment and our management (i) formally designates the derivative instrument as a “cash flow hedge” and (ii) documents the intended hedging relationship, as required by SFAS 133. Consequently, fluctuation in fair value of our hedges could affect earnings regardless of how sound the cash flows of our business may be. Whether a derivative instrument qualifies for cash flow hedge accounting treatment depends upon it meeting specific criteria used to determine whether the cash flow hedge is and will remain appropriate for the term of the derivative. Economic hedges will not necessarily qualify for cash flow hedge accounting treatment or, if qualified, be designated and documented as cash flow hedges. As a result, we may experience earnings volatility due to accounting for hedges.

Environmental laws and regulations impose extensive and possibly increasingly stringent requirements on our operations as well as substantial liabilities that could adversely impact our business, financial condition or operating results.

Our business is subject to the environmental laws and regulations of federal, state and local authorities. We must comply with these laws and regulations and obtain numerous governmental permits and approvals to operate our plants. If we fail to comply with any environmental requirements applicable to our operations, we could be subject to administrative, civil and/or criminal liability, including fines or penalties, and regulatory agencies could take other actions to curtail our operations, such as revoking permits necessary for our operations. In addition, new environmental requirements or changes to or reinterpretations of existing environmental requirements or enforcement policies could adversely affect our business, financial condition or operating results.

Certain environmental laws impose strict, joint and several liability for costs to clean up and restore sites where hazardous substances have been disposed or released. We are generally responsible for all liabilities associated with any environmental contamination at our power generation plants. These liabilities may include costs to clean up any soil or groundwater contamination that may be present, regardless of whether contamination is caused by the activities of predecessors or third parties.

Regulations relating to air permitting and control of air emissions have become more stringent over time and are subject to future changes. We anticipate that we will need to implement process changes, acquire emissions allowances and/or incur capital expenditures for additional environmental controls under current and future regulations regarding air emissions permitting and control.

Due to potential air regulations, we may need to purchase emissions allowances to cover future air emissions to comply with clean air initiatives. The costs of such purchases may be material. For example, the recently vacated Clean Air Interstate Rule (“CAIR”) would have permanently capped sulfur dioxide (“SO₂”) and NO_x emissions from power plants in most eastern states in two phases: 2010 and 2015 for SO₂ and 2009 and 2015 for NO_x. The implementation of CAIR could have materially affected our operations. CAIR and its associated federal implementation plan (“FIP”) were both vacated in their entirety and remanded to the Environmental Protection Agency (“EPA”) by the U.S. Court of Appeals for the District of Columbia Circuit in its decision in North Carolina v. Environmental Protection Agency issued July 11, 2008.

We may be required to install air emission controls to comply with air emission regulations. The Clean Air Visibility Rule provides regional haze controls by targeting SO₂ and NO_x (and particulate matter and volatile organic compounds) emissions from sources, including certain power plants, through the installation of Best Available Retrofit Technology (“BART”). The Massachusetts Department of Environmental Protection (“MassDEP”), has identified our Mystic 7 generator as a unit that will fall under the BART rules, and therefore we may incur additional expenditures for compliance. Also, on March 2, 2007, the Ozone Transport Commission (“OTC”) passed an initiative to reduce emissions on high electric demand days in New York. The impact of this initiative on our generating portfolio is unknown at this time, but the costs of complying with the rules could be material.

We may be affected by the regulation of CO₂ emissions. There is a growing consensus in the U.S. and globally that emissions of greenhouse gases (“GHGs”) are linked to global climate change and this consensus may lead to more stringent regulation of GHGs in the future. Increased public concern and mounting political pressure may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. States in the Northeast under the Regional Greenhouse Gas Initiative (“RGGI”) are in the process of implementing rules to stabilize and reduce emissions of GHGs. RGGI allows each state flexibility in the distribution of its carbon dioxide (“CO₂”) allocations. Massachusetts has adopted final rules and New York has issued draft rules with respect to RGGI requiring that 100% of available allowances be allocated through an open auction scheduled for September 2008. The floor price of the initial auction is $1.86 per short ton. Companies will subsequently be allowed to trade their allowances in a secondary market and may be able to reduce costs by available offsetting activities. Our generating portfolio includes oil- and natural gas-fired plants covered by RGGI that emitted approximately 7.5 million short tons of CO₂, a GHG, in the year ended December 31, 2007. The majority of our generating capacity will be subject to regulation under RGGI and this

will likely result in material costs associated with compliance. Our power generating facilities in Massachusetts are already subject to existing state-level GHG regulations. It is likely that our plants will also be subject to any new federal or state GHG legislation. The costs of complying with potential GHG regulations, including costs of purchasing emissions allowances to cover future CO₂ emissions to comply with RGGI or other regional/federal GHG programs, may be substantial and may have a significant impact on our operations, cash flow or financial position. There is also proposed federal legislation to regulate GHG emissions. In addition, the EPA issued an Advance Notice of Proposed Rulemaking on July 11, 2008 for a request for public comment on how to respond to the U.S. Supreme Court’s decision in Massachusetts v. Environmental Protection Agency, in which the Supreme Court ruled that the Clean Air Act authorizes regulation of greenhouse gases. We cannot accurately predict the outcome of such proposals, although they could potentially adversely affect our business.

The costs of compliance with these regulations, including any purchases of carbon credits or allowances, may be substantial and we cannot be certain of our ability to recover costs from any of these programs. Moreover, our derivative instruments may not have structural mechanisms to take into account all or any of these additional costs. Therefore, any changes in the energy markets resulting from environmental legislation may have a significant impact on our derivative instrument performance, cash flow or financial position. See “Management’s Discussion and Analysis of Financial Conditions and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Energy and Capacity Price Risk.”

We may also incur capital costs to comply with Clean Water Act requirements. The Clean Water Act requires that cooling water intake structures reflect the Best Technology Available (“BTA”) for minimizing adverse environmental impact. In July 2004, the EPA published regulations governing cooling water intake structures at large existing power plants that withdraw more than 50 million gallons of cooling water per day. The regulations would apply to our Astoria and Mystic 7 facilities. The regulations required implementation of the BTA for minimizing adverse environmental effects and provided generating facilities with several options for achieving the required BTA. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit vacated key portions of the regulation. In July 2007, the EPA suspended the regulation. A new round of rulemaking has not been announced and it may be several years before a revised cooling water intake structure regulation is finalized.

How we implement BTA will depend upon the options provided in the EPA’s new rulemaking, and they vary for each of our affected facilities. Possibilities include upgrades of existing water intake structures and/or equipment to the construction and installation of new, extensive water intake structures and/or equipment or reducing intake water flows. Until the EPA proposes new regulations it is not possible to estimate with certainty the capital costs that will be required to comply with BTA. However, if our BTA requires significant changes to the cooling water intake systems at our Astoria and Mystic 7 facilities, our costs to implement these changes may be material.

Our New York Facilities are a party to an Order on Consent with the New York State Department of Environmental Conservation (“NYSDEC”) pursuant to which we agreed to undertake, over time, certain environmental remediation obligations relating to historical releases of hazardous substances at those facilities. In addition, we are required to modify our cooling water intake system at the Astoria facility to minimize adverse environmental impact to marine life. These modifications are expected to result in capital and other expenditures that could be material.

We are also subject to marine regulations. All of our facilities are located next to high traffic waterways and two of these locations, our Gowanus and Narrows facilities, float on permanently moored barges. These facilities are subject to inspection by various marine regulatory agencies, including the U.S. Coast Guard. Requirements to maintain aging dock infrastructure, control erosion into the waterway, proactively protect against hazardous waste spillage and changes in marine safety regulations could adversely impact our operations, cash flow or financial position. See “Business — Environmental, Health, Safety and Security Matters.”

Operation of our power generation facilities involves significant risks and hazards inherent to the power industry that could have a material adverse effect on our revenues and operating results; our insurance may not be adequate to mitigate our losses.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. Hazards, such as fire, explosion, release of high-temperature steam or water, structural collapse and machinery failure, are inherent risks in our operations. These and other hazards can cause severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The age of some of our facilities increases the risk associated with these hazards. For example, our older facilities do not have state of the art fire suppression equipment in place. In addition, we routinely ship equipment, including critical components, to third parties for repair and refurbishing. This equipment may be damaged in transit or at the third parties’ facilities. The occurrence of any one of these events may result in loss of plant availability for an extended period of time and/or our being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties.

We maintain an amount of insurance protection that we consider adequate and that meets the requirements of our lenders, but we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Specifically, our insurance may not be sufficient to replace facilities or equipment that are damaged in part or in full. Damages or third party claims for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, in the future our insurance coverage may not continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on our business, financial condition or operating results.

Maintenance requirements or mechanical failures at our power generation facilities could require significant expenditures and could result in unplanned power outages.

The generating units at our New York Facilities began operations between 1953 and 1971 and the Mystic 7 and Mystic Jet units at our Boston Facilities began operations in 1969 and 1975, respectively. The age of these units exposes us to risks relating to increased maintenance costs, breakdown of equipment, possible shortages of or difficulties in obtaining replacement equipment, difficulties in finding repair service providers with sufficient expertise to maintain this equipment and other operational risks. Older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling less energy or require us to incur significant costs as a result of running one of our higher cost units or obtaining replacement power from third parties in the open market.

In addition, we are party to long-term service agreements with Mitsubishi Power Systems Americas, Inc. (“MPS”) relating to the maintenance of the plants at our Mystic 8&9 and Fore River facilities, which will be subject to renewal in 2009 and 2011, respectively. If we cannot agree on terms relating to the future maintenance of this equipment, we would have to find a new counterparty to maintain this equipment. This outcome may result in increased maintenance costs, and since MPS was the original supplier of this equipment, others may not be able to maintain it as effectively.

Reductions in the quality of fuel supplied to our Fore River facility since June 2008 have caused unplanned outages.

Our Fore River facility has recently on multiple occasions experienced large reductions in the heat content of the fuel used to operate its turbines. Heat content is a component of quality measurement relating to fuel. Our equipment operates within specific thresholds of heat content, and variances outside of those thresholds impact the operation of our equipment. Since June 2008, these reductions in heat content have

resulted in five unplanned gas turbine stoppages at our Fore River facility. When production is reduced, alternative fuel, which may not conform with our heat content standards, has been provided from an alternative source. To remedy this issue, we have had to, on occasion, restrict the output of the units of our Fore River facility to minimum output, since our generating equipment is better able to handle these variances (and not go offline) at a minimum load rather than at full load operation. However, when such outages occur, or when we are required to reduce our output, we are not always able to meet our power supply obligations and we have been required to cover our obligations by purchasing power from the real time market at higher prices. Our future capacity payments are also reduced due to these forced outages. In addition, we may incur higher costs associated with the restart of the impacted unit, primarily resulting from additional maintenance costs under our long-term service agreement with MPS. We are currently exploring solutions to these issues. However, should the outages or reductions in production continue, they may have a negative impact on our operations at the Fore River facility.

Weather and other natural conditions significantly affect our business and cause our financial results to fluctuate on a seasonal basis.

Weather conditions directly influence the demand for and prices of electricity, natural gas and fuel oil. Generally, demand for electricity peaks in the summer and demand for natural gas and fuel oil peaks in the winter. Recent growth in natural gas-fired electric generation has introduced a secondary peak for natural gas demand in the summer. Typically, when winters are warmer than expected and/or summers are cooler than expected, demand for energy is lower, resulting in lower consumption of electricity. Likewise, when winters are colder than expected and/or summers are warmer than expected, our consumption of natural gas may be greater than we are able to meet with storage or full requirements contracts. Depending on prevailing market prices for electricity and natural gas, these and other unexpected conditions may reduce our sales or increase our costs and negatively impact our financial condition. In addition, our generation plants typically operate more efficiently during cool, dry periods, and therefore we will be able to generate more electric energy at a lower cost during the winter. Consequently, our overall operating results may fluctuate substantially on a seasonal basis, and any change in weather patterns that reduces our sales or efficiency could negatively impact our financial results.

Natural risks such as earthquakes, floods, lightning, hurricanes and wind may significantly impact our plants. Our generating facilities are located on, or close to, high traffic waterways, and certain of our plants are located on barges, and, as a result, are subject to the risks associated with adverse weather conditions, including but not limited to hurricanes and flooding. Any increase in hurricane or storm-surge frequency or intensity could lead to increased risk to our properties given their location near high traffic waterways. All of our facilities are subject to ocean tidal forces and rising water levels that may require capital or other expenditures to raise or reinforce existing facilities that were not designed to deal with the higher average water levels. These and other hazards could cause severe damage to and destruction of property, plant and equipment, and cause us to suspend our generation operations for substantial periods of time. Any effects from adverse natural events, including a suspension of our operations, could lead to a reduction in our revenues and an increase in our costs as we seek to repair damaged plants.

Our dependence on transmission or distribution systems that we do not own or control may limit our ability to deliver electric energy.

We depend on transmission and distribution facilities owned and operated by others to deliver the wholesale power we sell from our power generation plants. If transmission is disrupted or if distribution systems fail, our ability to sell and deliver wholesale power may be adversely affected. If the regional power transmission and distribution infrastructure in one of our markets is inadequate, our profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may have insufficient incentive to invest in expansion of transmission and distribution infrastructure in the future. We cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

Our financial condition and operating results could be adversely impacted by changes in prices of our fuel supplies.

We rely on fuel oil and natural gas to fuel our power generation facilities. We purchase significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate significantly over relatively short periods of time. The prices we can obtain for the sale of electric energy may not rise at the same rate or at all, to match a rise in fuel or delivery costs. In addition, prices for different fuel types vary by region, and can change in manners which can have an adverse effect on our profitability. Many of our financial derivative instruments contain fuel cost provisions that are based on published natural gas price indices which may be different from the price indices used in our derivative instruments. Changes in market prices for natural gas and fuel oil may result from the following:


	•	weather conditions;

	•	seasonality;

	•	demand for energy commodities and general economic conditions;

	•	availability and levels of storage and inventory for fuel stocks;

	•	availability and pricing of fuel transportation;

	•	natural gas, crude oil and refined product production levels;

	•	federal, state and foreign governmental regulation and legislation;

	•	political instability, conflicts and other events affecting production and/or transportation; and

	•	the creditworthiness, liquidity and willingness of fuel suppliers/transporters to transact business with us.

These factors are largely beyond our control and any changes they create in fuel prices could have a material adverse effect on our results of operations and cash flows.

Failure by any of our suppliers to deliver fuel to our facilities could have a material adverse effect on our ability to generate electric energy.

We receive all of the fuel that we use to generate electricity from third parties, and we have limited fuel storage capabilities. In addition, we often rely on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of our facilities. For example, there currently is no alternative means of supplying natural gas to our Mystic 8&9 facility other than the Distrigas facility. In certain cases our fuel suppliers may not be able to obtain fuels or transport them to our sites due to disruptions in the markets in which the suppliers purchase the fuel or in transportation. For example, the Port of Boston was closed to liquified natural gas tankers for approximately 7 weeks following the events of September 11, 2001. On December 15, 2005, a short-term interruption in the natural gas supply to Mystic 8&9 caused the facility to shut down unexpectedly. If our existing suppliers cannot or will not perform, we will utilize the marketplace to provide these services. We may not be able to find other providers for these services, when and where required, or at prices that permit us to operate profitably. In addition, delivery of fuel to our facilities is dependent upon the infrastructure (including barge facilities and natural gas pipelines) available to serve each of our generation facilities. If there is a disruption in the fuel delivery infrastructure we will be subject to risks of disruptions or curtailments in the production of power at our generation facilities. In addition, regulators in our markets occasionally set restrictions on the amount of a particular type of fuel that we can use. If this occurs, we may be forced to use a higher cost fuel or curtail our operations at one or more of our facilities. Disruptions in our fuel supplies may, therefore, require us to find alternative fuel sources or other sources of energy at higher costs, or, if no alternative is available, we may be required to shut down facilities. Any such event could have a material adverse effect on our financial performance.

Counterparty concentration may expose us to significant financial credit or performance risks.

We rely on a few customers to purchase all or a significant portion of our electric energy output. In the year ended December 31, 2007, we derived 46.4% of our revenues from sales to NYISO. Electric energy and capacity purchased by NYISO are sold to load serving entities, such as Con Edison, in the NYISO market. Typically 3 to 4 load serving entities have purchased the majority of electric energy sold in the New York City market in which we operate. We sell all electric energy, capacity and ancillary services from our Boston Facilities to ISO-NE. In the year ended December 31, 2007, these sales accounted for 57.5% of our revenues. The credit worthiness of NYISO and ISO-NE is generally based on the credit worthiness of their customers. If any of their customers’ financial positions materially deteriorate, it may affect the credit worthiness of NYISO and ISO-NE, we may not be able to collect revenues from our sales and it may significantly adversely affect the operations of our markets.

We have long-term fuel contracts with third-parties to provide all or a substantial portion of the natural gas and/or fuel oil used at certain of our facilities. For example, Distrigas provides all of our natural gas requirements for our Mystic 8&9 facility pursuant to a contract that lasts through 2027. The Mystic 8&9 facility currently does not have an efficient means to receive natural gas other than through the pipeline connected to the Distrigas facility. If our fuel supplier counterparties do not perform under these agreements, we may be forced to temporarily cease operations at the affected location. We may not be able to enter into replacement agreements on terms as favorable as the existing agreements, or at all. If we are unable to enter into replacement fuel supply agreements, we would seek to purchase our fuel requirements at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.

We have also entered into derivative instruments to mitigate a portion of our exposure to capacity, energy and fuel market price fluctuations. Counterparties to these agreements may breach or may be unable to perform their obligations. If counterparties breach or become unable to perform, we may not receive payments to which we are entitled, and we will be exposed to changes in the prices of capacity, energy and fuel, which could materially harm our operating results. Because we tend to have a small number of derivative instrument counterparties, we face the possible risk associated with a relatively large exposure to a given counterparty.

We employ an experienced but aging workforce, and we will incur costs as a result of employee turnover in future periods, and this turnover may adversely affect our operations.

The average age of our employees at our Mystic Station facility is approximately 55. At our Astoria facility, approximately 9% of our employees are age 60 and over. Generally, these senior employees have a deep operational knowledge base, which is especially valuable in the operation of our Mystic Station facility and our Astoria facility. When these persons retire or otherwise leave our company, obtaining and training replacement personnel will be costly and time consuming. In addition, we cannot be sure that future employees will have the same capabilities and qualifications as our current employees. Currently, we are increasing our headcount at our Astoria facility to facilitate the transition as older workers retire. This has led to increased salary and other costs, and redundancy in certain of our positions. If the increased costs we experience as a result of employee turnover in future periods are substantial, or if new employees are not able to operate our plants in the same manner as current employees have, it could have a material adverse effect on our business, financial condition or operating results.

Our business, financial condition and operating results could be adversely impacted by strikes or work stoppages by our unionized employees.

As of June 30, 2008, approximately 75% of our employees at our generation plants were covered by collective bargaining agreements with various unions that expire in 2010 and 2012 for our Boston Facilities, and in 2012 for our New York Facilities. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be required to procure replacement labor or we could experience reduced power generation or outages. Our ability to procure replacement labor is uncertain. Strikes, work stoppages or the inability to negotiate future collective bargaining

agreements on favorable terms could have a material adverse effect on our business, financial condition and operating results.

In addition, our plants are dependent on receiving services and materials from third parties that are themselves unionized. A strike by workers at any of these providers, including transportation, electrical or dock workers, could have a material adverse effect on our ability to operate our plants.

We depend on the service of key individuals, the loss of whom could materially harm our business.

Our success will depend, in part, on the efforts of our executive officers and other key employees, none of whom are covered by key person insurance policies. These individuals possess sales, marketing, engineering, manufacturing, financial and administrative skills that are critical to the operation of our business. If we lose or suffer an extended interruption in the services of one or more of our executive officers or other key employees, our business, results of operations and financial condition may be negatively impacted. Moreover, the market for qualified individuals is highly competitive and, should the need arise, we may not be able to attract and retain qualified personnel to succeed members of our management team or other key employees.

Acts of terrorism and compliance with anti-terrorism requirements could have a material adverse effect on our business, financial condition and operating results.

Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. An act of terrorism targeting our generation facilities or the facilities of third parties adjacent to our facilities or on which our facilities rely could result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity, natural gas or fuel oil. Our insurance may not be sufficient to cover any such losses in full or at all. Any such events or disruptions could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition and operating results. In addition, we are required to comply with various anti-terrorism regulations and requirements, most of which require additional expenditures by us, for security and otherwise. Any material increase in the requirements of these regulations, or in the security that we feel we need to provide at our facilities, will result in increased costs, which will adversely affect our operating results.

For the year ended December 31, 2006, our independent auditors identified material weaknesses in our internal controls, which, if not properly remedied, could result in material misstatements in our financial statements.

In connection with the audit of Astoria’s financial statements for the year ended December 31, 2006, Astoria’s independent auditors reported to the then Board of Directors of Astoria that there existed material weaknesses in Astoria’s internal controls. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the financial statements will not be prevented or detected on a timely basis. The following material weaknesses were identified by Astoria’s independent auditors:


	•	Enhancement of Accounting Personnel — the auditors noted that because of the volume and significance of audit adjustments to Astoria’s consolidated financial statements and the failure to review and understand the accounting significance of material agreements, the technical competence of Astoria’s accounting personnel constituted a material weakness.

	•	Completeness of Accounts Payable and Accrued Expenses — the auditors noted that Astoria’s controls and procedures to ensure that all costs were properly captured in the correct financial reporting period were ineffective and constituted a material weakness.

We have developed and are implementing a plan to remediate these material weaknesses. We have expanded our professional accounting personnel and are recruiting additional personnel to further enhance our accounting and reporting functions. In addition, we have retained the services of two consulting firms to supplement our accounting functions. We have also implemented additional controls and procedures over the

timely recording of costs and are routinely monitoring their effectiveness in capturing costs in the correct financial reporting periods. No material weaknesses were identified in connection with the 2007 audit.

Additional measures may be necessary and the measures we have taken to improve our internal controls do not ensure that our internal controls are effective or ensure that such material weakness or other material weaknesses would not result in a material misstatement of our annual or interim financial statements in the future. In addition, other material weaknesses or significant deficiencies may be identified in the future. If we are unable to correct deficiencies in internal controls in a timely manner, our ability to record, process, summarize and report financial information accurately and within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission (“SEC”) will be adversely affected. This failure could negatively affect the market price and trading liquidity of our common stock, cause investors to lose confidence in our reported financial information, subject us to civil and criminal investigations and penalties and materially and adversely impact our business and financial condition.

Certain of the historical financial information included in this prospectus may not be representative of operations as a combined company or otherwise comparable to our current operating results.

Astoria and EBG operated as separate companies prior to the Combination and have limited history as a combined company. The historical financial statements may not reflect what the combined company’s results of operations, financial position and cash flows would have been had both companies operated on a combined basis during such periods and may not be indicative of what the combined company’s results of operations, financial position and cash flows will be in the future. In addition, we have included pro forma financial data in this prospectus. The unaudited pro forma financial data may not be indicative of actual results that would have been achieved had the transactions described herein been consummated on the date or for the periods indicated and most likely will not reflect combined or results of operations as of any future date or any future period.

Prior to the MDP Acquisition, our Astoria business was operated through wholly-owned subsidiaries of Reliant. As a result, the combined financial information of the Predecessor included in this prospectus is presented on a carve-out basis and reflects the assets, liabilities, revenues and expenses that were attributed or allocated to it as a business unit of Reliant. The historical financial results in the combined financial statements presented herein may not be indicative of the results that would have been achieved had the Predecessor operated as a stand-alone entity during this period. These combined financial statements include costs for certain functions and services performed by centralized Reliant organizations and directly charged to the Predecessor based on usage, and may not be indicative of our expenses in the future.

The MDP Acquisition was accounted for using the purchase method of accounting. As a result, the MDP Acquisition has and will continue to affect our results of operations significantly, and thus the results of prior periods may not be comparable. We allocated the aggregate acquisition consideration to the tangible and intangible assets acquired and liabilities assumed based on their respective fair values as of the date of the MDP Acquisition, resulting in a significant decrease in the accounting basis of some our assets. This decrease resulted in a significant decrease in our annual depreciation and amortization expenses. In addition, due to the effects of the increased borrowings to finance the MDP Acquisition, our interest expense has increased significantly in periods following the MDP Acquisition. As a result, the financial information for periods beginning on or after February 23, 2006 are not comparable to the information prior to that date.

We may incur substantial costs as a result of future repowering, expansion and acquisition activities, and these costs may not be offset by increased revenues.

We may seek to acquire additional companies or assets in our industry as well as expand through adding additional capacity to our existing sites or developing new sites. To the extent we pursue expansion, we will incur significant expenses in evaluating potential acquisitions and development projects with no certainty of recovery of costs. For example, substantial expenses may be incurred in investigating and evaluating any potential opportunity before we can determine whether the opportunity is feasible or economically attractive. Furthermore, we may not be able to obtain approval from regulatory agencies to modify or expand our facilities.

Any repowering or expansion may not be completed in a timely manner, in full or at all. If a repowering or expansion is completed, market conditions may not support the repowering, and we may incur substantial costs as a result of the repowering and our investment in the additional assets may not produce additional revenues. Expansion efforts may be limited by our ability to obtain financing on favorable economic terms.

The acquisition of power generation companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence and the risk of over-paying for assets. We will likely require significant additional financings to pursue such acquisitions. Such financings may include additional issuances of equity or the further incurrence of indebtedness. The effectiveness of this strategy may be limited because we may be unable to obtain such additional financings on favorable terms or at all. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, our acquisitions may not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the costs and indebtedness incurred for acquiring them.

If our repowering, expansion or acquisition activities do not result in increased earnings to offset the increased costs incurred by such activities, our business, operating results and financial position will be adversely affected.

The expected benefits of the Combination and related transactions may not be realized in a timely or efficient manner or at all.

EBG and Astoria entered into the Combination with the expectation that the combination of their businesses and operations would result in various benefits, including, among other things, operating efficiencies and improved access to capital markets. Such benefits may not be realized in a timely manner, in full or at all. We currently have two separate credit facilities that limit our ability to enter into related party transactions. As such, we may not be able to achieve some of the expected synergies of the Combination. In addition, we have incurred and expect to continue to incur significant costs and face significant challenges in connection with integrating the operations and procedures of EBG and Astoria. As a result, we cannot assure you that the integration will be completed in a timely or efficient manner. In addition, such integration efforts could divert our management’s focus and resources from day-to-day business and operations. Such diversion of our management’s focus and resources could have a material and adverse effect on our business, financial condition and results of operations.

We are subject to litigation and regulatory proceedings.

From time to time, we are subject to routine litigation. We intend to defend all of these proceedings vigorously; however, we cannot predict the ultimate resolution of any of these matters at this time, and there can be no assurance that these matters will not have a material adverse impact on our financial condition or results of operations. We have responded to a Civil Investigation Demand from the Antitrust Division of the Department of Justice (“DOJ”) which is investigating competitive issues in the New York City capacity market. An adverse resolution of this investigation could negatively impact our business.

Risks Related to This Offering

An entity controlled by Madison Dearborn will own a substantial portion of our common stock after the completion of this offering and will have a substantial influence in our affairs, which will limit your ability to influence corporate activities and may adversely affect the market price of our common stock.

Upon completion of the offering, New Astoria will own or control common stock representing, in the aggregate, a % voting interest in us, or % if the underwriters exercise in full their option to purchase additional shares. Madison Dearborn owns approximately 90% of the voting equity of New Astoria and therefore controls New Astoria. As a result of this ownership, New Astoria (and, in turn, Madison Dearborn) will have effective control over the outcome of votes on all matters requiring approval by our stockholders, including the election of directors, the adoption of amendments to our certificate of incorporation and by-laws and approval of significant corporate transactions. In addition, pursuant to the Investor Rights Agreement,

following this offering, New Astoria will be entitled to nominate a number of directors equal to its percentage ownership in our company. See “Certain Relationships and Related Party Transactions — Agreements Related to the Combination — Investor Rights Agreement.” We currently expect that following this offering, three of our nine board members will be principals of Madison Dearborn. New Astoria (and, in turn, Madison Dearborn) can take actions that have the effect of delaying or preventing a change in control of us or discouraging others from making tender offers for our shares, which could prevent stockholders from receiving a premium for their shares. These actions may be taken even if other stockholders oppose them.

Conflicts of interest may arise because some of our directors are affiliated with our principal stockholder.

Madison Dearborn and its affiliates may invest in entities that directly or indirectly compete with us or companies in which they currently invest may begin competing with us. As a result of these relationships, when conflicts between the interests of Madison Dearborn and the interests of our other stockholders arise, these directors may not be disinterested. Although our directors and officers have a duty of loyalty to us under Delaware law and the amended and restated certificate of incorporation that we intend to adopt in connection with this offering, transactions that we enter into in which a director or officer has a conflict of interest are generally permissible so long as (1) the material facts relating to the director’s or officer’s relationship or interest as to the transaction are disclosed to our board of directors and a majority of our disinterested directors, or a committee consisting solely of disinterested directors, approves the transaction, (2) the material facts relating to the director’s or officer’s relationship or interest as to the transaction are disclosed to our stockholders and a majority of our disinterested stockholders approve the transaction or (3) the transaction is otherwise fair to us. Under our certificate of incorporation, Madison Dearborn’s representatives are not required to offer to us any transaction opportunity of which they become aware and could take any such opportunity for themselves or offer it to other companies in which they have an investment, unless such opportunity is expressly offered to them solely in their capacity as a director of ours.

If we are not able to implement the requirements of Section 404 of the Sarbanes-Oxley Act in a timely manner or with adequate compliance, we may be subject to sanctions by regulatory authorities.

Section 404 of the Sarbanes-Oxley Act (“Section 404”) requires that we evaluate and determine the effectiveness of our internal controls over financial reporting for our annual report for fiscal 2009. If we have a material weakness in our internal controls over financial reporting, we may not detect errors on a timely basis and our financial statements may be materially misstated. We will be evaluating our internal controls systems to allow management to report on, and our independent auditors to attest to, our internal controls. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404. While we anticipate being able to fully implement the requirements relating to internal controls and all other aspects of Section 404 by the above deadline, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance, we may be subject to sanctions or investigation by regulatory authorities, such as the SEC or the New York Stock Exchange (“NYSE”). Any such action could adversely affect our financial results or investors’ confidence in us and could cause our stock price to fall. In addition, the controls and procedures that we will implement may not comply with all of the relevant rules and regulations of the SEC and NYSE. If we fail to develop and maintain effective controls and procedures, we may be unable to provide financial information in a timely and reliable manner, subjecting us to sanctions, harm to our reputation and a negative impact on the public trading price of our shares.

Future sales of our common stock, or the perception in the public markets that these sales may occur, could depress our stock price.

Sales of substantial amounts of our common stock in the public market after this offering, or the perception that these sales could occur, could adversely affect the price of our common stock and could impair our ability to raise capital through the sale of additional shares. Upon completion of this offering, we will

have shares of common stock outstanding. Of these shares, the shares of common stock sold in this offering will be freely tradable, without restriction, in the public market. After the lock-up agreements pertaining to this offering and the 180-day holdback provisions set forth in the Investor Rights Agreement expire, an additional shares will be eligible for sale in the public market, subject to applicable manner of sale and other limitations under Rule 144 under the Securities Act. Following the completion of this offering, we will be subject to a lock-up period lasting 180 days, during which time we will not be able to sell our securities. Upon expiration of the holdback period, we may register additional shares of our common stock for sale. Following the expiration of the lock-up and holdback periods, parties to our Investor Rights Agreement, subject to certain exceptions, will have demand registration rights with respect to the registration of shares under the Securities Act. Each of the New Astoria majority holders or holders of 25% of the EBG Investor’s registrable securities may demand up to three (3) additional long-form registrations or an unlimited number of registration of some or all of their registrable securities on form S-2 or S-3 or other similar short-form registration. Such requests for long-form registration must be for at least $150,000,000. If this right is exercised, holders of all shares subject to the Investor Rights Agreement will be entitled to participate in such registration. By exercising their registration rights, and selling a large number of shares, these holders could cause the price of our common stock to decline. An estimated shares of common stock will be entitled to registration rights pursuant to our Investor Rights Agreement upon completion of the offering.

Requirements associated with being a public company will increase our costs, as well as divert company resources and management attention.

Prior to this offering, we have not been subject to the reporting requirements of the Exchange Act, or the other rules and regulations of the SEC or any securities exchange relating to public companies. We are working with our legal, independent accounting and financial advisors to identify those areas in which changes should be made to our financial and management control systems to manage our growth and our obligations as a public company. These areas include corporate governance, corporate control, internal audit, disclosure controls and procedures and financial reporting and accounting systems. We have made, and will continue to make, changes in these and other areas. However, the expenses that will be required in order to adequately prepare for being a public company could be material. Compliance with the various reporting and other requirements applicable to public companies will also require considerable time and attention of management. We cannot predict or estimate the amount of the additional costs we may incur, the timing of such costs or the degree of impact that our management’s attention to these matters will have on our business. In addition, the changes we make may not be sufficient to allow us to satisfy our obligations as a public company on a timely basis.

In addition, being a public company could make it more difficult or more costly for us to obtain certain types of insurance, including directors’ and officers’ liability insurance, and we may be forced to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. The impact of these events could also make it more difficult for us to attract and retain qualified persons to serve on our board of directors, our board committees or as executive officers.

Our certificate of incorporation and by-laws contain provisions that could discourage another company from acquiring us and may prevent attempts by our stockholders to replace or remove our current management.

Some provisions of our certificate of incorporation and by-laws may have the effect of delaying, discouraging or preventing a merger or acquisition that our stockholders may consider favorable, including transactions in which stockholders may receive a premium for their shares. In addition, these provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace or remove our board of directors. These provisions include:


	•	authorization of the issuance of “blank check” preferred stock without the need for action by stockholders;

	•	the removal of directors only by the affirmative vote of a majority of the shares of our capital stock entitled to vote;


	•	any vacancy on the board of directors, however occurring, including a vacancy resulting from an enlargement of the board, may only be filled by vote of the directors then in office in accordance with the applicable class of such vacancy; and

	•	advance notice requirements for board nominations and proposing matters to be acted on by stockholders at stockholder meetings.

Our common stock has not been publicly traded prior to this offering, and we expect that the price of our common stock may fluctuate substantially.

There has not been a public market for our common stock prior to this offering. We cannot predict the extent to which a trading market will develop or how liquid that market may become. If you purchase shares of our common stock in this offering, you will pay a price that was not established in the public trading markets. The initial public offering price was determined by negotiations between the underwriters and us. You may not be able to resell your shares above the initial public offering price and may suffer a loss on your investment.

Broad market and industry factors may adversely affect the market price of our common stock, regardless of our actual operating performance. Factors that could cause fluctuations in our stock price may include, among other things:


	•	actual or anticipated variations in quarterly operating results;

	•	changes in financial estimates by us or by any securities analysts who may cover our stock or our failure to meet the estimates made by securities analysts;

	•	changes in regulatory conditions that affect the electric energy markets in which we operate;

	•	changes in market prices for electric energy, capacity, natural gas and fuel oil;

	•	changes in the market valuations of other companies operating in our industry;

	•	announcements by us or our competitors of significant acquisitions, strategic partnerships or divestitures;

	•	additions or departures of key personnel; and

	•	sales of our common stock, including sales of our common stock by our directors and officers or other principal stockholders.

Prior to this offering our common stock has been traded privately in the Rule 144A markets; trading prices following this offering may not reflect the prices in those markets.

Prior to the date of this prospectus, there has been no public market for our common stock. However, certain qualified institutional buyers have traded our common stock in sales effected pursuant to Rule 144A of the Securities Act (“Rule 144A”). The closing bid and ask prices on August 8, 2008 of one share of our common stock were $23.00 and $25.00, respectively, which may not be indicative of the prices at which our stock will trade in the future or reflect the implied valuation of our business at the time of this offering or in the future.

We currently do not intend to pay dividends on our common stock, and as a result, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We currently do not expect to declare or pay dividends on our common stock in the foreseeable future. Instead, we anticipate that all of our earnings in the foreseeable future will be used to service and redeem our existing indebtedness and in the operation and growth of our business. In addition, USPowerGen is a holding company, and has no existing operations of its own. Therefore, we would rely on distributions from our subsidiaries to pay dividends to our stockholders. Restrictive covenants under our senior credit facilities limit the ability of our subsidiaries and, as a result, our ability, to declare and pay dividends or other distributions on our common stock. As a result, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates and you sell your shares at a profit. The market price for our common stock may never exceed (and may fall below) the price that you pay for such common stock.

FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are based on our management’s beliefs and assumptions and on information currently available to us. These statements may be found throughout this prospectus, particularly under the headings “Summary,” “Risk Factors,” “Dividend Policy,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business,” among others. Forward-looking statements typically are identified by the use of terms such as “may,” “should,” “expect,” “anticipate,” “believe,” “could,” “estimate,” “intend” and similar words, although some forward-looking statements are expressed differently. You should consider statements that contain these words carefully because they describe our expectations, plans, strategies, goals and beliefs concerning future business conditions, our results of operations, financial position and our business outlook or state other “forward-looking” information based on currently available information. The factors listed under the heading “Risk Factors” and in the other sections of this prospectus provide examples of risks, uncertainties and events that could cause our actual results to differ materially from the expectations expressed in our forward-looking statements. These factors include, among other things, the following:


	•	significant and unpredictable price fluctuations in wholesale power markets;

	•	implementation of or changes in laws, regulations or policies that could negatively affect our operations;

	•	structural changes and price fluctuations in capacity markets;

	•	significant impairment charges against our goodwill;

	•	competition in wholesale power markets or efforts to reduce peak demand;

	•	our geographic concentration in the Boston and New York City metropolitan areas;

	•	enhancements to existing transmission systems and the construction of new transmission lines in our markets;

	•	the degree to which we are leveraged and the terms of our debt service obligations;

	•	our ability to comply with financial covenants in our existing senior credit facilities;

	•	losses related to our use of derivative instruments;

	•	having insufficient liquidity to effectively address market risks;

	•	our inability to fully eliminate the risks of commodity risk management activities;

	•	increased volatility in our quarterly and annual financial results due to accounting for derivative instruments;

	•	the extensive and possibly increasing environmental laws and regulations to which we are subject;

	•	the potential inadequacy of our insurance to cover losses resulting from risks and hazards inherent to the power industry;

	•	costs associated with maintenance requirements or mechanical failures at our facilities;

	•	reductions in the quality of fuel supply to our Fore River facility;

	•	the seasonal nature of the power generation industry;

	•	our dependence on transmission and distribution systems that we do not own or control;

	•	changes in the prices of our fuel supplies or failure by any of our fuel suppliers to deliver fuel to our plants;

	•	our dependence on a limited number of customers for the purchase of a substantial portion of our electric energy output;


	•	increased employee turnover in future periods due to our aging workforce;

	•	the possibility of strikes or work stoppages by our unionized employees;

	•	loss of executive officers and other key employees;

	•	acts of terrorism;

	•	our ability to remedy material weaknesses in our internal controls;

	•	the failure of historical financial information of our predecessors to be representative of operations as a combined company;

	•	costs associated with future repowering, expansion and acquisition activities;

	•	the failure to realize the expected benefits of the Combination; and

	•	the outcome of legal and regulatory proceedings.

The forward-looking statements made in this prospectus relate only to events as of the date on which the statements are made. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events, even if new information becomes available in the future. We note that the safe harbor for forward-looking statements provided by the Private Securities Litigation Reform Act of 1995 does not apply to statements made in connection with an initial public offering.

USE OF PROCEEDS

Our proceeds from the sale of shares of common stock in this offering will be approximately $ million, based on an initial public offering price of $ per share, the midpoint of the range set forth on the cover page of this prospectus, after deducting estimated underwriting discounts and expenses payable by us in connection with the offering. We will not receive any of the proceeds from the sale of shares by the selling stockholders in this offering. See “Principal and Selling Stockholders.”

We intend to use the net proceeds we receive from this offering to finance capital expenditures, including planned capital improvements and capacity expansions and for other general corporate purposes. In addition, we may, if circumstances warrant, use a portion of the net proceeds in lieu of the foregoing to repay a portion of our indebtedness. The terms of our credit facilities are described under “Description of Principal Indebtedness.”

DIVIDEND POLICY

We do not expect to pay dividends on our common stock for the foreseeable future. Instead, we anticipate that all of our earnings in the foreseeable future will be used to service and repay our existing indebtedness and in the operation and growth of our business. Any future determination to pay dividends will be at the discretion of our board of directors and will depend upon, among other factors, our results of operations, financial condition, capital requirements and contractual restrictions. In addition, USPowerGen is a holding company, and has no existing operations of its own. Therefore, USPowerGen would rely on distributions from its subsidiaries for any amounts payable to its stockholders. Restrictive covenants under our senior credit facilities limit the ability of our subsidiaries and, as a result, our ability, to declare and pay dividends or other distributions on our common stock.

CAPITALIZATION

The following table sets forth our consolidated cash and cash equivalents and our consolidated capitalization as of March 31, 2008 on an actual basis and an as adjusted basis giving effect to the use of proceeds from the shares sold by us in this offering. You should read this table in conjunction with “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and accompanying notes included elsewhere in this prospectus. This table gives effect to the completion of the conversion into Class A common stock of all shares of Class B common stock, and the conversion into common stock of all shares of Class A common stock.


	As of
	March 31, 2008
	Actual			As Adjusted
	($ in thousands, except share data)

Cash and cash equivalents	$	11,296		$

Long-term debt (including current maturities)⁽¹⁾:
Astoria credit facilities:
Astoria revolving loan		—
Astoria term loan B		326,400
Astoria term loan C		300,000
BG credit facilities:
BG revolving loan		41,500
BG term loan B		1,115,875
BG term loan C		350,000
EBG mezzanine loan facility		350,720
Other⁽²⁾		44,349

Total long-term debt		2,528,844

Stockholders’ equity:
Common stock, $0.00001 par value, 550,000,000 shares authorized; 76,608,600 shares issued and 76,408,890 outstanding, actual, shares issued and outstanding, as adjusted		—			—
Preferred stock, $0.00001 par value, voting rights may be designated upon issuance; 1,000,000 shares authorized, no shares issued and outstanding		—			—
Additional paid-in capital		1,466,075
Retained earnings		(330,737	)
Accumulated other comprehensive income		1,466

Total stockholders’ equity		1,136,804

Total capitalization	$	3,665,648		$


(1)		See “Description of Principal Indebtedness” for additional information regarding the terms of our outstanding indebtedness.
(2)		Reflects unamortized premium on EBG’s outstanding indebtedness that was initially recorded at the time of the Combination in connection with a fair value adjustment to such indebtedness due to the application of purchase accounting.

The number of shares of common stock shown in the table above assumes the effectiveness of a -for-1 stock split of our common stock, which will occur immediately prior to this offering, and the number of shares of common stock shown in the table above as issued and outstanding excludes 650,000 shares of our common stock issuable upon the exercise of outstanding warrants at an exercise price of $11.88 per share.

DILUTION

If you invest in our common stock, your interest will be diluted to the extent of the difference between the initial public offering price per share of our common stock and the net tangible book value per share of common stock upon completion of this offering.

As of March 31, 2008, our net tangible book value, which represents the amount of our total consolidated tangible assets minus the amount of our total consolidated liabilities, was approximately $ , or approximately $ per share. “Net tangible book value per share” represents our net tangible book value divided by the shares of our common stock outstanding at March 31, 2008. After giving effect to the sale of shares of our common stock in the offering at an assumed initial public offering price of $ per share, the midpoint of the range set forth on the cover of this prospectus, and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma net tangible book value as of March 31, 2008 would have been approximately $ , or approximately $ per share of our common stock. This represents an immediate increase in net tangible book value of $ per share to our existing stockholders and an immediate dilution in net tangible book value of $ per share to new investors purchasing shares of common stock in this offering.

The following table illustrates this dilution on a per share basis:


Assumed initial public offering price per share of common stock		$
Net tangible book value per share as of March 31, 2008	$
Increase per share attributable to the offering

Pro forma net tangible book value per share after this offering

Dilution in net tangible book value per share to new investors⁽¹⁾		$


(1)		Dilution is determined by subtracting pro forma net tangible book value per share after giving effect to the offering from the initial public offering price paid by a new investor.

Each $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) our pro forma net tangible book value by $ million, or $ per share, and the dilution in net tangible book value per share to investors in this offering by $ per share, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. The as adjusted information is illustrative only, and following the completion of this offering, will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.

If the underwriters exercise their over-allotment option in full, the pro forma net tangible book value as of will increase to approximately $ per share, representing an increase to existing stockholders of approximately $ per share, and there will be an immediate dilution of approximately $ per share to new investors.

The following table summarizes as of March 31, 2008 the differences between our existing stockholders and new investors with respect to the number of shares of our common stock sold in this offering, the total consideration paid and the average price per share paid. The calculations with respect to shares purchased by new investors in this offering reflect an assumed initial public offering price of $ per share, the midpoint of the range set forth on the cover of this prospectus, before deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us and gives effect to a -to-1 stock split to be effected prior to the completion of this offering:

Shares Purchased

Total Consideration

Average Price

Number

Percentage

Amount

Percentage

Per Share

Existing stockholders

New investors

Total

100

Each $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) total consideration paid by new investors, total consideration paid by all stockholders and the average price per share paid by all stockholders by $ million, $ million and $ , respectively. This information is illustrative only and, following the completion of this offering, will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.

If the underwriters exercise their over-allotment option in full, the following will occur:


	•	the percentage of shares of our common stock held by existing stockholders will decrease to approximately % of the total number of our common stock outstanding after this offering; and

	•	the number of shares of our common stock held by new public investors will increase to , or approximately % of the total number of shares of our common stock outstanding after this offering.

The tables and calculations above are based on shares outstanding as of March 31, 2008 and exclude 650,000 shares of our common stock issuable upon the exercise of outstanding warrants at a weighted average exercise price of $11.88 per share. To the extent that such warrants are exercised, your investment will be further diluted.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

We derived the following unaudited pro forma historical financial data by combining the 2007 audited consolidated financial data of USPowerGen and the unaudited financial data of EBG during 2007 prior to the Consolidation and applying pro forma adjustments. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2007 gives effect to the Combination, the effectiveness of the -for-1 stock split, which will occur immediately prior to this offering, and the pro forma effect of the sales of shares in this offering by us and the application of the net proceeds therefrom as if each occurred on January 1, 2007. The MDP Acquisition was effective February 23, 2006, the refinancing of all of EBG’s outstanding indebtedness (the “EBG Refinancing”) was effective on December 20, 2006, and the Combination was effective on June 1, 2007. We describe the assumptions underlying the pro forma adjustments in the accompanying notes, which should be read in conjunction with these unaudited pro forma financial statements.

The unaudited pro forma financial data is for informational purposes only and should not be considered indicative of actual results that would have been achieved had the transactions described herein been consummated on the date or for the periods indicated and do not purport to indicate combined balance sheet data or results of operations as of any future date or any future period. The unaudited pro forma financial data should be read in conjunction with the “Selected Historical Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the accompanying notes thereto included elsewhere in this prospectus.

US POWER GENERATING COMPANY
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
AS OF MARCH 31, 2008

($ in thousands)


			Offering
	As reported		Adjustments	Pro Forma

ASSETS
Current assets:
Cash and cash equivalents	$	11,296
Restricted cash		95,912
Accounts receivable		176,117
Derivative assets		8,509
Fuel inventory, materials and supplies		34,603
Deferred income taxes		28,055
Prepaid expenses and other current assets		35,988

Total current assets		390,480
Property, plant, and equipment, net		3,496,226
Other assets:
Goodwill		579,026
Other intangibles, net		78,105
Emissions allowances, net		130,441
Derivative assets		90
Deferred financing costs		21,625
Other long-term assets		19,225

Total assets	$	4,715,218


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	91,334
Fuel payable		98,844
Accrued transaction costs		32,400
Other current liabilities		5,268
Derivative liabilities		45,251
Revolving line of credit		41,500
Current portion of long-term debt		15,600

Total current liabilities		330,197
Other liabilities:
Derivative liabilities		62,887
Pension and postretirement obligations		19,283
Deferred income taxes		679,990
Asset retirement obligations		9,112
Other long-term liabilities		5,201
Long-term debt		2,471,744

Total liabilities		3,578,414
Total stockholders’ equity		1,136,804

Total liabilities and stockholders’ equity	$	4,715,218

US POWER GENERATING COMPANY
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2007


	Successor			EBG
	Year Ended
	December 31,			January 1 to			Combination			Offering	USPowerGen
	2007			May 31, 2007			Adjustments			Adjustments	Pro Forma
	($ in millions, except per share amounts)

Statement of Operations Data:
Revenues	$	1,182.7		$	465.2		$	—		$	$
Operating expenses:
Fuel		779.0			315.5			6.4	(a)
Operations and maintenance		106.2			37.4			—
General and administrative		64.4			12.9			—
Taxes, other than income		41.6			8.7			—
Depreciation		82.3			11.1			27.2	(b)

Operating (loss) income		109.2			79.6			(33.6	)
Other expense (income):
Interest expense (income), net		203.5			69.7			(4.6	)(c)
Other		3.9			(1.2	)		—

Total other expenses		207.4			68.5			(4.6	)

(Loss) income before income taxes		(98.2	)		11.1			(29.0	)
Income tax expense (benefit)		(35.9	)		—			(5.4	)(d)

Net (loss) income	$	(62.3	)	$	11.1		$	(23.6	)	$	$

(Loss) income per share
Basic and diluted											$
Shares used to compute (loss) income per share(e)
Basic and diluted


(a)		Adjustment reflects: (i) $3.2 million of additional fuel expense; (ii) $2.5 million of amortization of contractual obligations; and (iii) $0.7 million of emission credit amortization for the five months ended May 31, 2007, all as a result of the fair value adjustments in connection with the Combination.

(b)		Adjustment reflects $27.2 million additional depreciation expense for the five months ended May 31, 2007 as a result of the fair value adjustment of plant, property and equipment in connection with the Combination.

(c)		Adjustment reflects $4.6 million decrease in interest expense for the five months ended May 31, 2007 related to: (i) a $2.8 million elimination of deferred financing cost amortization and (ii) a $1.8 million decrease in interest expense in connection with the fair value adjustment of the debt assumed in connection with the Combination.

(d)		To reflect the income tax effect of the pro forma adjustments using a combined federal, state and local statutory rate of approximately 35.6% for the year ended December 31, 2007.

(e)		Basic and diluted (loss) income per share is net (loss) income available to common stockholders divided by the weighted average number of common shares outstanding during the period.

		The number of weighted average common shares outstanding was derived based on an IPO-split share equivalent basis for the Successor periods. For the Predecessor periods, IPO-split adjusted weighted average number of common shares outstanding at the time of the MDP Acquisition was used.

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth our summary consolidated financial data as of and for the periods indicated. The selected financial data as of and for the years ended December 31, 2007 and 2006 have been derived from the audited consolidated financial statements of the Successor. The selected financial data as of and for the years ended December 31, 2005, 2004 and 2003 and for the period from January 1, 2006 through February 23, 2006 have been derived from the historical consolidated financial statements of the Predecessor. The financial statements of the Successor and Predecessor, except as of and for the years ended December 31, 2004 and 2003, have been audited by KPMG LLP, an independent registered public accounting firm. Astoria had limited activity from January 1, 2006 to February 23, 2006. The selected unaudited financial data as of and for the three months ended March 31, 2008 and 2007 have been derived from our unaudited consolidated financial statements for such periods and date which appear elsewhere in this prospectus, and such financial data contains all adjustments, consisting solely of normal recurring adjustments, that, in the opinion of management, are necessary for their fair statement. Historical results are not necessarily indicative of the results expected in the future and results for an interim period are not necessarily indicative of results for a full year.

The accompanying financial information for the year ended December 31, 2006, and for the period from February 24, 2006 through December 31, 2006, reflects the consolidated financial position, results of operations and cash flows of the Successor subsequent to the date of the MDP Acquisition and includes adjustments required under the purchase method of accounting. In accordance with the requirements of purchase accounting, the assets and liabilities of the Successor were adjusted to their estimated fair values and the resulting goodwill was recorded as of the transaction date. The application of purchase accounting generally results in higher depreciation and amortization expense in future periods. Accordingly, the accompanying consolidated financial information of the Successor and Predecessor are not comparable in all material respects because of the effects of purchase accounting.

Prospective investors should read the data presented below together with, and qualified by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the accompanying notes thereto included elsewhere in this prospectus.


	Successor									Predecessor⁽¹⁾
										January 1,
										2006 to
	Three Months Ended March 31,					Year Ended December 31,				February 23,		Year Ended December 31,
	2008			2007		2007⁽²⁾		2006⁽³⁾		2006		2005			2004			2003
	(Unaudited)
	($ in millions, other than share data)
Statement of Operations Data:
Revenues	$	489.3		$	112.4	$	1,182.7	$	480.5	$	104.7	$	1,014.0		$	625.8		$	549.1
Operating expenses:
Fuel		333.9			60.3		779.0		258.9		50.7		555.2			318.5			257.6
Operations and maintenance		29.7			15.0		106.2		63.1		21.7		94.0			64.9			69.3
General and administrative		14.6			8.8		64.4		26.0		1.4		6.6			4.2			4.1
Taxes, other than income		12.6			7.2		41.6		35.8		5.7		33.8			36.9			35.8
Depreciation		30.4			7.1		82.3		22.9		5.9		38.8			42.1			39.3
Impairment of goodwill		250.1			—		—		—		—		—			—			—

Operating (loss) income		(181.9	)		14.0		109.3		73.7		19.4		285.6			159.2			143.0
Other expense (income):
Interest expense (income), net		87.0			15.8		203.5		55.2		0.2		(2.1	)		(0.1	)		—
Other		(0.7	)		—		3.9		0.9		—		—			—			—

Total other expenses		86.3			15.8		207.4		56.1		0.2		(2.1	)		(0.1	)		—


	Successor												Predecessor⁽¹⁾
													January 1,
													2006 to
	Three Months Ended March 31,						Year Ended December 31,						February 23,			Year Ended December 31,
	2008			2007			2007⁽²⁾			2006⁽³⁾			2006			2005			2004			2003
	(Unaudited)
	($ in millions, other than share data)
(Loss) income before income taxes		(268.2	)		(1.8	)		(98.1	)		17.6			19.2			287.7			159.3			143.0
Income tax expense (benefit)		(4.3	)		—			(35.9	)		0.7			0.7			11.5			7.5			6.6

Net (loss) income	$	(264.0	)	$	(1.8	)	$	(62.3	)	$	16.9		$	18.4		$	276.2		$	151.8		$	136.4

(Loss) income per common share⁽⁴⁾:
Basic and diluted	$	(0.48	)	$	(0.01	)	$	(0.15	)	$	0.07		$	0.07		$	1.10		$	0.60		$	0.54
Shares used to compute (loss) income per share⁽⁴⁾:
Basic and diluted		545.4			252.2			423.2			252.2			252.2			252.2			252.2			252.2
Other Financial Data:
Capital expenditures	$	13.8		$	14.4		$	49.0		$	39.4		$	5.5		$	17.6		$	13.3		$	22.1
Cash flows provided by (used in):
Operating activities		1.6			20.9			141.6			120.0			24.7			230.8			176.1			194.9
Investing activities		(10.0	)		(14.4	)		(94.0	)		(1,039.7	)		(5.5	)		(17.6	)		(13.3	)		(22.1	)
Financing activities		(14.6	)		(23.5	)		(57.7	)		964.2			(18.8	)		(214.7	)		(197.5	)		(143.6	)
Balance Sheet Data (at end of period):
Cash and cash equivalents	$	11.3		$	27.6		$	34.4		$	44.5		$	0.5		$	—		$	1.6		$	36.2
Total assets		4,715.2			1,068.6			5,004.5			1,104.6			2,097.8			2,082.6			1,786.3			1,640.7
Total debt		2,528.8			670.7			2,531.7			691.8			—			—			—			—
Total equity		1,136.8			323.9			1,409.0			326.8			2,025.8			2,006.7			1,713.0			1,564.7


(1)		Prior to the MDP Acquisition, the Predecessor operated as a subsidiary of Reliant.

(2)		The statement of operations for the fiscal year ended December 31, 2007 includes results of operations of EBG from June 1, 2007 (the date of the Combination).

(3)		The statement of operations for the fiscal year ended December 31, 2006 includes the results of operations for the Successor from February 24, 2006, the date of the MDP Acquisition through December 31, 2006. Astoria had limited activity from January 1, 2006 through February 23, 2006.

(4)		Basic and diluted (loss) income per common share is net (loss) income available to common stockholders divided by the weighted average of common shares outstanding during the period.

		Weighted average common shares outstanding were derived based on an IPO-split share equivalent basis for the Successor periods. For the Predecessor periods, IPO-split adjusted weighted average common shares outstanding at the time of the MDP Acquisition were used.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion together with “Selected Historical Financial Data,” and the historical financial statements and related notes included elsewhere in this prospectus. The statements in this discussion regarding industry outlook, our expectations regarding our future performance, liquidity and capital resources and other non-historical statements in this discussion are forward looking statements. These forward looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described in “Risk Factors” and “Forward-Looking Statements.” Our actual results may differ materially from those contained in or implied by any forward looking statements.

Overview

We are a wholesale power generation company that owns and operates electric power generation facilities located in New York City and the Boston metropolitan area. We have a portfolio of 58 generating units at six facilities, with a seasonally adjusted generation capacity of approximately 5,223 MW. We can generate sufficient power to serve approximately 20% of the summer peak load in New York City and approximately 31% of the summer peak load in eastern Massachusetts. We generate revenues by selling electric energy, capacity and ancillary services, which accounted for approximately 76.3%, 18.8% and 1.2%, respectively, of our pro forma revenues in the year ended December 31, 2007 (giving effect to the combination of Astoria and EBG as if it occurred on January 1, 2007), and approximately 75.1%, 14.4% and 1.9%, respectively, of our revenues for the three months ended March 31, 2008.

Our New York Facilities operate in and generate electricity for New York City’s power market, which is administered by NYISO. Our Boston Facilities operate in and generate electricity for the Boston metropolitan area power market, which is administered by ISO-NE. Each of NYISO and ISO-NE, in conjunction with FERC, are responsible for establishing and implementing rules and procedures regarding the transmission and sale of electric energy. NYISO and ISO-NE each administer centrally dispatched day-ahead and real-time energy, capacity and ancillary service markets. In each of these markets, electric energy is produced by generation facilities and sold for transmission and distribution to consumers of electricity.

USPowerGen, the issuer of the common stock being sold in this offering, is a Delaware corporation formed in February 2007 to facilitate the merger of Astoria and EBG, which was effected on June 1, 2007, and resulted in each of the entities that own our New York Facilities and Boston Facilities becoming a wholly-owned subsidiary of USPowerGen. The Combination was effected to leverage, under a common management team, the complementary nature of the two asset portfolios, including each being located in a market that we believe is characterized by expected high demand growth, well-established capacity markets and significant costs for new entry, as well as each portfolio having significant dual fuel capability.

Factors Affecting Our Operating Results

Prices of Electric Energy and Capacity

In the year ended December 31, 2007 and the three months ended March 31, 2008, approximately 76.3% and 75.1%, respectively, of our revenues (which revenues for the year ended December 31, 2007 give effect to the combination of Astoria and EBG as if it occurred on January 1, 2007) were derived from sales of electric energy. Fluctuations in electric energy prices are driven by several factors, including: seasonal, daily and hourly changes in demand for electricity, instances of extreme peak energy demand, price and availability of fuel supply, electric transmission availability and reliability within and between regions, procedures used to maintain the integrity of the overall electricity generation and transmission system during extreme conditions and the number of generating units undergoing maintenance (scheduled or unscheduled). The amounts of and prices at which we sell electric energy are determined by auctions administered by NYISO and ISO-NE. The price at which we bid our electricity into these auctions can vary and are determined, in large part, by our cost of production. Both NYISO and ISO-NE calculate electric energy prices and dispatch generation using a locational marginal pricing model, which is based on the premise that, in the absence of any transmission losses and transmission constraints, the least costly way of generating electric energy is achieved when

demand is satisfied starting with the lowest cost megawatt-hour offered, and the last megawatt-hour needed to meet demand sets the price at which all generators supplying electric energy receive compensation. In addition, prices for electric energy in NYISO are affected by the transmission constraints within New York City, each of which usually results in higher electric energy prices in New York City relative to the rest of New York state (and even higher prices within certain sub-load pockets within New York City relative to the rest of New York City).

During the year ended December 31, 2007 and the three months ended March 31, 2008, approximately 18.8% and 14.4%, respectively, of our revenues (which revenues for the year ended December 31, 2007 give effect to the combination of Astoria and EBG as if it occurred on January 1, 2007) were derived from sales of capacity. Capacity payments supplement the revenues earned by generators in sales of electric energy in energy markets. The capacity market offers a relatively predictable and recurring source of revenues designed to provide the necessary incentive for construction of new facilities and continued operation of older facilities. Generating units are eligible to receive capacity payments regardless of how often they are dispatched to generate energy. Capacity markets are indifferent to the efficiency of an operating unit so long as the unit is available when needed to maintain desired electricity generation levels, resulting in generally predictable capacity revenues for all units, including those dispatched only during periods of peak demand. In New York City, where there are constraints on the ability to transmit power into the city from outside the city, as well as constraints on transmitting power within the city, capacity payments sometimes represent the primary source of revenues for generators. The prices at which we sell capacity are determined by auctions, or, in the case of ISO-NE capacity sales through May 2010, a fixed-price schedule, administered by NYISO and ISO-NE. Capacity auction prices in NYISO are set by a demand curve mechanism. As a result of recent changes in the NYISO capacity market structure, described herein under “— NYISO Changes to Market Structure,” the financial counterparty to our fixed-price capacity contract has modified payments to us, exposing us to the NYISO market clearing price for capacity, rather than our continuing to receive the fixed price of $7.07 per kW-month under the contract. The effect of this modification is that we expect to receive the auction-based capacity price from NYISO through the termination of the contract in April 2009. This auction-based capacity price may be less than those reflected in the historic results discussed herein until the supply/demand balance tightens in the New York in-city market. If the supply/demand balance tightens in the New York in-city market, revenues from capacity payments would increase and may significantly exceed the historic results presented herein, largely as a result of the $105 per kW-year cap being removed as part of the recent changes to the NYISO market structure.

Demand for Electric Energy and Supply of Generation Capacity

Fluctuations in demand for electric energy, retirement of existing capacity and development of new capacity (or lack thereof) generally leads to changes in electric energy prices. From 1997 to 2007, peak demand in the New York City market and the New England market grew by a compound annual growth rate of 1.3% and 2.6%, respectively. In 2006, additional generating capacity of approximately 1,000 MW was introduced into Zone J of the NYISO market (one of the most transmission-constrained power markets in the United States), which has created a temporary capacity surplus. The expected retirement of an existing 885 MW facility at the New York Power Authority Poletti station (due to be retired by January 31, 2010), together with anticipated continued peak demand growth of approximately 100 to 200 MW per year within Zone J, will eventually eliminate this surplus and create the need for additional capacity.

Operating Expenses

Our operating expenses consist primarily of fuel expense and operations and maintenance expenses. Approximately 60% of our generating capacity, including 78% of our New York City generating capacity, have dual fuel capability, and when market conditions permit, we are able to use the lower cost fuel. Although availability is generally not an issue, localized shortages, transportation limitations and supplier financial stability issues can and do occur. We procure fuel for our facilities primarily through long-term contracts with third parties that either provide or procure fuel based primarily on market prices, and we procure the remainder of our fuel requirements through short-term contracts or spot market purchases. Therefore, our

operating expenses will increase based on increases in the market price of fuel, and electric energy prices may or may not correspondingly increase.

In addition to fuel expense, our operating expenses are impacted by the timing and nature of our maintenance activities, in particular as they relate to outage-related expenditures. We conduct both planned and unplanned maintenance work during generating unit outages, so periods during which we are conducting maintenance will incur higher operating expenses and work that is more extensive in scope will necessarily result in increased operating expenses. Further, our Mystic and Fore River facilities operate under a long-term services agreement under which some outage related expenses are accrued in accordance with Financial Accounting Standards Board (“FASB”) Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance Activities as the facilities produce electricity. However, the maintenance expense is only reflected in our results of operations in the period that the actual maintenance work is performed. The accounting for maintenance conducted under the long-term services agreement can add significant variability to our operating expenses and results of operations.

Derivative Instruments

To manage the risks inherent in the sale of electric energy and fuel procurement as well as seasonal variations in capacity payments, we enter into derivative instruments. We utilize a variety of derivative instruments, including forward contracts, futures contracts, swaps and options. The time periods during which our derivative instruments are effective vary according to the requirements of our credit facilities, our ability to find favorably priced long-term derivative instruments and our beliefs about the future state of the electric energy, fuel and capacity markets. EBG has entered into derivative instruments relating to electric energy for approximately 100% of the seasonally adjusted generation capacity of the Mystic 8&9 and Fore River facilities through December 31, 2010. Astoria has entered into derivative instruments relating to electric energy for 300 to 600 MW (varying by month) of its summer generation capacity in 2008 and 2009 and a derivative instrument related to capacity equal to approximately 78% of its seasonally adjusted generating capabilities through April 2009. At this time, we do not expect to renew Astoria’s current derivative instrument related to capacity or to enter into future capacity-based derivative instruments in NYISO or ISO-NE.

Although our payment obligations to derivative instrument counterparties are designed to approximate net revenues that we earn from our generating assets through market sales, our net revenues from operations often do not match these payment obligations, which may result in losses. We do not apply hedge accounting under SFAS 133 and therefore, our derivative instruments are required to be recorded at the end of each period on our balance sheet at fair value, with changes in the fair value resulting from fluctuations in the underlying commodity prices being immediately recognized in our earnings for the preceding period. As a result, we may experience earnings volatility due to accounting for our derivative instruments. See “Risk Factors — Risks Related to Our Business — Accounting for derivative instruments will increase the volatility in our quarterly and annual financial results.”

Our risk management policy seeks to provide cash flow stability by managing our exposure to market price risk, particularly those related to changing electric energy prices. Our risk management strategy is to contract for highly structured long-term derivative instruments when favorable prices are available. We also plan to engage in short-term “active” risk management strategies based on our portfolio exposure in various time horizons. We intend to continue to use energy derivative instruments and explore other opportunities to mitigate our risk and exposure to the uncertainties of energy markets. The energy-related derivative instruments recently entered into at Astoria were opportunistically identified and negotiated based on market conditions. These derivatives are typical of our “active” risk management strategy in that they are relatively short in duration, and are for a quantity significantly less than the generating capability of the associated assets. In addition, as a result of agreements with lenders, we are in some instances required to enter into derivative instruments that are not wholly consistent with our risk management strategy. For example, the derivative instruments in effect at EBG, which are required by the EBG credit facilities, are longer in duration and larger in size than those we normally seek pursuant to our risk management policy. See “— Quantitative and Qualitative Disclosure About Market Risk — Energy and Capacity Price Risk.”

Generating Unit Efficiency and Availability

The amount of electric energy we can generate and sell into our markets, and the prices at which we can sell our electric energy, capacity and ancillary services, is dependent on the availability and efficiency of our generating units. If our units are not able to produce electric energy as efficiently as they have in the past, our operating expenses will increase and we may earn lower margins on our sales or we may not be able to sell our electric energy or other products at all. From time to time, we must shut generating units down to perform maintenance or repairs. Generally, maintenance is scheduled during periods when demand for power is lowest. Occasionally, it is necessary to shut units down for maintenance or repair during periods of high power demand. Any outages, whether scheduled or unscheduled, will usually result in a reduction in our sales.

Competitive Conditions

Wholesale power generation is a commodity-based, capital-intensive business that is subject to long-term industry cycles. Our competitors may use different fuels and/or technologies that allow them to generate electric energy more efficiently than us or earn government subsidies, which may allow them to bid into our markets at lower prices, decreasing the hours during which our units can be economically dispatched. We expect that either existing or potentially new competitors will compete to add capacity in our markets by adding new units at existing sites, repowering older equipment or siting new transmission lines, which will continue to shift the supply/demand balance in our markets. Any new supply of electricity may have the effect of decreasing prices at which electric energy is sold.

Changes in Weather Conditions

Extreme high and low temperatures in our service area have a significant impact on our revenues, since end-users increase their use of electricity in warm and cold weather. We derive a majority of our annual revenues in the months of May through September, when demand for electricity is the highest in our markets. Further, electricity price volatility is generally higher in the summer months. The winter months of December through February are also characterized by volatility and price spikes in underlying fuel prices, which have tended to drive variability in energy prices. In addition, our results may vary from year to year based on changes in average temperatures. Storm activity can have an adverse effect on our operating performance since severe storms may impair fuel availability and damage transmission and distribution equipment, which can cause power outages, and thereby reduce revenues.

Changes in Federal, State and Local Regulations

We are subject to extensive regulation at the federal, state and local levels in both of our markets. We are substantially affected by the EPA, FERC and the North American Electric Reliability Corporation (“NERC”) at the federal level and the New York Public Service Commission (“NYPSC”), NYSDEC, the Massachusetts Department Of Energy Resources (“MADOER”), MassDEP and the Massachusetts Department of Public Utilities (“MADPU”) at the state level. We are also subject to numerous environmental regulations in the development, ownership, construction and operation, as well as the decommissioning or closure of projects. An inherent business risk facing any company such as ours is that of unexpected or adverse regulatory action, or compliance with known regulatory actions, that require significant expenditures or that change the manner in which (or prices for which) our electric energy and other products are sold. In addition, failure to comply with current regulations could lead to substantial penalties and/or significant capital expenditures.

NYISO Changes to Market Structure

NYISO). Under the terms of the approved plan, the bid and revenue cap previously imposed on our New York Facilities as a result of our status as a DGO, or an owner of facilities divested in 1999 by Con Ed, have been removed. However, the approved plan imposes a new bid cap on our New York Facilities. The new bid cap is equal to the higher of: (i) the market clearing price on NYISO’s administratively set installed capacity demand curve on the basis of which all qualified in-city capacity is sold; and (ii) the marginal generating unit’s net avoided costs achieved by removing the unit from operations but maintaining the unit in operating condition. Additionally, NYISO implemented market power mitigation measures to discourage future construction of uneconomic generation capacity that would artificially reduce capacity prices below just and reasonable levels. The revised market rules are being implemented prospectively, without refunds to market participants.

In the near term, we believe the market changes may substantially reduce capacity prices in Zone J within New York City because the new market rules ignore the 1,000 MW of recently constructed facilities in Zone J. However, we also believe the expected retirement in 2010 of the 885 MW New York Power Authority Poletti power generation station is likely to reduce the current surplus of capacity, leading to an increase in Zone J capacity prices at that time. We believe the market changes are likely to produce a more predictable capacity market, and that the removal of the DGO revenue caps will in the future increase the prices at which capacity is permitted to be sold by our New York Facilities.

In addition, we are party to a capacity swap that effectively exchanges a substantial portion of our installed capacity spot market auction payments for a fixed payment. The fixed payment to us from the counterparty on an annual basis is substantially higher than the payments that would likely result from the projected NYISO market clearing price. This contract has a stated maturity of April 30, 2009, and contains provisions that provide for modification or early termination upon certain significant regulatory changes. On May 7, 2008, we received notification from the counterparty that it interprets recent regulatory developments to trigger modification of the pricing provisions within the contract, and the counterparty has adjusted its payments to Astoria effective May 1, 2008. As a result of these modifications, we may be exposed to the NYISO market clearing price for capacity. See “Risk Factors — Risks Related to Our Business — A substantial portion of our revenues come from sales of capacity, and therefore our financial performance may be impacted by structural changes and price fluctuations in capacity markets.”

ISO-NE Changes to Capacity Market Pricing

Due to regulatory changes to the ISO-NE capacity market that became effective December 1, 2006, power generators in that market such as EBG can sell capacity as part of a FERC-approved FCM settlement. The settlement provides for capacity to be sold at fixed prices through May 2010 and at auctions within price collars for a period of time thereafter. We cannot predict the prices at which capacity will be sold in future auctions. Capacity prices in the first auction, held in February, 2008, for the 2010 capacity year, were set at the regulatory floor of $4.50 per kW-month. More capacity was bid into the auction than was required. This resulted in downward pressure on the final price set by the auction. We will therefore receive less capacity revenues for the 2010 period than we could have if there had not been an oversupply of capacity in the auction.

Components of Our Operating Results

The following discussion describes certain of the line items in our consolidated statements of operations as well as certain operating performance measures that we utilize.

Revenues. We generate revenues principally from the sale of electric energy and capacity, which are impacted by our risk management activities, and ancillary services to the ISO for the markets that we serve.


	•	Electric energy revenues are earned by selling electricity into the ISO markets in which we operate, which involves generating electricity and delivering it to the ISO transmission and distribution grid.

	•	Capacity revenues are derived primarily from forward capacity sales to the ISOs. Capacity is purchased by load serving entities who must ensure the availability of generating capacity sufficient to meet their


		peak load operating requirements plus a reserve. We receive capacity revenues whether or not our plants are dispatched to produce electricity.


	•	Risk management activities relate to realized and unrealized gains and losses associated with derivative instruments used to mitigate price volatility inherent in the sale of electric energy and fuel procurement. Due to the nature of these derivative instruments, they do not qualify for hedge accounting treatment in accordance with the requirements of SFAS 133. As a result, we are required at the end of each quarterly period to estimate the fair market value of our existing contracts for derivative instruments and immediately record any change in their fair market value as an unrealized gain or loss in our results of operations for that period. Consequently, recording changes in the fair market value of derivative instruments can cause significant period-to-period fluctuations in our financial results. Because most of the risk management activities are intended to mitigate the risk of price fluctuations on revenues and fuel costs, the changes in these results should not be viewed in isolation, but rather taken together with the effects of pricing and cost changes on gross margin.

	•	Ancillary revenues are derived from the sale of the ancillary services that we offer to the ISOs, which include:


	•	automatic generation control, which is used by the ISO to balance energy supply with system load requirements in real time;

	•	operating reserves, which is generation available to generate additional electric energy within a designated time period to meet unexpected increases in demand or in place of electric energy generating units in the event such units or transmission facilities become unavailable;

	•	reactive supply and voltage support, to maintain voltages on the transmission and distribution system within acceptable limits; and

	•	black-start capability, which is the capability of a generating facility to start-up and synchronize to the electrical system without reliance on external energy sources.

Operating Expenses. Operating expenses include fuel expense, operations and maintenance expense, depreciation expense, taxes other than income and general and administrative expenses.


	•	Fuel expense reflects the cost to purchase and transport natural gas and fuel oil for our generation plants. Fuel expense also includes fuel contract and emissions allowance amortization. We procure all of our day-ahead natural gas and all fuel oil for the New York Facilities and our Fore River facility from Sequent Energy Management L.P. (“Sequent”), which procures fuel pursuant to a fuel management agreement that we have entered into with them. Sequent also at times provides fuel for the Mystic Station facility. Pricing for natural gas and fuel oil purchased from Sequent pursuant to this agreement is based on published indices for natural gas and fuel oil. We procure natural gas for our Mystic facilities pursuant to various agreements with Distrigas that obligate us to purchase, and Distrigas to provide, a minimum quantity of natural gas. The Mystic 8&9 facility receives all of its natural gas requirements from the adjacent natural liquified gas terminal facility of Distrigas pursuant to a long-term natural gas supply agreement. We are required to pay certain liquidated damages if we do not purchase our obligated quantity of natural gas for any period.

	•	Operations and maintenance expenses reflect the costs of plant employee salaries and benefits, production costs typically associated with materials and services, routine maintenance of our plants and expenses related to planned outages.

	•	Depreciation expense consists of depreciation of our property, plant and equipment based on management’s estimates and determinations of the assets’ economical useful lives.

	•	Taxes other than income consists primarily of property taxes.

	•	General and administrative expenses. Our general and administrative expenses consist of salaries of our corporate personnel, rent for our corporate office, insurance, information technology costs and other administrative expenses.

Derivative Instruments. The impact of our derivative instruments are reflected in the following components of our operating results: (i) electric energy revenues; (ii) capacity revenues; (iii) risk management activities; and (iv) fuel expense. We make these classifications depending upon the nature of the derivative instruments being recorded. We record settled risk management transactions and the unrealized gains and losses on mark-to-market (“MTM”) valuations of our commodity index priced derivative instruments, such as forward sales of electric energy and future purchases of natural gas, within their respective line items (i.e., electric energy revenues or fuel expense). We record settled risk management transactions and unrealized gains and losses on MTM valuations related to our capacity derivative instruments in capacity revenues. Settled risk management transactions and unrealized gains and losses on MTM valuations related to derivatives where the revenues and cost components are not separable, such as our spark spread hedges, are presented in risk management activities. See “— Quantitative and Qualitative Disclosures about Market Risk — Energy and Capacity Price Risk.”

Gross Profit. Gross profit is measured by deducting cost of revenues from revenues. Gross profit is considered a key operating metric as its changes measure the effect of movements in sales volumes and pricing compared to the variable and fixed costs required to generate and deliver electricity to the ISO.

Electric Energy Revenues Net of Fuel Expense. We use electric energy revenues net of fuel expense as a measure of our operating performance. We believe that electric energy revenues net of fuel expense is a useful measurement of our performance because it provides information that can be used to evaluate our operational performance. We have included the analysis in this section as a complement to the financial information provided in accordance with U.S. generally accepted accounting principles (“GAAP”). Electric energy revenues net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this section. Electric energy revenues net of fuel expense is measured by deducting the fuel expense from electric energy revenues and is expressed as a dollar amount and as a percentage of electric energy revenues, or the revenues net of fuel margin. Revenues net of fuel are primarily impacted by the price of energy sold, relative to the cost of fuel, and the volume of electric energy generated.

Interest Expense. Interest expense is comprised of current pay interest, non-current pay interest, amortization of deferred financing costs, amortization of the fair value adjustment of the outstanding debt of EBG assumed in the Combination, settlements on interest rate swaps and unrealized gains and losses on the MTM valuation of interest rate swaps.

Income Tax Expense (Benefit). Income tax provision includes U.S. federal, state and local income taxes and is based on pre-tax income or loss. The interim period provision or benefit from income taxes is based upon our estimated annual effective income tax rate. In determining the estimated annual effective income tax rate, we analyze various factors, including projections of our annual earnings and taxing jurisdictions in which earnings will be generated, the impact of state and local income taxes and our ability to use tax credits. From the date of the MDP Acquisition, February 23, 2006, until the effective date of the Combination, June 1, 2007, we were a limited liability company with no state or federal income tax obligations and we did not have any interest and penalties on income taxes in any of the periods presented.

Basis of Presentation

On February 23, 2006, Astoria, a newly formed holding company controlled by Madison Dearborn, completed the MDP Acquisition. The financial information as of and for the year ended December 31, 2005 and as of February 23, 2006 and for the period from January 1, 2006 to February 23, 2006 set forth in this section have been derived from the combined financial statements of the Astoria Generating Company, L.P. and Orion Power Operating Services Astoria, Inc. We use the term “Predecessor” to collectively refer to Astoria Generating Company, L.P. and Orion Power Operating Services Astoria, Inc. for periods prior to the MDP Acquisition and the term “Predecessor Period” to refer to the period from January 1, 2006 to February 23, 2006.

Prior to the MDP Acquisition, our business was operated through wholly-owned subsidiaries of Reliant. As a result, the combined financial information of the Predecessor included in this prospectus is presented on

a carve-out basis and reflects the assets, liabilities, revenues and expenses that were attributed or allocated to it as a business unit of Reliant. The historical financial results in the combined financial statements presented may not be indicative of the results that would have been achieved had the Predecessor operated as a stand-alone entity during this period. These combined financial statements include costs for certain functions and services performed by centralized Reliant organizations and directly charged to the Predecessor based on usage. The combined statements of operations for the Predecessor include allocations of certain expenses of Reliant, including general corporate overhead, insurance, stock compensation and pension plans, royalty fees, facilities and other expenses. These allocations were based on a variety of factors.

The MDP Acquisition was accounted for using the purchase method of accounting in accordance with SFAS 141. As a result, we allocated the aggregate acquisition consideration to the tangible and intangible assets acquired and liabilities assumed based on their respective fair values estimated as of the date of the MDP Acquisition, which resulted in a significant decrease in the accounting bases of some our tangible and intangible assets. In addition, due to the effects of the increased borrowings to finance the MDP Acquisition, our interest expense has increased significantly in periods following the MDP Acquisition. As a result, the financial information for periods beginning on or after February 23, 2006 for the Successor may not be comparable to the financial information of the Predecessor for periods prior to this date.

On June 1, 2007, USPowerGen became the parent holding company of Astoria and EBG in the Combination. Astoria was determined to be the accounting acquirer of EBG in accordance with SFAS 141. As a result, the historical operating results of Astoria and the Predecessor are set forth in this prospectus for all periods presented prior to the Combination. In accordance with SFAS 141, we allocated the aggregate acquisition consideration for EBG to the tangible and intangible assets and liabilities acquired by USPowerGen based on their respective fair values as of the date of the Combination. See Note 3 of our consolidated financial statements included elsewhere in this prospectus for further details regarding the Combination.

We use the term “Successor” to collectively refer to (i) Astoria for the periods subsequent to the MDP Acquisition and prior to the Combination and (ii) USPowerGen and its consolidated subsidiaries for periods following the Combination. The financial information as of and for the year ended December 31, 2006 set forth in this section has been derived from the combined financial statements of Astoria and EBG. The financial information for the year ended December 31, 2007 reflect the consolidation of USPowerGen and include the results of operations of EBG for the period beginning January 1, 2007 and ending May 31, 2007. The financial information for the three months ended March 31, 2008 reflect the consolidated results of operations of Astoria and EBG under USPowerGen.

Management believes that the most meaningful way to discuss our statements of operations for the periods ended March 31, 2008 and 2007 is to compare (i) the Successor’s results of operations for the three months ended March 31, 2008 with (ii) the mathematical addition of the Successor’s results of operations for the three months ended March 31, 2007 and the results of operations of EBG for the same period provided in the supplemental discussion, which we refer to as our adjusted results. We believe that the most meaningful way to discuss our statements of operations for the periods ended December 31, 2007 and 2006 is to compare (i) the mathematical addition of the Successor’s results of operations for the year ended December 31, 2007 and the results of operations for EBG for the period from January 1, 2007 to May 31, 2007 with (ii) the mathematical addition of the Successor’s results of operations for the year ended December 31, 2006 and the Predecessor’s results of operations for the Predecessor Period and the EBG results of operations for the year ended December 31, 2006. We believe that presenting the discussion and analysis of the results of operations in this manner promotes the overall usefulness of the comparison given the complexities involved with comparing two significantly different periods. At the same time, we believe that it enables the reconciliation of the discussion and analysis to the statement of operations information provided herein. In addition, we have provided a separate discussion of the results of operations of EBG for the three months ended March 31, 2008 and 2007 and the years ended December 31, 2007 and 2006.

Results of Operations

Three Months Ended March 31, 2008 compared to Adjusted Three Months Ended March 31, 2007

The table below sets forth our results of operations for the three months ended March 31, 2008 on an actual basis and our adjusted results of operations for the three months ended March 31, 2007, which has been calculated by adding our results of operations for the three months ended March 31, 2007 with the results of operations of EBG for the same period. We have included the adjusted financial information in order to facilitate a comparison of our results of operations for comparable periods and operating assets. This presentation is not consistent with GAAP, and may yield results that are not strictly comparable on a period-to-period basis primarily due to the impact of required purchase accounting adjustments for the Combination. Such results are not necessarily indicative of what the results for the respective periods would have been had the Combination not occurred. All references to the three months ended March 31, 2007 in the following discussion are based on the as adjusted information presented in the table below. The purpose of presenting this table is to provide a convenient reference for the discussion of the results of operations that follows due to the significant effects of these events on the comparability of the periods.


										Combined
										Successor / EBG
	Successor						EBG			Three Months
	Three Months			Three Months			Three Months			Ended
	Ended			Ended			Ended			March 31,
	March 31,			March 31,			March 31,			2007
	2008			2007			2007			as Adjusted
	($ in thousands)

Revenues
Electric energy revenues	$	367,612		$	65,437		$	178,428		$	243,865
Capacity revenues		70,604			43,115			26,884			69,999
Risk management activities		41,585			1,839			50,295			52,134
Ancillary revenues		9,513			2,000			642			2,642

Total revenues		489,314			112,391			256,249			368,640
Operating expenses
Fuel		333,915			60,298			177,558			237,856
Operations and maintenance		29,656			15,001			15,709			30,710
Depreciation		30,403			7,086			6,691			13,777
Taxes, other than income		12,601			7,200			5,224			12,424
Impairment of goodwill		250,067			—			—			—

Total operating expenses		656,642			89,585			205,182			294,767
Gross (loss) profit		(167,328	)		22,806			51,067			73,873
Gross margin		(34.2	)%		20.3	%		19.9	%		20.0	%
General and administrative		14,602			8,827			9,371			18,198

Operating (loss) income		(181,930	)		13,979			41,696			55,675
Operating margin		(37.2	)%		12.4	%		16.3	%		15.1	%
Other expense (income)
Interest expense, net		87,031			15,770			41,425			57,195
Other expense, net		23			36			—			36
Gain on disposal of assets		(738	)		(2	)		(979	)		(981	)

Total other expenses		86,316			15,804			40,446			56,250
(Loss) income before income taxes		(268,246	)		(1,825	)		1,250			(575	)
Income tax expense (benefit)		(4,276	)		(20	)		—			(20	)

Net (loss) income	$	(263,970	)	$	(1,805	)	$	1,250		$	(555	)

As a % of total revenues		(53.9	)%		(1.6	)%		0.5	%		(0.2	)%

Revenues

Total revenues were $489.3 million for the three months ended March 31, 2008 compared to $368.6 million for the three months ended March 31, 2007, an increase of $120.7 million, or approximately 32.7%. The increase was the result of higher electric energy revenues, capacity revenues and ancillary revenues, which were partially offset by lower risk management activities revenues. Revenues for the three months ended March 31, 2008 include $367.6 million of electric energy revenues, $70.6 million of capacity revenues, $41.6 million of risk management activities and $9.5 million of ancillary revenues.

Electric energy revenues. Electric energy revenues were $367.6 million for the three months ended March 31, 2008 compared to $243.9 million for the same period in 2007, an increase of $123.7 million, or approximately 50.7%. During the three months ended March 31, 2008, average realized electric energy prices increased by 39.4% at the New York Facilities and 27.0% at the Boston Facilities, compared to those in the same period for 2007, resulting in an increase in electric energy revenues of $74.4 million. We experienced higher demand for electricity from our plants during the three months ended March 31, 2008 and as a result sold 3,513,576 MWh compared to 3,097,037 MWh during the same period in 2007. Supply in the NYISO in-city market was impacted by forced outages at other generating units, which reduced available supply throughout most of the three months ended March 31, 2008. Supply in the ISO-NE market was impacted by the retirement of 350 MW of generating capacity in Northeast Massachusetts (“NEMA”) in August 2007 and increased demand for generation in Southeast Massachusetts (“SEMA”) due to transmission improvements, favorably impacting deliverability from our Fore River facility. The increase in generation volume resulted in an increase in electric energy revenues of approximately $46.7 million. There were no unrealized losses on short-term power derivative instruments for the three months ended March 31, 2008, compared with $13.8 million for the same period in 2007. Additionally, realized gains on the short-term power derivative instruments decreased by $11.1 million during the three months ended March 31, 2008 compared to the same period for 2007, resulting in a net contribution of $2.7 million from short-term power derivative instruments during the three months ended March 31, 2008.

Capacity revenues. Capacity revenues were $70.6 million for the three months ended March 31, 2008 compared to $70.0 million for the same period in 2007, an increase of $0.6 million, or approximately 0.9%. The increase in capacity revenues during the three months ended March 31, 2008 was primarily the result of lower equivalent forced outage rate demand (“EFORd”) for the Boston Facilities and higher qualified capacity at the Fore River facility of 14 MW during the period.

Risk management activities. Risk management activities for the three months ended March 31, 2008 and 2007 are set forth in the table below.


	Three Months Ended March 31,
	2008			2007
	($ in thousands)

Settled results:
Net gains on settled positions	$	13,648		$	23,092

Subtotal for settled positions		13,648			23,092
Mark to market results:
Reversal of previously recognized unrealized losses (gains) on settled positions		43,459			(16,421	)
Net unrealized (losses) gains on open positions related to economic hedges		(15,522	)		45,463

Subtotal for mark to market results		27,937			29,042

Total risk management activities	$	41,585		$	52,134

Risk management activities resulted in a total derivative gain of approximately $41.6 million for the three months ended March 31, 2008 compared to a $52.1 million gain for the same period in 2007, a decrease of $10.5 million, or approximately 20.2%. For the three months ended March 31, 2008, these activities were comprised of $13.6 million in settled financial gains and $27.9 million of MTM gains, compared with

$23.1 million and $29.0 million, respectively, for the same period in 2007. The decrease is primarily due to the termination of the Astoria spark spread hedge on December 31, 2007, resulting in the loss of $12.7 million of settled financial gains, offset by an increase in settled financial gains of $3.4 million on the new derivative instrument entered into at EBG commencing on January 1, 2008 as a requirement of the BG credit facilities. Additionally, there was a decrease in unrealized gains on the spark spread hedges of $1.1 million during the three months ended March 31, 2008 compared to the same period for 2007.

Ancillary revenues. Ancillary revenues were $9.5 million for the three months ended March 31, 2008 compared to $2.6 million for the same period in 2007, an increase of $6.9 million, or approximately 265.4%. The increase in ancillary revenues was primarily the result of higher automatic generation control revenues, operating reserves and voltage support revenues of $3.3 million, $2.6 million and $0.9 million, respectively.

Operating Expenses

Total operating expenses were $656.6 million for the three months ended March 31, 2008 compared to $294.8 million for the same period in 2007, an increase of $361.8 million, or approximately 122.7%. The increase was primarily the result of an increase in fuel expense and depreciation expense at EBG associated with the purchase accounting impact of the Combination as well as the impairment of goodwill associated with the ISO-NE FCM auction discussed below. Operating expenses for the three months ended March 31, 2008 include $333.9 million of fuel expense, $29.7 million of operations and maintenance expenses, $30.4 million of depreciation expense, $12.5 million of taxes, other than income and $250.1 million related to the impairment of goodwill.

Fuel Expense. Fuel expense was $333.9 million for the three months ended March 31, 2008 compared to $237.9 million for the same period in 2007, an increase of $96.0 million, or approximately 40.4%. The volume of fuel consumed during the period increased due to a higher level of generation and, together with higher average costs per MMBtu, resulted in an increase in fuel costs of $96.8 million in the three months ended March 31, 2008 compared to the same period in 2007. Fuel expense was impacted by non-cash amortization expenses associated with emissions allowances and purchase accounting adjustments associated with the Combination, including fuel oil valuation amortization and transportation contract amortization, of $3.1 million for the three months ended March 31, 2008, compared with $3.7 million for the same period in 2007. Fuel expense also includes unrealized losses on short-term fuel derivative instruments of $1.4 million for the three months ended March 31, 2008 compared with unrealized gains of $5.3 million for the same period in 2007, a net decrease of $6.7 million. Additionally, realized gains on the short-term fuel derivative instruments were $1.5 million for the three months ended March 31, 2008 compared with realized losses of $5.1 million for the same period in 2007.

Operations and Maintenance Expenses. Operations and maintenance expenses during the three months ended March 31, 2008 were $29.7 million compared to $30.7 million for the same period in 2007, a decrease of $1.0 million, or approximately 3.3%. This decrease resulted primarily from a $1.8 million decrease in production costs and lower plant outage and maintenance costs of $0.5 million associated with periodic timing differences in scheduled unit outages, partially offset by higher plant salary and benefits of $1.2 million.

Depreciation Expense. Depreciation expense for the three months ended March 31, 2008 was $30.4 million, compared to $13.8 million for the same period in 2007, an increase of $16.6 million, or approximately 120.3%. This increase resulted primarily from the impact of purchase accounting adjustments made as a result of the Combination.

Impairment of Goodwill. We determined that the results of the FCM auction for generating capacity in ISO-NE constituted a trigger event, as defined under SFAS 142, requiring an interim assessment of goodwill impairment. We evaluated: (i) the impact of the FCM auction on our capacity revenues projections through May 31, 2011; (ii) the potential impact of the FCM auction results on our capacity revenues beyond May 31, 2011; and (iii) the resultant impact on our estimate of the fair value of EBG. Based on our evaluation, we determined that an impairment of $250.1 million existed at March 31, 2008 and an impairment charge was recorded in our results of operations for the quarter ended March 31, 2008.

Gross (Loss) Profit

Gross profit for the three months ended March 31, 2008 was a loss of $167.3 million compared to profit of $73.9 million for the same period in 2007, a decrease of $241.2 million. This decrease was primarily due to the $250.1 million impairment of goodwill, lower risk management revenues and higher property taxes and depreciation expense, partially offset by increased electric energy revenues net of fuel expense, capacity and ancillary revenues, and lower operations and maintenance expenses.

Electric Energy Revenues Net of Fuel Expense

The following table sets forth a summary of electric energy revenues net of fuel expense for the three months ended March 31, 2008 and 2007.


	Three Months Ended
	March 31,
	2008			2007
	($ in thousands)

Electric energy revenues	$	367,612		$	243,865
Fuel expense		333,915			237,856

Electric energy revenues net of fuel expense	$	33,697		$	6,009

As a % of electric energy revenues		9.2	%		2.5	%

Electric energy revenues net of fuel expense for the three months ended March 31, 2008 were $33.7 million, or 9.2% of electric energy revenues, compared to $6.0 million, or 2.5% of electric energy revenues, for the same period in 2007, an increase of $27.7 million or approximately 461.7%. The increase in electric energy revenues net of fuel expense was a result of higher electric energy prices combined with higher electric generation volumes and lower unrealized net losses on short-term power derivative instruments, offset by higher fuel prices and higher fuel consumption. Our weighted average capacity factor for the three months ended March 31, 2008 was 12.5% for the New York Facilities and 43.3% for the Boston Facilities compared to 10.4% and 35.9%, respectively, for the same period in 2007.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2008 were $14.6 million, compared to $18.2 million for the same period in 2007, a decrease of $3.6 million, or approximately 19.8%. This decrease was primarily the result of lower costs incurred in connection with the Combination of $0.5 million as well as non-cash share-based compensation expense of $0.6 million, compared with $2.2 million for the same period in 2007.

Interest Expense, net

Interest expense, net was $87.0 million for the three months ended March 31, 2008, compared to $57.2 million for the three months ended March 31, 2007, an increase of $29.8 million, or approximately 52.1%. This increase was primarily due to MTM losses on interest rate swaps due to lower interest rates offset in part by the lower rates favorably impacting interest expense for the unswapped portion of the debt as well as principal reduction at the New York Facilities of $21.1 million during the three months ended March 31, 2008 compared to the same period for 2007.

The table below sets forth the components of interest expense for the three months ended March 31, 2008 and 2007.


	Three Months Ended
	March 31,
	2008			2007
	($ in thousands)

Interest (expense) income
Current interest	$	(52,016	)	$	(52,962	)
Non-current interest:
Amortization of deferred financing costs		(626	)		(1,696	)
Amortization of debt premium		1,107			—
Capitalized interest adjustment		1,061			230
Interest rate swaps:
Settlements		(3,521	)		(1,508	)
Mark to market		(33,429	)		(2,253	)
Other interest income		393			994

Interest expense, net	$	(87,031	)	$	(57,195	)

We use interest rate swaps so we pay a fixed interest rate on a portion of the outstanding borrowings under our senior credit facilities for which we would otherwise have to pay a floating rate. These interest rate swaps were not designated as cash flow hedges under SFAS 133 and, as a result, we recognize the unrealized gains and losses associated with measuring the value of the swaps on a MTM basis currently as part of interest expense. During the three months ended March 31, 2008, we recognized $33.4 million of unrealized losses.

Gain on Disposal of Assets

Gain on disposal of assets for the three months ended March 31, 2008 was $0.7 million, compared to $1.0 million for the same period in 2007, a decrease of $0.3 million. During the three months ended March 31, 2008, we sold fuel oil inventory on the open market and realized a gain on disposal of $0.7 million.

Income Tax Expense

Income tax benefit was $4.3 million for the three months ended March 31, 2008, compared to a slight benefit for the same period in 2007, an increase in benefit of $4.3 million.

For the quarter ended March 31, 2007, EBG was taxed as a C corporation. EBG had generated significant net operating losses (NOLs) and related deferred tax assets, but recorded a full valuation allowance after assessing it would not be likely that EBG would be able to realize the tax assets. However, for the quarter ended March 31, 2008, EBG was taxed as part of a consolidated entity. USPowerGen and its subsidiaries are responsible for their stand-alone tax liability and intend to establish a tax sharing agreement whereby the subsidiaries will be reimbursed for federal NOLs that they may generate. Therefore, pursuant to the proposed agreement, the federal NOLs generated were used to offset federal taxable income at Astoria and USPowerGen.

Supplemental Discussion of EBG Results of Operations for the Three Months Ended March 31, 2008 compared to Three Months Ended March 31, 2007

The table below sets forth EBG results of operations for the three months ended March 31, 2008 and for the three months ended March 31, 2007 on a stand-alone basis. We have included the Supplemental Discussion in order to better analyze EBG’s contribution to the results of operations of the Successor before and after the Combination. This presentation is not pro forma for the Combination and may yield results that are not strictly comparable on a period-to-period basis to the results of the Successor primarily due to the impact of required purchase accounting adjustments for the Combination. Such results are not necessarily indicative of what the results for the respective periods would have been had the Combination not occurred.


	Three Months Ended March 31,
	2008			2007
	($ in thousands)

Revenues:
Electric energy revenues	$	256,519		$	178,428
Capacity revenues		27,310			26,884
Risk management activities		41,585			50,295
Ancillary revenues		3,142			642

Total revenues		328,556			256,249
Operating expenses:
Fuel		240,232			177,558
Operations and maintenance		13,020			15,709
Depreciation		23,190			6,691
Taxes, other than income		5,231			5,224
Impairment of goodwill		250,067			—

Total operating expenses		531,740			205,182
Gross (loss) profit		(203,184	)		51,067
Gross margin		(61.8	)%		19.9	%
General and administrative		8,667			9,371

Operating (loss) income		(211,851	)		41,696
Operating margin		(64.5	)%		16.3	%
Other expense (income):
Interest expense, net		62,936			41,425
Other income, net		24			—
Gain on disposal of assets		(738	)		(979	)

Total other expenses		62,222			40,446
(Loss) income before income taxes		(274,073	)		1,250
Income tax benefit		(4,696	)		—

Net (loss) income	$	(269,377	)	$	1,250

As a % of total revenues		(82.0	)%		0.5	%

Revenues

Total revenues were $328.6 million for the three months ended March 31, 2008 compared to $256.2 million for the three months ended March 31, 2007, an increase of $72.4 million, or approximately 28.3%. The increase was the result of higher electric energy revenues, capacity revenues and ancillary revenues, which were partially offset by lower risk management activities. Revenues for the three months ended March 31,

2008 include $256.5 million of electric energy revenues, $27.3 million of capacity revenues, $41.6 million of risk management activities and $3.1 million of ancillary revenues.

Electric energy revenues. Electric energy revenues were $256.5 million for the three months ended March 31, 2008 compared to $178.4 million for the same period in 2007, an increase of $78.1 million, or approximately 43.8%. During the three months ended March 31, 2008, average realized electric energy prices increased by 27.0%, compared to those in the same period for 2007, resulting in an increase in electric energy revenues of $48.6 million. We experienced higher demand for electricity from our plants during the three months ended March 31, 2008, and as a result sold 2,872,230 MWh during the three months ended March 31, 2008 compared to 2,570,399 MWh during the same period in 2007. Supply in the ISO-NE market was impacted by the retirement of 350 MW of generating capacity in NEMA in August 2007 and increased demand for generation in SEMA due to transmission improvements, favorably impacting deliverability from our Fore River facility. The increase in generation volume resulted in an increase in electric energy revenues of approximately $26.8 million. There were no unrealized losses on short-term power derivatives for the three months ended March 31, 2008 compared with $13.8 million for the same period in 2007. Additionally, realized gains on the power derivative instruments decreased by $11.1 million during the three months ended March 31, 2008 compared to the same period for 2007, resulting in a net contribution of $2.7 million from short-term power derivative instruments during the three months ended March 31, 2008.

Capacity revenues. Capacity revenues were $27.3 million for the three months ended March 31, 2008 compared to $26.9 million for the same period in 2007, an increase of $0.4 million, or approximately 1.5%. The increase in capacity revenues during the three months ended March 31, 2008 was the result of lower EFORd for the portfolio and higher qualified capacity at the Fore River facility of 14 MW during this period.

Risk management activities. Risk management activities for the three months ended March 31, 2008 and 2007 are set forth in the table below.


	Three Months Ended
	March 31,
	2008			2007
	($ in thousands)

Settled results:
Net gains on settled positions	$	13,648		$	10,426

Subtotal for settled positions		13,648			10,426
Mark to market results:
Reversal of previously recognized unrealized losses (gains) on settled positions		43,459			(7,937	)
Net unrealized (losses) gains on open positions related to economic hedges		(15,522	)		47,806

Subtotal for mark to market results		27,937			39,869

Total risk management activities	$	41,585		$	50,295

Risk management activities resulted in a total derivative gain of approximately $41.6 million for the three months ended March 31, 2008 compared to a $50.3 million gain for the same period in 2007, or a decrease of $8.7 million. For the three months ended March 31, 2008, these activities were comprised of $13.6 million in settled financial gains and $27.9 million of MTM gains compared with $10.4 million and $39.9 million, respectively, for the same period in 2007. The increase in settled financial gains is attributed to the new energy-related derivative instrument at EBG commencing on January 1, 2008. There was a decrease in MTM of $11.9 million during the three months ended March 31, 2008 compared to the same period for 2007, composed of a $63.3 million decrease in unrealized gains on the spark spread hedges and a $51.4 million increase attributed to the reversal of previously unrecognized MTM values, which ultimately settled.

Ancillary revenues. Ancillary revenues were $3.1 million for the three months ended March 31, 2008 compared to $0.6 million for the same period in 2007, an increase of $2.5 million, or approximately 416.7%. The increase in ancillary revenues was the result of an increase in automatic generation control revenues,

operating reserves and voltage support of $1.8 million, $0.5 million and $0.4 million, respectively, partially offset by a decrease in other revenues of $0.2 million.

Operating Expenses

Total operating expenses were $531.7 million for the three months ended March 31, 2008 compared to $205.2 million for the same period in 2007, an increase of $326.5 million, or approximately 159.1%. The increase was primarily the result of an increase in fuel expense and depreciation expense associated with the purchase accounting impact of the Combination as well as the impairment of goodwill expense associated with the ISO-NE FCM auction, offset by a decrease in operations and maintenance expenses. Operating expenses for the three months ended March 31, 2008 include $240.2 million of fuel expense, $13.0 million of operations and maintenance expenses, $23.2 million of depreciation expense, $5.2 million of taxes, other than income, and $250.1 million of goodwill impairment.

Fuel Expense. Fuel expense was $240.2 million for the three months ended March 31, 2008 compared to $177.6 million for the same period in 2007, an increase of $62.6 million, or approximately 35.2%. The volume of fuel consumed during the period increased due to a higher level of generation and, together with higher average costs per MMBtu, resulted in an increase in fuel costs of $62.5 million in the three months ended March 31, 2008 compared to the same period in 2007. Fuel expense was impacted by non-cash amortization expenses associated with emissions allowances and purchase accounting adjustments associated with the Combination, including fuel oil valuation amortization and transportation contract amortization, of $1.5 million for the three months ended March 31, 2008 compared with $1.2 million for the same period in 2007. Fuel expense also includes unrealized losses on short-term fuel derivative instruments of $1.4 million for the three months ended March 31, 2008 compared with unrealized gains of $5.3 million for the same period in 2007, a net decrease of $6.7 million. Additionally, realized gains on the short-term fuel derivative instruments were $1.5 million for the three months ended March 31, 2008 compared with realized losses of $5.1 million for the same period in 2007.

Operations and Maintenance Expenses. Operations and maintenance expenses during the three months ended March 31, 2008 were $13.0 million compared to $15.7 million for the same period in 2007, a decrease of $2.7 million, or approximately 17.2%. This decrease resulted primarily from lower plant maintenance and outage costs of $1.3 million associated with periodic timing differences in scheduled unit outages and a $1.3 million decrease in production costs.

Depreciation Expense. Depreciation expense for the three months ended March 31, 2008 was $23.2 million, compared to $6.7 million for the same period in 2007, an increase of $16.5 million, or approximately 246.3%. This increase resulted primarily from the impact of purchase accounting adjustments made as a result of the Combination.

Impairment of Goodwill. We determined that the results of the FCM auction for generating capacity in ISO-NE constituted a trigger event, as defined under SFAS 142 requiring an interim assessment of goodwill impairment. We evaluated: (i) the impact of the FCM auction on our capacity revenues projections through May 31, 2011; (ii) the potential impact of the FCM auction results on our capacity revenues beyond May 31, 2011; and (iii) the resultant impact on our estimate of the fair value of EBG. Based on our evaluation, we determined that an impairment of $250.1 million existed at March 31, 2008 and an impairment charge was recorded in our results of operations for the quarter ended March 31, 2008.

Gross Profit

Gross profit for the three months ended March 31, 2008 was a loss of $203.2 million, or a negative 61.8% of total revenues, compared to $51.1 million, or 19.9% of total revenues, for the same period in 2007, a decrease of $254.3 million. This decrease was primarily due to lower risk management revenues, higher depreciation expense and the goodwill impairment, offset by increased electric energy revenues net of fuel expense, capacity and ancillary revenues and lower operations and maintenance expenses.

Electric Energy Revenues Net of Fuel Expense

The following table sets forth a summary of electric energy revenues net of fuel expense for the three months ended March 31, 2008 and 2007.


	Three Months Ended
	March 31,
	2008			2007
	($ in thousands)

Electric energy revenues	$	256,519		$	178,428
Fuel expense		240,232			177,558

Electric energy revenues net of fuel expense	$	16,287		$	870

As a % of electric energy revenues		6.3	%		0.5	%

Electric energy revenues net of fuel expense for the three months ended March 31, 2008 was $16.3 million, or 6.3% of electric energy revenues, compared to $0.9 million, or 0.5% of electric energy revenues, for the same period in 2007, an increase of $15.4 million. The increase in electric energy revenues net of fuel expense was a result of higher electric energy prices combined with higher electric generation volumes and lower unrealized net losses on short-term power derivative instruments, offset by higher fuel prices and higher fuel consumption. Our weighted average capacity factor for the three months ended March 31, 2008 was 43.3% compared to 35.9% for the same period in 2007.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2008 were $8.7 million, compared to $9.4 million for the same period in 2007, a decrease of $0.7 million, or approximately 7.4%. This decrease was primarily the result of lower costs incurred in connection with the Combination of $3.0 million, offset by higher management fees of $2.5 million.

Interest Expense, net

Interest expense, net was $62.9 million for the three months ended March 31, 2008, compared to $41.4 million for the three months ended March 31, 2007, an increase of $21.5 million, or approximately 51.9%. This increase was primarily due to MTM losses on interest rate swaps due to lower interest rates offset in part by the lower rates favorably impacting interest expense for the unswapped portion of the debt.

The table below sets forth the components of interest expense for the three months ended March 31, 2008 and 2007.


	Three Months Ended
	March 31,
	2008			2007
	($ in thousands)

Interest (expense) income:
Current interest	$	(39,195	)	$	(39,028	)
Non-current interest:
Amortization of deferred financing costs		—			(1,696	)
Amortization of debt premium		1,107			—
Capitalized interest adjustment		635			230
Interest rate swaps:
Settlements		(3,521	)		(1,900	)
Mark to market		(22,217	)		(405	)
Other interest income		255			1,374

Interest expense, net	$	(62,936	)	$	(41,425	)

Gain on Disposal of Assets

Income Tax Benefit

Income tax benefit was $4.7 million for the three months ended March 31, 2008. Although taxable income for the three months ended March 31, 2008 was a loss of $274.1 million, consolidation under USPowerGen and a plan to establish a tax sharing agreement allowed EBG to book a benefit to offset the taxable income generated at Astoria and USPowerGen of $5.8 million.

For the quarter ended March 31, 2007, EBG was taxed as a C corporation. EBG had generated significant NOLs and related deferred tax assets, but recorded a full valuation allowance after assessing it would not be likely that EBG would be able to realize the tax assets. However, for the quarter ended March 31, 2008, EBG was taxed as part of a consolidated entity; therefore the federal NOLs generated were used to offset federal taxable income at Astoria and USPowerGen.

Adjusted Year Ended December 31, 2007 compared to Adjusted Year Ended December 31, 2006

The table below sets forth our results of operations for the year ended December 31, 2007 on a historical basis and on an as adjusted basis including the contribution of EBG for the period of January 1, 2007 through May 31, 2007, which has been calculated by adding the results of USPowerGen to the results of EBG prior to the Combination. Our adjusted results of operations for the year ended December 31, 2006, which has been calculated by adding our results of operations for the year ended December 31, 2006 with the results of operations of the Predecessor for the Predecessor Period and the results of operations for EBG for the year ended December 31, 2006, are presented for comparison. We have included the adjusted financial information in order to facilitate a comparison of our results of operations for comparable periods and operating assets. This presentation is not consistent with GAAP, and may yield results that are not strictly comparable on a period-to-period basis primarily due to (i) the impact of required purchase accounting adjustments and (ii) the new basis of accounting established on the closing date of the MDP Acquisition. Such results are not necessarily indicative of what the results for the respective periods would have been had the MDP Acquisition or the Combination not occurred. All references to the years ended December 31, 2006 and 2007 in the following discussion are based on the as adjusted information presented in the table below. The purpose of presenting this table is to provide a convenient reference for the discussion of the results of operations that follows due to the significant effects of these events on the comparability of the periods.


																			EBG/
																			Predecessor/
																			Successor
	Successor												Predecessor			EBG			Combined
										Astoria
				EBG Period			Year Ended			February 24,			January 1,						Year Ended
	Year Ended			from January 1,			December 31,			2006 to			2006 to			Year Ended			December 31,
	December 31,			2007 to May 31,			2007			December 31,			February 23,			December 31,			2006
	2007			2007			as Adjusted			2006			2006			2006			as Adjusted
	($ in thousands)

Revenues:
Electric energy revenues	$	923,960		$	332,957		$	1,256,917		$	282,720		$	44,429		$	829,200		$	1,156,349
Capacity revenues		265,818			44,759			310,577			147,915			23,007			16,480			187,402
Risk management activities		(26,142	)		86,828			60,686			40,601			36,495			(58,032	)		19,064
Ancillary revenues		19,083			643			19,726			9,275			790			80,232			90,297

Total revenues		1,182,719			465,187			1,647,906			480,511			104,721			867,880			1,453,112
Operating expenses:
Fuel		778,986			315,474			1,094,460			258,949			50,686			723,180			1,032,815
Operations and maintenance		106,208			37,360			143,568			63,143			21,731			89,507			174,381
Depreciation		82,285			11,157			93,442			22,923			5,897			26,737			55,557
Taxes, other than income		41,571			8,708			50,279			35,826			5,696			21,225			62,747

Total operating expenses		1,009,050			372,699			1,381,749			380,841			84,010			860,649			1,325,500
Gross profit		173,669			92,488			266,157			99,670			20,711			7,231			127,612
Gross margin		14.7	%		19.9	%		16.2	%		20.7	%		19.8	%		0.8	%		8.8	%
General and administrative		64,395			12,940			77,335			26,016			1,350			29,531			56,897

Operating income (loss)		109,274			79,548			188,822			73,654			19,361			(22,300	)		70,715
Operating margin		9.2	%		17.1	%		11.5	%		15.3	%		18.5	%		(2.6	)%		4.9	%
Other expense (income):
Interest expense, net		203,475			69,694			273,169			55,199			164			75,308			130,671
Other expense (income), net		74			(241	)		(167	)		(463	)		—			(768	)		(1,231	)
Gain on early extinguishment of debt		—			—			—			—			—			17,460			17,460
Loss (gain) on disposal of assets		3,870			(979	)		2,891			1,344			—			—			1,344

Total other expenses		207,419			68,474			275,893			56,080			164			92,000			148,244
(Loss) income before income taxes		(98,145	)		11,074			(87,071	)		17,574			19,197			(114,300	)		(77,529	)
Income tax (benefit) expense		(35,879	)		—			(35,879	)		651			748			—			1,399

Net (loss) income	$	(62,266	)	$	11,074		$	(51,192	)	$	16,923		$	18,449		$	(114,300	)	$	(78,928	)

As a % of total revenues		(5.3	)%		2.4	%		(3.1	)%		3.5	%		17.6	%		(13.2	)%		(5.4	)%

Revenues

Total revenues were $1,647.9 million for fiscal 2007 compared to $1,453.1 million for fiscal 2006, an increase of $194.8 million, or approximately 13.4%. The increase was the result of higher electric energy revenues, higher capacity revenues and higher revenues generated by risk management activities, which were partially offset by lower ancillary revenues. Revenues for fiscal 2007 include $1,256.9 million of electric energy revenues, $310.6 million of capacity revenues, $60.7 million of risk management activities and $19.7 million of ancillary revenues.

Electric energy revenues. Electric energy revenues were $1,256.9 million for fiscal 2007 compared to $1,156.3 million for fiscal 2006, an increase of $100.6 million, or approximately 8.7%. During fiscal 2007,

average realized electric energy prices increased by 11.0% at the New York Facilities and 14.4% at the Boston Facilities, compared to those in fiscal 2006, resulting in an increase in electric energy revenues of $147.3 million. Supply in the NYISO market was impacted by the addition of 1,000 MW of new generation capacity, which came on line by mid-year 2006, and resulted in a decline in generation from our New York Facilities of 426,057 MWh during fiscal 2007 compared to fiscal 2006. We experienced higher demand for electricity from our Boston Facilities in 2007 and as a result sold 12,909,479 MWh during fiscal 2007 compared to 12,266,894 MWh during fiscal 2006. The decrease in generation at our New York Facilities resulted in a $55.7 million decrease in electric energy revenues, but was partially offset by a $46.3 million increase in electric energy revenues as a result of the increase in generation at our Boston Facilities. Electric energy revenues included unrealized losses on short-term power derivative instruments of $13.4 million for fiscal 2007 and $51.7 million for fiscal 2006, resulting in a net decrease in unrealized losses for fiscal 2007 compared to fiscal 2006 of $38.3 million. There was also a decrease in realized gains of $75.7 million for fiscal 2007 compared to fiscal 2006.

Capacity revenues. Capacity revenues were $310.6 million for fiscal 2007 compared to $187.4 million for fiscal 2006, an increase of $123.2 million, or approximately 65.7%. The increase in capacity revenues during fiscal 2007 was the result of the capacity hedge at Astoria and significantly higher capacity prices in ISO-NE as prescribed by the FCM settlement period that became effective December 1, 2006. The capacity hedge, which was not in place until April of 2006, contributed $24.9 million of the overall increase in revenues. Realized losses on the hedge were $44.0 million in fiscal 2007 compared with $53.7 million in fiscal 2006, or a net increase of $9.7 million. Unrealized gains were approximately $17.2 million for fiscal 2007 compared with $2.0 million for fiscal 2006, an increase of $15.2 million in 2007. The higher capacity prices in ISO-NE led to capacity revenues for our Boston Facilities of $103.0 million for fiscal 2007 compared with $16.5 million for fiscal 2006, an increase of $86.5 million or 524.2%.

Risk management activities. Risk management activities for fiscal 2007 and 2006 are set forth in the table below.


	Years Ended
	December 31,
	as Adjusted
	2007		2006
	($ in thousands)

Settled results:
Net gains on settled positions	$	56,837	$	54,557

Subtotal for settled positions		56,837		54,557
Mark to market results:
Reversal of previously recognized unrealized losses (gains) on settled positions		1,518		(48,239	)
Net unrealized (losses) gains on open positions related to economic hedges		2,331		12,746

Subtotal for mark to market results		3,849		(35,493	)

Total risk management activities	$	60,686	$	19,064

Risk management activities resulted in a total derivative gain of approximately $60.7 million for fiscal 2007 compared to a $19.1 million gain for fiscal 2006. For fiscal 2007, these activities were comprised of $56.8 million in settled financial gains and $3.8 million of MTM gains compared with $54.6 million in settled financial gains and MTM losses of $35.5 million for fiscal 2006. The $56.8 million in gains in financial revenues represents the settled value for derivative instruments that do not qualify for hedge accounting treatment. $1.5 million of the $3.8 million MTM gains represents the reversal of MTM losses, which ultimately settled as financial revenues.

Ancillary revenues. Ancillary revenues were $19.7 million for fiscal 2007 compared to $90.3 million for fiscal 2006, a decrease of $70.6 million, or approximately 78.2%. The decrease in ancillary revenues was primarily the result of our Mystic 8&9 facilities running under a reliability must run (“RMR”) agreement in fiscal 2006 and not in fiscal 2007, which revenues were $76.4 million and have been classified as ancillary

service revenues in fiscal 2006. The RMR agreement was a fixed-cost recovery agreement with ISO-NE that was accepted by FERC subject to refund on February 24, 2006 with an effective date of January 1, 2006. A settlement agreement was reached and the RMR agreement was amended to reflect the settlement terms which terminated RMR payments effective January 1, 2007. Mystic 8&9 is not entitled to further fixed cost recovery arrangements with ISO-NE during the FCM settlement period.

In addition, our New York Facilities earned $16.2 million in ancillary services in fiscal 2007 compared to $10.1 million in fiscal 2006, primarily as a result of adding automatic generation control and black start capability at the Astoria facility during fiscal 2007.

Operating Expenses

Total operating expenses were $1,381.7 million for fiscal 2007 compared to $1,325.5 million for fiscal 2006, an increase of $56.2 million, or approximately 4.2%. The increase was the result of an increase in fuel expense and depreciation, partially offset by decreased operations and maintenance, and taxes, other than income expense. Operating expenses for fiscal 2007 include $1,094.5 million of fuel expense, $143.6 million of operations and maintenance expenses, $93.4 million of depreciation expense and $50.2 million of taxes, other than income.

Fuel Expense. Fuel expense was $1,094.5 million for fiscal 2007 compared to $1,032.8 million in fiscal 2006, an increase of $61.7 million, or approximately 6.0%. The volume of fuel consumed during the period increased due to a higher level of generation and, together with higher average costs per MMBtu, resulted in an increase in fuel costs of $76.3 million in fiscal 2007 compared to fiscal 2006. Fuel expense also includes unrealized gains on short-term fuel derivative instruments of $7.0 million for fiscal 2007 compared with $15.6 million for 2006, a decrease of $8.6 million. Additionally, realized gains on the short-term fuel derivative instruments were $12.7 million for fiscal 2007 compared with $21.7 million for 2006, a decrease of $9.0 million. Fuel expense was also impacted by non-cash amortization expenses associated with emissions allowances and purchase accounting adjustments associated with the Combination of $13.4 million for fiscal 2007 compared with $15.3 million for fiscal 2006. Higher fuel expense was also impacted by an impairment charge related to our emissions allowances of $5.0 million in 2007.

In fiscal 2007, we sold certain of our emissions allowances in the open market and realized a loss of $2.9 million. In light of the significance of this loss, we evaluated the balance of our emissions allowances to determine whether an impairment charge was required to be recognized. Based on that analysis, we concluded that a write-down of the carrying value of our remaining emissions allowances was required and recorded a charge of $5.0 million in fuel expense in September, 2007.

Operations and Maintenance Expenses. Operations and maintenance expenses during fiscal 2007 were $143.6 million compared to $174.4 million for fiscal 2006, a decrease of $30.8 million, or approximately 17.7%. This decrease resulted primarily from lower maintenance costs and lower plant outage costs, offset by higher productions costs as well as salaries and benefits. Maintenance costs were $35.2 million in fiscal 2007 compared to $52.8 million in 2006, a decrease of $17.6 million, due to repair costs necessary in 2006 that did not occur in 2007. Outage costs were $35.3 million in 2007 compared to $54.1 million in 2006, a decrease of $18.8 million, associated with periodic timing differences in scheduled unit outages. In particular, outages at our Boston Facilities under the long-term service agreement with MPS resulted in charges of $17.9 million in fiscal 2007 compared to $28.3 million in fiscal 2006, a decrease of $10.4 million or 36.7%. Salaries and benefit expenses increased $3.3 million due to additions to plant personnel and production costs increased by $2.4 million. There was a favorable non-cash adjustment of $5.1 million to operations and maintenance expenses in fiscal 2007 related to an environmental liability charge.

Depreciation Expense. Depreciation expense for fiscal 2007 was $93.4 million, compared to $55.6 million for fiscal 2006, an increase of $37.8 million, or approximately 68.0%. This increase resulted primarily from an increase in the carrying values of fixed assets at our Boston Facilities that occurred in connection with the purchase accounting for the Combination.

Gross Profit

Gross profit for fiscal 2007 was $266.2 million, or 16.2% of total revenues, compared to $127.6 million, or 8.8% of total revenues, for fiscal 2006, an increase of $138.6 million, or 108.6%. This increase was primarily due to increased electrical energy revenues net of fuel expense, capacity revenues and revenues from risk management activities, lower operations and maintenance expenses and property taxes, partially offset by lower ancillary revenues and higher depreciation expense.

Electric Energy Revenues Net of Fuel Expense

The following table sets forth a summary of electric energy revenues net of fuel expense for fiscal 2007 and 2006.


	Years Ended
	December 31,
	as Adjusted
	2007			2006
	($ in thousands)

Electric energy revenues	$	1,256,917		$	1,156,349
Fuel expense		1,094,460			1,032,815

Electric energy revenues net of fuel expense	$	162,457		$	123,534

As a % of electric energy revenues		12.9	%		10.7	%

Electric energy revenues net of fuel expense for fiscal 2007 was $162.5 million, or 12.9% of electric energy revenues, compared to $123.5 million, or 10.7% of electric energy revenues, for fiscal 2006, an increase of $39.0 million or approximately 31.6%. The increase in electric energy revenues net of fuel expense was a result of higher electric energy prices combined with higher electric generation volumes offset by higher fuel prices and higher fuel consumption during the period. We also experienced higher fuel expense as compared to the prior period as a result of an impairment charge of $5.0 million for emissions allowances described above under “Fuel Expense.” Our weighted average capacity factor for fiscal 2007 was 11.8% for the New York Facilities and 47.9% for the Boston Facilities compared to 14.1% and 43.7%, respectively, for fiscal 2006 as a result of higher demand in ISO-NE due to warmer weather and transmission upgrades, offset by lower demand in NYISO as a result of increased supply. Excluding the $5.0 million impairment charge, the electrical energy revenues net of fuel expense margin for fiscal 2007 would have been 13.3% compared to 10.7% in fiscal 2006.

General and Administrative Expenses

General and administrative expenses for fiscal 2007 were $77.3 million, compared to $56.9 million for fiscal 2006, an increase of $20.4 million, or approximately 35.9%. This increase was primarily the result of costs incurred in connection with the Combination and increases in payroll and related costs associated with our administrative functions in anticipation of the Combination. We also incurred $6.0 million of compensation expense in connection with the departure of Ian Nutt, our former Executive Vice President, during fiscal 2007. General and administrative expenses for fiscal 2007 included non-cash share-based compensation expense of $5.0 million compared with $0.3 million for fiscal 2006.

Interest Expense, net

Interest expense was $273.2 million for fiscal 2007, compared to $130.7 million for fiscal 2006, an increase of $142.5 million, or approximately 109.0%. The increase was primarily due to the fact that the existing financing at EBG was not put into place until December 2006, at which time aggregate leverage at EBG increased from $795.4 million to $1,809.8 million.

The table below sets forth the components of interest expense for fiscal 2007 and 2006.


	Years Ended
	December 31,
	as Adjusted
	2007			2006
	($ in thousands)

Interest (expense) income:
Current interest	$	(216,122	)	$	(138,775	)
Non-current interest:
Amortization of deferred financing costs		(5,357	)		(1,110	)
Amortization of debt premium		2,555			—
Capitalized interest adjustment		2,321			—
Interest rate swaps:
Settlements		(6,333	)		4,720
Mark to market		(56,158	)		(2,699	)
Other interest income		5,925			7,193

Interest expense, net	$	(273,169	)	$	(130,671	)

We use interest rate swaps for the purpose of fixing the interest rate on a portion of our outstanding borrowings under its senior credit facilities. These interest rate swaps were not designated as cash flow hedges under SFAS 133 and, as a result, we recognize the unrealized gains and losses associated with measuring the value of the swaps on a MTM basis currently as part of interest expense. During fiscal 2007, we recognized $56.2 million of unrealized losses.

Loss on Disposal of Assets

Loss on disposal of assets for fiscal 2007 was $2.9 million, compared to $1.3 million for fiscal 2006, a decrease of $1.6 million. During fiscal 2007, we sold certain emissions allowances on the open market and realized a loss on disposal of $2.9 million.

Income Tax Expense

Income tax benefit was $35.9 million for fiscal 2007, compared to an expense of $1.4 million for fiscal 2006, an increased benefit of $37.3 million. The increase in benefit was primarily the result of greater losses in operating income. For fiscal 2006, Astoria was a limited liability company and elected pass-through status for tax purposes. In March 2006, EBG elected to be taxed as a corporation. In fiscal 2007, Astoria incorporated as a C corporation to facilitate the Combination and became subject to federal income taxes commencing June 1, 2007. Prior to this, Astoria was only subject to New York unincorporated business taxes of 4.0%.

Supplemental Discussion of EBG Results of Operations for the Year Ended December 31, 2007, compared to Year Ended December 31, 2006

The table below sets forth EBG results of operations for the years ended December 31, 2007 and December 31, 2006 on a stand-alone basis. We have included the Supplemental Discussion in order to better analyze EBG’s contribution to the results of operations of the Successor before and after the Combination. This presentation is not pro forma for the Combination and may yield results that are not strictly comparable on a period-to-period basis to the results of the Successor primarily due to the impact of required purchase accounting adjustments for the Combination. Such results are not necessarily indicative of what the results for the respective periods would have been had the Combination not occurred.


	Combination			Successor			EBG
	EBG Period from			EBG Period from			Year Ended
	June 1,			January 1,			December 31,			Year Ended
	2007 to December 31,			2007 to May 31,			2007			December 31,
	2007			2007			as Adjusted			2006
	($ in thousands)
Revenues:
Electric energy revenues	$	616,670		$	332,957		$	949,627		$	829,200
Capacity revenues		58,241			44,759			103,000			16,480
Risk management activities		(77,189	)		86,828			9,639			(58,032	)
Ancillary revenues		2,883			643			3,526			80,232

Total revenues		600,605			465,187			1,065,792			867,880
Operating expenses:
Fuel		509,074			315,474			824,548			723,180
Operations and maintenance		38,731			37,360			76,091			89,507
Depreciation		53,805			11,157			64,962			26,737
Taxes, other than income		12,447			8,708			21,155			21,225

Total operating expenses		614,057			372,699			986,756			860,649
Gross (loss) profit		(13,452	)		92,488			79,036			7,231
Gross margin		(2.2	)%		19.9	%		7.4	%		0.8	%
General and administrative		17,137			12,940			30,077			29,531

Operating (loss) income		(30,589	)		79,548			48,959			(22,300	)
Operating margin		(5.1	)%		17.1	%		4.6	%		(2.6	)%
Other expense (income):
Interest expense, net		131,594			69,694			201,288			75,308
Other (income), net		—			(241	)		(241	)		(768	)
Loss on early extinguishment of debt		—			—			—			17,460
Loss (gain) on disposal of assets		392			(979	)		(587	)		—

Total other expenses		131,986			68,474			200,460			92,000
(Loss) income before income taxes		(162,575	)		11,074			(151,501	)		(114,300	)
Income tax (benefit) expense		(57,022	)		—			(57,022	)		—

Net (loss) income	$	(105,553	)	$	11,074		$	(94,479	)	$	(114,300	)

As a % of total revenues		(17.6	)%		2.4	%		(8.9	)%		(13.2	)%

Revenues

Total revenues were $1,065.8 million for fiscal 2007 compared to $867.9 million for fiscal 2006, an increase of $197.9 million, or approximately 22.8%. The increase was the result of higher electric energy revenues, higher capacity revenues and higher revenues generated from risk management activities, which was partially offset by lower ancillary revenues. Revenues for fiscal 2007 include $949.6 million of electric energy revenues, $103.0 million of capacity revenues, $9.6 million of risk management activities and $3.6 million of ancillary revenues.

Electric energy revenues. Electric energy revenues were $949.6 million for fiscal 2007 compared to $829.2 million for fiscal 2006, an increase of $120.4 million, or approximately 14.5%. During fiscal 2007, average realized electric energy prices increased by 14.4%, compared to those in fiscal 2006, resulting in an increase in electric energy revenues of $111.5 million. In addition, we experienced higher demand for electricity in 2007 and as a result sold 12,909,479 MWh during fiscal 2007 compared to 12,266,894 MWh during fiscal 2006. The increase in generation at EBG resulted in a $46.3 million increase in electric energy revenues. Electric energy revenues included unrealized losses on short-term power derivative instruments of $13.4 million for fiscal 2007 and $51.7 million for fiscal 2006, resulting in a net decrease in unrealized losses during fiscal 2007 compared to fiscal 2006 of $38.3 million. There was also a decrease in realized gains of $75.7 million for fiscal 2007 compared to fiscal 2006.

Capacity revenues. Capacity revenues were $103.0 million for fiscal 2007 compared to $16.5 million for fiscal 2006, an increase of $86.5 million, or approximately 524.2%. The increase in capacity revenues during fiscal 2007 was the result of significantly higher capacity prices in ISO-NE as prescribed by the FCM settlement period that became effective December 1, 2006.

Risk management activities. Risk management activities for fiscal 2007 and 2006 are set forth in the table below.


	EBG
	Years Ended
	December 31,
	as Adjusted
	2007			2006
	($ in thousands)

Settled results:
Net (losses) gains on settled positions	$	(80	)	$	2,815

Subtotal for settled positions		(80	)		2,815
Mark to market results:
Reversal of previously recognized unrealized losses on settled positions		7,388			—
Net unrealized gains (losses) on open positions related to economic hedges		2,331			(60,847	)

Subtotal for mark to market results		9,719			(60.847	)

Total risk management activities	$	9,639		$	(58,032	)

Risk management activities resulted in a total derivative gain of approximately $9.6 million for fiscal 2007 compared to a total derivative loss of $58.0 million for fiscal 2006. The $58.0 million loss for fiscal 2006 was primarily attributed to a $57.3 million MTM loss recognized on the EBG spark spread hedge during the period ended December 31, 2006. For fiscal 2007, these activities were comprised of $0.1 million in settled financial losses and $9.7 million of MTM gains compared with settled financial gains of $2.8 million and MTM losses of $60.8 million for fiscal 2006. The $0.1 million loss in risk management activities represents the settled value for derivative instruments that do not qualify for hedge accounting treatment. In addition, $7.4 million of the $9.7 million MTM gains represents the reversal of MTM losses, which ultimately settled as financial revenues.

Ancillary revenues. Ancillary revenues were $3.6 million for fiscal 2007 compared to $80.2 million for fiscal 2006, a decrease of $76.6 million, or approximately 95.5%. The decrease in ancillary revenues was primarily the result of our Mystic 8&9 facilities running under an RMR contract in fiscal 2006 and not in fiscal 2007, which revenues were $76.4 million and have been classified as ancillary services revenues in fiscal 2006. The RMR agreement was a fixed-cost recovery agreement with ISO-NE that was accepted by FERC subject to refund on February 24, 2006 with an effective date of January 1, 2006. A settlement agreement was reached and the RMR agreement was amended to reflect the settlement terms which terminated RMR payments effective January 1, 2007. Mystic 8&9 is not entitled to further fixed cost recovery arrangements with ISO-NE during the FCM settlement period.

Operating Expenses

Total operating expenses were $986.8 million for fiscal 2007 compared to $860.6 million for fiscal 2006, an increase of $126.2 million, or approximately 14.7%. The increase was the result of an increase in fuel expense and depreciation, offset by decreased operations and maintenance and taxes, other than income expense. Operating expenses for fiscal 2007 include $824.5 million of fuel expense, $76.1 million of operations and maintenance expenses, $65.0 million of depreciation expense and $21.2 million of taxes, other than income.

Fuel Expense. Fuel expense was $824.5 million for fiscal 2007 compared to $723.2 million in fiscal 2006, an increase of $101.3 million, or approximately 14.0%. The volume of fuel consumed during the period increased due to a higher level of generation and, together with higher average costs per MMBtu, resulted in an increase in fuel costs of $119.2 million in fiscal 2007 compared to fiscal 2006. Fuel expense also includes unrealized gains on short-term fuel derivatives of $7.0 million for fiscal 2007 compared with $15.6 million for 2006, a decrease of $8.6 million. Additionally, realized gains on the short-term fuel derivatives were $12.7 million for fiscal 2007 compared with $21.7 million for 2006, a decrease of $9.0 million. Fuel expense was also impacted by non-cash expenses associated with emission allowances amortization and purchase accounting adjustments associated with the Combination, including fuel oil valuation amortization and transportation contract amortization, of $2.9 million for fiscal 2007 compared with $3.1 million for fiscal 2006.

Operations and Maintenance Expenses. Operations and maintenance expenses during fiscal 2007 were $76.1 million compared to $89.5 million for fiscal 2006, a decrease of $13.4 million, or approximately 15.0%. This decrease resulted primarily from lower plant outage costs of $11.2 million, associated with periodic timing differences in scheduled unit outages. In particular, outages at our Boston Facilities under the long-term service agreement with Mitsubishi Power System resulted in charges of $17.9 million in fiscal 2007 compared to $28.3 million in fiscal 2006, a decrease of $10.4 million or 36.7%. Maintenance expense decreased from $11.3 million in 2006 to $7.5 million in 2007, a decrease of $3.8 million, due to repair costs necessary in 2006 that did not occur in 2007.

Depreciation Expense. Depreciation expense for fiscal 2007 was $65.0 million, compared to $26.7 million for fiscal 2006, an increase of $38.3 million, or approximately 143.4%. This increase resulted primarily from an increase in the carrying values of fixed assets that occurred in connection with the purchase accounting for the Combination.

Gross Profit

Gross profit for fiscal 2007 was $79.0 million, or 7.4% of total revenues, compared to $7.2 million, or 0.8% of total revenues, for fiscal 2006, an increase of $71.8 million. This increase was primarily due to increased electrical energy revenues net of fuel expense, capacity revenues and revenues from risk management activities, lower operations and maintenance expenses and property taxes, partially offset by lower ancillary revenues and higher depreciation expense.

Electric Energy Revenues Net of Fuel Expense

The following table sets forth a summary of electric energy revenues net of fuel expense for fiscal 2007 and 2006.


	EBG
	Years Ended
	December 31,
	as Adjusted
	2007			2006
	($ in thousands)

Electric energy revenues	$	949,627		$	829,200
Fuel expense		824,548			723,180

Electric energy revenues net of fuel expense	$	125,079		$	106,020

As a % of electric energy revenues		13.2	%		12.8	%

Electric energy revenues net of fuel expense for fiscal 2007 was $125.1 million, or 13.2% of electric energy revenues, compared to $106.0 million, or 12.8% of electric energy revenues, for fiscal 2006, an increase of $19.1 million, or approximately 18.0%. The increase in electric energy revenues net of fuel expense was a result of higher electric energy prices combined with higher electric generation volumes and lower unrealized and realized losses on short-term fuel derivative instruments offset by higher fuel prices and higher fuel consumption during the period. Our weighted average capacity factor for fiscal 2007 was 47.9% compared to 43.7% for fiscal 2006 as a result of higher demand in ISO-NE due to warmer weather and transmission upgrades.

General and Administrative Expenses

General and administrative expenses for fiscal 2007 were $30.1 million, compared to $29.5 million for fiscal 2006, an increase of $0.6 million, or approximately 2.0%. This increase was primarily the result of costs incurred in connection with the Combination.

Interest Expense, net

Interest expense, net was $201.3 million for fiscal 2007, compared to $75.3 million for fiscal 2006, an increase of $126.0 million, or approximately 167.3%. The increase was primarily due to the fact that the existing financing at EBG was not put into place until December 2006, upon which aggregate leverage at EBG increased from $795.4 million to $1,809.8 million.

The table below sets forth the components of interest expense for fiscal 2007 and 2006.


	Years Ended
	December 31,
	2007			2006
	($ in thousands)

Interest (expense) income:
Current interest	$	(158,666	)	$	(77,684	)
Non-current interest:
Amortization of deferred financing costs		(2,825	)		(1,110	)
Amortization of debt premium		2,555			—
Capitalized interest adjustment		1,232			—
Interest rate swaps:
Settlements		(7,706	)		(1,142	)
Mark to market		(40,426	)		(732	)
Other interest income		4,548			5,360

Interest expense, net	$	(201,288	)	$	(75,308	)

Adjusted Year Ended December 31, 2006 compared to the Year Ended December 31, 2005

The table below sets forth the results for the year ended December 31, 2006 for Astoria on a historical basis and on an as adjusted basis to include the mathematical addition of the results of the Predecessor during the Predecessor Period. We have included the adjusted financial information in order to facilitate a comparison with fiscal 2005. This presentation is not consistent with GAAP, and may yield results that are not strictly comparable on a period-to-period basis primarily due to (i) the impact of required purchase accounting adjustments and (ii) the new basis of accounting established on the closing date of the MDP Acquisition. All references to fiscal 2006 in the following discussion are based on the as adjusted financial information presented in the table below. The purpose of presenting this table is to provide a convenient reference for the discussion of the results of operations that follows due to the significant effects of these events on the comparability of the periods.


							Predecessor/
							Successor
	Successor			Predecessor			Combined			Predecessor
	Astoria
	February 24,			January 1,			Year Ended
	2006 to			2006 to			December 31,			Year Ended
	December 31,			February 23,			2006			December 31,
	2006			2006			as Adjusted			2005
	($ in thousands)

Revenues:
Electric energy revenues	$	282,720		$	44,429		$	327,149		$	691,303
Capacity revenues		147,915			23,007			170,922			229,677
Risk management activities		40,601			36,495			77,096			83,987
Ancillary revenues		9,275			790			10,065			9,078

Total revenues		480,511			104,721			585,232			1,014,045
Operating expenses:
Fuel		258,949			50,686			309,635			555,227
Operations and maintenance		63,143			21,731			84,874			94,005
Depreciation		22,923			5,897			28,820			38,816
Taxes, other than income		35,826			5,696			41,522			33,782

Total operating expenses		380,841			84,010			464,851			721,830
Gross profit		99,670			20,711			120,381			292,215
Gross margin		20.7	%		19.8	%		20.6	%		28.8	%
General and administrative		26,016			1,350			27,366			6,628

Operating income		73,654			19,361			93,015			285,587
Operating margin		15.3	%		18.5	%		15.9	%		28.2	%
Other expense (income):
Interest expense, net		55,199			164			55,363			(2,135	)
Other (income) expense, net		(463	)		—			(463	)		22
Loss (gain) on disposal of assets		1,344			—			1,344			(23	)

Total other expenses		56,080			164			56,244			(2,136	)
Income (loss) before income taxes		17,574			19,197			36,771			287,723
Income tax expense		651			748			1,399			11,530

Net income	$	16,923		$	18,449		$	35,372		$	276,193

As a % of total revenues		3.5	%		17.6	%		6.0	%		27.2	%

Revenues

Total revenues were $585.2 million for fiscal 2006 compared to $1,014.0 million for fiscal 2005, a decrease of $428.8 million, or approximately 42.3%. The decrease was the result of new capacity added to the market in 2006 and higher energy revenues in fiscal 2005 driven by favorable market conditions for burning fuel oil, higher demand due to extreme weather and higher electricity prices during the period. Revenues for

fiscal 2006 include $327.1 million of electric energy revenues, $170.9 million of capacity revenues, $77.1 million of risk management activities and $10.1 million of ancillary revenues.

Electric energy revenues. Electric energy revenues for fiscal 2006 were $327.1 million, compared to $691.3 million during fiscal 2005, a decrease of $364.2 million, or approximately 52.7%. This was primarily the result of lower average electric energy prices and a decrease in generation during the period compared to fiscal 2005. Prices during the peak months of fiscal 2005 were driven by extreme weather conditions, which impacted demand and the cost of fuel. Fiscal 2005 was characterized by extreme heat and unusual weather conditions, including a very active hurricane season that impacted regions of the country that supply natural gas. During fiscal 2006, our plants sold 2,774,756 MWh of electric energy compared to 5,249,090 MWh in fiscal 2005. Supply in the New York ISO market was impacted by the addition of 1,000 MW of new generation capacity, which came on line by mid-year 2006.

Capacity revenues. Capacity revenues for fiscal 2006 were $170.9 million, compared to $229.7 million for fiscal 2005, a decline of $58.8 million or approximately 25.6%. This decline was related to lower average capacity prices and lower capacity volume available for sale in fiscal 2006 compared to fiscal 2005. In 2006, average realized capacity prices were lower due to the capacity derivative instrument. Since it became effective in April, capacity revenues were affected by lower winter market prices, reducing the overall average capacity price for 2006. The capacity derivative instrument reduced exposure to fluctuating capacity prices by means of a fixed price. Realized revenues from capacity sales and the capacity derivative instrument decreased $60.8 million in 2006 compared to 2005, but was partially offset by an increase in unrealized MTM gains of $2.0 million on the capacity derivative instrument.

Risk management activities. Risk management activities for fiscal 2006 and fiscal 2005 are set forth in the table below.


	Year Ended
	December 31,
	as Adjusted
	2006			2005
	($ in thousands)

Settled results:
Net gains on settled positions	$	51,742		$	—

Subtotal for settled positions		51,742			—
Mark to market results:
Reversal of previously recognized unrealized gains on settled positions		(48,239	)		—
Net unrealized gains on open positions related to economic hedges		73,593			83,987

Subtotal for mark to market results		25,354			83,987

Total risk management activities	$	77,096		$	83,987

Risk management activities resulted in a total derivative gain of approximately $77.1 million for fiscal 2006. These gains were comprised of $25.4 million in MTM gains and $51.7 million in settled financial revenues gains compared with approximately $84.0 million of MTM gains in fiscal 2005. The $51.7 million gains in financial revenues represents the settled value for derivative instruments that do not qualify for hedge accounting treatment. The $25.4 million in MTM gains represents the change in the fair value of our spark spread hedge.

Ancillary revenues. Ancillary revenues for fiscal 2006 were $10.1 million, compared to $9.1 million for fiscal 2005, an increase of $1.0 million, or approximately 11.0%.

Operating Expenses

Total operating expenses for fiscal 2006 were $464.9 million, compared to $721.8 million for fiscal 2005, a decrease of $256.9 million, or approximately 35.6%. The decrease was the result of lower expenses in fuel, operations and maintenance and depreciation, offset by higher taxes, other than income. Operating expenses for fiscal 2006 include $309.6 million of fuel expense, $84.9 million of operations and maintenance expenses, $28.8 million of depreciation expense and $41.6 million of taxes, other than income.

Fuel Expense. Fuel expense for fiscal 2006 was $309.6 million, compared to $555.2 million in fiscal 2005, a decrease of $245.6 million, or approximately 44.2%. The cost of fuel, which is one of the principal factors that drive the price of electric energy, was impacted by disruptions in natural gas supply that resulted from hurricane Katrina and other severe weather events during fiscal 2005 compared to fiscal 2006. Fuel expense was also impacted by non-cash amortization expenses associated with emissions allowances of $12.2 million for fiscal 2006 compared with $4.2 million for fiscal 2005.

Operations and Maintenance Expense. Operations and maintenance expenses for fiscal 2006 were $84.9 million, compared to $94.0 million in fiscal 2005, a decrease of $9.1 million, or approximately 9.7%. The decline was primarily the result of a significant maintenance project on generating units at one of our New York Facilities in 2005. In addition, following the MDP Acquisition we adopted a practice of competitively bidding all major maintenance projects, which were carried out by an in-house engineering group during the Predecessor’s ownership. As a result, we lowered our outage and maintenance costs. Finally, the Predecessor recorded an asset retirement obligation on December 31, 2005, which increased operations and maintenance expenses by $4.3 million for fiscal 2005.

Depreciation Expense. Depreciation expense for fiscal 2006 was $28.8 million, compared to $38.8 million for fiscal 2005, a decrease of $10.0 million, or approximately 25.8%. The decrease was primarily the result of the MDP Acquisition, which resulted in a reduction of the carrying values of the acquired tangible assets. The fair market value of the acquired assets at February 23, 2006 was lower than the Predecessor’s historical cost, resulting in a “step-down” of $59.1 million.

Gross Profit

Gross profit for fiscal 2006 was $120.4 million, or 20.6% of total revenues, compared to $292.2 million, or 28.8% of total revenues, for fiscal 2005, a decrease of $171.8 million, or approximately 58.8%. This was primarily the result of significantly lower electric energy revenues net of fuel expense in fiscal 2006 and an unusual MTM gain recognized in fiscal 2005.

Electric Energy Revenues Net of Fuel Expense

The following table sets forth a summary of electric energy revenues net of fuel expense for fiscal 2006 and fiscal 2005.


	Year Ended
	December 31,
	as Adjusted
	2006			2005
	($ in thousands)

Electric energy revenues	$	327,149		$	691,303
Fuel expense		309,635			555,227

Electric energy revenues net of fuel expense	$	17,514		$	136,076

As a % of electric energy revenues		5.4	%		19.7	%

For fiscal 2006, electric energy revenues net of fuel expense was $17.5 million, or 5.4% of electric energy revenues, compared to $136.1 million, or 19.7% of electric energy revenues, for fiscal 2005, a decrease of $118.6 million, or approximately 87.1%. Of this amount, $67.6 million of the decline in revenues net of fuel was the result of lower generation volumes in fiscal 2006 and $42.9 million was the result of lower average prices in fiscal 2006. The balance of the decline in fiscal 2006 was primarily the result of $8.1 million of amortization expense related to the use of emissions allowances and the amortization of fuel transport agreements during the period and reflects the fair value of these assets acquired as part of the MDP Acquisition, which were recorded at fair value in accordance with purchase accounting.

General and Administrative Expenses

General and administrative expenses for fiscal 2006 were $27.4 million, compared to $6.6 million for fiscal 2005, an increase of $20.8 million or 315.2%. This increase was the result of integration costs associated with the MDP Acquisition, higher insurance costs and payroll and related expenses associated with establishing our

administrative functions in anticipation of the MDP Acquisition. During 2006, we incurred $4.2 million of professional fees and other costs for the integration of the MDP Acquisition. Our insurance costs in fiscal 2006 were $3.4 million higher than the Predecessor’s cost due to the Predecessor’s favorable insurance premium structure resulting from its overall size and asset diversification compared to ours and higher rates in general due to the insurance market conditions in 2006 compared to 2005. The balance of the difference was attributable to establishing our administrative functions, which required us to incur expenses related to payroll and benefits, rent and related costs. The total impact of these costs in fiscal 2006 was $13.1 million higher than the Predecessor’s corporate general and administrative expenses allocation. The Predecessor allocated its corporate general and administrative costs to its entire business resulting in lower costs compared to our actual expenses.

Interest Expense, net

Interest expense, net for fiscal 2006 was $55.4 million, compared to interest income, net of $2.1 million for fiscal 2005, an increase of $57.5 million. The increase in interest expense was a result of the MDP Acquisition and reflects our use of a debt financing structure compared to the equity financing structure used by the Predecessor. In addition, interest expense would have been higher had the MDP Acquisition occurred on January 1, 2006. Interest expense, net also includes the amortization of deferred financing costs, which amounted to $8.1 million of interest expense.

During fiscal 2006, we recognized $1.2 million of net interest expense related to our interest rate swaps, comprised of $0.8 million of gains on settled swaps and $2.0 million of MTM unrealized losses on open swaps.

Income Tax Expense

Income tax expense was approximately $1.4 million and approximately $11.5 million for fiscal 2006 and fiscal 2005, respectively. The reduction in income tax expense is the result of our tax structure compared to the Predecessor. We were a limited liability company in 2006, and as a result all of our taxable income passed through to our unitholders. The Predecessor was part of a consolidated tax entity that was a corporation. Our income tax expense for fiscal 2006 was principally unincorporated business taxes paid in New York.

Liquidity and Capital Resources

Power generation is a capital intensive business that is prone to seasonal fluctuations in demand and long-term industry cycles as well as variations in commodity prices. Our principal sources of cash have included cash generated from our operations and borrowings under our senior revolving credit facilities. Our principal uses of cash have included commercial operations activities, capital expenditures and debt service obligations. We expect that these will remain our principal uses of cash in the future; however, we may use additional cash to pursue acquisitions and project development.

While we believe that our sources of liquidity are currently adequate to meet our needs, this belief is based on a number of material assumptions, including, without limitation, assumptions about seasonal demand for electric energy, our credit ratings and rates on our borrowings, certain assumptions about our derivative instruments and structures, fuel purchases and future market conditions, including forward prices for energy and fuel and market volatility. If and to the extent these assumptions prove to be inaccurate, our sources of liquidity may be affected. Moreover, changes in these factors or in the bank or other credit markets could affect our liquidity requirements and/or reduce available credit or our ability to renew existing liquidity facilities on acceptable terms. The absence of adequate liquidity could adversely affect our ability to operate our business, our results of operations and financial condition.

Comparability of cash flows for the three months ended March 31, 2008 and 2007 and for the fiscal years ended December 31, 2007, 2006 and 2005 is impacted by the MDP Acquisition and the Combination. See “— Basis of Presentation.” Management believes that the most meaningful way to discuss our cash flows for the periods ended March 31, 2008 and 2007 is to compare (i) the Successor’s cash flows for the three months ended March 31, 2008 with (ii) the mathematical addition of the Successor’s cash flows for the three months ended March 31, 2007 and cash flows from EBG for the same period. We believe that the most meaningful way to discuss our cash flows for the periods ended December 31, 2007 and 2006 is to compare (i) the mathematical addition of the Successor’s cash flows for the year ended December 31, 2007 and the cash flows

for EBG for the period from January 1, 2007 to May 31, 2007 with (ii) the mathematical addition of the Successor’s cash flows for the year ended December 31, 2006 and the Predecessor’s cash flows for the Predecessor Period and the EBG cash flows for the year ended December 31, 2006. We believe that presenting the discussion and analysis of the cash flows in this manner promotes the overall usefulness of the comparison given the complexities involved with comparing two significantly different periods. At the same time, we believe that it facilitates the reconciliation of the discussion and analysis to the cash flow information provided herein. In addition, we have provided a separate discussion of the cash flows of EBG for the three months ended March 31, 2008 and 2007 and the years ended December 31, 2007 and 2006.

Cash Flows

The tables below set forth our sources and uses of cash in the periods presented on an actual basis and on an as adjusted basis. We have included the adjusted financial information in order to facilitate a comparison of our cash flows for comparable periods and operating assets. This presentation is not consistent with GAAP, and may yield results that are not strictly comparable on a period-to-period basis primarily due to the impact of the Combination. Such results are not necessarily indicative of what the results for the respective periods would have been had the Combination not occurred. All references to period cash flows in the following discussion are based on the as adjusted information presented in the table below. The purpose of presenting this table is to provide a convenient reference for the discussion of cash flows that follows due to the significance of these events on the comparability of the periods.

The following table summarizes our sources and uses of cash in the periods presented:


										Successor/
										EBG
							EBG			Combined
	Successor									Three
	Three			Three			Three			Months
	Months			Months			Months			Ended
	Ended			Ended			Ended			March 31,
	March 31,			March 31,			March 31,			2007
	2008			2007			2007			as Adjusted
	(Dollars in thousands)

Beginning cash and cash equivalents	$	34,409		$	44,507		$	8,079		$	52,586
Net cash (used in) provided by:
Operating activities		1,566			20,906			9,412			30,318
Investing activities		(10,038	)		(14,358	)		708			(13,650	)
Financing activities		(14,641	)		(23,467	)		(16,825	)		(40,292	)

Net decrease in cash and cash equivalents		(23,113	)		(16,919	)		(6,705	)		(23,624	)

Ending cash and cash equivalents	$	11,296		$	27,588		$	1,374		$	28,962


																			EBG/
																			Predecessor/
																			Successor
	Successor												Predecessor			EBG			Combined			Predecessor
				EBG Period
				from
				January 1,			Year			Astoria									Year
	Year			2007			Ended			February 24,			January 1,			Year			Ended			Year
	Ended			through			December 31,			2006 to			2006 to			Ended			December 31,			Ended
	December 31,			May 31,			2007			December 31,			February 23,			December 31,			2006			December 31,
	2007			2007			as Adjusted			2006			2006			2006			as Adjusted			2005
	(Dollars in thousands)


Beginning cash and cash equivalents	$	44,507		$	8,079		$	52,586		$	—		$	15		$	712		$	727		$	1,559

Net cash (used in) provided by:

Operating activities		141,617			11,763			153,380			119,950			24,715			(19,276	)		125,389			230,783

Investing activities		(95,967	)⁽¹⁾		(1,065	)		(97,032	)		(1,039,676	)		(5,474	)		(6,968	)		(1,052,118	)		(17,639	)

Financing activities		(57,700	)		(16,825	)		(74,525	)		964,233			(18,779	)		33,611			979,065			(214,688	)


Net (decrease) increase in cash and cash equivalents		(12,050	)⁽¹⁾		(6,127	)		(18,177	)		44,507			462			7,367			52,336			(1,544	)


Ending cash and cash equivalents	$	32,457	⁽¹⁾	$	1,952		$	34,409		$	44,507		$	477		$	8,079		$	53,063		$	15


(1)		Values have been adjusted to remove the effect of the Combination.

Operating Activities. Net cash provided by operating activities was approximately $1.6 million in the three months ended March 31, 2008, compared to net cash provided by operating activities of approximately $30.3 million in the same period of 2007. Net cash provided by operating activities was approximately $153.4 million in fiscal 2007 compared to $125.4 million for fiscal 2006 and $230.8 million for the Predecessor in 2005.

Cash provided by operating activities for the three months ended March 31, 2008 was $1.6 million and was impacted by an increase in accounts receivable of $22.3 million and in prepaid expenses and other current assets of $13.3 million. Cash flow from operating activities for the three months ended March 31, 2007 was $30.3 million, primarily the result of strong operating earnings at EBG, excluding the goodwill impairment charge of $250.1 million. Cash flow from operating activities for fiscal 2007 was $153.4 million and was negatively impacted by an increase in accounts receivable of $38.5 million and in deferred taxes of $40.4 million, partially offset by favorable changes to restricted cash of $61.9 million. Cash flow from operating activities for fiscal 2006 was approximately $125.4 million, which was negatively impacted by unfavorable operating earnings at EBG prior to establishment of the FCM capacity market by ISO-NE. Cash flow from operating activities for the Predecessor in 2005 was $230.8 million, impacted by strong operating earnings prior to the addition of 1,000 MW of new generation capacity in NYISO in 2006. See “— Results of Operations.”

Investing Activities. For the three months ended March 31, 2008, cash used in investing activities was approximately $10.0 million compared to approximately $13.7 million for the same period in 2007. Cash used in investing activities was $97.0 million for fiscal 2007, $1,052.1 million for fiscal 2006 and $17.6 million for the Predecessor in 2005.

Cash used in investing activities for the three months ended March 31, 2008 was $10.0 million, including $13.8 million of capital expenditures that was favorably impacted by proceeds from sale of assets of $4.9 million. For the same period in 2007, cash used in investing activities was $13.7 million, comprised of $15.5 million of capital expenditures offset in part by approximately $1.9 million of proceeds from sale of assets. Cash used in investing activities for fiscal 2007 was $97.0 million, including $51.9 million of capital expenditures and expenditures of $50.6 million associated with the Combination, favorably impacted by approximately $5.5 million of proceeds from sale of assets. For fiscal 2006, cash used in investing activities was $1,052.1 million. Included in fiscal 2006 investing activities is $1,002.4 million associated with the MDP Acquisition and $52.4 million of capital expenditures offset by $2.2 million of proceeds from sale of assets.

Cash used in investing activities for the Predecessor in 2005 was $17.6 million, all of which was capital expenditures.

Financing Activities. For the three months ended March 31, 2008, cash used in financing activities was $14.6 million compared to $40.3 million for the three months ended March 31, 2007. Cash used in financing activities was $74.5 million in fiscal 2007, and in fiscal 2006 financing activities provided cash of approximately $979.1 million. In fiscal 2005, the Predecessor used cash in financing activities of $214.7 million.

Cash used in financing activities for the three months ended March 31, 2008 was $14.6 million, comprised of $23.9 million of debt repayments, $2.7 million of final tax distributions to the New Astoria unitholders for that portion of fiscal 2007 when the Successor was a limited liability company, offset by a $12.0 million draw on the BG revolving credit facility (“BG revolver”). For the same period in 2007, cash used in financing activities was $40.3 million and included $23.9 million of debt repayments, a $14.0 million paydown on the BG revolver and $2.4 million of tax distributions to our unitholders. For the year ended December 31, 2007, net cash used in financing activities was approximately $74.5 million. This was comprised of debt repayments of $55.6 million, net paydown on the BG revolver of $10.5 million, tax distributions to our unitholders during that portion of the period when we were a limited liability company of $5.4 million and $3.0 million expended to retire Series B units of New Astoria as part of a settlement agreed in connection with the departure of an executive. Net cash provided by financing activities was approximately $979.1 million in fiscal 2006 compared to net cash used in financing activities of approximately $214.7 million in fiscal 2005. In fiscal 2006, cash provided by financing activities included the issuance of common equity and long-term debt in connection with the MDP Acquisition. Proceeds from the issuance of common equity were $314.4 million and long-term debt proceeds were $657.0 million net of repayments and financing costs. In the year ended December 31, 2005, cash used in financing activities was $214.7 million and reflected the Predecessor distribution of cash to Reliant, Inc.

Supplemental Discussion of EBG Cash Flows

The tables below set forth EBG sources and uses of cash in the periods presented on a stand-alone basis. We have included the Supplemental Discussion in order to better analyze EBG’s contribution to the cash flows of the Successor before and after the Combination. This presentation is not pro forma for the Combination and may yield results that are not strictly comparable on a period-to-period basis primarily due to the impact of the Combination. Such results are not necessarily indicative of what the results for the respective periods would have been had the Combination not occurred. All references to period cash flows in the following discussion are based on the information presented in the table below. The purpose of presenting this table is to provide a convenient reference for the discussion of cash flows that follows due to the significant effects of these events on the comparability of the periods.


	Three Months Ended
	March 31,
	2008			2007
	($ in thousands)

Beginning cash and cash equivalents	$	5,475		$	8,079
Net cash (used in) provided by:
Operating activities		(9,538	)		9,412
Investing activities		(362	)		708
Financing activities		9,175			(16,825	)

Net (decrease) increase in cash and cash equivalents		(725	)		(6,705	)

Ending cash and cash equivalents	$	4,750		$	1,374


							Predecessor/
							Successor
	Successor			Predecessor			Combined			Predecessor
	EBG Period			EBG Period			EBG Year			EBG Year
	from June 1,			from January 1,			Ended			Ended
	2007 to			2007 to			December 31,			December 31,
	December 31,			May 31,			2007			2006
	2007			2007			as Adjusted			Actual
				($ in thousands)

Beginning cash and cash equivalents	$	1,952		$	8,079		$	8,079		$	712
Net cash provided by (used in):
Operating activities		17,418			11,763			29,181			(19,276	)
Investing activities		(8,920	)		(1,065	)		(9,985	)		(6,968	)
Financing activities		(4,975	)		(16,825	)		(21,800	)		33,611

Net increase (decrease) in cash and cash equivalents		3,523			(6,127	)		(2,604	)		7,367

Ending cash and cash equivalents	$	5,475		$	1,952		$	5,475		$	8,079

Operating Activities. Net cash used by operating activities was approximately $9.5 million in the three months ended March 31, 2008, compared to net cash provided by operating activities of approximately $9.4 million in the same period of 2007. Net cash provided by operating activities was approximately $29.2 million in fiscal 2007 compared to net cash used by operating activities of approximately $19.3 million for fiscal 2006.

Cash used by operating activities for the three months ended March 31, 2008 was $9.5 million and was impacted by unfavorable changes in accounts receivable of $14.2 million. Cash flow from operating activities for the three months ended March 31, 2007 was $9.4 million, primarily the result of strong operating earnings, excluding the goodwill impairment charge of $250.1 million. Cash flow from operating activities for fiscal 2007 was $29.2 million and was negatively impacted by unfavorable changes in deferred taxes of $49.4 million, accounts receivable of $33.3 million and prepaid expenses and other current assets of $17.4 million, but benefited from favorable changes to restricted cash of $61.9 million. Cash flow used by operating activities for fiscal 2006 was approximately $19.3 million, which was impacted by unfavorable operating earnings prior to establishment of the FCM capacity market by ISO-NE.

Investing Activities. For the three months ended March 31, 2008 cash used in investing activities was approximately $0.4 million compared to cash provided by investing activities of approximately $0.7 million for the same period in 2007. Cash used in investing activities was approximately $10.0 million for fiscal 2007 and approximately $7.0 million for fiscal 2006.

Cash used in investing activities for the three months ended March 31, 2008 was $0.4 million, including $5.2 million of capital expenditures that was favorably impacted by proceeds from sale of assets of approximately $4.8 million. For the same period in 2007, cash provided by investing activities was $0.7 million, comprised of $1.1 million of capital expenditures offset by approximately $1.8 million of proceeds from sale of assets. Cash used in investing activities for fiscal 2007 was approximately $10.0 million, including $14.0 million of capital expenditures favorably impacted by approximately $4.0 million of proceeds from sale of assets. For fiscal 2006, cash used in investing activities was $7.0 million. Included in 2006 investing activities is $7.5 million of capital expenditures offset by $0.5 million of proceeds from sale of assets.

Financing Activities. For the three months ended March 31, 2008, cash provided by financing activities was $9.2 million compared to cash used by financing activities of $16.8 million for the three months ended March 31, 2007. Cash used in financing activities was $21.8 million in fiscal 2007, and in fiscal 2006 financing activities provided cash of approximately $33.6 million.

Cash provided by financing activities for the three months ended March 31, 2008 was $9.2 million, comprised of a $12.0 million draw on the BG revolver, offset by $2.8 million of debt repayments. For the

same period in 2007, cash used in financing activities was $16.8 million and included a $14.0 million paydown on the BG revolver and $2.8 million of debt repayments. For the year ended December 31, 2007, net cash used in financing activities was approximately $21.8 million. This was comprised of debt repayments of $11.3 million and a net paydown on the BG revolver of $10.5 million. In fiscal 2006, cash provided by financing activities was approximately $33.6 million and included proceeds from long-term debt of $1,030.2 million net of repayments and financing costs, partially offset by $996.6 million in expenditures related to repurchases and distributions to our unitholders.

Capital Expenditures

Our capital expenditures are used primarily to make regularly scheduled repairs to our facilities as well as to cover the cost of maintenance intended to increase capacity and maintain compliance with environmental regulations. For the three months ended March 31, 2008, our capital expenditures were $13.8 million, of which $7.9 million was used by our New York Facilities to perform refurbishment of a major power generation unit and $5.2 million was used by our Boston Facilities primarily in preparation for the scheduled refurbishment of a major power generation unit. This compares with $15.5 million for the same period in 2007, of which approximately $14.4 million was used by our New York Facilities to perform refurbishment of a major power generation unit and the remaining $1.1 million was used by our Boston Facilities for scheduled repair and maintenance.

For fiscal 2007, our capital expenditures were approximately $51.9 million, of which approximately $38.0 million was used by our New York Facilities to perform the refurbishment of a major power generation unit and to upgrade the dock facilities and approximately $13.9 million was used by our Boston Facilities primarily for scheduled repair and maintenance. Our annual capital expenditures are limited by the terms of our senior credit facilities for both our New York and Boston Facilities. Capital expenditures for our New York Facilities and Boston Facilities are limited to annual expenditures of $65.0 million and $10.0 million, respectively. The terms of our credit facility relating to our Boston Facilities also provides for the carryover and pull forward of capital expenditure allowances from years immediately preceding or following the current period, up to a maximum of $30.0 million of capital expenditures in any one year.

Power generation plants like ours require scheduled and unscheduled major maintenance, which can result in prolonged periods when the impacted plant is out of service, a condition referred to as an outage. We typically schedule outages during periods when demand is seasonally low to minimize the overall cash flow impact due to the loss of generating capacity. Scheduled outages during the twelve months ending December 31, 2008 are expected to result in estimated expenditures of approximately $53.6 million. Outage expenditures during the year ended December 31, 2007 were $59.0 million, comprised of $35.3 million of operations and maintenance expenses and $23.7 million of capital expenditures. Outage expenditures during fiscal 2006 were $69.0 million, comprised of $54.1 million of operations and maintenance expenses and $14.9 million of capital expenditures.

Environmental capital expenditures for fiscal 2007 and fiscal 2006 were approximately $1.0 million and $1.1 million, respectively. Based on current environmental regulations, technology and plans, we estimate that approximately $34.2 million of environmental capital expenditures will be incurred during the period 2008 through 2013, primarily related to the installation of variable speed pumps (BTA required per Section 316(b) of the Clean Water Act) and barge double-hulling at our New York Facilities. We update our estimates for environmental capital expenditures annually, and these estimates can be expected to change over time, in some cases materially. These plans are based on current regulatory requirements and best engineering practices. Changes to regulations or market conditions could result in changes to installed equipment timing or associated costs.

The following table summarizes the estimated environmental capital expenditures for the referenced period:


Year	Astoria		EBG		Total
	($ in thousands)

2008	$	580	$	2,250	$	2,830
2009		3,850		2,000		5,850
2010		—		2,000		2,000
2011		7,260		2,000		9,260
2012		7,260		2,000		9,260
2013		3,000		2,000		5,000

Total	$	21,950	$	12,250	$	34,200

Liquidity Position

As of March 31, 2008, our liquidity position was approximately $285.2 million, which was comprised of approximately $107.2 million of unrestricted and restricted cash, $125.5 million of borrowing capacity under existing revolving credit facilities and $52.5 million of availability under existing letter of credit facilities. As of December 31, 2007, our liquidity position was $315.7 million, comprised of $135.3 million of unrestricted and restricted cash, $137.5 million of borrowing capacity under existing revolving credit facilities and $42.9 million of availability under existing letter of credit facilities. As of December 31, 2006, our liquidity position was $402.9 million, which was comprised of $215.3 million of unrestricted and restricted cash, $125.6 million of borrowing capacity under existing revolving credit facilities and $62.0 million of available capacity under existing letter of credit facilities.

The following tables summarize our liquidity position as of the dates presented:


	March 31,		December 31,		December 31,
	2008		2007		2006
			($ in thousands)

Cash and cash equivalents⁽¹⁾	$	107,208	$	135,265	$	215,292
Available under senior revolving credit facilities		125,472		137,500		125,600
Available under letter of credit facilities		52,470		42,900		62,000

Total liquidity	$	285,150	$	315,665	$	402,892


	Astoria						EBG
	March 31,		December 31,		December 31,		March 31,		December 31,		December 31,
	2008		2007		2006		2008		2007		2006
	($ in thousands)						($ in thousands)

Cash and cash equivalents⁽¹⁾	$	6,546	$	28,934	$	44,506	$	100,662	$	106,331	$	170,786
Available under senior revolving credit facilities		96,972		97,000		95,600		28,500		40,500		30,000
Available under letter of credit facilities		—		—		—		52,470		42,900		62,000

Total liquidity	$	103,518	$	125,934	$	140,106	$	181,632	$	189,731	$	262,786


(1)		Includes restricted cash.

Our existing credit facilities impose restrictions on our ability to transfer cash between our Astoria and EBG operating subsidiaries. Therefore, we assess the adequacy of our liquidity based on the needs of each operating unit separately.

Power generating companies typically require a significant amount of liquidity and capital resources. As part of our business strategy, we have sought to fund our operations in a cost effective manner. To secure our

obligations, we have in many instances granted our contractual counterparties a first lien security interest in our assets in order to reduce the amount of cash collateral and letters of credit we may otherwise be required to post to support such obligations. As of March 31, 2008, we had $29.5 million of total cash collateral outstanding and $200.6 million of outstanding letters of credit that were issued to third parties primarily to support our derivative instruments. In addition to our collateral requirements for derivative instruments, we sometimes experience liquidity requirements in connection with the establishment of power dispatch and fuel procurement relationships and the purchase of commodities.

Our liquidity needs vary seasonally in a manner consistent with the other seasonal variations in our business. As a result, at certain times during the year our cash flows may not be sufficient to cover our total cash needs, especially during those periods accompanied by a major plant outage. During periods such as these, we would experience lower cash flows from operations due to lower generation and higher cash outflows for capital and maintenance expenditures due to the outage. When this occurs we utilize our existing cash on hand and borrowings available under our senior revolving credit facilities to meet our cash needs.

Existing Credit Facilities

Astoria. In connection with the MDP Acquisition, Astoria entered into a credit facility consisting of a first lien facility, a second lien facility and a special letter of credit facility (collectively, the “Astoria credit facilities”). The first lien facility includes: (i) a working capital revolving facility, which permits borrowings up to $100.0 million (“Astoria revolver”); (ii) a term loan of $430.0 million (“Astoria term loan B”); and (iii) a funded synthetic term LC facility pursuant to which letters of credit could be issued up to $120.0 million (“Astoria term loan LC”). The Astoria term loan LC was fully repaid and terminated in December 2006. As of March 31, 2008, $0 was outstanding under the Astoria revolver, and $326.4 million was outstanding under Astoria term loan B, with an average interest rate of 4.4%.

The Astoria revolver provides for the issuance of up to $60.0 million in letters of credit. As of March 31, 2008, Astoria had approximately $3.0 million in letters of credit outstanding.

The Astoria second lien facility includes a $300.0 million term loan facility. As of March 31, 2008, Astoria had $300.0 million outstanding under its second lien facility, with an average interest rate of 6.4%.

The Astoria special letter of credit facility matured on October 31, 2007 and was repaid at that time.

EBG. In December 2006, BG, a wholly-owned subsidiary of EBG, entered into a secured credit facility consisting of a first and second lien credit facility. The first lien facility includes: (i) the BG revolver, which permits borrowings up to $70.0 million; (ii) a $1,130.0 million term loan facility (“BG term loan B”); and (iii) a synthetic letter of credit facility pursuant to which letters of credit can be issued up to $250.0 million (“BG synthetic LC”). As of March 31, 2008, BG had approximately $41.5 million outstanding under the BG revolver, with an average interest rate of 4.9%, $1,115.9 million outstanding under the BG term loan B, with an average interest rate of 4.9%, and approximately $197.5 million in letters of credit outstanding under the BG synthetic LC.

The BG second lien facility includes a $350.0 million term loan facility. As of March 31, 2008, BG had approximately $350.0 million outstanding under the BG second lien facility, with an average interest rate of 6.9%.

In December 2006, EBG entered into an unsecured credit facility consisting of a $300.0 million term loan. As of March 31, 2008, EBG had approximately $350.7 million outstanding under this facility, with an average interest rate of 9.7%. Under this facility, EBG has the option to pay interest in either cash or by increasing the principal amount of the term loan. To date, EBG has elected to pay interest by increasing the principal amount of the term loan.

Covenants. Our senior credit facilities contain covenants that may restrict our and our subsidiaries’ ability to make payments or distributions (including dividends) with respect to our capital stock or otherwise restrict payments or distributions to our equity holders, prepay other debt, encumber our assets, incur additional indebtedness, make capital expenditures above specified levels, engage in business combinations or undertake various other corporate activities. Our senior credit facilities also limit the type and value of

affiliated transactions that we can undertake, which may limit our ability to realize synergies resulting from the Combination. These covenants also require us to maintain certain specified financial ratios, relating to total leverage and interest coverage. As of March 31, 2008, we were in compliance with our financial and restrictive covenants under each of our credit facilities. See “Description of Principal Indebtedness.”

The Astoria credit facilities contain certain financial covenants requiring Astoria to maintain minimum levels of interest coverage and imposing maximum levels of leverage. While we were within the limits of those covenants at March 31, 2008 and December 31, 2007, our current operating projections indicate a significant increase in the leverage ratio during the next five quarters. These projections have been negatively affected by recent developments in the New York City (Zone J) capacity markets, described in “— NYISO Changes to Market Structure.” We expect to remain in compliance with this covenant for the foreseeable future. The Astoria credit facilities contain an equity cure provision that allows us to invest additional capital into Astoria in order to cure any financial covenant defaults.

The BG credit facilities contain certain financial covenants requiring BG to maintain minimum interest coverage ratios and maximum debt to EBITDA levels. In addition, the BG credit facilities required us to establish a post closing contingency account, which is carried on our balance sheet as restricted cash. The purpose of this account was to ensure that sufficient working capital was available to meet certain obligations anticipated at the closing of the BG credit facilities. Those obligations related to the settlement of an RMR dispute with ISO-NE and the Distrigas litigation related to the natural gas supply contract at certain of our facilities. See “Business — Fuel Supply and Transportation.”

At the time the BG credit facilities were closed it was anticipated that we would be required to make a refund of revenues collected under the RMR agreement we had with ISO-NE that was terminated in December 2006. Also, at that time we were potentially required to make payments of liquidated damages under the Distrigas contract which amounts were in dispute. Both contingencies were resolved with final payments made to ISO-NE and Distrigas pursuant to their respective settlement agreements. The RMR settlement was finalized in April 2007 and the Distrigas settlement was finalized in April 2008. At March 31, 2008, the post-closing contingency account had a balance, in excess of the settlement payments, of approximately $67.6 million, which became available for inclusion in calculating compliance EBITDA. The transfer of excess amounts from the reserve account is eligible, under the BG credit facilities, to be used in the determination of covenant compliance.

While we were within the limits of the financial covenants at December 31, 2007 without transfers from the post-closing contingency account, we were required to transfer approximately $2.5 million from the post-closing contingency account to comply with the financial covenants at March 31, 2008. We anticipate additional releases from the post-closing contingency account in the future to ensure covenant compliance under the BG credit facilities. In addition, similar to the Astoria credit facilities discussed above, the BG credit facilities also contain an equity cure provision whereby any financial covenant default could be cured with the investment of additional capital by EBG. The equity cure provision of the BG credit facilities may only be used once every four quarters. Any net proceeds of this offering that are contributed to BG will be available for purposes of the equity cure provision of the BG credit facilities.

Currently, there is approximately $65.1 million of cash in the post-closing contingency account available to maintain future compliance with the financial covenants contained in the BG credit facilities. Our current operating projections with respect to our Boston Facilities indicate that the remaining funds in the post-closing contingency account will be transferred to operating accounts over the next five quarters to ensure covenant compliance under the BG credit facilities. Following this period, we may not be able to remain in compliance with our financial covenants under the BG credit facilities. USPowerGen may need to contribute a portion of the net proceeds of this offering to BG in the form of a capital contribution in order for BG to remain in compliance with the financial covenants contained in the BG credit facilities.

In the event we do not have sufficient funds in the post-closing contingency account or at USPowerGen in order to remain in compliance under the BG or Astoria credit facilities, we would either have to seek a waiver of such covenant compliance from the respective lenders under such senior credit facilities or seek to raise additional equity capital to fund any required payments.

Credit Ratings

Credit rating agencies rate our bank debt and their ratings are utilized by lenders to evaluate our credit worthiness. Ratings influence the price we pay to borrow money and our ability to utilize secured lien positions in place of cash or standby letter of credit collateral with counterparties. Rating agencies evaluate a firm’s industry, cash flow, leverage, liquidity and hedge profile, among other factors, in their credit analysis of a firm’s credit worthiness.

The table below summarizes the credit ratings related to our senior secured credit facilities at March 31, 2008:

Astoria

Moody’s

S&P

Moody’s

S&P

Senior revolving credit facility

BB-

B+

First lien senior term loan

BB-

B+

Second lien senior term loan

B-

Mezzanine loan facility

N/A

On August 1, 2008, Moody’s Investor Service issued a press release indicating that the BG first lien senior term loan and the BG second lien senior term loan have been placed under review for possible downgrade.

Net Operating Loss Carryforwards, Deferred Tax Assets and FIN 48 Implications

EBG generated NOLs for the three months ended March 31, 2008, which were partially used to offset taxable income generated at Astoria and USPowerGen. However, we do not currently believe that the NOLs will be realized going forward. Therefore, a valuation allowance for the full amount of the NOLs has been recorded at March 31, 2008 for the NOLs generated during the first quarter as well as NOL carryforwards from prior periods, and related deferred tax assets.

From the date of the MDP Acquisition, February 23, 2006, until the date of the Combination, June 1, 2007 we were a limited liability company with no state or federal income tax obligations and we did not have any interest and penalties on income taxes in any of the periods presented. Significant judgment is required in determining our company’s income tax provision and recording the related income tax assets and liabilities. In the ordinary course of business, there are many transactions and calculations where this judgment must be applied. FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), clarifies disclosure and recognition of uncertain tax positions. It requires that we determine whether tax positions are more likely than not to be sustained upon examination based upon their technical merits. In assessing our tax positions, we have based those positions on clear and unambiguous tax law. Therefore, we have determined that there are no material tax positions that would require recognition of any uncertain tax positions.

Material Weakness Report

In connection with the audit of the consolidated financial statements of Astoria for the year ended December 31, 2006, our independent auditors reported to our Board of Directors that there existed material weaknesses in our internal controls. The following are the material weaknesses identified by our independent auditors:


	•	Enhancement of Accounting Personnel — the auditors noted that because of the volume and significance of audit adjustments to our consolidated financial statements and the failure to review and understand the accounting significance of material agreements, the technical competence of our accounting personnel constituted a material weakness.

	•	Completeness of Accounts Payable and Accrued Expenses — the auditors noted that our controls and procedures to ensure that all costs were properly captured in the correct financial reporting period were ineffective and constituted a material weakness.

We have developed and are implementing a plan to remediate these material weaknesses. We have expanded our professional accounting and internal audit personnel and are recruiting additional personnel to further enhance our accounting and reporting functions. In addition, we have retained the services of two consulting firms to supplement our accounting functions. We have also implemented additional controls and procedures over the timely recording of costs and are routinely monitoring their effectiveness in capturing costs in the correct financial reporting periods. No material weaknesses were identified in connection with the 2007 audit.

Off-Balance Sheet Instruments and Other Contractual Arrangements

Our off-balance sheet arrangements consist of our operating leases and outstanding letters of credit.

Contractual Obligations and Commercial Commitments

The table below summarizes our contractual obligations as of March 31, 2008. For additional information, see Note 13 to our consolidated financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. We have a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to our capital expenditure programs.


	By Remaining Maturity
	2008		2009		2010		2011		2012		Thereafter
					($ in thousands)

Contractual Obligations:
Long-term debt	$	11,700	$	15,600	$	15,600	$	15,600	$	15,600	$	2,410,395
Natural gas supply agreement		129,654		172,872		172,872		172,872		172,872		1,714,314
Long-term service agreements		20,395		27,193		27,190		23,710		—		—
Transportation services — fuel		21,458		18,055		18,055		18,055		18,055		75,552
Operating leases		1,539		1,911		1,742		937		955		3,662

Total contractual obligations	$	187,746	$	235,631	$	235,459	$	231,174	$	207,482	$	4,203,923

Set forth below is a summary of certain of the agreements relating to our contractual obligations:

Fuel Supply and Transportation Agreements. Our global fuel requirements consist primarily of natural gas and fuel oil. The prices of natural gas and fuel oil are subject to macro- and micro-economic forces that can change dramatically in both the short and long term. We obtain our natural gas and fuel oil primarily from Sequent and Distrigas. In addition, Iroquois Gas Transmission System, L.P. (“Iroquois”), KeySpan Energy Delivery New England and KeySpan Energy Delivery New York (together, “KeySpan”) and Spectra Energy (“Spectra”) provide fuel transportation services for us. Although availability is generally not an issue, localized shortages, transportation availability and supplier financial stability issues can and do occur. Issues related to the sources and availability of raw materials are fairly uniform across our business.

Facility Maintenance Agreements. We have two long-term services agreements with MPS under which MPS provides all major maintenance services, including refurbishment of spare parts, for our gas turbine generators and related equipment at our Mystic 8&9 and Fore River facilities. Under these agreements, MPS receives a fixed fee for monitoring this equipment and a variable fee based on the number of equivalent operating hours incurred by this equipment, and each of these fees is paid on a monthly basis.

Derivative Instruments. We may enter into long-term power sales contracts, fuel purchase contracts and other energy-related derivative instruments to mitigate variability in earnings due to fluctuations in spot market prices, to manage fuel requirements at generation facilities and protect fuel inventories. In addition, to mitigate interest rate risk associated with the issuance of our variable rate debt, we enter into interest rate swap and cap agreements.

The tables below disclose the activities that include non-exchange traded contracts accounted for at fair value. Specifically, these tables: (i) disaggregate realized and unrealized changes in fair value; (ii) identify changes in fair value attributable to changes in valuation techniques; (iii) disaggregate estimated fair values at

March 31, 2008, based on whether fair values are determined by quoted market prices or more subjective means; and (iv) indicate the maturities of contracts at March 31, 2008.

Derivative Activity Gains/(Losses)


	($ in Thousands)

Fair value of contracts as of December 31, 2006	$	5,931
Initial value of contracts acquired in the Combination		15,683
Fair value of new contracts executed during the period		523
Settlements and maturities of positions held as of December 31, 2006		(14,250	)
Settlements and maturities of positions added during 2007		(23,711	)
Realized loss in excess of previous fair value estimate		36,156
Change in fair value of unmatured positions held as of December 31, 2006 or acquired in the Combination		(103,406	)

Fair value of contracts as of December 31, 2007		(83,074	)
Fair value of new contracts executed during the period		—
Settlements and maturities of positions held as of December 31, 2007		(15,285	)
Settlements and maturities of positions added during 2008		(11,317	)
Realized loss in excess of previous fair value estimate		63,738
Change in fair value of unmatured positions held as of December 31, 2007		(53,601	)

Fair value of contracts as of March 31, 2008	$	(99,539	)

Sources of Fair Value Gains/(Losses)


	Fair Value of Contracts as of March 31, 2008											Fair Value of Contracts as of December 31, 2007
	Maturity						Maturity		Total			Maturity						Maturity			Total
	Less Than			Maturity			Greater Than		Fair			Less Than			Maturity			Greater Than			Fair
	1 Year			1-3 Yrs			3 Years		Value			1 Year			1-3 Yrs			3 Years			Value

Prices provided by other external sources	$	(37,334	)	$	(49,327	)	$	—	$	(86,661	)	$	(16,362	)	$	(37,593	)	$	(724	)	$	(54,679	)
Prices provided by models and other valuation methods with one or more unobservable inputs		(1,623	)		(11,255	)		—		(12,878	)		(34,201	)		5,806			—			(28,395	)

Totals	$	(38,957	)	$	(60,582	)	$	—	$	(99,539	)	$	(50,563	)	$	(31,787	)	$	(724	)	$	(83,074	)

Critical Accounting Policies and Estimates

The audited financial statements contained in this prospectus have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and assumptions which we believe to be reasonable under the circumstances. Those estimates form the basis of our judgments that affect the amounts reported in the financial statements. Actual results could differ from our estimates under different assumptions or conditions. Our significant accounting policies, which may be affected by our estimates and assumptions, are more fully described in the Notes to our financial statements, which appear elsewhere in this prospectus. We believe the following to be the most critical of those accounting policies that necessitate subjective judgments.

Revenue recognition

We recognize revenues from the sale of electricity when earned and collection is reasonably assured. We recognize revenues when electric power is delivered to a customer pursuant to contractual commitments that specify volume, price and delivery requirements. Some sales of electricity are based on economic dispatch, or “as-ordered” by an ISO, based on member participation agreements, but without an underlying contractual commitment. ISO revenues and revenues from sales of electricity based on economic dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices. When a long-term electric power agreement permits the buyer of the electric power to use the generating capacity of our generation plants, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power. None of our capacity arrangements qualify as leases. Capacity revenues are recognized when contractually earned on a straight-line basis in accordance with Emerging Issues Task Force 91-6, Revenue Recognition of Long-Term Power Sales Contracts, and consist of revenues received from third parties at either the market or negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.

Derivative Instruments

We account for our derivative instruments in accordance with SFAS 133. In connection with our energy commodity price and interest rate hedging activities, we use various contracts that provide for cash net settlements. The contracts meet the definition of derivative instruments promulgated by SFAS 133. As of March 31, 2008, we did not use hedge accounting in connection with any of our derivative instruments, either because the contracts did not meet the requisite criteria to qualify for hedge accounting treatment under SFAS 133, or we elected not to designate them as accounting hedges at inception or upon acquisition in connection with the Combination. As derivative instruments, we measure and report the fair value of our derivative contracts in our consolidated statements of financial position. Because hedge accounting is not utilized, changes in the fair value are recognized on a current basis as a component of net income reported in our consolidated statements of operations.

When measuring the fair value of derivatives instruments, in accordance with Statement of Financial Accounting Standards No. 157 Fair Value Measurements (“SFAS 157”), which we adopted with respect to our financial assets and financial liabilities as of January 1, 2008, we utilize a variety of sources, including: (a) third party price quotations for similar instruments in actively traded markets (Level 2 inputs), (b) third party quotations in connection with valuation model inputs that are directly or indirectly observable for similar instruments in active markets; for example, interest rates, yield curves, credit default risk premiums, and forward commodity price curves and volatilities (Level 2 inputs), (c) inputs that are derived principally from or corroborated by observable market data by correlation or other analytical (Level 2 input), and in certain cases (d) price, volatility and other valuation model inputs that are not directly observable based on models and other valuation methods (Level 2 input). Specifically, we utilize quoted exchange prices and broker or counterparty quotes when and to the extent available. For our interest rate derivatives, we utilize counterparty quotes, which we validated with third party quotes and internally developed models. We utilize internally developed models to measure the fair value of our operating risk management derivatives. For energy related derivatives, we estimate future prices of energy, specifically the relationship between natural gas and electricity prices, for a specific market. When estimating these relationships, we use externally available forward market pricing curves as provided by brokers when available. To the extent such curves are not available for a specific market or commodity, we utilize information for similarly situated markets and/or commodities to estimate the relationship with the underlying reference commodity and market of the derivative contract. We utilize an internally developed model to measure the fair value of our New York capacity derivative, which due to the nature of the market, relies upon internally generated forward capacity price curves, which cannot be fully supported by observable data.

Significant changes in the fair value of our derivative instruments could result were we to use alternative quotation sources, commodity quotation references and/or markets, and/or valuation methodologies to measure the fair value of our derivative contracts. Furthermore, our estimates include certain forward-looking assumptions that may deviate from historical relationships. We evaluate these deviations to ensure they are

consistent and reasonable assumptions of future market relationships. However, were we to solely utilize a historical approach, the MTM valuations could be materially different.

Asset Impairments

In accordance with Statement of Financial Accounting Standards 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate long-lived assets when changes in events or circumstances indicate potential for impairment. Impairment for assets held for use is evaluated based upon a comparison of the carrying value and the total future undiscounted cash flows of the asset. An impairment loss is recognized when the carrying value exceeds the total future undiscounted cash flows.

In determining asset impairments, we evaluate triggering events in the context of available market data as well as our own experiences related to the sale of similar type assets. Upon an indication of a triggering event, we utilize an undiscounted future cash flow to determine recoverability. This undiscounted future cash flow is subject to various assumptions by management as to future results of operations, which can significantly impact the results of the analysis. Key assumptions that impact the impairment test include: estimated useful remaining lives of the assets, environmental obligations of operating the assets, estimates of future cash flows, estimates concerning fair value, judgments made by management about triggering events, and assumptions concerning regulatory and political disposition toward the power generation sector in general. Alternative assumptions could yield a different outcome. In determining the amount of impairment, we utilize third-party market data for similar types of assets to the extent available. To the extent this data is unavailable, we utilize a discounted cash flow analysis. This discounted cash flow analysis is also subject to management’s assumptions, including the appropriate discount rate to utilize, changes in which could result in different impairment amounts.

Income Taxes

We account for income taxes using the liability method in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences. We have two categories of income tax expense or benefit: current and deferred. Current income tax expense or benefits consist solely of regular tax less applicable tax credits, and deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income. We report some of our revenues and expenses differently for financial statement purposes than for income tax return purposes resulting in temporary and permanent differences between our financial statements and income tax returns. The tax effects of temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in our consolidated balance sheets. We measure deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. A valuation allowance is recorded to reduce our net deferred tax assets to an amount that is more likely than not to be realized. We account for uncertain tax positions pursuant to FIN 48. Our policy for classification of interest and penalties on income taxes is to record such amounts as a component of the provision for income taxes. We did not have any interest and penalties on income taxes for the periods presented.

Goodwill and Intangible Assets

We account for goodwill and intangible assets in accordance with SFAS 142 at the reporting unit level at least annually or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carry amount. SFAS 142 requires a two-step impairment test. Step 1 of the test is used to identify whether a goodwill impairment may exist by comparing the fair value of a reporting unit with its carrying amount. If a reporting unit’s carrying amount exceeds it fair value, a goodwill impairment may exist. Step 2 of the test is then performed to determine the amount of the impairment, if any. In step 2, an entity compares the implied fair value of goodwill with its carrying amount. An impairment loss is measured by the excess of the carrying amount of goodwill over its implied fair value.

Calculation of goodwill and the testing for impairment is subject to significant judgment of and estimates made by management. Key factors impacting these calculations include the estimated fair value of the assets,

judgments made by management about impairment triggering events and the estimated useful lives of the assets. In the calculation of goodwill and in testing for impairment, we largely utilize valuation estimates for our business based upon a discounted cash flow model. As such, we are required to make assumptions as to EBITDA growth, future capital expenditures as well as determination of an appropriate discount rate. We utilize a discounted cash flow model due to the lack of an actively traded market in our stock and the lack of comparability between our business and other public independent power providers. Specifically, our business is uniquely situated in dense urban locations. Although we evaluate other public independent power providers valuations in the context of determining reasonableness for our own internal assessment, we do not solely rely upon these comparisons. If we were to rely on a strictly market-based comparison, calculation of goodwill and impairment testing could be materially different.

Equity-Based Compensation

We account for equity-based compensation in accordance with Statement of Financial Accounting Standards No. 123(R) Share-Based Payment (“SFAS 123(R)”), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options and unit awards, based on estimated fair values recognized over the requisite service period. We adopted SFAS 123(R) in connection with our initial share-based payment award on February 23, 2006, made at the time of the MDP Acquisition. Prior to the February 23, 2006 award, we did not have share-based payment awards and therefore we were not required to transition from another accounting policy.

We made the following grants of Series B restricted common units (“Series B Units”) to employees from February 23, 2006 through March 31, 2008:

New Astoria Units
(Amounts in whole dollars)


	Number of		Purchase
	Series B		Price per		Fair Value per
Grant Date	Units		Unit		Series B Unit

February 23, 2006		567	$	—	$	4,398
December 31, 2006		105	$	—		122,367
February 16, 2007		28	$	—		130,144

As of March 31, 2008, we had 623 Series B Units outstanding from the grants made on February 23, 2006, December 31, 2006 and February 16, 2007. During 2007, we repurchased 48.5 Series B Units and cancelled 28.5 Series B Units in connection with the departure of an executive officer. The 28.5 Series B Units that were cancelled will be available for granting by us.

Determining the estimated fair value of our Series A and Series B Units requires making complex and subjective judgments. For our initial share-based payment award on February 23, 2006, we estimated the fair value of each Series B Unit based upon an enterprise value that was derived from the purchase price of our New York Facilities. The MDP Acquisition resulted from a competitive auction and the purchase price was determined to be the best indicator of the fair value of the enterprise at that date. We conducted a retrospective valuation using the purchase price of the New York Facilities as the basis for estimating the enterprise value. Due to the nature of the method used in estimating the fair value of the Series B award at February 23, 2006 we did not obtain a contemporaneous valuation as of the date of the issuance. We conducted the retrospective valuation in connection with our annual financial statement closing process.

For the grants made on December 31, 2006 and February 16, 2007, we estimated the fair value based upon a retrospective valuation by using the income approach to estimate the value of the enterprise at each date on which awards were made. We did not obtain a contemporaneous valuation for the Series B Units in connection with the December 31, 2006 and February 16, 2007 awards due to the proportionately small number awarded and the short period of time between initial award and the subsequent awards. We obtained retrospective valuations as soon as practicable after the awards were made. The income approach involves

applying appropriate discount rates to estimated cash flows that were based on forecasts of revenues and costs. Our revenue forecasts were based on an expected annual growth rate of 13% which is driven by publicly available estimates of demand growth for electricity in the ISO markets we serve. Due to the high degree of correlation between our variable costs of operation and the price of electric energy our forecast was based on electric energy revenues net of fuel expense margins and assumed that the revenues net of fuel margin would remain stable. We expect our operations and maintenance costs to grow at an annual rate that approximates the anticipated inflation rate of the general economy. The assumptions underlying the estimates are consistent with our business plan. The risks associated with achieving our forecasts were assessed in selecting the appropriate discount rates, which ranged from 8.5% to 9.0%. If different discount rates had been used, the valuations would have differed.

Due to the competitive nature of the auction process preceding the MDP Acquisition, we believed that the enterprise value and aggregate equity value derived from this transaction were representative of their respective fair values. We used a lattice option-pricing method to allocate our aggregate equity value between our Series A and Series B Units. We determined that the option-pricing method was the most appropriate method to use in estimating the value of the Series B Units given our expectations related to: (i) potential growth opportunities; (ii) expected time to liquidity event; (iii) subjectivity with regards to estimating possible proceeds from a future liquidity event; and (iv) complex capital structure and distribution of returns. Specifically, we utilized a multi-period binomial option-pricing model. Our option-pricing model utilized the following key assumptions:



• Stock Price		Underlying total equity value of $241.8 million
• Expected Term		Assumed that a liquidity event will occur in September 2008
• Volatility		40% based on an analysis of the historical volatility of comparable companies using daily stock price returns
• Risk Free Rate		4.70% based on the three-year U.S. Treasury rate as of the valuation date

Using the option-pricing method and the assumptions detailed above, we determined that the estimated value of a Series B Unit was equal to $4,398 per unit. We assumed a 2.6 year holding period based upon an expected exit event in September 2008, which we considered reasonable at the time based on typical targeted holding periods for private equity funds. Because we had just acquired the New York Facilities and assembled a new management team, we considered an exit event that is typical for private equity funds as the most appropriate outcome for us.

The allocation of value between our Series A and Series B Units considered the impact of certain rights related to the Series A and restrictions related to the Series B Units. Our estimate of the total equity value to be used in the option-pricing model was subject to a minority discount of 23.1%. We determined this discount based upon the following:



• Liquidity		The holders of Series A common units have redemption rights and registration rights that enhance the liquidity of the Series A common units. Additionally, the holders of Series A common units have first refusal rights and co-sale rights that reduce the liquidity of the Series B Units.
• Valuation		The holders of Series A common units have protection from dilution and declines in future value.
• Control		The holders of Series A common units have voting rights, protective provisions and veto rights, board composition rights, drag-along rights, participation rights, first refusal rights, co-sale rights, management rights and information rights that the holders of Series B do not have.

The option-pricing model, using the assumptions detailed above, resulted in an estimated value for Series B Units of $6,421 per unit on a minority, marketable basis. That value was adjusted to reflect the lack of marketability using a put option analysis in which the discount for lack of marketability is expressed as a ratio of the put option value to the exercise price. Based on the put option analysis, a discount for lack of marketability of 31.5% was applied to the minority, marketable value of a Series B Unit to estimate the

minority, non-marketable value of one Series B Unit. Therefore, the estimated value of one minority, non-marketable Series B Unit was $4,398 per unit.

On December 31, 2006, we determined that the estimated fair value of the Series B Units had increased from $4,398 on a minority, non-marketable basis to $122,367 on a minority, non-marketable basis. The change in fair value between February 23, 2006 and December 31, 2006 is related to the difference in valuation methodologies used to estimate the enterprise value at those dates. On December 31, 2006, the enterprise value was estimated using an income approach valuation which was based on a discounted cash flow analysis (“DCF”). Consistent with the approach used for the February 23, 2006 grant, we used an option-pricing model to determine the estimated allocation of the total equity value between Series A and Series B Units. Specifically, we utilized a multi-period binomial option-pricing model and the following key assumptions:



• Stock Price		Underlying total equity value of $1,260 million
• Expected Term		Assumed that a liquidity event will occur in September 2008
• Volatility		33% based on an analysis of the historical volatility of comparable companies using daily stock price returns
• Risk Free Rate		5.00% based on the three-year U.S. Treasury rate as of the valuation date

Using the option-pricing method and the assumptions detailed above, we determined that the estimated value of a Series B Unit was equal to $122,367 per unit. We assumed a 1.8 year holding period based upon an expected exit event in September 2008, which was consistent with the assumption we used for the February 23, 2006 grant.

The allocation of value between our Series A and Series B Units considered the impact of certain rights related to the Series A and restrictions related to the Series B Units, which were consistent with those existing at February 23, 2006.

The option-pricing model resulted in an estimated value for Series B Units of $164,877 per unit on a minority, marketable basis. That value was adjusted to reflect the lack of marketability using a put option analysis in which the discount for lack of marketability is expressed as a ratio of the put option value to the exercise price. Based on the put option analysis, a discount for lack of marketability of 19.4% was applied to the minority, marketable value of a Series B Unit to estimate the minority, non-marketable value of one Series B Unit. Therefore, the estimated value of one minority, non-marketable Series B Unit is $122,367 per unit.

On February 16, 2007, we determined that the estimated fair value of the Series B Units had increased from $122,367 on a minority, non-marketable basis to $130,144 on a minority, non-marketable basis. The change in fair value between December 31, 2006 and February 16, 2007, which is relatively small, is related to the time value of money factors in the DCF analysis. Consistent with the approach used for the February 23, 2006 and December 31, 2007 grants, we used an option-pricing model to determine the estimated allocation of the total equity value between Series A and Series B Units. Specifically, we utilized a multi-period binomial option-pricing model and the following key assumptions:



• Stock Price		Underlying total equity value of $1,282 million
• Expected Term		Assumed that a liquidity event will occur in September 2008
• Volatility		32% based on an analysis of the historical volatility of comparable companies using daily stock price returns
• Risk Free Rate		4.94% based on the three-year U.S. Treasury rate as of the valuation date

Using the option-pricing method and the assumptions detailed above, we determined that the estimated value of a Series B Unit was equal to $130,144 per unit. We assumed a 1.6 year holding period based upon an expected exit event in September 2008, which was consistent with the assumptions we used for the February 23, 2006 and December 31, 2006 grants.

The option-pricing model resulted in an estimated value for Series B Units of $172,783 per unit on a minority, marketable basis. That value was adjusted to reflect the lack of marketability using a put option analysis in which the discount for lack of marketability is expressed as a ratio of the put option value to the exercise price. Based on the put option analysis, a discount for lack of marketability of 18.2% was applied to the minority, marketable value of a Series B Unit to estimate the minority, non-marketable value of one Series B Unit. Therefore, the estimated value of one minority, non-marketable Series B Unit is $130,144 per unit.

Inflation

Inflation can affect us in two principal ways. First, the interest on a significant portion of our debt is tied to prevailing short-term interest rates that may change due to changes in inflation rates, translating into changes in our interest expense. Second, inflation can impact energy, labor and other costs. We do not believe that inflation has had a material effect on our business, financial condition or results of operations in recent years. However, if our costs were to become subject to significant inflationary pressures, either as described above or otherwise, we may not be able to fully offset such higher costs through higher revenues.

Quantitative and Qualitative Disclosures about Market Risk

As described above, in the ordinary course of our business, we are exposed to potential losses arising from changes in interest rates and the prices of electric energy, capacity, natural gas and fuel oil. We use derivative instruments to reduce the volatility of our revenues from sales of electric energy generation and capacity obligations and to reduce borrowing costs associated with our variable rate debt. These instruments are types of “hedges,” and are generally in the form of “swaps” or “index” contracts with counterparties willing to assume certain risks or volatility that are inherent in our business. These contracts are expected to provide us, as described below, with a more predictable revenue stream. As further described above, when we use derivative instruments to reduce our exposure to price changes, we limit our upside exposure to potential gains, but also seek to limit our downside exposure to potential losses.

Accordingly, our risk management policy seeks to meet our overall goal of managing our exposure to market price risk, particularly risks related to changing electric energy and capacity prices, to attempt to ensure a more predictable revenue stream. All of our derivative instrument contracts are held for purposes other than trading, and are used primarily to mitigate the volatility of our expected cash flow. The use of derivatives exposes us to losses in the event of non-performance by the counterparties to the derivative instruments we enter into. Derivative instrument counterparties are typically investment banks or large investment grade participants in energy markets and are evaluated for creditworthiness and risk assessment both prior to our initiating contract activities and on an ongoing basis.

Interest Rate Risk

We are subject to interest rate risk in connection with our Astoria and EBG senior credit facilities. These facilities provide for aggregate borrowings of up to $2.5 billion as of March 31, 2008. All of these facilities bear interest at variable rates. Assuming that our senior credit facilities are fully drawn and that market and other conditions that impact our business remain constant, and excluding the impact of any derivative instruments, each one percentage point change in interest rates would be expected to have a cumulative impact of approximately $24.9 million on our pre-tax earnings and $21.6 million on our cash flows. As of March 31, 2008, we had derivative instruments designed to limit interest rate risk in place covering approximately 84% of Astoria debt and 64% of EBG debt. These derivative instruments primarily involve the exchange of a portion of our floating rate interest obligations for fixed rate interest obligations or a cap on our exposure to floating interest rates to reduce our exposure to the volatility of interest rates. The last of these derivative instruments will expire on March 23, 2011 for Astoria and December 31, 2010 for EBG. We may enter into additional interest rate derivative instruments in the future to seek to reduce interest rate volatility. We cannot assure you, however, that any interest rate derivative instruments we implement will be effective.

Energy and Capacity Price Risk

Our business consists principally of the sale of electric energy and capacity. As a result, our revenues may be significantly impacted by changes in the market prices of electric energy and capacity. To produce electric energy and maintain our capacity requirements, we consume substantial amounts of fuel in our commercial operations, and therefore our cost of sales is vulnerable to changes in prevailing energy prices, particularly natural gas and fuel oil, our main sources of fuel.

To mitigate our risk and exposure to the uncertainties of changing energy and fuel prices, we may enter into short- or long-term power sales contracts, fuel purchase contracts and other energy related derivative instruments to reduce our exposure to changes in our cash flows. These changes may be caused by changes in “spot” power and fuel market prices, which are prices for these commodities that are immediately deliverable. These contracts also allow us to manage current and future fuel requirements at our generation facilities while effectively dispatching our current fuel inventories. Our risk management strategy employs what we refer to as (a) “static hedges” and (b) “active hedges.” The static hedges tend to be highly structured derivative instruments that are executed for two to five years and involve hundreds of MWs of generation. The counterparty pays us a fixed price and receives a variable revenue stream which is based on the difference between the market price for energy and the contract strike price. The contract strike price is intended to approximate the variable operating expenses of our generating units. We prefer to use static hedges when counterparties are willing and able to take on these positions at prices we find favorable.

Often, however, our counterparties discount the prices they pay us for static hedges relative to active hedges because they assume considerable risk by being unable to immediately sell offsetting net positions in the markets. For this reason, we also use “active hedging” strategies when we are unable to find favorable prices for static hedges. Active hedges work by continuously examining the market for opportunities and buying or selling energy positions based on our portfolio exposure in various time horizons. Active strategies manage the residual post-static hedge positions we maintain at each of the Astoria and EBG portfolios to expiration and take into account all aspects of the business and risk management portfolio we maintain (including actual plant performance, outage insurance contracts and previously transacted active and static hedges).

As of January 1, 2008, we executed derivative instruments for a substantial portion of the Boston Facilities’ output and fuel requirements. Our derivative instruments at the Boston Facilities are static hedges and vary seasonally in size between 2,100 MW and 2,275 MW (on a megawatt output basis) and are in place for calendar years 2008, 2009 and 2010. The following table shows a sensitivity analysis for our static hedges, which were the only material derivative instruments associated with the Boston Facilities at that time. A sensitivity analysis serves to determine what may happen to a derivative instrument should a variable component of that derivative instrument change.


	Fair Value of All
	Contracts Under
	These Assumptions
	in $ Million
	(parentheses			On-Peak		Off-Peak			Percent Change
	indicate			Spark Spread		Spark Spread			in On-Peak
Assumption	losses to us)			($/MWh)		($/MWh)			Spark Spread

Market Value at December 31, 2007		(47.6	)		22.02		(3.06	)	None
Power prices increase by 5%		(203.2	)		26.51		0.31		20% increase
Power prices decrease by 5%		96.0			17.54		(6.43	)	20% decrease
Natural Gas prices increase by 5%		63.9			18.64		(6.58	)	15% decrease
Natural Gas prices decrease by 5%		(170.1	)		25.41		0.46		15% increase

The above table shows the aggregate present value of the market value of the Boston Facilities energy derivative instruments and four significant sensitivity cases in which either power or natural gas prices change by a given percentage, but no other model inputs change. The final column describes the change in the “spark spread” for each sensitivity case. These derivative instruments are designed to mitigate risks associated with spark spread. “Spark spread” is the difference between the market price of electrical energy and the market

price of the natural gas required to generate such energy, utilizing an assumed conversion factor or heat rate, for the conversion of natural gas to electrical energy. “Spark spreads” are therefore used as an indication of the per-unit gross operating margin to be earned by converting fuel into electricity. Due to the economic fundamentals in the power markets of New England, power prices typically track natural gas prices very closely. Accordingly, if natural gas prices rise, there will be a corresponding rise in wholesale power prices. Therefore, the five percent price changes in the chart above in either power or natural gas actually represent changes of fifteen to twenty percent in the on-peak spark spreads. For example, in the case of an on-peak spark spread increase caused by increased power prices with constant fuel costs, there will be a larger payment to a “static hedge” counterparty, who has assumed the risk of paying us a fixed payment while facing decreased power costs. Such increased payment to the “static hedge” counterparty will reduce the fair value of the derivative instrument as they are receiving the profit which we would have received had we not executed this derivative instrument. The changes in fair value of these contracts are significant, but are designed to be offset by a change in the value of the cash flows generated by the Boston Facilities. Accounting treatment of our hedging activities will generate a significant amount of earnings volatility as changes in fair values are recorded. The values in this table were computed before adoption of SFAS 157, and therefore do not reflect the creditworthiness of our counterparties, which are major investment banks and large energy companies backed by investment grade parent guarantees. However, we cannot guarantee that changes in derivative instrument cash flows and changes in cash flows from operating our generating assets will effectively offset each other which could adversely affect our results of operations.

The model used to produce the results of the table above is based on “Kirk’s Approximation,” a formula often used in the energy industry to value option contracts that depend on two underlying prices. Our model obtains forward prices, interest rates and volatilities from various standard market sources, including large energy brokers. We apply this formula each month separately for the on-peak and off-peak time periods. Each of the derivative instruments in the Boston Facilities portfolio is valued in this way and the results are then summed to form the aggregate MTM results shown above.

For certain of our operating derivative instruments, our fair value measurements of these contracts for accounting purposes are based on proprietary mathematical models that utilize one or more internally developed assumptions that are not directly observable in certain markets. These assumptions are designated as Level 3 Inputs pursuant to SFAS 157. Level 3 Inputs are estimated independent of their impact on the fair value measurement process and reflect management’s best estimate of current forward market conditions and predictions about future spot market outcomes. To the extent these estimates and predictions do not ultimately reflect actual spot market outcomes, the fair value measurements derived could potentially under or overstate the resulting cash flow at the fair value measurement date.

We have two types of Level 3 Inputs:

1. Static Hedges (Kirk’s Approximation Formula) — The models we utilize to measure the fair value of our static hedges described above utilize estimates of the correlation between power and fuel prices. We use our best estimate of this correlation appropriate for use within this model. This correlation is often called an “implied correlation” by option pricing experts, and is not directly related to the historical correlation between price changes. Based upon the underlying, observable market data as of March 31, 2008, a single percentage point change in correlation can result in a change in the value of our static hedges of approximately $8 million.

2. Capacity Hedge — The model we utilize to measure the fair value of the three-year financially settled derivative known as a “fixed for floating” unforced capacity swap (the “Capacity Hedge”) utilizes an internally developed forecast of NYISO spot auction closing prices for Zone J over the remaining length of the contract. As of March 31, 2008, due to changes in the auction market structure implemented by the NYISO, settlements under the contract have only been projected for one month, beyond which we have assumed that the contract counterparty will assert its right to re-price the contract for each of the other 12 settlement periods remaining, resulting in zero net settlement. Therefore, risk associated with the internally developed forecast is nominal.

Each period, we assess the accuracy of the assumptions underlying the Level 3 Inputs described above, and if we determine that the then current underlying assumptions no longer support or are no longer supported by current and/or projected market conditions, our estimates are adjusted to reflect management’s best estimates and predictions regarding the market conditions for the energy we sell and the fuel we utilize in our production processes.

As of March 31, 2008, we had not executed derivative instruments for the future energy output of our New York Facilities.

As of June 2, 2008, we have used derivative instruments in the form of fixed for float swaps for between 300 MW and 600 MW of energy output from our New York Facilities for the months of June through September 2008 and the same period in 2009. The Boston Facilities’ derivative instruments are substantially the same at June 30, 2008 as they were at December 31, 2007.

In January 2006, we entered into the Capacity Hedge to reduce our exposure to price variability inherent in the short term capacity contracts exchanged in the NYISO auctions. The Capacity Hedge fixed payment to us was originally fixed at $7.07 per kW-month with the floating payment to the counterparty calculated pursuant to the corresponding spot auction settlement. On May 7, 2008 we received notification from our Capacity Hedge counterparty that it interprets recent regulatory developments to trigger a “repricing event” under the specific provisions in the contract contemplating such modifications. The counterparty has adjusted its payments to us accordingly. As now revised, the fixed payment from the counterparty to us and the floating payment to the counterparty will be reset to the lower of “default reference price” or “spot auction outcome” (as such terms are defined in the NYISO rules), the net effect of which is a fixed and floating settlement which match exactly, meaning no funds will be owed to or from the counterparty. This may cause us to revise our valuation of the Capacity Hedge. Accordingly, although the Capacity Hedge is still in full force and effect from a legal perspective, it no longer provides us with protection against market outcomes. See “Risk Factors — A substantial portion of our revenues come from sales of capacity, and therefore our financial performance may be impacted by structural changes and price fluctuations in capacity markets.”

As of June 2, 2008, we did not have any derivative instruments relating to capacity in the EBG portfolio.

Accounting for Derivative Instruments

Our derivative instruments are accounted for in accordance with SFAS 133, which requires us to record all derivatives on our balance sheet at fair value, with changes in the fair value resulting from fluctuations in the underlying commodity prices and interest rates immediately recognized in earnings, unless the derivative instrument qualifies for “cash flow hedge” accounting treatment and our management (i) formally designates the derivative instrument as a “cash flow hedge” and (ii) documents the intended hedging relationship, as required by SFAS 133. Whether a derivative instrument qualifies for “cash flow hedge” accounting treatment depends upon it meeting specific criteria used to determine whether the cash flow hedge is at inception and will continue to be an effective hedge against a specific transaction or a specific series of transactions. Our economic hedge derivatives do not qualify for “cash flow hedge” accounting treatment, or have not been designated as accounting hedges. Consequently, fluctuation in the fair value of our derivative instruments resulting from changes in market perceptions regarding future commodity prices and interest rates, the impact of which will not be recognized until such expectations are realized in the future, could affect our reported earnings, regardless of how sound the cash flows of our business may be.

SFAS 157, the adoption of which is required for reporting periods commencing after November 15, 2007, establishes a framework for measuring fair value, requires that credit risk be explicitly considered when estimating fair value measurements and expands disclosures about fair value measurements. In February 2008, FASB issued FASB Staff Positions No. FAS 157-1 and FAS 157-2, which effectively deferred the effective date of SFAS 157 until fiscal years beginning after November 15, 2008 for non-financial assets and non-financial liabilities not typically recognized or disclosed at fair value in the financial statements on a recurring basis.

USPowerGen adopted SFAS 157 as of January 1, 2008, applying the standard to our derivative instruments reported at fair value, including our derivative contracts, while deferring application to any non-financial assets and non-financial liabilities, as permitted by FAS 157-1 and FAS 157-2. Explicitly including credit default risk in our valuation estimates resulted in a $14.1 million increase in the fair value of our derivative instrument portfolio. This increase was driven primarily by the spread between market estimates of our credit default risk versus those of our contract counterparties. Changes in market perceptions regarding our credit default risk or that of our contract counterparties could affect our fair value measurements in future periods. We do not anticipate that application of SFAS 157 to our non-financial assets and non-financial liabilities will have a material impact on consolidated financial position, statement of operations and cash flows in future periods; however we continue to assess the impact of fully adopting the standard in future periods.

Environmental Matters and Legal Proceedings

See Note 15 to our consolidated financial statements for the year ended December 31, 2007 for a discussion of environmental matters affecting our company. See Note 6 to our consolidated financial statements for the three months ended March 31, 2008 and “Business — Litigation” for a discussion of litigation matters affecting our company. Environmental regulatory compliance and litigation matters could each result in significant costs in the future.

BUSINESS

Company Overview

We are a wholesale power generation company that owns and operates electric power generation facilities located in New York City and the Boston metropolitan area. We have a portfolio of 58 generating units at six facilities, with seasonally adjusted generation capacity of approximately 5,223 MW. We can generate sufficient power to serve approximately 20% of the summer peak load in New York City and approximately 31% of the summer peak load in eastern Massachusetts. Over 93% of our generating capacity operates on natural gas as a primary fuel. We believe that we have a competitive advantage in our markets due to our strategic urban locations that have high costs of entry, favorable siting within these urban locations, access to well developed capacity markets and an asset portfolio consisting primarily of clean burning natural gas-fired generating units with significant dual fuel capability.

We generate revenues by selling electric energy, capacity and ancillary services, which accounted for approximately 76.3%, 18.8% and 1.2%, respectively, of our pro forma revenues in the year ended December 31, 2007 (giving effect to the combination of Astoria and EBG as if it had occurred on January 1, 2007), and approximately 75.1%, 14.4% and 1.9%, respectively, of our revenues for the three months ended March 31, 2008. We sell electric energy generated by our facilities to two ISOs: NYISO and ISO-NE, both of whom administer centralized electric energy markets. The ISOs are responsible for ensuring reliability, adequacy and security of the electric transmission system as well as providing generators with fair and non-discriminatory access to the transmission grid. We sell energy capacity to NYISO and ISO-NE for purchase by load-serving entities (entities that provide electric service to end-users and wholesale customers) in our markets. Load-serving entities are required to purchase sufficient capacity to demonstrate their ability to provide electric energy in an amount equal to peak load forecast for the relevant period plus a reserve. Due to this requirement, NYISO and ISO-NE have capacity markets separate from the electric energy market. Capacity sales provide us with a relatively predictable and recurring source of revenues. Our diverse power generation portfolio provides us with opportunities to generate additional revenues from sales of ancillary services to ISOs in our respective markets, including voltage support, reserves, black-start capability and automatic generation control.

Set forth below is information regarding our power generation portfolio as of June 30, 2008:


											Dual Fuel Capability
									No. of		No. of		% of Net
			Net Generation Capacity (MW)						Generation		Generating		Generating
Name of Facility	Location		Winter		Summer		Average⁽¹⁾		Units		Units		Capacity

New York Facilities:
Astoria		Queens, NY		1,314		1,312		1,313		5		3		85	%
Gowanus		Brooklyn, NY		745		556		651		32		16		52	%
Narrows		Brooklyn, NY		391		297		344		16		16		100	%
Boston Facilities:
Mystic 8&9		Everett, MA		1,658		1,360		1,558		2		0		0	%
Mystic Station:
Mystic 7		Everett, MA		560		578		566		1		1		100	%
Mystic Jet		Everett, MA		12		7		10		1		0		0	%
Fore River		North Weymouth, MA		831		682		781		1		1		100	%⁽²⁾

Total				5,511		4,792		5,223		58		37		60	%


(1)		Seasonally adjusted generating capacity. NYISO uses a May to October summer and November to April winter; ISO-NE uses a June to September summer and October to May winter.

(2)		Our Fore River generating unit’s capacity is limited to 635 MW when it operates using ultra-low sulfur diesel versus 831 MW when it operates using natural gas. Due to air permit restrictions, this unit can only operate using ultra-low sulfur diesel for approximately 45 days during the non-ozone season from October 1 to April 30.

Our New York Facilities operate in and generate electricity for New York City’s power market, which is administered by NYISO. Peak demand for energy within the New York City power market has grown from 9.6 gigawatts in 1997 to 11.0 gigawatts in 2007, representing a compound annual growth rate of approximately 1.3%. NYISO forecasted in April 2008 that the summer peak-load in New York City would increase to 13.0 gigawatts in 2017, representing a compound annual growth rate of approximately 1.7% from 2007. In June 2008, peak demand was 700 MW higher than the previous record for the month of June, which was set in June 2007. NYISO currently requires that all load serving entities operating in New York City purchase at least 80% of their capacity from in-city power generators due to the significant transmission constraints that limit generators’ ability to deliver electric energy into and within New York City. The average on-peak prices in New York City (Zone J) were approximately $98 per MWh, or 10.1% higher than the average on-peak prices in NYISO as a whole for the three-year period ended December 31, 2007. Additionally, as a result of transmission constraints within New York City, sub-load pockets exist in which energy prices often reflect a premium over prices in other parts of New York City. All of our New York Facilities are located within these sub-load pockets, and we have generally sold energy generated by these facilities at prices higher than average prices in the other parts of New York City. On-peak prices at our Gowanus and Narrows facilities were nearly $32 higher per MWh, or approximately 36% higher than the average on-peak prices for NYISO for the three-year period ended December 31, 2007.

Our Boston Facilities operate in and generate electricity for the Boston metropolitan area. Peak demand for energy within the New England market has grown from 21.2 gigawatts in 1997 to 27.5 gigawatts in 2007, representing a compound annual growth rate of approximately 2.6%. ISO-NE forecasted in April 2008 that the summer peak-load in New England would increase to 31.3 gigawatts in 2017, representing a compound annual growth rate of approximately 1.3% from 2007. Most of the generating capacity of our Boston Facilities (approximately 80% of their average net generation capacity) is less than six years old and we believe it to be among the lowest cost and most environmentally efficient fossil fuel power generating capacity in New England. Due to changes to the ISO-NE capacity market rules that became effective December 1, 2006, the revenues we receive for providing capacity to that market have increased significantly. These market rules provide that power generators supplying capacity will receive payments at set, escalating prices until May 2010, following which capacity prices will be set by an annual auction process. The first forward capacity auctions, covering the 2010 capacity year (beginning June 1, 2010), were held in February 2008 and had a capacity floor price of $4.50 per kW-month and a ceiling price of $10.50 per kW-month with the market clearing at the floor price. The second auction covering the 2011 capacity year (beginning June 1, 2011) will be held in December 2008.

Market Overview

Background

The U.S. electricity industry includes approximately 100 investor-owned power companies, over 2,000 public power systems, nearly 1,000 consumer-owned rural electric cooperatives and a growing number of power companies owned by financial sponsors. Many regions of the U.S. have adopted competitive electricity markets with independent power producers owning generation and selling electricity at market-based rates in lieu of traditional public utilities that are subject to cost-of-service rate regulation. While the extent of “deregulation” and the characteristics of competitive power markets vary from region-to-region, common elements of organized markets generally include bid-based energy and ancillary services markets, and in some cases, developed capacity markets. Most of these organized markets operate under the oversight of FERC. FERC is an independent regulatory commission within the U.S. Department of Energy that, among other things, regulates the transmission and the sale of electricity in wholesale markets in interstate commerce under the authority of the Federal Power Act (“FPA”). In accordance with the FPA, FERC has approved ISOs in New York and New England. These ISOs administer organized wholesale electric energy markets in their respective regions pursuant to tariffs approved or accepted by FERC. These tariffs and associated market rules dictate how the capacity and electric energy markets operate, how certain market participants may make bilateral sales with one another, and how power generators with market-based rates are compensated within

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those markets. ISOs also control access to and the operation of the transmission grid and distribution facilities used for wholesale power sales within their regions.

Industry Trends

We believe that three general trends are currently affecting the U.S. generation market: (1) load growth and unit retirements have been greater than new generation additions; (2) construction costs for new generation have risen substantially over the last several years; and (3) capacity markets have developed in certain regions that are intended to provide the necessary incentive for the construction of new facilities and the continued operation of older facilities. While we believe that all regions are affected to some degree by certain of these trends, only a few regions, including the New York and New England markets, are affected by all three of these trends.

NERC expects electricity demand to grow by approximately 60,100 MW from the summer of 2007 to the summer of 2011, while committed resource additions over this period are projected to be approximately 35,700 MW. NYISO projects that roughly 4,200 MW of new capacity will be needed by 2017 in New York State, including 1,200 MW in Zone J. In New England, over 3,000 MW of new resources will be required by 2017. Participants in the first ISO-NE forward capacity auction recently committed to make 2,400 MW of new capacity resources available by 2010. If all the auction participants meet their 2010 commitments on an ongoing basis, then only 600-700 MW of additional resources will be required before 2017. Additional capacity requirements may be met by new generating capacity, imports, demand response or emergency generation resources.

The cost of construction of new generating units has risen substantially across the country, particularly in the New York City and New England markets. Rising costs for raw materials and labor, as well as more restrictive environmental requirements, have all contributed to significant increases in construction costs for electricity generating facilities over the last several years.

Market Operation

NYISO and ISO-NE each administer centrally dispatched day-ahead and real-time energy, capacity and ancillary service markets. Generating units that sell their capacity in either the NYISO or ISO-NE markets are generally required to offer their electric energy into that market on a day-ahead basis. The day-ahead market is conducted prior to the commencement of each day. Forward contracts are established for each hour of the next day. The real-time market is conducted on the same day in which it will be consumed and, specifically, each hour for the following hour’s anticipated load when electricity demand actually occurs. At the close of each auction, both ISOs initiate a bid evaluation process which involves retrieving bids, analyzing the bids according to prescribed rules, making adjustments to ensure that reliability requirements are met and posting results. All units that are dispatched to provide energy receive the market clearing price.

Both NYISO and ISO-NE calculate electric energy prices and dispatch generation using a locational marginal pricing model. The locational marginal pricing model is based on the premise that, in the absence of any transmission losses and transmission constraints, the least costly way of generating electric energy is achieved when demand is satisfied starting with the lowest cost megawatt-hour with the last megawatt-hour needed to meet demand setting the price at which dispatched generators receive compensation. In some instances, generation scheduled strictly according to this criterion may cause one or more transmission lines or other transmission equipment to carry more power than their rating allows, or otherwise may compromise reliability requirements. In these cases, more expensive units that do not need to use the congested path are scheduled to satisfy the loads.

Each NERC region is required by NERC’s electric reliability rules to have sufficient capacity to meet expected consumption of electricity (known as load). Each NERC region calculates the reserve requirement that it must have in order to manage potential unit outages. In many markets in the U.S., there is no separate market for capacity, and the value of the underlying capacity is included in the price of the energy generated. In NYISO and ISO-NE, a market for capacity exists distinct from the market for energy generated by that capacity. NERC has forecasted that reserve capacity levels will continue to shrink due to continued growth in

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electricity demand and lack of new generating capacity resulting from high costs of construction and permits and other barriers to entry.

Capacity payments supplement the revenues earned by generators in energy markets. The capacity market offers a relatively predictable and recurring source of revenues designed to provide the necessary incentive for the construction of new facilities and continued operation of older facilities. Generating units are eligible to receive capacity payments regardless of how often they are dispatched to generate energy. Capacity markets are indifferent to the efficiency of an operating unit so long as the unit is available when needed to maintain desired electricity generation levels, resulting in generally predictable capacity revenues for all units, including those dispatched only during periods of peak demand. In New York City, where there are constraints on the ability to transmit power into the city from outside the city, as well as constraints on transmitting power within the city, capacity payments sometimes represent the primary source of revenues for generators.

Most organized power markets in the U.S. also have a market for ancillary services, which are services that must be provided to ensure the reliable generation, transmission and delivery of electricity. As defined by FERC, ancillary services include: coordination and scheduling services (load following, energy imbalance service, control of transmission congestion); automatic generation control (load frequency control and the economic dispatch of plants); loss compensation service; and support of system integrity and security (reactive power, or spinning and operating reserves).

Ancillary services provided in NYISO and ISO-NE include automatic generation control, operating reserves, energy imbalance, and the cost-based services of scheduling, system control and dispatch, reactive supply and voltage support and black-start capability. Ancillary services that we offer include:


	•	automatic generation control, which is used by the ISO to balance energy supply with system load requirements in real time;

	•	operating reserves, which is generation available to generate additional electric energy within a designated time period to meet unexpected increases in demand or in place of electric energy generating units in the event such units or transmission facilities become unavailable;

	•	reactive supply and voltage support, which is used to maintain voltages on the transmission and distribution system within acceptable limits; and

	•	black-start capability, which is the capability of a generating facility to start-up and synchronize to the electrical system without reliance on external energy sources.

New York State Electric Power Market

NYISO administers New York State’s organized wholesale electric power markets with oversight of approximately 39,900 MW of existing generation capacity and annual energy consumption of approximately 167,000 gigawatt hours (“GWh”). The NYISO market is subdivided into different geographic zones, with New York City comprising an area referred to as Zone J. NYISO is comprised of generators, transmission owners, end users, public power/environmental organizations and other suppliers. Approximately 43% of the population of New York State and over 34% of the electric load resides within Zone J. Peak demand in Zone J has grown at an average rate of 1.3% in the last 10 years.

NYISO’s Market Monitoring Unit monitors and investigates suspected anti-competitive behavior. NYISO’s market power mitigation plan specifies that physical or economic withholding of an electric facility and uneconomic production from an electric facility are the types of conduct that may warrant mitigation. Pivotal suppliers located in New York City are presumed to have “market power” and are subject to more specific mitigation measures.

Zone J is one of the most transmission constrained power markets in the United States and there are limits on the amount of electricity that existing transmission systems can transport into Zone J. To ensure reliability within Zone J, NYISO currently requires all load serving entities operating in Zone J to purchase 80% of their peak load requirements from in-city power generators. NYISO is routinely required to dispatch operating units located within Zone J that have higher operating costs than units running outside this zone,

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causing prices in this zone to be higher than they would otherwise be with no transmission constraints and creating what is referred to as a load pocket. As a result, energy prices in Zone J reflect a premium (approximately 10% for average on-peak prices in 2007) over the NYISO market average. The average on-peak prices in New York City (Zone J) were approximately $98 per MWh, or 10.1% higher than the average on-peak prices in NYISO as a whole for the three-year period ended December 31, 2007. In addition, localized transmission constraints make it difficult to transport electricity within Zone J from other parts of Zone J, creating sub-load pockets in which energy prices often reflect a premium over other parts of Zone J. All of our New York Facilities are located within these sub-load pockets, and the prices we have received for the energy generated by these facilities are generally higher than average prices in the other parts of Zone J. For example, on-peak prices at our Gowanus and Narrows facilities were approximately $32 higher per MWh, or approximately 36% higher than the average on-peak prices in the NYISO as a whole for the three-year period ended December 31, 2007. However, the addition of 1,000 MW of new generation capacity in the Astoria load pocket caused the price premium to fall to approximately $4 per MWh in 2007.

The capacity market is an integral part of the NYISO market design, through which NYISO ensures system reliability and resource adequacy by providing incentives for generators to participate in energy markets. NYISO administers seasonal, monthly and spot auctions for capacity. All load serving entities operating in the NYISO market must demonstrate that they either own or have purchased capacity currently amounting to 115% of their forecast annual peak load.

In 2003, NYISO implemented a “Demand Curve” mechanism (the “Demand Curve”) for calculating pricing for capacity for three locational zones: New York City, Long Island, and the remainder of New York State. The Demand Curve (i) is intended to provide stability, predictability and price transparency for capacity markets; (ii) provides guidance on future market prices designed to attract new generation when and where new supply is needed; (iii) is set every three years for a subsequent three-year period; (iv) provides for incrementally higher capacity pricing at lower reserve margins (i.e., less available capacity), such that the economic incentive for a new entrant becomes increasingly attractive as the reserve margin approaches target levels of little to no excess capacity; and (v) assumes the use of certain technology as a “proxy” for new entrants such that the capacity price during periods of supply/demand balance reflects the net cost of that “proxy” unit’s new entry. NYISO is obligated to select a peaking unit as the proxy unit. The criteria for selection is the unit with technology that results in the lowest fixed costs and highest variable costs among all other units’ technology that are economically viable. NYISO adopted the use of the GE LMS-100 for the New York City Demand Curve beginning with the 2008/2009 period and currently requires that load serving entities in New York City procure 80% of their load obligations from generating capacity electrically connected to New York City, resulting in a price of $13.36 per kW-month during periods of supply/demand balance. The 80% locational capacity requirement is subject to change as it is dependent upon analyses conducted annually by the New York State Reliability Council and NYISO.

The addition in 2006 of two new combined cycle generation plants totaling approximately 1,000 MW created a supply surplus in the Zone J capacity market, which continues to exist today. Total in-city capacity supply as a percentage of peak Zone J demand was approximately 91% in 2007, versus the NYISO requirement of 80%. Peak demand growth is projected by NYISO to increase from 11.0 gigawatts in 2007 to 12.2 gigawatts in 2010, which combined with the expected retirement of the NYPA Poletti station (885 MW) in 2010, is projected to eliminate the current surplus of capacity and create a need for additional capacity in 2010 or 2011. The projected growth in peak demand means that approximately 100 to 200 MW of incremental generation resources must be added each year to meet reserve margin requirements. See “Risk Factors — Risks Related to Our Business — A substantial portion of our revenues come from sales of capacity, and therefore our financial performance may be impacted by structural changes and price fluctuations in capacity markets.”

New England Electric Power Market

ISO-NE administers New England’s organized wholesale electric power markets and this oversight has over 31,000 MW of existing generating capacity and annual energy consumption of approximately 134,000 GWh. ISO-NE’s region consists of Connecticut, Rhode Island, Massachusetts, Vermont, New Hampshire and

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Maine. There are over 300 participants in ISO-NE including cooperatives, municipal utilities, load serving entities and power marketers. ISO-NE forecasted in April 2008 that the summer peak-load in New England would increase by a combined annual growth rate of approximately 1.3% through 2017.

ISO-NE implemented changes to its capacity market on December 1, 2006. Generators in ISO-NE can sell capacity as part of the FERC-approved FCM structure. This structure contemplates an initial settlement period followed by forward capacity auctions. During the settlement period, power generators supplying capacity receive fixed transition payments which started December 1, 2006 according to the following schedule: $3.05 per kW-month from inception through May 31, 2008; $3.75 per kW-month from June 1, 2008 through May 31, 2009; and $4.10 per kW-month from June 1, 2009 to May 31, 2010. For the periods after May 2010, load serving entities will be required to purchase capacity through capacity auctions three years in advance of the delivery year to meet their installed capacity requirement.

The forward capacity auctions began during the first quarter of 2008, with the initial auction having a capacity floor price of $4.50 per kW-month and a ceiling price of $10.50 per kW-month. The market is designed to include a locational component in the pricing structure so that separate pricing zones may be used if needs for power exist at specific locations. Over 39,100 MW of generating capacity, demand response resources, emergency generation and imports participated in the auction to meet 32,305 MW of net installed capacity requirements. When the auction stopped at the floor of $4.50 per kW-month, 2,047 MW of excess supply was still in the market. Due to the substantial incremental supply available at the conclusion of the auction, the $4.50 floor price was adjusted downward pro rata.

A newly constructed 345 kV transmission line which enters Boston from the south has relieved a significant portion of the historical transmission constraints in this region. The first phase of this construction was completed in the spring of 2007, adding approximately 850 MW of transmission capacity, and the second phase is scheduled to be complete in 2009, adding an additional 250 MW of transmission capacity. The new transmission lines have resulted in the convergence of prices for energy generated at our Mystic facility and Fore River facility (prices were historically higher at our Mystic facility due to transmission constraints).

Reserve margins continue to decline in ISO-NE as peak demand grows. Reserve margins in ISO-NE were 20% in 2007, and based on capacity committed in the 2010 forward capacity auction, reserves are expected to drop below the ISO minimum requirements by 2015. The projected growth in peak demand means that approximately 200-400 MW of incremental generation resources must be added each year once reserve margins reach the required minimum. New resource requirements may be met by new generating capacity, imports or by demand response resources.

Business Strengths

We believe that the key strengths of our company are the following:

Located in Attractive Competitive Power Markets. Our facilities are located in well-developed markets with mature regulatory frameworks. NYISO and ISO-NE focus on providing open-access transmission services on a non-discriminatory basis and administering competitive electric power markets. Aggregate electric energy demand in our markets is high, and our urban locations are subject to transmission constraints, resulting in electric energy prices that are higher than the nationwide average. Capacity markets in New York and New England are designed so that constraints in supply and increases in construction costs will typically result in higher capacity prices. The market for ancillary services provides an additional revenue stream while supporting the reliability of the transmission system by providing critical system functions including black-start capacity, automatic generation control and reserves.

Favorable Locations within the Markets. The high population density and load usage levels and, in some cases, transmission constraints in our markets generally result in high dispatch levels and energy prices that are higher than the nationwide average. Our New York Facilities are located in New York City, which is one of the most transmission constrained energy markets in the United States, and benefit from the current NYISO requirement that all load serving entities operating in New York City purchase at least

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80% of their peak load from in-city power generators, which results in premium capacity prices for existing in-city generation resources compared to the rest of NYISO. Transmission constraints within New York City further limit the ability to transmit electricity freely throughout the zone, creating sub-load pockets (in which our facilities are located), resulting in higher energy prices for generation located within these sub-load pockets, compared to elsewhere in the New York City market. For example, average on-peak pricing at our Gowanus facility was nearly $23 per MWh, or 23% higher than the Zone J average for the three year period from 2005 to 2007. In Boston, the proximity of our Mystic 8&9 facility to a liquified natural gas terminal facility of Distrigas enables this facility to receive natural gas through a dedicated pipeline connected at a market price while reducing transportation costs and interruptions. The dense population and high construction costs at our locations within our markets act as a deterrent to construction of new generating facilities at greenfield sites in our markets.

Growing Markets with Inherent Development Opportunities. Our generating facilities are located within densely populated areas in which the current high demand for electricity is expected to increase. NYISO forecasted in April 2008 that the summer peak-load in New York City would increase by a compound annual growth rate of approximately 1.7% from 2007 through 2017. In April 2008, ISO-NE forecasted that the summer peak-load in New England would increase by a compound annual growth rate of approximately 1.3% from 2007 through 2017. We believe that additional generating capacity will be required in these markets to meet this expected growth, and potential new entrants into these markets will face challenges associated with limited site availability, difficult permitting processes, high construction costs and long development times. We believe that we have the market and regulatory knowledge, infrastructure and available land to support an additional 500 to 700 MW at our Astoria facility, up to an additional 100 MW at our Gowanus facility and an additional 600 to 900 MW at the Mystic site. All of these sites are located near existing substations that either have adequate capacity or the ability to upgrade to adequate capacity. These sites would require modifications to their fuel supply infrastructure to support these capacity increases. Our existing sites also offer significant economies of scale related to management, staffing and operations.

Dual Fuel Capability. Approximately 60% of our total generating capacity, including 78% of our New York City generating capacity, have dual fuel capability, which provides significant value to our generating portfolio due to the relative price volatility of each fuel. When natural gas prices are higher than fuel oil prices, units that are capable of running on fuel oil have a distinct competitive advantage. Historically, the price of natural gas in the Northeast has spiked during the winter, causing a large divergence between the prices of the two fuels and allowing oil-fired plants to earn higher margins than natural gas-fired plants. This capability allows us to use the most cost-efficient fuel when prices diverge, and makes us less vulnerable to interruptions in fuel supply.

Proven and Reliable Technology. All of the generating units at our facilities were built by well-established manufacturers using proven technologies from industry-leading suppliers, including Babcock & Wilcox, General Electric, Combustion Engineering, Allis Chalmers and MPS. These units were conservatively designed and, as a result of our comprehensive maintenance program, have good operational records. As a result of the maintenance plan we implemented in 2006, the average forced outage rate at our New York Facilities was reduced to its lowest point in the last 10 years, from an average rate of nearly 9% in 2005 to approximately 2% in 2007, compared to an average of 4% in 2007 for the rest of in-city power generators. The average forced outage rate for the Boston Facilities was reduced from 8% in 2005 to approximately 2% in 2007, compared to a five year system-wide average of 5% for ISO-NE. MPS designed our MHI 501-G turbines at Mystic 8&9 and Fore River facilities, and these turbines have among the highest efficiency ratings of all industrial gas turbines currently in service in the world. This resulting increase in availability has had a favorable impact on both our power sales and capacity revenues.

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generators using other fossil fuels. In addition, the combination of state-of-the-art gas turbine technology with dry, low NO_x combustion systems makes our Mystic 8&9 and Fore River units among the lowest cost and cleanest natural gas-fired generating facilities in the ISO-NE control area.

Experienced, Committed Management Team. The members of our senior management team have extensive experience in the energy sector. We have an established record of improving performance and cash flows by investing in our capital assets to increase reliability, operating flexibility and safety. These initiatives have increased the operating availability of our New York Facilities by 8% from 2005 to 2007, and significantly reduced our forced outage rate, while maintaining an Occupational Safety and Health Administration injury rate that is 72% below the industry average. Our management team has a meaningful equity ownership stake in our company and is committed to creating value for our stockholders by building on our core strengths. Following this offering, our management team will collectively indirectly own in excess of % of our common stock on a fully diluted basis.

Business Strategy

Our strategy is to optimize the value of our power generation assets while using our existing asset base as a platform for future growth. We plan to grow our portfolio of generating facilities in strategic locations, while seeking to maximize value for our stockholders. We believe that by operating a carefully assembled portfolio of generating assets in a cost-efficient manner, we will be able to compete effectively in the market for wholesale electric power. We plan to continue to approach our business with financial discipline, applying a rigorous approach to valuing acquisition and development opportunities.

Our business strategy includes the following elements:

Maximize Value from Existing Assets. We intend to continue to focus on maximizing value from our assets by improving our operating efficiency, operating flexibility and reliability. We plan to continue to implement our long-term operational improvement initiatives and capital expenditure plans that have led to increased operating availability, higher levels of capacity and reduced forced outage rates at our facilities. These initiatives include implementation of selected capital projects to obtain additional ancillary services and revenue streams (such as control systems, voltage regulation and black-start), routine analysis of plant performance, staff training and the use of operational metrics in our annual bonus program. For example, as a result of management’s operational improvement initiatives, we have been able to increase the capacity of our New York Facilities in 2007 by over 125 MW above the prior five-year average.

Expand and Develop Facilities. We intend to enhance and/or expand our existing generation capabilities to meet growing electricity demand by developing economic, reliable and environmentally responsible generating capacity. Recently, we announced the addition of approximately 100 MW of peaking capacity at our Gowanus facility, which is tentatively scheduled to be completed by 2010 to 2011. Our Mystic Station and Fore River facilities have considerable undeveloped land and infrastructure support systems that may allow us to add generation capacity in a cost-efficient manner. Additionally, we are also currently evaluating the market feasibility of a repowering at our Astoria facility and are actively exploring additional brownfield and greenfield development opportunities, and we are building a dedicated team to evaluate and target these opportunities. We intend to continue to evaluate new redevelopment and expansion opportunities by focusing on projects with expected revenues and operating cash flow growth in amounts necessary to meet our required capital investment return criteria. We intend to identify and pursue attractive projects through applying a rigorous set of criteria, including projected returns, environmental impacts and community relations.

Pursue Selective Mergers and Acquisitions. We intend to evaluate and pursue selective joint venture and merger and acquisition opportunities with both strategic and financial owners of electric generation assets and portfolios in target markets throughout the U.S. to expand our generation portfolio. We will focus primarily on acquiring assets in competitive markets with existing or developing regulatory structures where we believe we can apply our existing market and technical knowledge to maximize contribution from these assets. In addition to pursuing such opportunities, we believe that a number of

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portfolio assets in the U.S. that are held by short-term owners, similar to EBG prior to the Combination, will present us with attractive acquisition opportunities. We intend to evaluate acquisition opportunities and compare them to other investment opportunities in our markets, such as greenfield and brownfield development, and only pursue them when the expected returns would exceed our cost of capital.

Improve Financial Flexibility and Liquidity. Pursuant to the terms of our credit agreements at both Astoria and EBG, we will continue to use a significant portion of the cash we generate from operations to service our indebtedness. We may consider refinancing our debt for either or both of Astoria and EBG in the future, which may provide us with greater financial flexibility to pursue strategic initiatives. In addition, we plan to continue to pursue cost-efficient means of providing collateral to secure our fuel purchase commitments and our risk management activities, with an emphasis on lien-based structures as opposed to cash-based collateral. We intend to continue to explore opportunities to mitigate our risk and exposure to the uncertainties of energy markets.

Mitigate Market and Industry Risks. We intend to continue to use derivative instruments and explore other opportunities to mitigate our risk and exposure to the uncertainties of the energy markets in which we operate. We also intend to enter into interest rate swaps so we pay a fixed interest rate on a portion of our outstanding floating rate borrowings. We intend to continue our current risk management policy which is designed to stabilize our revenue by managing our exposure to market price risks, particularly those related to changing electric energy and capacity prices. This risk management policy will help us meet our overall goal of managing our exposure to market price risk, particularly risks related to changing electric energy and capacity prices. As of June 2, 2008, Astoria had entered into derivative instruments relating to between 300 to 600 MW (varying by month) of its summer generation capacity in 2008 and 2009 to mitigate our exposure for output from our New York Facilities and EBG had entered into derivative instruments relating to 100% of the energy output from our Boston Facilities. We will continue to focus primarily on opportunistically entering into derivative contracts when we deem market conditions are favorable for such a strategy.

Our History

USPowerGen, the issuer of the common stock being sold in this offering, is a Delaware corporation formed in February 2007 to facilitate the combination of the operations of Astoria and EBG, which was effected on June 1, 2007, and resulted in each of the entities that own our New York Facilities and Boston Facilities becoming wholly-owned subsidiaries of USPowerGen. The Combination was effected to leverage the complementary nature of the two asset portfolios, including each being located in markets characterized by expected high demand growth, well-established capacity markets and significant costs of entry and each portfolio having significant dual fuel capability.

Our New York Facilities were originally developed and owned by Con Edison, which divested these facilities through a competitive auction in 1999 under the terms of a 1997 settlement agreement with the New York Public Service Commission prior to the commencement of the NYISO market. Orion Power New York GP II, Inc. (“Orion”) was the winning bidder for the New York Facilities. In 2002, Orion was acquired by Reliant. In 2003, Mr. Jacob Worenklein, our Chief Executive Officer, formed an acquisition and management company to acquire and manage domestic power generation facilities. In 2004, Hunt Generation joined as an investor in this acquisition and management company. On February 23, 2006, a newly formed entity owned by Madison Dearborn, certain other equity investors and officers of this acquisition and management company acquired our New York Facilities from Reliant.

Our Mystic 7 and Mystic Jet facilities began operations in 1975 and 1969, respectively, and were part of a group of fossil fuel plants purchased in 1998 by certain subsidiaries of Sithe Energies, Inc. (“Sithe New England”) from Boston Edison Company. Our Mystic 8&9 and Fore River facilities were initially developed in 2000 by Sithe New England. Exelon Generation Company, LLC (“Exelon”) acquired a minority interest in Sithe New England in 2000, and acquired the remaining equity of Sithe New England in November 2002, which resulted in Exelon taking control of the Mystic 8&9 and Fore River facilities. Our Mystic Unit 8 and Mystic Unit 9 facilities commenced commercial operation in April 2003 and June 2003, respectively, and our

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Fore River facility commenced commercial operation in August 2003. In May 2004, Exelon completed the transfer of ownership of all of these facilities to EBG.

Power Generation Assets

New York Facilities

Astoria Facility. The Astoria facility consists of five operating units (Units 20, 30, 40, 50 and GT-1). The combined net capacities of these five operating units are 1,312 MW in the summer and 1,314 MW in the winter. Units 30, 40 and 50 operate as intermediate units, which run frequently, but are often used to follow load, ramping up during the peak and shoulder hours of the day and backing down or shutting off during most low load hours. Units 20 and GT-1 operate primarily as peaking facilities, running only during high load periods. Units 30, 40 and 50 can operate on either natural gas or low-sulfur No. 6 fuel oil or a blend of the two fuels and Unit 20 operates only on natural gas. Unit GT-1 is a natural gas-fired combustion turbine. This unit also receives ancillary services payments for black-start capability.

The table below outlines annual output and key operating statistics for units 20, 30, 40 and 50 at the Astoria facility for the years ended December 31, 2007, 2006 and 2005, and for the twelve months ended March 31, 2008. We primarily focus on the “equivalent availability factor” (“EAF”) and EFORd as the key operating metrics for these facilities.


	Twelve Months
	Ended
	March 31,		Year Ended December 31,
Astoria Facility⁽¹⁾	2008		2007		2006		2005

Astoria Unit 20
Net Generation (MWh)⁽²⁾		21,194		12,431		26,712		91,270
Net Capacity Factor (%)⁽³⁾		1.4		0.8		1.7		5.9
Equivalent Availability Factor (%)⁽⁴⁾		99.2		95.6		98.9		93.6
Equivalent Forced Outage Rate demand (%)⁽⁵⁾		0.2		0.3		0.0		11.9
Net Heat Rate (BTU/kWh)⁽⁶⁾		16,464		19,327		16,414		12,839
Astoria Unit 30
Net Generation (MWh)		862,493		805,457		474,426		1,514,554
Net Capacity Factor (%)		26.4		24.8		14.9		46.5
Equivalent Availability Factor (%)		91.3		88.5		70.4		66.8
Equivalent Forced Outage Rate demand (%)		4.3		3.8		0.7		9.1
Net Heat Rate (BTU/kWh)		12,294		12,290		11,306		10,258
Astoria Unit 40
Net Generation (MWh)		410,554		561,310		895,724		1,412,952
Net Capacity Factor (%)		12.4		17.0		27.3		43.2
Equivalent Availability Factor (%)		45.4		65.0		83.3		81.6
Equivalent Forced Outage Rate demand (%)		1.3		0.9		2.6		14.5
Net Heat Rate (BTU/kWh)		11,980		11,947		11,160		10,100
Astoria Unit 50
Net Generation (MWh)		993,144		805,015		1,087,284		1,721,631
Net Capacity Factor (%)		30.5		24.7		33.3		52.8
Equivalent Availability Factor (%)		89.6		86.2		88.6		87.5
Equivalent Forced Outage Rate demand (%)		1.9		1.7		0.6		4.2
Net Heat Rate (BTU/kWh)		11,284		11,626		11,291		10,435


(1)		Unit GT-1 was brought back into service during 2007 and as a result operating data is unavailable with respect to this unit.

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(2)		Net generation is the total amount of electric energy (as measured by the generating unit) generated during the specified period minus the electrical energy consumed by the generating unit.

(3)		Net capacity factor is the ratio of the actual net output of our generating units during the specified period over their output if they had operated at full capacity during that period.

(4)		Equivalent availability factor of our generating units is the percentage of time that they are able to generate electricity over a given period, adjusted to account for partial outage time of equivalent generating units.

(5)		Equivalent forced outage rate demand is the historical percentage of the generating units’ maximum output lost to forced outages when such output is demanded.

(6)		Net heat rate is a measure of generating unit thermal efficiency, and is the amount of fuel energy required by our generating units to generate one kilowatt-hour of electrical output. It is computed by dividing the total BTU content of fuel burned for electric generation by the resulting net kWh generation.

The decreases in net capacity factor and gross generation observed at the Astoria units from 2005 to 2006 were due, in part, to the addition of approximately 1,000 MW of new combined cycle capacity at the SCS Astoria and NYPA Poletti facilities within Astoria’s load pocket. Increases in net heat rate from 2005 to 2006 were also related to the entrance of the new, more efficient SCS Astoria and NYPA Poletti units which resulted in the Astoria units being dispatched at partial load more often.

Our Astoria facility is strategically situated in Astoria, Queens, New York, on a 21-acre site, adjacent to the NYPA Poletti and certain other power generation facilities. Fuel oil can be delivered to this site by barge or ship and is unloaded using a dedicated oil dock located along the East River.

Unit 20 commenced operations in 1953. Units 30, 40 and 50 commenced operations in 1958, 1961 and 1962, respectively. All of these units were originally designed to operate using coal as fuel. Due to the requirements of its air permit, Unit 20 was decommissioned in 1993 and recommissioned in 2000 as a natural gas-fired unit. Units 30, 40 and 50 were converted in 1970 to operate using natural gas as their primary fuel and No. 6 fuel oil as an alternative fuel. All of the Astoria facility boilers were produced by either Combustion Engineering or Babcock & Wilcox. All of these units utilize conventional cross-compound steam turbine sets produced by either General Electric or Allis Chalmers. The turbine sets drive hydrogen-cooled electric generators manufactured by either General Electric or Allis Chalmers.

A complete overhaul and upgrade of Unit 30 was completed in the fall of 2006 at a total cost of approximately $20.0 million. This work included a complete turbine overhaul, multiple inspections, component repairs and the installation of a new boiler control system. This refurbishment contributed to a 13.5 MW increase in Unit 30’s capacity rating for the summer of 2007 over its capacity rating in the summer of 2006. A major overhaul of Unit 40 was completed in April 2008. The work included a major overhaul of the steam turbine and the generator as well as replacement of the control and burner management system. In addition, the boiler windboxes and burner components were replaced, at a cost of approximately $35.9 million. A similar overhaul is scheduled for Unit 50 in the fall of 2009, with an estimated cost of $20.8 million. These overhauls are expected to result in increased reliability, improved efficiency and the ability to offer automatic generator control, a product we can sell as an ancillary service for additional revenues.

Gowanus Facility. Our Gowanus facility consists of 32 simple cycle combustion turbine units that are arranged in groups of eight on four floating power barges that are each 80 feet by 200 feet. The Gowanus facility has a net capacity of 556 MW in the summer and 745 MW in the winter. We operate our Gowanus facility primarily as a peaking facility due to its relatively high variable operating costs. As a result, we generally only run its turbines during the highest load hours, when capacity loads cannot otherwise be met, or to resolve congestion because of transmission constraints. Half of the units can operate on No. 2 fuel oil, kerosene or natural gas (and are not required to operate on the same fuel as other units) and the other half operate only on No. 2 fuel oil or kerosene. These units are flexible from an operating perspective and can be started in as little as fifteen minutes, qualifying them as quick-start units by NYISO eligible for additional compensation. In addition, this facility can be started remotely and has black-start capability, making it eligible for additional compensation. This facility was the first in-city generating facility to start after the blackout in New York City in August 2003.

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The table below outlines annual output and key operating statistics for the Gowanus facility for the years ended December 31, 2007, 2006 and 2005, and for the twelve months ended March 31, 2008. As with the Astoria facility, we manage the Gowanus facility with a focus on EAF and EFORd as the key operating metrics for this facility.


	Twelve Months
	Ended
	March 31,		Year Ended December 31,
Gowanus Facility	2008		2007		2006		2005

Net Generation (MWh)		45,430		50,750		86,480		222,043
Net Capacity Factor (%)		0.8		0.9		1.6		3.7
Equivalent Availability Factor (%)		96.5		96.6		93.3		84.7
Equivalent Forced Outage Rate demand (%)		2.8		2.5		1.2		2.2
Net Heat Rate (BTU/kWh)		16,959		16,806		17,433		17,875

The Gowanus facility is located in Brooklyn, New York along the east side of Upper New York Bay at an area known as Gowanus Bay, and includes approximately 25 acres of piers and underwater land on which additional piers may be sited. Fuel oil is delivered by barge or ship to the facility’s floating oil storage barges. These fuel barges are routinely serviced and are scheduled to be upgraded to double-hulled barges by 2015 at an estimated cost of approximately $9 million.

The Gowanus facility commenced operations in 1971. The 16 units on power barges 2 and 3 were converted to operate on natural gas in 2001 and can now all operate on No. 2 fuel oil, kerosene or natural gas. The 16 units on power barges 1 and 4 can only operate on No. 2 fuel oil or kerosene, but are capable of being converted to operate on natural gas. All of the units at the Gowanus facility are General Electric Frame 5 combustion turbines, a design which has over 30 years of reliable performance history.

Narrows Facility. Our Narrows facility consists of 16 simple cycle combustion turbines that are arranged in two groups of eight on two floating power barges that are each 80 feet by 200 feet. The Narrows facility has a net capacity of 297 MW in the summer and 391 MW in the winter. We operate the Narrows facility primarily as a peaking facility. All of the operating units at this facility can be started remotely and have black-start and quick-start capabilities, making the facility eligible to provide ancillary services to NYISO. All of the units at the Narrows facility can operate on No. 2 fuel oil, kerosene or natural gas.

The table below outlines annual output and key operating statistics for the Narrows facility for the years ended December 31, 2007, 2006 and 2005, and for the twelve months ended March 31, 2008. We focus on EAF and EFORd as the key operating metrics for this facility.


	Twelve Months
	Ended
	March 31,		Year Ended December 31,
Narrows Facility	2008		2007		2006		2005

Net Generation (MWh)		130,450		113,690		204,130		286,640
Net Capacity Factor (%)		4.6		4.0		7.2		9.4
Equivalent Availability Factor (%)		97.1		95.9		92.4		75.9
Equivalent Forced Outage Rate demand (%)		0.9		0.6		0.6		2.1
Net Heat Rate (BTU/kWh)		15,991		16,126		16,405		16,884

The Narrows facility is located in Brooklyn, New York, approximately one mile south of the Gowanus facility. The entire site consists of twelve acres of land, six acres of which are under water. The Narrows facility utilizes three on-shore storage tanks for fuel oil storage. These above-ground storage tanks have a total capacity of approximately 5 million gallons. Fuel oil is supplied to these storage tanks through fuel barges. Fuel oil is pumped from the fuel barges at the dock through a conventional pier mounted pipe manifold to the two storage tanks. Natural gas is provided directly to the site from an interconnection on the KeySpan Energy Corporation’s natural gas pipeline system.

The Narrows facility commenced operation in 1972. All of this facility’s units are General Electric Frame 5 gas turbine generators that are mounted on two marine power barges.

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Boston Facilities

Mystic 8&9 Facility. The Mystic 8&9 facility consists of two combined-cycle power plants. Each power plant consists of two gas turbines and one steam turbine. The Mystic 8&9 facility has a net capacity of 1,360 MW in the summer and 1,658 MW in the winter. Our units at the Mystic 8&9 facility operate as intermediate units due to their relatively low heat rates and are independently dispatched. These units operate only on natural gas.

The table below outlines annual output and key operating statistics for the Mystic 8&9 facility for the years ended December 31, 2007, 2006 and 2005, and for the twelve months ended March 31, 2008. Because of their low heat rate, we view “net heat rate” in addition to EAF and EFORd as the key operating metrics for this facility.


	Twelve Months
	Ended
	March 31,		Year Ended December 31,
Mystic 8&9 Facility	2008		2007		2006		2005

Mystic Unit 8
Net Generation (MWh)		4,439,892		4,391,860		4,733,085		3,755,167
Net Capacity Factor (%)		64.2		63.7		69.0		54.6
Equivalent Availability Factor (%)		86.3		88.9		88.8		87.0
Equivalent Forced Outage Rate demand (%)		0.8		1.8		3.0		5.1
Net Heat Rate (BTU/kWh)		7,404		7,402		7,319		7,427
Mystic Unit 9
Net Generation (MWh)		4,140,101		4,126,722		4,711,631		3,624,848
Net Capacity Factor (%)		59.9		59.8		68.7		52.7
Equivalent Availability Factor (%)		82.8		85.4		89.9		84.0
Equivalent Forced Outage Rate demand (%)		1.0		0.7		2.6		9.1
Net Heat Rate (BTU/kWh)		7,377		7,387		7,303		7,510

The Mystic 8&9 facility is located on a 53-acre site in Everett, Massachusetts, directly north of Boston, adjacent to the Mystic River. There is land and infrastructure available at this site for development of new generating facilities. The Mystic 8&9 facility receives all of its natural gas requirements from the adjacent natural liquified gas terminal facility of Distrigas pursuant to a long-term gas supply agreement. This facility is connected to the Distrigas facility through a dedicated high pressure pipeline, which allows Distrigas to deliver natural gas at sufficiently high pressure such that costly natural gas compressors are not required.

The operating units at the Mystic 8&9 facility commenced commercial operations in April 2003 and June 2003, respectively. The units at Mystic 8&9 facility utilize the highly efficient MHI 501-G technology with dry, low NO_x combustion systems, which lower NO_x levels during the combustion process. MPS performs maintenance on our operating units at our Mystic 8&9 facility pursuant to two long-term service agreements.

Mystic Station Facility. The Mystic Station facility is comprised of a 566 MW steam combustion turbine, which we refer to as Mystic 7, and a 10 MW combustion turbine, which we refer to as Mystic Jet. The Mystic Station facility has a net capacity of 585 MW in the summer and 572 MW in the winter. Mystic 7 operates as an intermediate unit and the Mystic Jet unit operates as a peaking unit. Mystic 7 has the ability to operate at a minimum output level of 90 MW. This flexibility provides Mystic Station with the ability to easily respond to changes in regional load requirements. Mystic 7 can operate on either natural gas or No. 6 fuel oil any time of the year and fuel switching can be undertaken while the unit is in operation. The Mystic Jet unit operates on No. 2 fuel oil.

The table below outlines annual output and key operating statistics for Mystic Station for the years ended December 31, 2007, 2006 and 2005, and for the twelve months ended March 31, 2008. We focus on EAF and EFORd as the key operating metrics for this facility.

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	Twelve Months
	Ended
	March 31,		Year Ended December 31,
Mystic Station Facility	2008		2007		2006		2005

Mystic Jet
Net Generation (MWh)		103		88		269		137
Net Capacity Factor (%)		0.1		0.1		0.3		0.2
Equivalent Availability Factor (%)		80.5		80.5		93.9		85.5
Equivalent Forced Outage Rate demand (%)		18.2		18.2		34.2		41.4
Net Heat Rate (BTU/kWh)		19,281		20,292		19,578		20,349
Mystic 7
Net Generation (MWh)		852,687		930,697		413,038		891,344
Net Capacity Factor (%)		17.2		18.8		8.4		18.1
Equivalent Availability Factor (%)		89.0		85.4		89.4		76.4
Equivalent Forced Outage Rate demand (%)		1.6		3.4		3.3		14.8
Net Heat Rate (BTU/kWh)		13,903		12,900		12,851		12,788

The Mystic Station facility is located adjacent to the Mystic 8&9 facility in Everett, Massachusetts. Mystic 7 has 288,000 barrels of fuel oil storage on-site and leases an additional 575,000 barrels of storage capacity from ExxonMobil, which is connected to the facility through a dedicated pipeline. This fuel storage capacity facilitates fuel switching as well as providing additional revenue opportunities to resell fuel oil back to the market when beneficial.

Mystic Station has a strong operating history, with Mystic 7 and Mystic Jet having commenced operations in 1975 and 1969, respectively. Mystic 7’s turbine was manufactured by General Electric and Mystic Jet’s turbine was manufactured by Rolls Royce.

Fore River Facility. The Fore River facility consists of a 781 MW combined-cycle power plant consisting of two gas turbines and one steam turbine. The Fore River facility has a net capacity of 682 MW in the summer and 831 MW in the winter. The Fore River facility operates as an intermediate unit. This facility was designed, constructed and permitted with the potential for dual fuel capability. Commissioning of fuel oil operations was completed in the first quarter of 2007. As a result, the Fore River facility can operate on either natural gas or ultra low sulfur distillate fuel oil for up to approximately 45 days during the months of October through April of each year.

The table below outlines annual output and key operating statistics for the Fore River facility for the years ended December 31, 2007, 2006 and 2005, and for the twelve months ended March 31, 2008. We focus on net heat rate as well as EAF and EFORd as the key operating metrics for this facility.


	Twelve Months
	Ended
	March 31,		Year Ended December 31,
Fore River Station	2008		2007		2006		2005

Net Generation (MWh)		3,778,527		3,460,112		2,408,871		1,713,511
Net Capacity Factor (%)		54.7		50.2		35.1		24.9
Equivalent Availability Factor (%)		92.3		89.6		83.2		83.5
Equivalent Forced Outage Rate demand (%)		2.0		2.4		4.0		3.0
Net Heat Rate (BTU/kWh)		7,416		7,421		7,413		7,456

The Fore River facility is located on a 77-acre site in North Weymouth, Massachusetts, approximately 12 miles south of Boston. The physical plant is substantially similar to each unit of the Mystic 8&9 facility. There is land and infrastructure available at this site for development of new generating facilities. This facility has a firm natural gas transportation contract with Spectra. The Fore River facility has approximately 47,000 barrels of fuel storage on site and has a 10-year terminalling agreement with Sprague Energy, which includes the lease of a 94,000-barrel storage tank. This leased storage tank is located offsite and is connected to the facility through a dedicated pipeline.

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The Fore River facility commenced commercial operation in August 2003 and utilizes the same highly efficient MPS 501-G technology as the Mystic 8&9 facility.

Current and Potential Development Initiatives

Operational Efficiency Improvements

Our in-house corporate operations and engineering teams focus on improving our operating efficiency. These teams work with plant personnel to update our operating and training procedures, improve safety programs, environmental monitoring and compliance, and to identify capital projects to improve the reliability, efficiency and capacity of our plants. Our corporate operations and engineering teams also work with plant personnel to coordinate plant dispatch and fuel supply scheduling, general operational and engineering support, online electrical and mechanical system monitoring, health and safety monitoring and computerized data collection. Such oversight has improved our strategic planning of maintenance and outages, allowing us to optimize availability and reduce the effective forced outage rate.

Our corporate operations and engineering teams evaluate discretionary capital projects to meet certain return on capital thresholds and to maximize portfolio value, and have worked to improve contracting processes to focus on performance gains. These processes resulted in the overhaul at Astoria Unit 30 in the fall of 2006 that contributed to a 13.5 MW increase in Unit 30’s summer capacity rating for 2007 versus 2006. In addition, our preventative maintenance practices, capital investments made during recent major outages and strategic outage management have recovered the equivalent of over 125 MW of effective capacity by significantly lowering our forced outage rate relative to previous levels. Our corporate operations and engineering teams are proactive with respect to facility repairs and maintenance. Astoria Unit 40 commenced an overhaul in the fall of 2007 and Unit 50 is scheduled for overhaul in the fall of 2008, respectively, which are expected to result in increased reliability, improved efficiency and the ability to offer automatic generator control, which can be sold as a service in the ancillary market for additional revenues. Three of our gas turbine units at our Gowanus facility are scheduled for overhaul in the fall of 2009 to limit their susceptibility to an identified potential mechanical deficiency.

In addition to the unit overhauls, we have implemented other capital projects to maximize asset value, including projects focused on obtaining additional ancillary services revenue streams (i.e., control systems, voltage regulation and black-start). Astoria GT-1 was re-commissioned in August 2007 and provides the necessary energy for black-start capabilities with respect to Astoria Units 30, 40 and 50, allowing us to collect ancillary services payment for this capability. The restart of Unit GT-1 also provided 17 MW of additional capacity for the Astoria facility that is now bid into the NYISO capacity and electric energy markets.

Gowanus Improvement Project

Our Gowanus facility has a significant amount of unused space that could be utilized for new generating units. We believe that increasing our generating capacity at our Gowanus facility would enable us to capitalize on the favorable market conditions at this location within Zone J. In addition, we believe that this new capacity can be added in a cost-effective manner due to the existing infrastructure at such facility and our ability to spread the fixed costs with little incremental overhead needed.

After reviewing several equipment options, we recently announced that we will add approximately 100 MW of peaking generation capacity at the Gowanus facility. We refer to this project as the South Pier Improvement Project (“SPIP”). This project is anticipated to meet the specific needs of the immediate communities served by the Gowanus and Greenwood load pockets within Zone J area, which require more electricity than can currently be supplied during periods of high electrical demand. We expect to receive the necessary permits by the end of 2008 and our current plans provide that we will be in a position to begin construction as early as 2009, with the expansion fully operational by 2011. We estimate the expansion will cost between $100 million and $150 million. We anticipate financing this expansion through internally generated cash flow and external financing, as necessary.

As a result of the new installation, the existing units at the Gowanus facility as well as other units are expected to run less and SPIP is projected to reduce the environmental impact of the existing Gowanus facility. Additional environmental benefits will result from commitments made by us to achieve net

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environmental improvements through measures implemented in cooperation with the community and stakeholders.

Astoria Repowering Project

In June 2003, we were granted a certificate of environmental compatibility and public need (known as an “Article X certificate”) to repower the Astoria facility. The original repowering plan provided for replacement of the older combustion boilers with modern state-of-the-art combustion turbines. We subsequently have developed a revised plan that, because of technical changes to our original repowering plan, would require changes to the existing Article X certificate or would require new or additional permits. The current repowering plan is a three-phase approach based on combustion turbine that is currently commercially available. Each of the phases would be built generally within the footprint of the existing facility and the build-out process would systematically remove older equipment, remediate the facility as required and install state-of-the-art combined cycle equipment. The phases would be independent of one another so that each phase could be optimized, evaluated and financed separately based on market conditions at the time the phase is contemplated. We are currently evaluating the economics of the project to determine the market feasibility and optimum timing.

Fore River Facility

The 77-acre Fore River facility has considerable undeveloped land, on-site and off-site liquid fuel storage, a high pressure natural gas line and the existing basic infrastructure support systems that would be required for additional generation. Feasibility of this additional conventional generation and possible alternative energy generation would require a review of the existing infrastructure and a detailed evaluation of the project economics.

Competition

Wholesale power generation is a commodity-based, capital-intensive business that is prone to long-term industry cycles. Generation businesses operate locally, with regional supply largely serving regional demand to meet local system needs. Relative to other commodity industries, the business is highly fragmented with numerous market participants competing to provide supply to regional markets. There is wide variation in the capabilities, resources and nature of the market participants in most regions leading to a complex competitive dynamic unique to each regional market. Over the long term, market participants compete to build new plants, expand existing facilities, retire old plants and add new transmission lines, each of which can significantly change the amount of supply in a market. This complex interplay of individual competitor actions on the supply/demand balance in a region typically leads to periods of capacity shortage or surplus, creating long-term industry cycles in our markets.

Wholesale power generation is also sensitive to short-term fluctuations in energy supply and demand. Hour-to-hour changes in available generation resources, congestion on transmission lines and local weather conditions create hourly volatility in the energy supply/demand balance in a region. To meet fluctuating demand, available generation resources compete primarily on the basis of fuel cost and plant efficiency to supply energy at the lowest variable cost. The fleet of generation resources competing to supply electricity in a given region is largely dependent on the surrounding network of transmission lines and the ability to import electricity. As a result, the competitive position of our generation facilities is sensitive to their respective variable costs relative to other existing generation facilities in the same region and to changes in transmission import capability.

Our New York Facilities compete principally with other power generation facilities that are located within, or directly electrically connected to, the Zone J market. Our New York Facilities represent approximately 22% of the generation capacity available to the Zone J market and generate power to serve approximately 20% of the peak load in New York City. Four other competitors account for approximately 71% of the generation capacity available to the Zone J market (none of whom individually account for more than 23%) and two additional competitors comprise the remaining 7% of such peak generation capacity. Because natural gas and fuel oil typically set the market clearing price for energy in Zone J, we believe that our dual fuel capability provides us with a competitive advantage in being able to supply energy at a competitive price.

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Approximately 72% of the total peak generating capacity in Zone J has dual fuel capability. However, this percentage is significantly lower for intermediate units and thereby benefits our Astoria Units 30, 40 and 50 that can burn No. 6 fuel oil. Other units operated by competitors generally burn ultra-low sulfur diesel or other more expensive fuels and are subject to permit limitations (the ability to run on oil for some units is restricted to 30 days per year). In 2006, additional generating capacity of approximately 1,000 MW was introduced into Zone J, which has created a temporary capacity surplus. We expect that the mandated retirement of an existing 885 MW facility at the NYPA Poletti station in 2010, together with anticipated continued demand growth of approximately 100 to 200 MW per year within Zone J, will eventually eliminate this surplus capacity and create the need for additional capacity. We expect that either existing or potentially new competitors will compete to supply this additional capacity adding new units at existing sites, repowering older equipment or siting new transmission lines, which will continue to shift the supply/demand balance in Zone J.

Our Boston Facilities compete principally with other power generation facilities located in the New England area. As compared to our New York Facilities, our Boston Facilities compete across a broader geographic region due in part to the recent addition of transmission lines around Boston, which have relieved the transmission constraints in the region. A significant amount of the power generators within the ISO-NE market also utilize either natural gas or fuel oil to generate energy with natural gas or fuel oil setting the market clearing price for energy nearly 80% of the time in 2007. As a result, we believe our Boston Facilities are well-positioned relative to many competitors due to the highly efficient combined cycle technology utilized at the Mystic 8&9 and Fore River facilities as well as the dual fuel capability of the Mystic 7 facility. We believe that the supply/demand balance is tightening in the ISO-NE market as demand for energy continues to increase. Similar to the Zone J market, market participants will compete to add additional capacity to meet this increased demand, which will continue to affect our competitive position within this market.

Seasonality and Price Volatility

Our annual and quarterly operating results can be significantly affected by weather and energy commodity price volatility. Significant other events, such as substantial changes in demand for natural gas, damage to fuel supply or energy transmission infrastructure or interruptions in fuel supply or electricity transmission can increase fuel and power price volatility. We derive a majority of our annual revenues in the months of May through September, when demand for electricity is the highest in our core markets. Further, power price volatility is generally higher in the summer months. The winter months of December through March are characterized by volatility and price spikes in underlying fuel prices, which have tended to drive variability in energy prices. We apply risk management strategies to manage the seasonal and price volatility associated with our business.

Fuel Supply and Transportation

Our fuel requirements consist primarily of fuel oil and natural gas. The prices of fuel oil and natural gas are subject to macro- and micro-economic forces that can change dramatically in both the short and long term. At all of our dual fuel capable facilities other than Fore River, we can quickly and efficiently switch between fuels allowing us to adjust to changes in the cost and availability of fuels that we use. We obtain our fuel oil and natural gas primarily from Sequent and Distrigas. Spectra, Iroquois, Consolidated Edison and KeySpan provide us with fuel transportation services. Although temporary fuel availability generally does not have a material adverse impact on our business, localized shortages, transportation availability and supplier financial stability issues can and do occur. Issues related to the sources and availability of raw materials are fairly uniform across our business.

In 2006, we entered into a fuel management agreement (“FMA”) with Sequent for the Astoria facilities. We procure all day-ahead natural gas and all fuel oil for the New York Facilities from Sequent pursuant to the FMA and natural gas and fuel oil agreements entered into by us and Sequent in connection with the FMA. Pricing for natural gas and fuel oil purchased from Sequent pursuant to the FMA is based on published indices for natural gas and fuel oil. Additionally, Sequent provides management services related to the procurement, transportation and delivery of natural gas and fuel oil to the New York Facilities. Sequent is compensated for its services through a fee per unit of natural gas and fuel oil delivered to the New York Facilities, which is added to the price paid by us for natural gas and fuel oil. Sequent is paid monthly through a secured account

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into which certain of our electric energy revenues from NYISO are transferred. Pursuant to a Security Agreement between us and Sequent, Sequent has a first-priority lien on such revenues. We receive the net electric energy revenues from the secured account as long as Sequent has been paid amounts owed under the FMA, to the extent the amounts due are not disputed. If there is a dispute, we may nevertheless receive such revenues if we post a letter of credit for the benefit of Sequent in the disputed amount. The term of the FMA is through October 31, 2009, with automatic one-year extensions unless a party provides notice of termination at least six months prior to any such extension. In 2008, we entered into an FMA with Sequent for Fore River. We procure all day-ahead natural gas for Fore River pursuant to the FMA. This agreement also provides for secondary gas delivery to Mystic Station. Pricing for natural gas purchased from Sequent is based on published indices for natural gas. The term of the FMA is through March 31, 2011, with automatic one-year extensions unless either party provides notice of termination at least six months prior to any such extension.

We procure natural gas for our Mystic facilities pursuant to various agreements with Distrigas that obligate us to purchase and the supplier to provide a minimum quantity of natural gas. The price we pay for natural gas is based on certain published natural gas price indices. The price we pay for natural gas under these agreements may be subject to change if certain indices are no longer published or no longer represent the prevailing market price for the referenced market. We are required to pay certain liquidated damages if we do not purchase our obligated amount. This agreement was amended in April 2008 in connection with a settlement agreement resolving disputes under prior agreements with Distrigas. Pursuant to the terms of the settlement, we agreed to pay $18,175,000 plus accrued interest of $91,000 in full satisfaction of the amounts past due for liquidated damages and the disputed gas invoices. Our other natural gas and fuel oil requirements are satisfied through short-term arrangements or through purchases in the spot market. Fuel expense also includes fuel contract and emissions allowance.

We are party to an agreement with Spectra that provides natural gas transportation service to our Fore River facility. This agreement has a primary term of 20 years commencing on September 1, 2001, and continuing on a year-to-year basis after the primary term. The agreement provides that Spectra will transport a maximum of 140,000 dekatherms per day of natural gas to the Fore River facility. All pricing under this agreement is subject to contract rates accepted by FERC.

We are party to agreements with Iroquois for our Astoria facilities pursuant to which Iroquois transports up to 40,000 dekatherms per day of natural gas from Waddington to Hunts Point, New York, and up to 10,000 dekatherms per day from Brookfield to Hunts Point, New York. These contracts expire on February 1, 2013, but automatically renew for one-year terms thereafter.

We are party to agreements with KeySpan Energy Delivery New York pursuant to which they transport up to 100,000 dekatherms per day of natural gas from Goethals Station to the Gowanus facility, and up to 100,000 dekatherms per day from Goethals Station to the Narrows facility. The Gowanus agreement expires December 22, 2008, while the Narrows agreement expires October 25, 2008, but both agreements automatically renew for one-year terms thereafter.

Facility Maintenance Arrangements

We have two long-term services agreements with MPS under which they provide major maintenance services, including refurbishment of spare parts, for our gas turbine generators and related equipment at our Mystic 8&9 and Fore River facilities. Under these agreements, MPS receives a fixed fee (which is currently $30,000 per month) for monitoring this equipment and a variable fee based on the number of equivalent operating hours incurred by this equipment, and each of these fees is paid on a monthly basis. Planned maintenance services are required to be performed by MPS at intervals of no more than every 8,800 equivalent operating hours for each service. The agreements also provide that MPS shall receive minimum variable fees so as to require an aggregate payment equivalent to at least 8,600 equivalent hours for each major maintenance service. In the twelve months ended December 31, 2007, we paid $23.3 million to MPS pursuant to these agreements.

Significant Customers

For the three months ended March 31, 2008, we derived approximately 30.1% and 58.6% of our revenues from sales to NYISO and ISO-NE, respectively, and for the year ended December 31, 2007, we derived

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approximately 33.3% and 64.2% of our pro forma revenues from sales to NYISO and ISO-NE, respectively. NYISO and ISO-NE are ISOs or regional transmission organizations and are FERC-regulated entities that administer day-ahead and real-time energy markets, capacity and ancillary service markets and manage transmission assets collectively under their respective control to provide fair and competitive access to the transmission grid. We anticipate that NYISO and ISO-NE will continue to be significant markets given the scale of our asset base in these areas.

Employees

As of June 30, 2008, we had 400 employees, approximately 257 of whom were covered by collective bargaining agreements. During 2007, we did not experience any significant labor stoppages or labor disputes at any of our facilities. A summary of our employee structure is set forth below:


	Salaried		Union		Total

USPowerGen Corporate:
Corporate		53		—		53
New York Facilities:
Astoria		40		110		150
Gowanus		7		22		29
Narrows		2		14		16

Total New York Facilities		49		146		195
Boston Facilities:
Mystic 8&9		7		38		45
Mystic Station		9		47		56
Fore River		6		25		31
Management/Operations Support		19		1		20

Total Boston Facilities		41		111		152

Total		143		257		400

Properties

Our corporate headquarters are located in New York City, where we lease approximately 20,000 square feet. We also lease approximately 10,000 square feet in Charlestown, Massachusetts, a suburb of Boston. All of our power generation facilities are owned by us and are described in further detail in “— Company Overview” and “— Power Generation Assets.”

All of our properties are pledged to secure our borrowings under our existing credit facilities. See “Description of Principal Indebtedness.”

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Regulatory Matters

We are subject to extensive regulation by various federal and state government agencies. For ease of future reference, we have set forth below the names of these agencies along with the defined term we use for them in this section and throughout the document:


Name of Agency		Defined Term

Commodity Futures Trading Commission		CFTC
Federal Energy Regulatory Commission		FERC
Massachusetts Department of Energy Resources		MADOER
Massachusetts Department of Environmental Protection		MassDEP
Massachusetts Department of Public Utilities		MADPU
New York State Department of Environmental Conservation		NYSDEC
New York State Public Service Commission		NYPSC
North American Electric Reliability Corporation		NERC
Occupational Safety and Health Administration		OSHA
United States Environmental Protection Agency		EPA

In addition, we are subject to the market rules, procedures, and protocols of NYISO and ISO-NE.

Federal Energy Regulatory Commission

In 1978, Congress passed the Public Utility Regulatory Policies Act of 1978 which created a class of generating facilities known as Qualifying Facilities (“QFs”) and created the first real opportunity for private investment capital in the electric power industry in the United States. Up until that point, virtually all of the investment in the sector was made by vertically integrated utilities operating in a fully regulated, cost-based environment or by government-owned or financed entities. The Energy Policy Act of 1992 set the stage for competition in the wholesale electricity markets in the United States. This legislation, among other things, expanded FERC’s authority to order electric utilities to open their transmission systems to allow third-party suppliers to transmit, or “wheel,” electricity over their transmission lines and established a class of generators known as “Exempt Wholesale Generators” (“EWGs”) that were exempted from regulation under the Public Utility Holding Company Act of 1935. In 1996, FERC issued Order No. 888 that resulted in expanded open access to transmission lines, providing all eligible third-party wholesale market participants comparable transmission access. These actions have enabled power marketers, independent power producers, EWGs, QFs and utilities to compete actively in wholesale electric energy markets, consumers to have the right to choose their energy suppliers and competition to set the price of the generation component of electricity bills in deregulated areas.

In the late 1990s, deregulation evolved in a patchwork fashion across the country as individual states and regional markets implemented divergent market models with differing commercial rules, with certain states resisting the movement toward competitive markets. In an effort to promote competition, utilities in many states were forced to either divest their generation assets to independent power producers or transfer the assets to independent subsidiaries. This ushered in a major wave of private investment and the development of the “merchant generator” sector.

The Energy Policy Act of 2005 (the “EPAct of 2005”) was enacted on August 8, 2005. Among other things, EPAct of 2005 introduced new regulatory responsibilities for FERC and repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA of 2005”). The new responsibilities given to FERC under EPAct of 2005 include overseeing the reliability of the nation’s electricity transmission grid, implementing new mechanisms (including civil penalty authority) to prevent manipulation in energy markets, providing rate incentives to promote electric transmission investment, supplementing state transmission siting efforts in national interest electric transmission corridors, and reviewing certain holding company mergers and acquisitions involving electric utility facilities, as well as certain public utility acquisitions of generating facilities. EPAct of 2005 gave FERC the authority to issue

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rules to bar market manipulation in wholesale electric power and natural gas markets, and in electric transmission and natural gas transportation services. Congress granted FERC this authority out of recognition that wholesale power and natural gas markets had dramatically changed since the 1930s when the FPA and the Natural Gas Act were enacted. FERC has issued a final rule banning market manipulation in any transaction under its jurisdiction. This rule makes it unlawful for any entity involved directly or indirectly in a FERC jurisdictional transaction to intentionally defraud, make untrue statements, or omit material facts. The rule applies to electric utilities, natural gas companies, market participants, and any person or entity that is a part of FERC jurisdictional transactions, including our generating companies.

FERC, among other things, regulates the transmission and the wholesale sale of electric energy in interstate commerce under the authority of the FPA. In addition, under existing regulations, FERC determines whether an entity owning or operating a generation facility is an EWG, as now defined in PUHCA of 2005. Each of our U.S. companies that owns or operates generating facilities has been determined by FERC to qualify as an EWG.

The FPA gives FERC exclusive rate-making jurisdiction over the wholesale sale of electric energy and transmission of electric energy in interstate commerce. Under the FPA, FERC, with certain exceptions not applicable in our case, regulates the owners and operators of facilities used for the wholesale sale of electric energy or transmission in interstate commerce as public utilities. The FPA also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities.

Public utilities under the FPA are required to file their rate schedules for the wholesale sale of electric energy, pursuant to Section 205 of the FPA. All of our generating and power marketing companies make sales of electric energy pursuant to market-based rate schedules filed with and accepted by FERC. FERC’s orders that grant our generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently were to determine that we can exercise market power, create barriers to entry, or engage in abusive affiliate transactions. As a condition to the orders granting our generating companies market-based rate authority, we are required to periodically file an updated market power analysis to show that our generating companies continue to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. We are also required to report to FERC any material change in status that would reflect a departure from the characteristics that FERC relied upon when it granted our generating and power marketing companies market-based rates, and our generating and power marketing companies are required to make quarterly electronic filings with FERC providing information on sales of electric energy, capacity and ancillary services.

Since we last submitted our market power analyses to FERC necessary to retain authorization to make market-based rate sales from our New York and Boston Facilities, FERC has adopted new policies used to determine whether a seller possesses market power. We filed a revised market power analysis relating to our New York and Boston Facilities with FERC in June 2008. We believe that, unless modified, FERC’s new policies could result in a rebuttable presumption of market power with respect to both our New York and Boston Facilities. At the same time, FERC has adopted a rebuttable presumption that market monitoring and mitigation in ISO power markets is adequate to mitigate any market power that a seller may possess in such markets. Motions to intervene and comments relating to our revised market power analysis were required to be filed by July 15, 2008. No filings were timely submitted. We cannot predict at this time whether a late intervenor might be able to rebut this presumption as to the effect of ISO mitigation in one or both of the NYISO or ISO-NE markets and whether FERC would conclude that additional mitigation or revocation of market-based rate authority is appropriate.

In addition, our market-based sales are subject to certain market behavior rules and, if any of our generating companies were deemed to have violated any one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority, as well as criminal and civil penalties. If our generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

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The FPA also gives FERC jurisdiction to review certain corporate transactions and numerous other activities of public utilities. Section 203 of the FPA requires FERC authorization for: (1) direct or indirect mergers or consolidations involving public utilities; (2) the sale, lease or other disposition of public utility facilities of a value in excess of $10 million, as well as any direct or indirect transfer of control over a public utility; (3) the purchase by a public utility of the securities of another public utility with a value in excess of $10 million; (4) a public utility to purchase, lease or otherwise acquire an existing generation facility that has a value in excess of $10 million that is used for interstate wholesale sales and over which FERC has jurisdiction for ratemaking purposes; and (5) certain public utility holding company purchases of securities and direct or indirect mergers and consolidations. FERC will grant approval under FPA Section 203 if it finds that the proposed transaction will be consistent with the public interest, and does not raise concerns with respect to cross-subsidization involving a traditional public utility that has captive customers which receive services at cost-based rates.

Section 204 of the FPA gives FERC jurisdiction over a public utility’s issuance of securities or assumption of liabilities. However, FERC typically grants blanket approval for future securities issuances and the assumption of liabilities to entities with market-based rate authority. All of our generating and power marketing companies with market-based rate authority have blanket authorization under Section 204. In the event that one of our generating and/or power marketing companies were to lose its market-based rate authority, such company’s future securities issuances or assumption of liabilities could require specific approval from FERC.

In compliance with Section 215 of the FPA, as amended by the EPAct of 2005, FERC has approved the NERC as the Electric Reliability Organization (“ERO”). As the ERO, NERC will be responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. FERC has authorized NERC to delegate responsibility for developing and enforcing reliability standards, including the authority to impose penalties, to eight regional entities, including the Northeast Power Coordinating Council (“NPCC”), which is the regional entity for the New York and New England regions in which we operate. We are responsible for complying with standards developed by NERC and NPCC. NERC and NPCC may assess financial penalties for violations of reliability standards. Penalties assessed by NPCC are subject to review by NERC, and penalties assessed by either NPCC and NERC are ultimately subject to review by FERC.

PUHCA of 2005 provides FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs and Foreign Utility Companies. Because we are a holding company under PUHCA of 2005 solely as the result of owning one or more EWGs, we and our subsidiary generating companies are exempt from FERC access to books and records under PUHCA of 2005. However, FERC has asserted independent authority under the FPA granting it access to the books and records of public utilities and holding companies under certain circumstances. PUHCA of 2005 also provides state regulators access to books and records of public utility holding companies (including exempt holding companies that own EWGs) under certain circumstances.

Regional Regulation

In New York and New England, FERC has approved ISOs to administer wholesale centralized bid-based spot markets in their regions pursuant to tariffs accepted by FERC and associated ISO market rules. These tariffs/market rules dictate how the capacity and energy markets operate, how certain market participants may make bilateral sales with one another, and how entities with market-based rates are compensated within those markets. The ISOs in these regions also control access to and the operation of the transmission grid within their regions. We are affected by rule/tariff changes that occur in the NYISO and ISO-NE regions. The ISOs that oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address market power or price volatility. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell capacity, electric energy and ancillary services into the wholesale power markets.

ISO-NE and NYISO have Market Monitoring Units that monitor and investigate suspected anti-competitive behavior. ISO-NE and NYISO’s market mitigation plans specify that physical or economic

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withholding of an electric facility and uneconomic production from an electric facility are the types of conduct that may warrant mitigation. If a generator’s conduct is judged to have had or likely to have material price effects in the market, one of three types of mitigation measures may be imposed: bid restrictions, an obligation to pay for operating reserves or a default. Each of our assets has a “reference price” which can vary based on output. The reference price is designed to reflect our cost of generation transmission at the relevant output level. When certain electric system conditions are met (e.g., the presence of a constrained interface), NYISO and ISO-NE will apply a “conduct and impact” test to our bid. For ISO-NE, if our energy bid exceeds a $25 per MWh conduct test then our energy bid is replaced with our reference price. Similarly, if our bid in New York exceeds our relevant reference price plus a NYISO determined “load pocket threshold,” then our bid is replaced with our reference price. NYISO’s Automated Mitigation Procedures software reviews bids submitted by generators into the day-ahead market and automatically mitigates bids if specific thresholds for both bidding conduct and market impact are crossed. In addition, our New York Facilities are subject to several additional market power mitigation measures because we are a DGO.

New York Public Service Commission

The NYPSC currently exercises limited jurisdiction over the owners of generating facilities in New York State. For example, the NYPSC exercises jurisdiction with respect to transfers of control over companies owning generating assets in New York State. In addition, the NYPSC must approve any debt issued by a generating owner that is secured by assets located in New York State. Under New York State law and the EPAct of 2005, NYPSC has authority to impose reliability standards that exceed other locations. One example is the requirement that all load serving entities operating in Zone J currently purchase at least 80% of their peak load from in-city power generators.

Massachusetts Department of Public Utilities and Massachusetts Department of Energy Resources

MADPU is responsible for the structure and control of monopoly energy in the Commonwealth of Massachusetts; developing alternatives to traditional regulation and traditional monopoly arrangements; controlling prices and profits; monitoring service quality; regulating safety in the transportation and natural gas pipeline areas; and the siting of energy facilities. Its mission is to ensure that utility consumers are provided with the most reliable service at the lowest possible cost; protect the public safety from transportation- and gas pipeline-related accidents; oversee the energy facilities siting process; and ensure that residential ratepayers’ rights are protected.

The mission of MADOER is to implement energy policies that ensure an adequate supply of reliable, affordable and clean energy for the businesses and residents of Massachusetts, and to improve and streamline energy regulation, promote greater efficiency in all energy uses, reduce energy costs and mobilize energy education. Currently, our facilities are not directly regulated by either MADPU or MADOER.

Commodity Futures Trading Commission

CFTC, among other things, has regulatory oversight authority over the trading of certain energy-related commodities, including financial products and derivatives, under the Commodity Exchange Act (“CEA”). Specifically, under existing statutory authority, CFTC has the authority to commence enforcement actions and seek injunctive relief against any person, whenever that person appears to be engaged in the communication of false or misleading or knowingly inaccurate reports concerning market information or conditions that affected or tended to affect the price of natural gas, a commodity in interstate commerce, or actions intended to or attempting to manipulate commodity markets. CFTC also has the authority to seek civil monetary penalties, as well as the ability to make referrals to the Department of Justice for criminal prosecution, in connection with any conduct that violates the CEA. Proposals are pending in Congress to expand CFTC oversight of the over-the-counter markets and bilateral financial transactions.

Recent Regulatory Developments

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artificially raising capacity prices and to also prevent net purchasers of capacity including local load serving entities that provide electricity to end-users, from artificially depressing capacity prices by building uneconomic generation facilities. The measures will apply to pivotal suppliers, such as us, that own or control more than 500 MW of New York in-city capacity. Under the terms of the approved plan, the bid cap and revenue cap previously imposed on our New York Facilities as a result of our status as a DGO, or an owner of facilities divested in 1999 by Con Ed, has been removed. However, the approved plan imposes a new bid cap on our New York Facilities that require bids for capacity sales to be submitted at or below a new reference price. The new bid cap is equal to the higher of (i) the market clearing price on NYISO’s administratively set installed capacity demand curve on the basis of which all qualified in-city capacity is sold, and (ii) the marginal generating unit’s net avoided costs achieved by removing the unit from operations but maintaining the unit in operational condition. Additionally, market power mitigation measures were implemented to discourage future construction of uneconomic generation capacity that artificially reduces capacity prices below just and reasonable prices. The revised market rules will be implemented prospectively, without refunds to market participants.

The FERC order was issued concurrently with a report from FERC’s Office of Enforcement, which closed its investigation of the New York City installed capacity market, and concluded that the Enforcement Staff had found no evidence that any of the generators involved, including our New York Facilities, in the matter had violated NYISO’s service tariff or FERC’s anti-manipulation regulations.

In the near term, as a result of the reference price mechanism described above and the fact that the new market rules ignore the 1,000 MW of recently constructed facilities with uneconomic characteristics, we believe the market changes may substantially reduce capacity prices in Zone J within New York City. However, we also believe the expected retirement in 2010 of the 885 MW New York Power Authority Poletti station is likely to reduce the current surplus of capacity, eventually leading to an increase in Zone J capacity prices at that time. We believe the market changes are likely to produce a more predictable capacity market, and that the removal of the DGO revenue caps will increase the prices at which capacity is permitted to be sold by our New York Facilities.

ISO-NE implemented changes to its capacity market on December 1, 2006. Generators in that market can sell capacity as part of the FERC-approved FCM structure. This structure contemplates an initial settlement period followed by forward capacity auctions. During the settlement period, power generators supplying capacity receive fixed transition payments starting December 1, 2006, and ranging from $3.05 per kW-month from December 1, 2006 through May 31, 2008, increasing to $3.75 per kW-month from June 1, 2008 through May 31, 2009, to $4.10 per kW-month from June 1, 2009 to May 31, 2010. These capacity payments are adjusted based on plant availability. For the periods after May 2010, load serving entities will be required to purchase capacity through capacity auctions for three years forward to meet their installed capacity requirement. The forward capacity auctions began in the first quarter of 2008, with the initial auction for the June 1, 2010 to May 31, 2011 capacity year having cleared at the capacity floor price of $4.50 per kW-month. The second auction covering the June 1, 2011 to May 31, 2012 capacity year will be held in December 2008.

Environmental, Health, Safety and Security Matters

To assist us in managing our compliance with laws and regulations relating to the environment, occupational health, safety and security, we maintain an environmental, health, safety and security management system (“EHSMS”). The EHSMS is the framework for managing organizational processes, practices, procedures and resources for developing, implementing, achieving, reviewing and maintaining our environmental, health, safety and security policy and strategy. In addition, it is our intention to align our programs with the EPA’s National Environmental Performance Track Program and OSHA’s Voluntary Protection Program. Both programs offer regulatory incentives and recognition for strong compliance records. By focusing on our EHSMS performance, we believe we can progress towards and maintain sustainable environmental, health, safety and security practices across our company. We also benefit from the fact that most of the generating capacity of our Boston Facilities is less than six years old and is among the most efficient and environmentally friendly fossil-fuel power generating units in New England.

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Nonetheless, we are subject to numerous environmental laws and regulations in the development, ownership, construction and operation, as well as the decommissioning or closure of projects. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental laws, regulations and permit conditions, especially those with respect to air emissions from power generators, have become increasingly stringent in recent years. Such laws generally require regular capital expenditures for power plant upgrades, as well as modifications and the installation of certain pollution control equipment. We believe that future laws and regulations will require the acquisition of emissions allowances, the addition of emissions control or other environmental quality equipment as well as the imposition of certain restrictions on the operations of our facilities. We spent approximately $1.0 million in capital expenditures for environmental control projects in 2007, and we project that we will spend approximately $2.8 million for such projects in 2008 and approximately $5.9 million for such projects in 2009.

Environmental Regulatory Compliance Matters

Air Regulatory Requirements

Air emissions from our generating units are subject to federal and state regulatory requirements. Some facilities are subject to explicit, unit-by-unit emissions limits and most units are also subject to limitations on total annual emissions or total ozone season (May to October) emissions. In addition, our units are subject to compliance within existing “cap-and-trade” emissions allowance programs. Under “cap-and-trade programs” a total emissions target is established and affected generating units are allocated a certain portion of the total emissions. Units that emit fewer emissions than their allocated allowances can sell surplus allowances. Units that emit more than their allocated allowances must purchase allowances from others with surplus allowances.

In May 2005, the EPA published CAIR. This rule, which was recently vacated, applied to 28 eastern states and the District of Columbia and capped SO₂ and NO_x emissions from power plants in two phases — 2010 and 2015 for SO₂ and 2009 and 2015 for NO_x. These rules had differing application for states like Massachusetts which were considered to be “downwind” states. In August 2005, the EPA published a FIP, to ensure that generators affected by CAIR reduce emissions on schedule. In parallel actions in late 2005, the EPA proposed the second phase of the 8-hour ozone National Ambient Air Quality Standards (“NAAQS”) rule relating to NO_x emissions and signed proposed revisions to address attainment of NAAQS for “fine particulates” or “PM2.5” which would require affected states to implement further rules to address SO₂ and NO_x emissions. Numerous environmental groups, states and industry organizations challenged aspects of CAIR.

CAIR was subject to legal challenges and on July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit, in North Carolina v. Environmental Protection Agency vacated both CAIR and its associated FIP in their entirety and remanded them to the EPA. The EPA may either appeal the Court of Appeal’s decision or develop new proposed regulations to comply with section 110(a)(2)(D) of the Federal Clean Air Act (“CAA”) that requires states to develop implementation plans intended to prohibit sources from contributing to nonattainment of NAAQS in other states.

The Court of Appeal’s decision will likely result in a significant delay in the EPA promulgating a revised CAIR rule. In the interim, congressional action could result in new legislation that replaces part or all of CAIR. In addition, individual states may take action in response to the decision. For example, the NYSDEC indicated that it will repeal regulations intended to implement CAIR should CAIR remain vacated. The existing NYSDEC rules (Part 237 and 238) limiting NO_x and SO₂ emissions will remain in effect. Although currently uncertain, MassDEP may continue implementation of rules promulgated pursuant to CAIR. The Court of Appeal’s decision creates regulatory uncertainty with respect to the regulation of NO_x and SO₂ and the implementation of new programs in response to this decision could materially affect our operations.

In July 2005, the EPA published the Clean Air Visibility Rule which provides regional haze controls by targeting SO₂, NO_x, particulate matter and VOC emissions from various sources, including power plants of specific ages through the installation of BART. We believe most of our facilities will be in compliance with BART, except for our Mystic 7 unit, which has been identified as subject to BART by the MassDEP.

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There is increasing public concern and mounting political pressure to reduce or mitigate the effects of GHG emissions. Accordingly, ten Northeast and Mid-Atlantic states, in response to these public concerns, agreed to participate in the RGGI mandatory regional cap-and-trade program to reduce emissions of CO₂, which is considered a GHG and is linked to global climate change. From 2009 to 2015, RGGI aims to stabilize annual power sector emissions of CO₂ at the level of average annual emissions from 2000 to 2004, and from 2015 to 2018, RGGI would impose an annual reduction of approximately 2.5% in CO₂ emissions to achieve an overall 10% reduction in CO₂ emissions.

RGGI allows each state flexibility in the distribution of its CO₂ allocations. Both Massachusetts and New York are requiring that allowances are allocated through an open auction. Companies will subsequently be allowed to trade their allowances in a secondary market. RGGI will also allow affected facilities to reduce up to 3.3% of their CO₂ emissions by what is known as “acquiring offsets.” RGGI offsets include qualifying projects such as afforestation projects, methane capture, reduction of sulfur hexafluoride emissions and reduction or avoidance of CO₂ emissions from natural gas. However, RGGI restricts offsets to certain projects performed in certain states and to certain total quantities below a threshold. RGGI will run on three year cycles (2009 through 2011; 2012 through 2014; etc.) to adjust for any particular higher-than-expected demand year.

RGGI applies to electricity generator units that have a capacity of at least 25 MW and whose use of fossil fuels (such as coal or fuel oil) is greater than 50%. Our Gowanus and Narrows, Astoria GT-1 and Mystic Jet units will be exempt from RGGI because they fall below the 25 MW threshold. However, our other units, which operate using either natural gas or fuel oil, both of which emit CO₂, will be subject to RGGI which, together with other similar proposed regulations, could affect our costs of operations. Under the proposed RGGI rules, affected sources will be required to purchase allowances corresponding to 100% of their CO₂ emissions beginning in January 2009. We may obtain a portion of our RGGI allowances through offset projects or other projects designed to reduce emissions. We cannot predict the effect such requirements would have on our operations, although we manage our operations with a goal of minimizing our emissions and supporting long-term solutions.

There is also proposed federal legislation to regulate GHG emissions. In addition, the EPA issued an Advance Notice of Proposed Rulemaking on July 11, 2008 for a request for public comment on how to respond to the U.S. Supreme Court’s decision in Massachusetts v. Environmental Protection Agency, in which the Supreme Court ruled that the Clean Air Act authorizes regulation of greenhouse gases. We cannot accurately predict the outcome of such proposals, although they could adversely affect our business.

Our facilities are subject to a federal cap-and-trade program governing NO_x emissions during the ozone season from May 1 through September 30 of each year, designed to reduce summertime NO_x, an ingredient in the formation of smog. The program requires that one NO_x allowance be held for each ton of NO_x emitted. Each of our facilities that are subject to these rules have been allocated NO_x emissions allowances through 2011. We estimate that our current NO_x allowance portfolio total is sufficient to cover operations through 2011 based on current projections of unit operations and fuel use. However, if at any point emissions allowances are insufficient for the anticipated operation of each of these facilities, we would be required to purchase NO_x allowances to cover any deficit, and the cost could be material.

Most of our facilities are also subject to a cap-and-trade program governing SO₂ emissions under Phase II of the Federal Acid Rain Program (the “Acid Rain program”). Our Astoria (with the exception of Astoria

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GT-1), Mystic (with the exception of Mystic Jet) and Fore River facilities are subject to the SO₂ emissions regulated allowance program. Similar to the NO_x program, this program requires affected units to hold adequate allowances to cover all SO₂ emissions, and one SO₂ allowance must be held for each ton of SO₂ emitted over a calendar year. We estimate that our current SO₂ allowance is sufficient to cover operations at these facilities. If, however, at any point emissions allowances are insufficient for the anticipated operation of each of these facilities, we would be required to purchase SO₂ allowances to cover any deficit, and the cost could be material.

In addition to these Federal cap-and-trade programs, our units at Astoria (except for GT-1) are also subject to New York state-level NO_x and SO₂ cap-and-trade programs. The NO_x program is governed by the Acid Deposition Reduction NO_x Budget Trading Program (Part 237) and is only applicable during the non-ozone season. The state-level SO₂ program is regulated under the Acid Deposition Reduction SO₂ Budget Trading Program (Part 238). Similar to the federal programs, one NO_x or SO₂ allowance must be held for each ton emitted during the relevant compliance period. We believe that our current allowances are sufficient to cover operations at these facilities. If, however, at any point emissions allowances are insufficient for the anticipated operation of each of these facilities, we would be required to purchase NO_x and SO₂ allowances to cover any deficit, and the cost could be material.

The OTC has been established by Congress to govern the ozone and NO_x budget programs along the U.S. eastern seaboard from Maine to Virginia. The OTC proposes to implement a regional plan containing emission reduction targets for power plants. The OTC targets and timelines are yet to be implemented although additional SO₂ and NO_x reductions remain in discussion. While it is not possible to predict the effect of this effort, to the extent that the OTC is successful in implementing emission requirements that are more stringent than existing regimes, our company could be materially affected.

Water Regulatory Requirements

The Clean Water Act requires that cooling water intake structures reflect the BTA to minimize adverse environmental impact. In July 2004, EPA published regulations, applicable to our Astoria and Mystic 7 facilities, governing cooling water intake structures at large existing power plants that withdraw more than 50 million gallons of cooling water per day. The regulations required implementation of the BTA to minimize adverse environmental effects. The rules further provided facilities with several options for achieving the required BTA for cooling water systems. In January 2007, the U.S. Court of Appeals for the Second Circuit, in Riverkeeper v. Environmental Protection Agency, vacated key portions of the regulation and restricted the EPA’s ability to allow generators options for complying with BTA, including the ability to use habitat restoration or other measures for compliance. In July 2007, the EPA suspended the regulation. A new round of rulemaking has not been announced, and it may be several years before a revised cooling water intake structure regulation is finalized.

How we implement BTA will depend upon the options provided in EPA’s new rulemaking and may vary for each of our affected facilities. Possibilities include upgrades of existing water intake structures and/or equipment to the construction and installation of new, extensive water intake structures and/or equipment or reducing water intake flows. Until EPA proposes new regulations, it is not possible to estimate with certainty the capital costs that will be required to comply with this rulemaking. However, if BTA requires significant changes to the cooling water intake systems at our Astoria and Mystic 7 facilities, our costs to implement BTA may be material.

Our compliance with BTA will be further affected by additional requirements contained within an Order on Consent with NYSDEC, pursuant to which we agreed to undertake certain environmental obligations at our Astoria facility, including cooling water intake structure modifications.

Site Remediation Matters

Environmental laws impose liability on the owner or operator of any facility, including an electric generating facility, for releases of hazardous substances, including petroleum products. These laws impose

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liability without regard to whether the owner knew of or caused the release. We record an accounting accrual for site remediation matters when a cleanup obligation is reasonably estimable.

Our New York Facilities are party to an Order on Consent with the NYSDEC pursuant to which we agreed to undertake certain remediation obligations relating to historical releases of hazardous substances. Areas of known environmental contamination at the Astoria facility include soil, groundwater and non-aqueous phase liquid (“NAPL”) contamination, which are currently being passively recovered, as well as contaminated storm sewer sediment, soil and groundwater in the area around the facility’s storage tanks. Prior to our ownership of the Astoria facility, spills of transformer oil and fuel oil resulted in soil contamination that exceeded certain NYSDEC soil cleanup objectives in selected soil samples for polychlorinated biphenyls (“PCBs”), metals, and volatile and semi-volatile organic compounds. In accordance with documents previously submitted to the NYSDEC (including remedial action plans, a subsurface characterization report, an exposure assessment and a selected remedy report), remediation in a portion of Area 4 of our Astoria facility has been completed. Remedial plans for the remainder of Area 4 will be prepared and submitted to NYSDEC for approval and implementation. Additional selected areas at our Astoria facility have seven groundwater wells in which NAPL contamination has been detected. We are continuing to conduct NAPL removal in these groundwater wells as an interim remedial measure pending completion of the site-wide characterization efforts. Prior to our ownership, spills of No. 2 and No. 6 fuel oil occurred in the area of the Astoria “Fuel Oil Tank Farm,” where we store the fuel for our Astoria facilities. In 2007, we proposed to NYSDEC to perform a remedial investigation of the Fuel Oil Tank Farm in order to determine the potential for contamination of soil and groundwater. The potential for additional groundwater clean-up obligations will not be known until the remedial investigation is completed. We recorded an accrual of approximately $759,300 to address site investigation and remediation obligations at our Astoria facility. We maintain an insurance policy to address aggregate remediation costs at the Astoria facility. The insurance policy expires in 2009 and covers remediation costs if the cumulative total of remediation expenses exceeds a $10 million deductible. The policy is subject to an overall limit of $100 million.

At our Narrows facility, NAPL is present in the vicinity of that facility’s fuel oil storage tanks. Prior to our ownership of this facility, a spill of No. 2 fuel oil resulted in levels of NAPL in four on-site and two off-site groundwater monitoring wells. We are conducting remediation of NAPL, in accordance with the Site Investigation and Remediation Plan via the use of vacuum enhanced fluids recovery and manual bailing. Continued removal and recovery of NAPL is required for wells with greater than 0.1 feet of NAPL, in accordance with an August 23, 2002 agreement with NYSDEC, to achieve satisfactory remediation, with remediation expected to continue for an additional 10 years. We recorded an accrual of $650,000 for these clean-up efforts.

At our Mystic 7 facility, contamination is located beneath the facility’s active aboveground storage tanks (“AST”). Under the Massachusetts Contingency Plan (“MCP”) process, remediation of the soil and groundwater beneath these tanks will be required once these tanks are no longer in use. We do not currently intend to take these tanks out of service. The expected life of these ASTs is through 2020 (based on the expected life of the Mystic 7 generating unit). Currently, groundwater monitoring and periodic NAPL recovery is being conducted under an approved remedial plan. Should evidence of contaminant migration be discovered during routine monitoring, further remedial actions will be required even if the aboveground storage tanks are still in use. We recorded an accrual of $195,000 to address these groundwater monitoring and NAPL recovery monitoring activities through 2020. At the end of the useful life of the Mystic 7 facility, we would either refurbish these ASTs for an allowed alternative use, or remove them from service. Should we decide to remove these ASTs from service, additional investigative activities will be conducted to refine necessary remediation actions. We recorded an accrual of $45,000 to address these additional investigation activities.

The construction of Mystic 8&9 required the investigation and remediation of certain contaminants in accordance with the MCP. In completing the project, an Activity Use Limitation (“AUL”), was instituted for the remediation area. The AUL, recorded against the property deed for this facility, allows some contaminants to remain on site, with no further remediation required, provided affected soils are not disturbed and the site remains as an industrial use site.

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The construction of our Fore River facility required the investigation and remediation of certain contaminants in accordance with the MCP and the federal Toxic Substance Control Act. In completing the project, various AULs were instituted for the remediation area. These AULs, recorded against the property deed for this facility, allowed some contaminants to remain on site, with no further remediation required, provided affected soils are not disturbed and the site remains as an industrial use site.

Our total accrual for environmental contamination liabilities at our facilities that are probable and reasonably estimable at this time is $1,649,300. Other conditions that could give rise to environmental liabilities but are not reasonably estimable at this time, include soil and groundwater effects in the area around the Astoria facility’s storage tanks; additional remediation of the storm sewer line at the Astoria facility; and soil and groundwater effects at the Mystic 8&9, Mystic 7, and Fore River facilities.

Certain of our facilities were constructed at a time when asbestos was routinely used as an insulating material. We are not required under any applicable laws or regulations to remove the asbestos containing materials currently present at our facilities. We do, however, as a matter of course abate any such materials in connection with any significant facility expansion or improvements, or in the event that the material becomes damaged or could present a risk to our employees.

Homeland Security Regulations

Under the guidelines of the Maritime Transportation Security Act of 2002 and the requirements of homeland security advisories and directives, we have undergone substantial improvement to our facility security programs. We have made facility infrastructure improvements including perimeter access controls; camera surveillance and intrusion detection systems. We have increased security readiness by providing maritime security training to security and operational personnel. We regularly conduct operational security and emergency response readiness drills and exercises.

Litigation

Our principal stockholder, Madison Dearborn, was served with a Civil Investigative Demand (“CID”), by the DOJ on May 29, 2007. In the CID, the DOJ requested information from Madison Dearborn and its affiliates, including Astoria, related to transactions in the New York City capacity market, including the capacity swap we currently have in place. The DOJ’s investigation is pending. We responded to the information request contained in the CID on November 1, 2007. See “Risk Factors — We are subject to material litigation and regulatory proceedings.”

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MANAGEMENT

Directors, Executive Officers and Key Employees

Set forth below are the name, age, position and a description of the business experience of each of our executive officers, directors and other key employees.


Name	Age		Position

Directors and Executive Officers
Jacob J. Worenklein		59	Chairman, Chief Executive Officer and Director
Mark R. Sudbey		47	President and Chief Operating Officer
Jeff D. Hunter		43	Executive Vice President, Chief Financial Officer
Belinda Foxworth		49	Executive Vice President, General Counsel and Secretary
Craig Hart		39	Senior Vice President, Strategy and Corporate Development
Zaid F. Alsikafi		33	Director
Patrick C. Eilers		41	Director
Kip Horton		29	Director
Hunter Hunt		40	Director
Michael Kramer		38	Director
Thomas S. Souleles		40	Director
Barry Sullivan		76	Director
Jerry D. Thurmond		55	Director
Other Key Employees
Adam Allen		37	Vice President and Treasurer
Theodore A. Babcock		54	Vice President, Finance and Investor Relations
Wesley E. Kern		42	Senior Vice President Finance
John Reese		54	Vice President, Governmental Affairs
David White		50	Vice President and Controller

Directors and Executive Officers

Jacob J. Worenklein has served as our Chairman and Chief Executive Officer and as a member of our board of directors since the Combination and prior thereto he served in the same capacity at Astoria since February 2006. Prior to joining Astoria, Mr. Worenklein served as Chairman and Chief Executive Officer of American Power Generating, LLC, formerly known as US Power Generating Company, LLC (“APGLLC”), which was engaged in U.S. power asset acquisition initiatives since April 2003. Prior to joining APGLLC, Mr. Worenklein was head of the global power and energy sectors and the project finance business at Société Générale from 1996 until April 2003. Before joining Société Générale, Mr. Worenklein was a Managing Director and Global Head of Project Finance at Lehman Brothers from 1993 until 1996. Prior to joining Lehman Brothers, Mr. Worenklein was a partner and member of the executive committee at Milbank, Tweed, Hadley & McCloy LLP, where he founded and headed the law firm’s power, utility and project finance practices. Mr. Worenklein is a member of the Board of Directors and Audit Committee of Ormat Technologies, Inc., a NYSE listed developer and owner of geothermal and other renewable energy projects, and he is a member of the Board of Directors of GridPoint, Inc., a company engaged in the “smart grid” electric load management business. Mr. Worenklein served as an Adjunct Professor of Finance at The NYU Stern School of Business from 1997 to 2002. Mr. Worenklein has a BA degree from Columbia College and JD and MBA degrees from New York University.

Mark R. Sudbey has served as our President and Chief Operating Officer since the Combination and prior thereto he served in the same capacity at Astoria since October 2006. Prior thereto, Mr. Sudbey served as an Executive Vice President — Finance and Administration at Astoria since February 2006. Prior to joining Astoria, Mr. Sudbey served as an Executive Vice President of APGLLC since January 2006. Prior to joining

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APGLLC, Mr. Sudbey was the President, New York and Southeast Regions, of the Reliant Energy Wholesale Group, from June 2003 until January 2006. From February 2002 until June 2003 Mr. Sudbey served as Vice President, East Region Origination, of the Reliant Energy Wholesale Group. Mr. Sudbey served as Vice President of Energy Management Power Holdings for Orion Power Holdings from 1999 until 2002. Mr. Sudbey has a BS degree in engineering from the University of Massachusetts.

Jeff D. Hunter has served as our Chief Financial Officer since November 2007 and as our Executive Vice President since the Combination and prior thereto he served in the same capacity at Astoria since February 2006. Prior to joining Astoria, Mr. Hunter served as the Executive Vice President, Corporate Development, of APGLLC since September 2003. Prior to joining APGLLC, Mr. Hunter was a Partner with PA Consulting Group (and its predecessor company Hagler Bailly) where he was the global practice head of Energy Strategy & Risk Management from June 1998 until September 2003. Prior to joining PA Consulting Group, Mr. Hunter held various roles with El Paso Merchant Energy (and its acquired predecessor company Eastex Energy) from 1993 through 1997. Mr. Hunter graduated from the University of Texas at Austin with a BA degree in Economics in August of 1993.

Belinda Foxworth has served as our Executive Vice President since December 2007 and General Counsel and Secretary since the Combination. Prior thereto she served as Senior Vice President from the Combination until December 2007. Prior thereto she served as the Senior Vice President and General Counsel of Astoria from September 2006 until the Combination. Prior thereto, Ms. Foxworth was Vice President, Deputy General Counsel and Chief Compliance Officer of CMS Energy Corporation, an integrated energy company, and Senior Vice President and General Counsel of CMS Enterprises Corporation from July 1995 until March 2006. Prior to joining CMS, Ms. Foxworth was an attorney at Milbank, Tweed, Hadley & McCloy LLP from 1985 until 1995. Ms. Foxworth has a BA degree from Rollins College, an MBA from the University of Michigan and a JD from Georgetown University.

Craig Hart has served as our Senior Vice President of Strategy and Corporate Development since September 2007. Prior thereto, he served as our Vice President of Corporate Development and Commercial Strategy since the Combination, and prior to the Combination, he served in the same capacity at Astoria since February 2006. Prior thereto, Mr. Hart served as Vice President of APGLLC since November 2004. Before joining APGLLC, Mr. Hart was a Managing Consultant with the energy practice of PA Consulting Group where he worked from September 1999 until October 2004. Mr. Hart has a BA from The Colorado College and an MES from Yale School of Forestry and an MBA from Yale School of Management.

Zaid F. Alsikafi has served as a member of our board of directors since the Combination and prior thereto he served as a member of the board of directors of Astoria since February 2006. Mr. Alsikafi has been employed by Madison Dearborn since August 2003 and currently serves as a director, and was an associate at Madison Dearborn from 1999 until 2001. Mr. Alsikafi attended the Harvard Graduate School of Business Administration from 2001 to 2003. Mr. Alsikafi was with Goldman, Sachs & Co. in the financial institutions group from 1997 until 1999. Mr. Alsikafi currently serves on the Board of Directors of Boise Inc., Forest Products Holdings, L.L.C. (d.b.a. Boise Cascade, LLC), Univision Communications Inc. and First Wind Holdings Inc. Mr. Alsikafi has a BS from The Wharton School of the University of Pennsylvania and an MBA from Harvard Graduate School of Business Administration.

Patrick C. Eilers has served as a member of our board of directors since the Combination and prior thereto he served as a member of the board of directors of Astoria since February 2006. Mr. Eilers has been employed by Madison Dearborn since 1999 and currently serves as a Managing Director responsible for the firm’s energy and power practice. Prior to joining Madison Dearborn, Mr. Eilers was a Director with Jordan Industries, Inc. from 1995 to 1997 and an associate with IAI Venture Capital, Inc. from 1990 to 1994. Mr. Eilers played professional football with the Chicago Bears, Washington Redskins and Minnesota Vikings from 1990 to 1995. Mr. Eilers currently serves as a director of Magellan GP, LLC, Magellan Midstream Holdings GP, LLC and First Wind Holdings Inc. Mr. Eilers has a BS in Biology and Mechanical Engineering from the University of Notre Dame and an MBA from Northwestern University J.L. Kellogg Graduate School of Management.

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Kip Horton has served as a member of our board of directors since the Combination. Mr. Horton has served as a Director with Capstone Advisory Group, LLC since March 2004. Prior to joining Capstone, Mr. Horton was a consultant in Policano & Manzo, a legacy practice of FTI Consulting, from 2001 to February 2004. Mr. Horton has a BS in Business Administration from the University of Richmond.

Hunter Hunt has served as a member of our board of directors since the Combination and prior thereto he served as a member of the board of directors of Astoria since February 2006. Mr. Hunt is the founder of Hunt Power, L.P. and has served as its President since April 2005 and its Managing Director since June 1999. Mr. Hunt has also served as the President of Sharyland Utilities, L.P. since November 1998 and held the position of Senior Vice President at Hunt Consolidated Inc. since April 2001 and at Hunt Oil Company since April 2003. Mr. Hunt is a member of the executive board of the School of Engineering at Southern Methodist University, and serves as a member of the board of directors of Jeff Goodwin Town Center for Political Studies and as Chairman of 21st Century Council. Mr. Hunt has a BS from Southern Methodist University.

Michael Kramer has served as a member of our board of directors since the Combination. Mr. Kramer has served as a partner of Perella Weinberg Partners (“PWP”) since January 2007. Prior to joining PWP, Mr. Kramer was the founder and a partner of Kramer Capital Partners, an independent, privately-held investment banking firm, from August 2005 to January 2007. Prior to founding Kramer Capital Partners, Mr. Kramer was a partner and member of the Management Committee at Greenhill & Co. from January 2001 until May 2005. Mr. Kramer currently serves as a director of Pacific Crossing Limited, Trump Entertainment Resorts, Inc. and Unity Media SCA. Mr. Kramer has a BS from the California State University at Northridge.

Thomas S. Souleles has served as a member of our board of directors since the Combination and prior thereto he served as a member of the board of directors of Astoria since February 2006. Mr. Souleles has been employed by Madison Dearborn since 1995 and currently serves as a Managing Director. Mr. Souleles currently serves on the boards of directors of Boise Inc.; Great Lakes Dredge & Dock Corporation; Forest Products Holdings, LLC (d.b.a. Boise Cascade, LLC); Magellan GP, LLC; Magellan Midstream Holdings GP, LLC; Packaging Corporation of America; and The Children’s Memorial Medical Center; and the board of trustees of the National Multiple Sclerosis Society, Greater Illinois Chapter. Mr. Souleles has an AB from Princeton University, a JD from Harvard Law School and an MBA from the Harvard Graduate School of Business Administration.

Barry Sullivan has served as a member of our board of directors since the Combination. Mr. Sullivan served as the President and Chief Operating Officer and a member of the board of directors of EBG from January 2006 until the completion of the Combination. Mr. Sullivan has served as the President and Chief Operating Officer of K Road Power Management, LLC, a private investment company that targets investments in the U.S. power industry, since March 2003. Mr. Sullivan currently serves on the boards of directors of Liati Group, LLC, Liati Capital, LLC, Omega Tools, Inc., Perftech, Inc. and Hilliard Farber & Co. Inc. Mr. Sullivan has a BA from Columbia University and an MBA from the University of Chicago.

Jerry D. Thurmond has served as a member of our board of directors since the Combination. Mr. Thurmond has served as the Managing Partner of Willow Bend Capital Management, LLC (“Willow Bend”), a company that provides power sector consulting services to hedge funds, since December 2003. Mr. Thurmond has also served as Chief Financial Officer of Orbit Acquisition Corp. since December 2007 and as Treasurer of Navasota Funding Corp since February 2006. Prior to joining Willow Bend, Mr. Thurmond served as the Chief Financial Officer of Panda Energy International Inc. from December 1997 to December 2003. Mr. Thurmond currently serves on the Board of Directors of LSP Energy Limited Partnership. Mr. Thurmond has a BA in business administration and accounting from The University of Texas at Arlington and is a Certified Public Accountant.

Other Key Employees

Adam Allen has served as our Vice President and Treasurer since the Combination and prior thereto he served in the same capacity at Astoria since February 2006. Prior thereto Mr. Allen served as a Vice President of APGLLC since June 2003. Prior to joining APGLLC, Mr. Allen served as a consultant to technology and media companies in France. Prior to his work as a consultant, Mr. Allen was Chief Executive Officer of Magic

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Arts Corporation, a video-game software development studio he founded in 1996. From 1993 to 1996 Mr. Allen was an investment banking analyst at Lehman Brothers Inc. Mr. Allen has a BS in economics from The Wharton School of the University of Pennsylvania.

Theodore A. Babcock has served as our Vice President, Finance and Investor Relations since May 2008. Prior to joining our company, he was Managing Director of LS Power Equity Advisors, LLC from January 2007 until October 2007. Prior thereto, Mr. Babcock was a Managing Director with Laurel Hill Capital Partners from June 1999 to March 2006 and Chief Financial Officer of TNP Enterprises, Inc. from April 2000 to June 2005. From 1992 to 1998 he served in a number of capacities with Long Island Lighting Company, as well as KeySpan Energy Corporation following its merger with Long Island Lighting Company, most recently as Vice President, Treasurer and Assistant Corporate Secretary. Mr. Babcock has a BS in accounting from Manhattan College and an MBA in finance from Iona College.

Wesley E. Kern has served as our Senior Vice President Finance since January 2008. Previously, he served as Vice President of Corporate Development, and prior to the Combination he served in the same capacity at Astoria since June 2006. Prior thereto, Mr. Kern served as a corporate strategy advisor to APGLLC since August 2004. Prior to his affiliation with APGLLC, Mr. Kern served as a consultant to various renewable energy development companies from January 2003 to August 2004. Mr. Kern served as the Chief Financial Officer of Pacific Natural Energy from 2001 to 2002 and was a Vice President and energy investment banker with Simmons & Company International from 1997 until 2001. Mr. Kern has a BS from Rensselaer Polytechnic Institute and an MBA from The Jesse H. Jones Graduate School of Management at Rice University.

John Reese has served as our Vice President of Governmental Affairs since the Combination and prior thereto he served in the same capacity at Astoria since February 2007. Prior to joining Astoria, Mr. Reese worked at the New York State Public Service Commission as Executive Deputy from December 2006 until January 2007 and as Senior Policy Advisor from November 2003 until November 2006. Prior to joining the New York State Public Service Commission, Mr. Reese served as Vice President of Governmental Affairs for Reliant/Orion Power Holdings from March 2000 until October 2003. Mr. Reese worked on the development and implementation of the Climate Change Action plan for the U.S. Department of Energy from 1994 until 1998. Mr. Reese also served as a member of the Board of Directors of Enerwise Global Technologies from February 2007 to July 2007. Mr. Reese has a BA from Pennsylvania State University and an MBA from Russell Sage College.

David White has served as our Vice President and Controller since the Combination and prior thereto he served in the same capacity at Astoria since January, 2006. Prior to joining Astoria, Mr. White served as Vice President of Operations of Hunt Power, L.P. from September 1999 until January 2006. Mr. White worked in various management roles at Hunt Oil Company from September 1982 until September 1999. Mr. White has a BBA from the University of Texas at Austin and is a Certified Public Accountant.

Board Composition

Each of our directors was nominated to be a director pursuant to our Investor Rights Agreement. Messrs. Souleles, Alsikafi, Eilers, Hunt and Worenklein were nominated by the persons who held a majority of our Class B common stock at the time of such nomination (which was New Astoria). Messrs. Horton, Kramer, Sullivan and Thurmond were nominated by persons who held a majority of the Class A common stock at the time of such nomination. Our certificate of incorporation provides that, following the consummation of this offering, persons who held a majority of the Class B common stock immediately prior to this offering will be entitled to require any directors previously nominated by holders of Class A common stock pursuant to the Investor Rights Agreement to resign, and such vacancies shall be filled by independent directors appointed by the persons who held a majority of the Class B common stock immediately prior to this offering. We expect that, prior to the completion of this offering, our board will determine that Messrs. Horton, Kramer and Thurmond are “independent” according to the rules of the NYSE. If, following the completion of this offering, any of these directors are removed by the persons who held a majority of the Class B common stock prior to this offering, we may be required to appoint additional independent directors.

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In any event, we will be required to appoint additional independent directors within one year from the closing of this offering to satisfy the NYSE requirements that our board must be comprised of a majority of directors who are independent as defined under the rules of the NYSE, and our audit committee, compensation committee and corporate governance and nominating committee each must be comprised entirely of independent directors. See “Certain Relationships and Related Party Transactions — Agreements Related to the Combination — Investor Rights Agreement.”

Our amended and restated certificate of incorporation provides that, upon the completion of this offering, our board of directors will consist of three staggered classes of directors, as nearly equal in number as possible. The directors then in office will be entitled to assign directors to certain classes. At each annual meeting of stockholders, a class of directors will be elected for a three-year term to succeed the directors of the same class whose terms are then expiring. The terms of the directors will expire upon election and qualification of successor directors at the annual meeting of stockholders to be held during the years 2009 for the Class I directors, 2010 for the Class II directors and 2011 for the Class III directors.

Our by-laws provide that the authorized number of directors may be changed by a resolution adopted by our directors then in office. Any additional directorships resulting from an increase in the number of directors may only be filled by the directors and will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the directors. This classification of our board of directors could have the effect of delaying or preventing changes in control or changes in our management.

Board Committees

Our board of directors has established an audit committee, a compensation committee, a nominating and corporate governance committee and an IPO committee. Our board of directors has adopted a written charter for each of its committees other than the IPO committee, which charters will be available on our website upon the completion of this offering. The composition, duties and responsibilities of these committees are set forth below. Committee members will hold office for a term of one year. In the future, our board may establish other committees, as it deems appropriate, to assist with its responsibilities. Our Investor Rights Agreement provides that we are obligated to use reasonable best efforts to cause each committee of our board of directors to have a number of directors nominated by New Astoria in equal proportion to the number of directors nominated by New Astoria on our board. We will be required to make changes in the personnel serving on our audit committee, compensation committee and corporate governance and nominating committee to satisfy the NYSE requirement that each of these committees be comprised of a majority of independent directors within ninety days after the completion of this offering.

Audit Committee. The audit committee is responsible for (1) selecting the independent auditors, (2) pre-approval of all audit and non-audit services by the independent auditors, (3) assisting the board in monitoring the integrity of our financial statements, the independent auditors’ qualifications and independence, the performance of the independent auditors and our internal audit function and our compliance with legal and regulatory requirements, (4) establishing procedures for the receipt, retention, and treatment of complaints received by us regarding accounting, internal accounting controls or auditing matters, and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters, (5) annually reviewing an independent auditors’ report describing the auditing firms’ internal quality-control procedures and any material issues raised by the most recent internal quality-control review, or peer review, of the auditing firm, (6) discussing the annual audited financial and quarterly statements with management and the independent auditor, (7) discussing earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies from time to time, (8) discussing policies with respect to risk assessment and risk management, (9) meeting separately, periodically, with management, internal auditors and the independent auditor, (10) reviewing with the independent auditor any audit problems or difficulties and management’s response, (11) reviewing reports of attorneys or others with respect to evidence of material violations of securities laws or breaches of fiduciary duty, (12) setting clear hiring policies for employees or former employees of the independent auditors, (13) handling such other matters that are specifically delegated to the audit committee by the board of directors from time to time and (14) reporting regularly to the full board of directors.

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Our audit committee currently consists of Messrs. Alsikafi, Horton, Souleles, Thurmond and Worenklein. We expect that upon the completion of this offering, Messrs. Horton and Thurmond will be considered “independent” according to the rules and regulations of the SEC and the NYSE and that Mr. Alsikafi will qualify as an “audit committee financial expert” as such term is defined in Item 407(d) of Regulation S-K.

Compensation Committee. The compensation committee is responsible for (1) reviewing key employee compensation policies, plans and programs, (2) reviewing and approving the compensation of our executive officers and members of the board of directors, (3) reviewing and approving employment contracts and other similar arrangements between us and our executive officers, (4) reviewing and consulting with our Chief Executive Officer on the selection of officers and evaluation of executive performance and other related matters, (5) administration of stock plans and other incentive compensation plans, (6) developing and periodically reviewing succession plans of the Chief Executive Officer and screening and recommending to the Board candidates for Chief Executive Officer, (7) producing a compensation committee report on executive compensation as required by the SEC for inclusion in our annual proxy statement and (8) such other matters that are specifically delegated to the compensation committee by the board of directors from time to time. Upon completion of this offering, we expect our compensation committee to consist of Messrs. Eilers, Hunt, Kramer and Worenklein and we expect that Mr. Kramer will be considered “independent” according to the rules and regulations of the NYSE.

Nominating and Corporate Governance Committee. Our nominating and corporate governance committee’s purpose is to assist our board by identifying individuals qualified to become members of our board of directors consistent with criteria set by our board and to develop our corporate governance principles. This committee’s responsibilities include: (1) evaluating the composition, size and governance of our board of directors and its committees and making recommendations regarding future planning and the appointment of directors to our committees, (2) establishing a policy for considering stockholder nominees for election to our board of directors, (3) evaluating and recommending candidates for election to our board of directors, (4) overseeing the performance and self-evaluation process of our board of directors and developing continuing education programs for our directors, (5) reviewing our corporate governance principles and providing recommendations to the board regarding possible changes and (6) reviewing and monitoring compliance with our code of ethics and our insider trading policy. Upon the completion of this offering, we expect our nominating and corporate governance committee will consist of Messrs. Souleles, Eilers, Hunt, Sullivan and Worenklein and a director yet to be nominated who will be considered “independent” according to the rules and regulations of the NYSE.

IPO Committee. Pursuant to the Investor Rights Agreement, the IPO committee is responsible for strategy regarding execution, timing and pricing of this offering. The IPO committee consists of Messrs. Worenklein, Eilers, Kramer and Sullivan. Upon consummation of this offering, it is expected that the IPO committee will dissolve. See “Certain Relationships and Related Party Transactions — Agreements Related to the Combination — Investor Rights Agreement.”

Compensation Committee Interlocks and Insider Participation

Within six months of the date of the completion of this offering, no member of our compensation committee will be an officer or employee of us, nor will any member have been an officer or employee of us at any prior time. There is no interlocking relationship between any of our executive officers and compensation committee, on the one hand, and the executive officers and compensation committee of any other companies, on the other hand.

Code of Ethics

We will adopt a code of ethics that applies to our principal executive, financial and accounting officers and all persons performing similar functions, which will be available on our website. We intend to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of our code of ethics that apply to our principal executive, financial and accounting officers by posting such information on our website.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

This Compensation Discussion and Analysis (“CD&A”) describes the compensation arrangements we have with our “named executive officers” as required under the rules of the SEC. The SEC rules require disclosure for the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) (or principal financial officer), regardless of compensation level, and the three most highly compensated executive officers in our last completed fiscal year, other than the CEO and CFO. All of these executive officers, including the CEO and CFO for fiscal 2007, are sometimes referred to herein as the “named executive officers.”

Our named executive officers are:


Name		Title

Jacob J. Worenklein		Chairman and Chief Executive Officer and Director
Mark R. Sudbey		President and Chief Operating Officer
Jeff D. Hunter		Executive Vice President, Chief Financial Officer
Belinda Foxworth		Executive Vice President, General Counsel and Secretary
Craig Hart		Senior Vice President, Strategy and Corporate Development
Donna Brandin		Former Executive Vice President and Chief Financial Officer
Ian Nutt		Former Executive Vice President

The SEC rules require us to disclose the compensation earned by our named executive officers, including all chief executive officers or chief financial officers (or persons acting in similar capacities), in our last completed fiscal year regardless of whether such individuals have left USPowerGen. During fiscal 2007, Mr. Sudbey functioned as our CFO at the beginning of fiscal 2007, and continued in that capacity after he was promoted to President and Chief Operating Officer on March 23, 2007. He relinquished that role upon the appointment of Donna Brandin as our CFO on September 15, 2007. Ms. Brandin resigned from that position on November 30, 2007, and in anticipation of her resignation, Mr. Hunter was named to the position of CFO on November 20, 2007. Mr. Ian Nutt resigned from his position as Executive Vice President of USPowerGen on June 30, 2007.

USPowerGen was formed in February 2007 to facilitate the combination of Astoria and EBG. The Combination was effected on June 1, 2007, and resulted in each of Astoria and EBG becoming a wholly-owned direct subsidiary of USPowerGen. All of our current executive officers were appointed to senior executive positions with USPowerGen in connection with the completion of the Combination, although Mr. Hunter did not assume the position of CFO until November 20, 2007. Prior to the Combination, other than Mr. Hunter, who served as Astoria’s Executive Vice President, Corporate Development, each of the named executive officers served in a similar capacity with Astoria. As a result, unless otherwise noted, all of the historical compensation information set forth in this section represents compensation received by our executive officers from Astoria prior to the Combination, and from USPowerGen following the Combination. For financial reporting purposes, Astoria is considered the accounting predecessor of USPowerGen and none of our current executive officers were formerly employed by EBG. As a result, we have not set forth any information regarding the historical compensation arrangements of the executive officers of EBG.

Astoria’s business was acquired from Reliant by Astoria, a newly formed company controlled by Madison Dearborn, on February 23, 2006 in the MDP Acquisition. Each of Messrs. Worenklein, Sudbey and Hunter became an executive officer of Astoria upon the completion of the MDP Acquisition and, prior thereto, these executive officers were employed by APGLLC, a firm that was established by Mr. Worenklein to acquire power assets in the United States. In connection with the MDP Acquisition, principals of Madison Dearborn negotiated the compensation arrangements with these named executive officers, and the compensation paid to these executive officers reflects those negotiations. After the MDP Acquisition, Astoria recruited additional

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executive officers, including Ms. Foxworth in September 2006. The overall amounts and mix of compensation paid to these officers primarily reflect negotiations with them in connection with their recruitment.

In connection with the MDP Acquisition, Astoria established a compensation committee comprised of Messrs. Eilers, Hunt and Souleles (the “Astoria Compensation Committee”). The Astoria Compensation Committee was responsible for the oversight, implementation and administration of all of Astoria’s executive compensation plans and programs for the period commencing on the date of the MDP Acquisition through the effective date of the Combination. The Astoria Compensation Committee determined all of the components of compensation of the CEO, and, in consultation with the CEO, the compensation of the remaining executive officers.

On July 19, 2007, the Board of Directors of USPowerGen established a compensation committee, which is currently comprised of Messrs. Eilers, Hunt, Kramer and Worenklein (the “Compensation Committee”). The rules of the NYSE will require that a majority of the Compensation Committee be independent within 90 days following the completion of this offering and that the Compensation Committee be comprised entirely of independent directors within one year following the consummation of this offering. The Compensation Committee is responsible for (1) establishing the compensation for the directors of USPowerGen; (2) establishing the CEO compensation package and approving executive officer compensation packages; (3) approving CEO and senior officer employment, severance or change of control agreements; (4) developing and reviewing CEO succession plans, and screening and recommending to the Board candidate(s) for CEO; (5) reviewing and approving Director, CEO and senior executive officer benefit plans; (6) approving the creation and/or revision of Company officer incentive compensation and equity based plans, including grants thereunder; (7) producing and approving the Compensation Committee Report on Executive Compensation included in USPowerGen’s proxy statements and generally overseeing compliance with SEC compensation reporting requirements; (8) approving USPowerGen’s overall compensation policy; (9) reviewing and approving or recommending to the Board changes to or adoption of retirement plans; and (10) administering all equity based incentive plans.

Compensation Committee Review of Compensation

In light of this offering and the Combination, we expect that the Compensation Committee will undertake a substantial review of our existing compensation programs, objectives and philosophy and determine whether such programs, objectives, and philosophy are appropriate for our company as a stand-alone public company. The Compensation Committee may create a sub-committee to administer our benefit programs.

We expect that the Compensation Committee will review compensation elements and amounts for named executive officers on an annual basis, at the time of a promotion or other change in level of responsibilities, as well as when competitive circumstances may require. We may, but do not currently, use a third party consultant to assist us with determining compensation levels. We expect that each year our human resources department will compile a report of benchmark data for executive positions for companies that are similar to ours in size and operation, including summaries of base salary, annual incentive plan opportunities and awards and long-term incentive award values. The Compensation Committee has not yet finalized the companies that we will benchmark our compensation packages against, but we expect that they will determine this list shortly after completion of this offering and will review companies with characteristics similar to our own, which could include publicly traded energy generators in the United States with similar revenues and operating income levels and other factors, such as market capitalization or the markets in which these companies operate.

We expect that this benchmark data report will include a presentation of the minimum, median and maximum salaries and other forms of compensation provided by these companies. We expect that the CEO will then provide compensation recommendations to the Compensation Committee for executives other than himself based on this data and the other considerations mentioned in this compensation section. We expect that the Compensation Committee will recommend a compensation package that is comparable to the median compensation amounts provided by these companies, but the Compensation Committee has not yet adopted specific guidelines on the use of this data. The Compensation Committee will then discuss these

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recommendations with the CEO and the human resources department and will make a recommendation to the board, which the board will consider and approve, if appropriate.

We expect that the Compensation Committee will consider input from our CEO and CFO when setting financial goals for our annual incentive plan and will consider input from our CEO, CFO and certain other officers responsible for the operation of our plants when setting operational goals for our annual incentive plan. Also, we expect that Compensation Committee will consider input from our CEO, with the assistance of our vice president of human resources (for officers other than himself), regarding benchmarking and recommendations for base salary, annual incentive targets and other compensation awards. The Compensation Committee gives significant weight to our CEO’s judgment when assessing each of the other officer’s performance and determining appropriate compensation levels and incentive awards.

Objectives of Our Compensation Programs

The key objectives of our executive compensation programs are (i) to attract, motivate, reward and retain the best possible executive officers with the skills necessary to successfully manage our business; (ii) to achieve accountability for performance by linking annual cash incentive compensation to the achievement of measurable performance objectives; and (iii) to align the interests of the executive officers and our stockholders through incentive and long-term compensation programs. For our named executive officers, our annual and long-term incentives are designed to accomplish these objectives by providing a significant financial correlation between our financial results and total compensation.

The Compensation Committee will determine annually whether the compensation programs have met the objectives outlined above by assessing (i) the retention level or level of attrition among key executive officers year-over-year; (ii) the relationship between our financial performance year-over-year and increases or decreases in executive compensation; and (iii) our performance in relation to market prices and other objective criteria affecting our financial results.

Historically, base salaries have not comprised a major portion of the named executive officers’ compensation. A significant portion of the compensation of the named executive officers has historically consisted of equity compensation and/or cash incentive compensation contingent upon the achievement of financial and operational performance metrics. We expect to continue to provide our named executive officers with a majority of their compensation in this manner. These two elements of executive compensation are aligned with the interests of our stockholders because the amount of compensation ultimately received will vary with stock price and/or financial performance. Equity compensation derives its value from our equity value, which is likely to fluctuate based on our financial and operational performance. Payment of annual cash incentives is dependent on our achievement of pre-determined financial and operational objectives.

What Our Compensation Programs are Designed to Reward

A significant portion of the compensation paid to our executive officers is designed to reward them based on our financial and operational performance and increased stockholder value, as reflected in increases in our equity value.

As discussed throughout this CD&A, the compensation policies applicable to our named executive officers are reflective of our pay-for-performance philosophy, whereby a significant portion of both cash and equity compensation is contingent upon achievement of measurable operating income targets and enhanced equity value, as opposed to current cash compensation and perquisites not directly linked to objective financial performance. This compensation mix is consistent with our performance-based philosophy that the role of executive officers is to enhance stockholder value over the long term.

Elements of Compensation

The elements of our compensation program are:


	•	base salary;

	•	annual cash incentives;

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	•	equity incentives; and

	•	certain additional executive benefits and perquisites.

While the base salaries, cash incentives and equity incentives of the named executive officers in 2007 were compared to those of other portfolio companies of Madison Dearborn when they were established, each element was also evaluated in terms of its contribution to each executive’s overall total compensation package for the year, and whether the total compensation was appropriate.

Base Salary

We provide a base salary to our executive officers to compensate them for their services during the year. The base salaries for our named executive officers in 2007 were established by the Astoria Compensation Committee, based in large part on the salaries established for these persons in connection with the MDP Acquisition. When establishing the base salaries of the executive officers for 2007, a number of factors were considered, including:


	•	the years of service of the individual;

	•	the duties and responsibilities of the individual;

	•	our ability to replace the individual;

	•	the base salary at the individual’s prior employment;

	•	the salaries paid in New York City for similar duties;

	•	the cost of living;

	•	our ability to pay; and

	•	Madison Dearborn’s experience with other portfolio companies.

Mr. Hunter’s base salary was increased from $350,000 to $375,000 on February 26, 2007, as part of the general salary increase provided to all qualified employees.

Salaries for executive officers are reviewed on an as-needed basis, including at the time of a promotion or other change in level of responsibilities, as well as when competitive circumstances may require review. We seek to maintain base salaries that are competitive with the marketplace, to allow us to attract and retain executive talent. Increases in salary were previously based on evaluation of factors such as the individual’s level of responsibility, performance, level of compensation compared to comparable companies, salaries paid by other companies in our markets and changes in cost of living indexes. When establishing the base salaries for 2008, the Compensation Committee considered the same factors as used in prior years, but also considered the effect of the Combination and the resulting expansion of our company and the resulting increased levels of responsibility for our named executive officers, in particular with respect to Mr. Worenklein. With respect to Mr. Hunter, the Compensation Committee considered his promotion to Executive Vice President, Chief Financial Officer when establishing his base salary. The annual salaries in effect for each of our current executive officers for 2007 and 2008 are as follows:


	Annual Base Salary
Name	2008		2007

Jacob J. Worenklein	$	800,000	$	480,000
Mark R. Sudbey	$	475,000	$	450,000
Jeff D. Hunter	$	450,000	$	375,000
Belinda Foxworth	$	350,000	$	300,000
Craig Hart	$	300,000	$	275,000

On December 13, 2007, the Compensation Committee reviewed and established the annual base salaries for all of our executive officers for 2008 except for Mr. Hart, whose 2008 base salary was approved by the Compensation Committee on February 27, 2008, with the increase effective on March 3, 2008.

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Annual Cash Incentives

We provide short-term annual cash incentive awards (in the form of an annual cash bonus) to named executive officers to drive our short-term performance goals. The short-term incentive performance goals are derived during our strategic planning process. We use the procedures described above under “Compensation Committee Review of Compensation” to determine the appropriate bonus potential for each executive.

USPowerGen Annual Incentive Plan. On September 6, 2007, we established the US Power Generating Company Annual Incentive Plan (“AIP”) which is designed to retain employees and to reward the achievement of outstanding performance on an annual basis. Final award determinations are based on a combination of company, operating unit, and individual performance against objectives set by our Compensation Committee at the outset of a plan period, which corresponds to the fiscal calendar year. Bonuses granted under the AIP are paid in cash and are generally paid in March following the end of the year in which such bonuses were earned. The AIP is administered by our Compensation Committee and is subject to amendment by the Compensation Committee.

Award determinations for each individual under the AIP are determined by multiplying (i) the individual’s base salary, (ii) the individual’s target bonus incentive percentage, (iii) the bonus pool funding result and (iv) the individual’s performance adjustment.

Participants in the plan have a target bonus incentive percentage which is expressed as a percentage of base salary. Targets for our employees range from 7.5% to 100%, depending on the level of the individual within the organization, his or her ability to impact the performance of the business or business unit, and the competitive compensation market. The target bonus incentive percentage for 2008 for Mr. Worenklein is 100%, for Mr. Sudbey is 80%, for Mr. Hunter is 75%, for Ms. Foxworth is 75% and for Mr. Hart is 50%.

For purposes of determining an individual’s bonus funding pool result, we have established bonus pools based on seven operating groups within our company. The total dollar amount available to each bonus pool is equal to the sum of each participant’s target bonus amount. Our seven operating groups are:


	•	executive, corporate development and corporate services;

	•	finance and accounting;

	•	commercial operations;

	•	corporate engineering;

	•	Astoria plant operations;

	•	Gowanus and Narrows plant operations; and

	•	EBG plant operations.

The performance of each operating unit is measured in three broad categories, consisting of the following factors:


	•	financial (adjusted EBITDA for Astoria and EBG (weighted equally at 50% each));

	•	strategic (preparation for this initial public offering and integration of the Combination); and

	•	operational (plant level measurements, such as EFORd, safety and capital budget management).

Each operating unit is assigned a specific set of measurements (which, depending on the type of unit, may not include all of the measurements described above) which are designed to reward employees according to their unit’s performance on specific company or unit objectives. Therefore, individuals in one bonus pool may receive payments even though corporate level measurements (such as adjusted EBITDA) are not met. Objectives and/or their weightings are designed to relate directly to performance measures which can be impacted, directly or indirectly, by a given unit’s efforts and accomplishments. Each objective is assigned three performance measurement levels: (i) target, (ii) threshold and (iii) stretch. Performance at each level determines the value a particular measure will add to the overall result calculation. An operating unit which

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achieves its target performance objectives will allow that unit’s employees to be eligible for a bonus of 100%, whereas a unit threshold achievement may yield a bonus as low as 75% of the target amount and stretch performance can yield unit employees a bonus as high as 200% of the target amount. Performance below threshold results in no value (0%) assigned for a particular objective. All of our named executive officers will be measured across all three measurement categories, with the following weightings applied to each: Financial — 60%, Strategic — 20% and Operational — 20%.

For our named executive officers, our strategic targets consist of presenting to the board proposals for and managing realistic growth opportunities. Our operational targets consist of EFORd, commercial availability, heat rate, starting reliability, safety, environmental, water chemistry, expense budget and capital budget management measures. The bonus pool at target (100%) available to our executives (which includes our named executive officers), corporate development and corporate services personnel is $4,670,140 (which includes pro-rated amounts for partial year service where applicable).

Following the determination of the bonus funding pool result, individuals within that pool are assigned performance adjustment measurements, whereby the bonus may be adjusted up or down based on a qualitative evaluation of their performance either by management or, in the case of our named executive officers, by the Compensation Committee based on input from the CEO for all such officers other than himself.

Equity Incentives

We believe that a large portion of each named executive officer’s compensation should be both performance-based and in the form of equity awards. Accordingly, our long-term incentive awards are designed to make the interests of management and executives consistent with those of our stockholders. As described below, in connection with the MDP Acquisition, Astoria established an equity-based compensation plan through the issuance of Series B Units to certain employees (including the named executive officers), and the availability of Series A Units, which our executive officers were permitted to purchase. Following this offering, our primary means of providing equity incentive awards to our employees, including the named executive officers, will be through our 2007 Stock Incentive Plan (“Stock Incentive Plan”) and our Employee Stock Purchase Plan.

Astoria Series B Units. The terms of the Series B Units were established pursuant to Astoria’s Amended and Restated Operating Agreement and were issued pursuant to participating employees under the terms of an Executive Purchase Agreement. The Series B Units, which are profits interests for tax purposes, were issued to participants for no consideration and generally provide that the holder thereof is not entitled to participate in any distribution by Astoria until holders of the Series A Units have received their investment amount plus a specified rate of return on their investment. The aggregate percentage of distributions to which holders of Series B Units are entitled vary based on the aggregate internal rate of return for Madison Dearborn relative to the investment Madison Dearborn made in connection with the MDP Acquisition. The Series B Units were subject to vesting, with 66.67% of each participant’s Series B Units vesting ratably over a five-year period and subject to accelerated vesting in certain circumstances and with the remaining one-third of such Series B Units vesting upon the occurrence of a “substantial liquidity” or other event, as defined therein in the Executive Purchase Agreement, in each case as long as the named executive officer was employed by Astoria at such vesting date. Astoria issued 567 Series B Units on February 23, 2006, of which 462 were to the named executive officers in connection with the completion of MDP Acquisition and another 105 Series B Units on December 31, 2006, of which 46 were to the named executive officers, 28 Series B Units on February 16, 2007, none of which were to the currently employed named executive officers and 13 Series B Units on April 1, 2008, none of which were issued to the named executive officers.

Subsequently, in connection with the Combination, each holder of Series B Units exchanged the Series B Units for an equal number of Series B Nonvoting Common Units in New Astoria (the “New Series B Units”) with substantially identical terms to the Series B Units, subject to the Amendment to the Executive Purchase Agreement (the “Amendment”). The Amendment modified the vesting schedule of the New Series B Units such that, upon the occurrence of an initial public offering of USPowerGen, 100% of the New Series B Units would then be subject to a modified five-year vesting schedule, occurring on a daily basis back to the date of

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the original grant, with accelerated vesting upon receipt by Madison Dearborn of its investment in USPowerGen, together with an 8% per annum return (compounded semi-annually). Until this initial public offering is completed, however, each participant’s New Series B Units will continue to vest in accordance with the original Executive Purchase Agreement described above. Upon completion of this offering, all unvested New Series B Units will then commence vesting in accordance with the schedule set forth above, subject to upwards adjustment in accordance with the increase from 66.67% to 100% of New Series B Units then available for vesting which will be applied from the date of the original grant. In certain circumstances, subject to certain conditions, each holder will be entitled to receive on account of such New Series B Units his or her pro rata interest in our shares of common stock held by New Astoria based on a value of our company as determined in relation to the average price of our shares over a period of 20 trading days after this initial public offering. Such shares of common stock received by such holder will continue to vest on the same schedule as the New Series B Units in respect of which they were received. Based on an assumed public offering price of $ per share, which is the midpoint of the range set forth on the cover page of this prospectus, holders of the New Series B Units will indirectly own approximately shares of our common stock.

In general, the issuance of the Series B Units was intended to accomplish the following main objectives:


	•	encourage the judgment, initiative and efforts of key employees toward USPowerGen’s continuing success;

	•	increase equity ownership levels of key employees;

	•	assist USPowerGen in attracting, retaining and motivating key employees;

	•	reward participants for demonstrated leadership and performance in relation to the creation of stockholder value;

	•	ensure competitive levels of compensation in line with chosen peer groups; and

	•	balance the interests of participants and stockholders.

Astoria Series A Units. In addition, certain of our named executive officers participated in the MDP Acquisition and purchased for cash Series A Units on the same terms and conditions as did Madison Dearborn. In the Combination, these Series A Units were exchanged for nearly identical Series A Voting Common Units of New Astoria (the “New Series A Units”). Collectively, these New Series A Units will represent ownership of approximately % of our outstanding common stock upon completion of this offering (assuming an initial public offering price of $ per share, which is the midpoint of the range set forth on the cover page of this prospectus). This equity ownership further directly aligns the interests of those certain named executive officers with the interests of our stockholders. Please see “Principal and Selling Stockholders” for the ownership amounts of New Series A Units held by certain of our named executive officers.

USPowerGen Equity Incentive Plans. On December 13, 2007, we adopted our Stock Incentive Plan and prior to the completion of this offering we intend to adopt the US Power Generating Company 2007 Employee Stock Purchase Plan (“ESPP”). These plans will be our primary means of granting equity awards following this offering. Our Stock Incentive Plan authorizes us to grant incentive awards to our employees and directors. We expect that following this offering the Compensation Committee will use stock appreciation rights, stock option grants and restricted stock units as our principal forms of equity compensation because they are an effective means to align the long-term interests of our executive officers, employees and our stockholders and they are common methods for publicly-held companies to provide equity incentives to executive officers and employees. The grant-date value of certain equity awards, including stock options and stock appreciation rights, may be at risk because they may decline over the vesting period if there is a corresponding decrease in our stock price. We may in the future grant other equity-based awards, subject to the Compensation Committee’s discretion. We expect that on a periodic basis, as the Compensation Committee deems appropriate but not less than annually, the Compensation Committee will review the equity awards previously awarded to management, the performance of our business and the performance of our stock. We expect that

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the Compensation Committee will establish target levels of incentive holdings that it would like members of our management to have. Based on these factors, the Compensation Committee will determine appropriate levels of equity awards and may make additional grants following a review. In determining the number of equity incentive awards to be granted to executives, we take into account the individual’s position, scope of responsibility, ability to affect profits and shareholder value and the individual’s historic and recent performance and the value of stock options or other equity incentive awards in relation to other elements of the individual’s total compensation.

Additional Executive Benefits and Perquisites

We expect that, prior to the completion of this offering, Mr. Worenklein will become party to an employment agreement with us pursuant to which he will be entitled to receive specified benefits. This agreement is described below in “Employment and Other Arrangements.” Since this employment agreement has not yet been executed, the payments and other benefits that Mr. Worenklein is entitled to receive upon a termination of his employment are set forth in his Executive Purchase Agreement, which is described below in “Potential Payments Upon Termination and Change in Control.” We anticipate that prior to the completion of this offering we will enter into employment agreements (which agreements will contain rights to certain payments and benefits upon a termination of employment) with our other named executive officers. Consistent with our compensation philosophy, we intend to continue to maintain our current benefits for our executive officers, including a 401(k) plan described below, executive medical benefits paid for by our company, life and accidental death and dismemberment insurance premiums, housing relocation benefits and paid vacation. The board, in its discretion, may revise, amend or add to an officer’s executive benefits if it deems it advisable. We believe these benefits are generally equivalent to benefits provided by comparable companies. We have no current plans to change the levels of benefits provided thereunder.

We sponsor a tax-qualified employee savings and retirement plan, or 401(k) plan, which covers most employees who satisfy certain eligibility requirements relating to minimum age and length of service. Under the 401(k) plan, eligible employees may elect to contribute a minimum of 1% of their annual compensation, up to a maximum amount equal to approximately 50% of compensation. The 401(k) plan provides for an annual matching contribution of 100% of the first 6% of the participants’ contribution, plus a 2% discretionary profit sharing matching contribution and a discretionary annual employer contribution of up to 3%. Union employees may contribute and receive a matching contribution based on the terms of their collective bargaining agreements. We announce annually the amount of discretionary matching contributions that we will make. For 2006, we made discretionary matching contributions of approximately $153,420 in July 2007. Of this amount, $26,587 was contributed in respect of our named executive officers.

Accounting and Tax Considerations

In determining which elements of compensation are to be paid, and how they are weighted, we also take into account whether a particular form of compensation will be deductible under Section 162(m) of the U.S. Internal Revenue Code of 1986, as amended (the “Code”). Section 162(m) generally limits the deductibility of compensation paid to our named executive officers to $1 million during any fiscal year unless such compensation is “performance-based” under Section 162(m). However, under a Section 162(m) transition rule for compensation plans or agreements of corporations which are privately held and which become publicly held in an initial public offering, compensation paid under a plan or agreement that existed prior to the initial public offering will not be subject to Section 162(m) until the earlier of: (1) the expiration of the plan or agreement; (2) a material modification of the plan or agreement; (3) the issuance of all employer stock and other compensation that has been allocated under the plan; or (4) the first meeting of stockholders at which directors are to be elected that occurs after the close of the third calendar year following the year of the initial public offering (the “Transition Date”). After the Transition Date, rights or awards granted under the plan, other than options and stock appreciation rights, will not qualify as “performance-based compensation” for purposes of Section 162(m) unless such rights or awards are granted or vest upon pre-established objective performance goals, the material terms of which are disclosed to and approved by our stockholders.

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Our compensation program is intended to maximize the deductibility of the compensation paid to our named executive officers to the extent that we determine it is in our best interests. Consequently, we may rely on the exemption from Section 162(m) afforded to us by the transition rule described above for compensation paid pursuant to our pre-existing plans. In addition, our Stock Incentive Plan has been designed to permit our Compensation Committee to grant stock options and other awards which will qualify as “performance-based compensation” under Section 162(m).

Many other Code provisions, SEC regulations and accounting rules affect the payment of executive compensation and are generally taken into consideration as programs are developed. Our goal is to create and maintain plans that are efficient, effective and in full compliance with these requirements.

Report on Executive Compensation

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee has recommended to the board of directors that the Compensation Discussion and Analysis be included in this registration statement on Form S-1.

The Compensation Committee consists of:

Patrick Eilers

Hunter Hunt

Michael Kramer

Jacob Worenklein

Compensation Tables

We are generally required to provide information regarding the compensation earned during our most recently completed fiscal year by our principal executive officer, principal financial officer and our three other most highly compensated executive officers. In addition, we are required to provide information regarding the compensation earned during the most recently completed fiscal year for any persons who served us in the capacity of principal executive officer or principal financial officer at any point during the fiscal year. As a result, the tables include compensation information for Ms. Brandin, even though she resigned as our CFO on November 30, 2007 and Mr. Nutt, who, although he resigned as an executive officer on June 30, 2007, was one of the most compensated officers of USPowerGen for the past year. As discussed above, we refer to the individuals listed in the tables as our named executive officers.

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Summary Compensation Table

The following table shows the compensation earned by our named executive officers during the payroll year ended December 31, 2007. The compensation consists of salary, cash bonus and, in some cases, equity awards. We did not grant any options to our named executive officers in 2007.

SUMMARY COMPENSATION TABLE


											Non-Equity		Nonqualified
							Stock		Option		Incentive Plan		Deferred			All Other
			Salary				Awards⁽²⁾		Awards		Compensation⁽³⁾		Compensation			Compensation⁽⁴⁾
Name and Principal Position	Year		($)⁽¹⁾		Bonus ($)		($)		($)		($)		Earnings ($)			($)
(a)	(b)		(c)		(d)		(e)		(f)		(g)		(h)			(i)			Total($)(j)

Jacob J. Worenklein		2007	$	481,846		—	$	155,982		—	$	470,000	$	2,200		$	87,581		$	1,197,609
Chairman and CEO
Mark R. Sudbey		2007	$	451,731		—	$	383,677		—	$	470,000	$	(730	)	$	41,340		$	1,346,018
President and COO⁽⁵⁾
Jeff D. Hunter		2007	$	372,596		—	$	53,362		—	$	470,000	$	468		$	151,766		$	1,048,192
Executive Vice President, Chief Financial Officer⁽⁶⁾
Belinda Foxworth		2007	$	301,154		—	$	407,891		—	$	280,000	$	(507	)	$	86,070		$	1,074,608
Executive Vice President, General Counsel and Secretary
Craig Hart		2007	$	270,687		—	$	20,524		—	$	280,000	$	(437	)	$	41,519		$	612,293
Senior Vice President, Strategy and Corporate Development
Donna Brandin		2007	$	95,192		—		—		—		—		—		$	463,099	⁽⁸⁾	$	558,291
Former Executive Vice President and Chief Financial Officer⁽⁷⁾
Ian Nutt		2007				—	$	213,303		—				—		$	3,011,341	⁽¹⁰⁾	$	3,224,644
Former Executive Vice President⁽⁹⁾


(1)		USPowerGen’s payroll is paid on a bi-weekly basis. The first payroll in a given year may contain payments for time worked in the prior calendar year. The first payroll in 2007 contained payment for 5 days carried over from the 2006 calendar year, and the first payroll in 2008 contained 6 days carried over from the 2007 calendar year. For purposes of this table, those amounts have been offset, resulting in the payment of one additional day in 2007. As a result, the named executive officers received the following additional amounts to their 2007 base pay, which were paid in 2008: Mr. Worenklein — $1,846 (base salary of $480,000); Mr. Sudbey — $1,731 (base salary of $450,000); Mr. Hunter — $1,442 (base salary of $375,000); Ms. Foxworth — $1,154 (base salary of $300,000); Mr. Hart — $1,058 (base salary of $275,000). Ms. Brandin’s and Mr. Nutt’s salaries do not include the additional day as their employment with USPowerGen ended prior to December 31, 2007.

(2)		Represents the dollar value of vesting of Series B Units during the year ended December 31, 2007 at the value per unit on the date of grant, as follows:


				Number of		Dollar Amount
Named Executive Officer	Stock Grant	Value Per Unit		Units Vested		of Vested Units

Mr. Worenklein	February 23, 2006	$	4,398		35.5	$	155,982
Mr. Sudbey	December 31, 2006	$	122,367		2.8	$	342,629
	February 23, 2006	$	4,398		9.3	$	41,048
Mr. Hunter	February 23, 2006	$	4,398		12.1	$	53,362
Ms. Foxworth	December 31, 2006	$	122,367		3.3	$	407,891
Mr. Hart	February 23, 2006	$	4,398		4.7	$	20,524
Mr. Nutt	February 16, 2007	$	130,144		—	$	—
	February 23, 2006	$	4,398		48.5	$	213,303


(3)		Represents the dollar amount of the named executive officer’s annual non-equity incentive bonus for 2007, which was paid on March 17, 2008.

(4)		Represents the amounts set forth in the table immediately below. We maintain medical, dental, life and disability insurance plans for all of our employees, including our named executive officers. Amounts paid by us for such insurance plans for the benefit of our named executive officers have not been individually included in the table above because these plans do not discriminate in scope, terms or operation in favor of executive officers and are generally available to all salaried employees.

(5)		Mr. Sudbey functioned as our Chief Administrative Officer until his promotion to President and Chief Operating Officer on March 23, 2007. Mr. Mark R. Sudbey also functioned as our CFO until he relinquished that role upon the appointment of Donna Brandin as our CFO on September 15, 2007.

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(6)		Mr. Hunter functioned as our Executive Vice President, Commercial and Corporate Development until his promotion to CFO on November 20, 2007.

(7)		Ms. Brandin resigned as an executive officer on November 30, 2007.

(8)		The $463,099 consists of a one-time payment of $458,599 and $4,500 for contributions to a retirement plan as set forth below to Ms. Brandin upon her resignation from USPowerGen.

(9)		Mr. Nutt resigned as an executive officer on June 30, 2007. Mr. Nutt was never formally an employee of USPowerGen, as he was employed by Atkins Global with whom our company had a consulting agreement by which Mr. Nutt provided services to us. However, during his consulting period, he was appointed an Executive Vice President of our company, and therefore we have included his compensation information in this CD&A.

(10)		The $3,011,341 consists of $11,341 for financial advisory and preparation services and as described below in “— Options Exercised and Stock Vested,” the $3,000,000 represents the amount paid in 2007 for the repurchase of Mr. Nutt’s vested Series B Units.

ALL OTHER COMPENSATION


							Company
	Perquisites and						Contributions to
	Other Personal				Insurance		Retirement and
Name	Benefits⁽¹⁾		Tax Payments		Premiums⁽²⁾		401(k) Plans		Total

Jacob J. Worenklein	$	33,226		—	$	25,293	$	37,119	$	95,638
Mark R. Sudbey	$	8,651		—	$	4,651	$	35,060	$	48,362
Jeff D. Hunter	$	107,121		—	$	13,078	$	37,398	$	157,597
Belinda Foxworth	$	56,248		—	$	2,668	$	28,859	$	87,775
Craig Hart	$	8,393		—	$	4,851	$	32,801	$	46,045
Donna Brandin		—		—		—	$	4,500	$	4,500
Ian Nutt	$	11,341		—		—		—	$	11,341


(1)		Represents the value of the following perquisites paid to each of the following of our named executive officers:


	•	Jacob J. Worenklein


	•	financial advisory and tax preparation services — $24,267^(a)
	•	insurance payments — $8,959^(b)


	•	Mark R. Sudbey


	•	financial advisory and tax preparation services — $5,989^(a)
	•	insurance payments — $2,662^(b)


	•	Jeff D. Hunter


	•	financial advisory and tax preparation services — $8,319^(a)
	•	commuting costs — $55,500^(c)
	•	housing — $43,302^(d)


	•	Belinda Foxworth


	•	financial advisory and tax preparation services — $8,577^(a)
	•	insurance payments — $7,501^(b)
	•	commuting costs — $19,170^(c)
	•	housing — $21,000^(d)


	•	Craig Hart


	•	financial advisory and tax preparation services — $7,914^(a)
	•	commuting costs — $479^(c)


	•	Ian Nutt


	•	financial advisory and tax preparation services — $11,341^(a)


	(a)	The financial advisory and tax preparation services for our named executive officers are provided through a third party vendor experienced with issues regarding the Series B Units. Given the complexity of these issues, we believe that the provision of such benefits to such individuals allow the named executive officers to focus on their job responsibilities.

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	(b)	The insurance payments provided to our named executive officers include disability policies for Messrs. Worenklein and Sudbey, and Ms. Foxworth.
	(c)	The commuting costs provided to Mr. Hunter and Ms. Foxworth, neither of whom are New York residents, represent transportation costs to our New York headquarters. The commuting costs provided to Mr. Hart represent in-city transportation costs to our New York headquarters.

	(d)	The housing costs provided to our named executive officers represent local living expenses for those named executive officers who are not New York residents.


(2)		Represents the value of non-standard life and disability benefits for such individual.

Grants of Plan-Based Awards

During the year ended December 31, 2007, each of our named executive officers participated in our annual cash bonus plan in which each officer was eligible for awards set forth under “Estimated Future Payouts Under Non-Equity Incentive Plan Awards” below. The following table provides information on each of these awards on a grant-by-grant basis. In each case, the grant date of the award is the same as the approval date. The actual payout for the named executive officers is set forth above in column (g) of the summary compensation table.

GRANTS OF PLAN-BASED AWARDS


																All Other			All Other
																Stock			Option
																Awards:			Awards:		Exercise
				Estimated Future Payouts						Estimated Future Payouts						Number of			Number of		or Base
				Under Non-Equity						Under Equity Incentive						Shares of			Securities		Price of		Grant Date
				Incentive Plan Awards						Plan Awards						Stocks or			Underlying		Option		Fair Value
	Grant			Threshold		Target		Maximum		Threshold		Target		Maximum		Units			Options		Awards		of Stock
Name	Date			($)		($)		($)		($)		($)		($)		(#)			(#)		($/Sh)		and Option
(a)	(b)			(c)		(d)		(e)		(f)		(g)		(h)		(i)			(j)		(k)		Awards

Jacob J. Worenklein		9/6/07⁽¹	⁾	$	180,000	$	240,000	$	480,000		—		—		—		—			—		—		—
Mark R. Sudbey		9/6/07⁽¹	⁾	$	168,750	$	225,000	$	450,000		—		—		—		—			—		—		—
Jeff D. Hunter		9/6/07⁽¹	⁾	$	140,625	$	187,500	$	375,000		—		—		—		—			—		—		—
Belinda Foxworth		9/6/07⁽¹	⁾	$	112,500	$	150,000	$	300,000		—		—		—		—			—		—		—
Craig Hart		9/6/07⁽¹	⁾	$	103,125	$	137,500	$	275,000		—		—		—		—			—		—		—
Donna Brandin⁽²⁾		9/6/07		$	168,750	$	225,000	$	450,000		—		—		—		—			—		—		—
Ian Nutt⁽⁴⁾		2/16/07			—		—		—		—		—		—		7	⁽³⁾⁽⁴⁾					$	130,144


(1)		The goals for the AIP were approved on September 6, 2007 and the amounts paid to the named executive officers in respect of such plan for 2007 are set forth in column “g” of the Summary Compensation Table above.

(2)		Ms. Brandin resigned as an executive officer on November 30, 2007.

(3)		Represents grant of Series B Units. These Series B Units are subject to vesting as described in “— Astoria Series B Units” above.

(4)		Mr. Nutt resigned as an executive officer on June 30, 2007.

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Outstanding Equity Awards at Fiscal Year-End

The table below sets forth certain information regarding the outstanding equity awards held by our named executive officers as of December 31, 2007.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END


	Option Awards										Stock Awards
																	Equity
																	Incentive		Equity
					Equity												Plan		Incentive
					Incentive												Awards:		Plan Awards:
					Plan												Number of		Market or
					Awards:												Unearned		Payout Value
	Number of		Number of		Number of						Number of			Market Value			Shares,		of Unearned
	Securities		Securities		Securities						Shares or			of Shares or			Units or		Shares, Units
	Underlying		Underlying		Underlying						Units of			Units of			Other		or Other
	Unexercised		Unexercised		Unexercised		Option				Stock That			Stock That			Rights		Rights That
	Options		Options		Unearned		Exercise		Option		Have Not			Have Not			That Have		Have Not
	(#)		(#)		Options		Price		Expiration		Vested			Vested			Not Vested		Vested
Name	Exercisable		Unexercisable		(#)		($)		Date		(#)			($)			(#)		(#)
(a)	(b)		(c)		(d)		(e)		(f)		(g)			(h)			(i)		(j)

Jacob J. Worenklein		—		—		—		—		—		230.5	⁽¹⁾	$	24,367,077	⁽²⁾		—		—
Mark R. Sudbey		—		—		—		—		—		78.9	⁽¹⁾	$	8,340,835	⁽²⁾		—		—
Jeff D. Hunter		—		—		—		—		—		78.9	⁽¹⁾	$	8,340,835	⁽²⁾		—		—
Belinda Foxworth		—		—		—		—		—		21.7	⁽¹⁾	$	2,293,994	⁽²⁾		—		—
Craig Hart		—		—		—		—		—		30.3	⁽¹⁾	$	3,203,134	⁽²⁾		—		—
Donna Brandin⁽³⁾		—		—		—		—		—		0		$	0			—		—
Ian Nutt⁽⁴⁾		—		—		—		—		—		0		$	0	⁽⁵⁾		—		—


(1)		Represents only unvested Series B Units held by each named executive officer. As of December 31, 2007, the named executive officers held the following vested Series B Units:


Named Executive Officer	Number of Units Vested

Mr. Worenklein		35.5
Mr. Sudbey		12.1
Mr. Hunter		12.1
Ms. Foxworth		3.3
Mr. Hart		4.7
Ms. Brandin		—
Mr. Nutt		—


(2)		Value based on a December 31, 2007 estimated Series B Unit price of $105,714. The methodology for computing such prices is set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Equity-Based Compensation.”

(3)		Ms. Brandin resigned as an executive officer on November 30, 2007.

(4)		Mr. Nutt resigned as an executive officer on June 30, 2007.

(5)		Upon the date of Mr. Nutt’s resignation as an executive officer of USPowerGen, USPowerGen repurchased from him and retired 48.5 vested Series B Units, in accordance with the terms of his Executive Purchase Agreement. Certain of the remaining 28.5 Series B Units that were granted to Mr. Nutt, but never vested (and were never owned by him) were issued to other parties, with the remaining Series B Units to be allocated on a pro-rata basis to the Series B holders as a whole.

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Option Exercises and Stock Vested

The table below sets forth certain information regarding the options exercised and stock vested held by our named executive officers as of December 31, 2007.

OPTION EXERCISES AND STOCK VESTED


	Option Awards				Stock Awards
	Number of Shares Acquired		Value Realized on		Number of Shares			Value Realized on
Name	on Exercise (#)		Exercise ($)		Acquired on Vesting (#)⁽¹⁾			Vesting ($)⁽²⁾
(a)	(b)		(c)		(d)			(e)

Jacob J. Worenklein		—		—		35.5	⁽³⁾	$	8,292,178
Mark R. Sudbey		—		—		12.1	⁽³⁾	$	2,836,798
Jeff D. Hunter		—		—		12.1	⁽³⁾	$	2,836,798
Belinda Foxworth		—		—		3.3	⁽³⁾	$	565,703
Craig Hart		—		—		4.7	⁽³⁾	$	1,091,076
Donna Brandin		—		—		—			—
Ian Nutt		—		—		48.5	⁽³⁾	$	6,000,000	⁽³⁾⁽⁴⁾


(1)		Sets forth the number of Series B Units held by our named executive officers that vested during the year ended December 31, 2007. None of our named executive officers were granted or exercised any options to purchase common units during the year ended December 31, 2007. As of December 31, 2007, our named executive officers held the following total vested Series B Units, which total includes all prior vesting dates:


	•	Jacob J. Worenklein — 35.5

	•	Mark R. Sudbey — 12.1

	•	Jeff D. Hunter — 12.1

	•	Belinda Foxworth — 3.3

	•	Craig Hart — 4.7


(2)		The yearly vesting dates for the named executive officers are as follows:


	•	Mr. Worenklein — February 23

	•	Mr. Sudbey — February 23 (both grants)

	•	Mr. Hunter — February 23

	•	Ms. Foxworth — September 1

	•	Mr. Hart — February 23


		The price per Series B Unit on February 23, 2007 was $233,802 and the price per Series B Unit on September 1, 2007 was $169,711. The methodology for computing such prices is set forth in the Management’s Discussion and Analysis section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Equity Based Compensation.”

(3)		Our named executive have received the following total grants of Series B Units:


Named Executive Officer	Grant Date		Grant Amount

Mr. Worenklein		2/23/06		266
Mr. Sudbey		12/31/06		21
		2/23/06		70
Mr. Hunter		2/23/06		91
Ms. Foxworth		12/31/06		25
Mr. Hart		2/23/06		35
Ms. Brandin		—		—
Mr. Nutt		2/16/07		7
		2/23/06		70

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(4)		Pursuant to the terms of Mr. Nutt’s June 30, 2007 Executive Purchase Agreement governing the terms of his departure from USPowerGen, it was determined by the Board that 48.5 Series B Units of the 77 Series B Units that he had previously been granted be deemed vested and that USPowerGen pay $6,000,000 for the repurchase of those Series B Units. The $6,000,000 is to be paid as follows (a) $3,000,000 on July 31, 2007, (b) $1,500,000 (including 7% interest) on July 31, 2008 and (c) $1,500,000 (including 7% interest) on July 31, 2009. To date, USPowerGen has made the July 31, 2007 payment to Mr. Nutt. Those Series B Units have been retired by USPowerGen. Certain of the remaining 28.5 Series B Units that were granted to Mr. Nutt, but never vested (and were never owned by him) were issued to other parties, with the remaining Series B Units to be allocated on a pro-rata basis to the Series B holders as a whole.

Other Equity Incentive Plans

2007 Employee Stock Purchase Plan

We anticipate that, when adopted, the ESPP will provide an opportunity for eligible employees of our company to purchase shares of our common stock at a 10% discount through voluntary automatic payroll deductions, thereby attracting, retaining and rewarding such persons and strengthening the mutuality of interest between such persons and our company as its shareholders.

The total number of shares of common stock that will be available for issuance under the ESPP is 250,000. If there is a change in the outstanding shares of common stock by reason of a stock dividend or distribution, stock split, recapitalization, combination or exchange of shares or by reason of certain other corporate transactions specified in the ESPP, the number of shares available for issuance under the ESPP will be equitably adjusted.

The Employee Benefits Administrative Committee (the “Administrative Committee”), or such other committee appointed by our board, will administer the ESPP. However, if no such committee is appointed, our board will have the authority to administer the ESPP and to take all actions that the Administrative Committee is otherwise authorized to take under the ESPP.

Eligible Employees. All regular employees of our company and its subsidiaries will be eligible to participate in the ESPP other than employees whose customary employment is twenty hours or less per week, employees whose customary employment is for not more than five months per year, collectively bargained employees whose bargaining representative has declined participation on behalf of such employees, and other than persons who own 5% or more of our outstanding common stock.

Offering Periods. The ESPP will provide for consecutive offering periods with the first offering period commencing on the date of the consummation of the offering contemplated in this prospectus, which first offering period shall close on the end of the last business day of the calendar quarter next following the calendar quarter of the consummation of this offering, and a new offering period commencing on the first day of every subsequent quarter, or such other period as the Administrative Committee shall determine. Shares will be purchased under the ESPP on the last trading date of an offering period, or on such other trading date designated by the Administrative Committee.

Payroll Deductions. Each employee that chooses to participate in the ESPP may contribute through payroll deductions an amount equal to not less than one percent (1%) and not more than fifteen percent (15%) of his or her cash earnings, or such other percentages as the Administrative Committee may establish. However, no participants shall have the right to purchase shares under the ESPP with fair a market value in excess of $25,000 for each calendar year. The accumulated deductions will be applied to the purchase of shares on each applicable purchase date or dates. The purchase price for shares purchased under the ESPP shall not be less than an amount equal to 90% of the closing price for the shares as quoted in the Wall Street Journal, excluding after-market trades.

Amendment. Our board may amend the ESPP at any time, subject to any required shareholder approval to comply with the requirements of the SEC and the Code. Our board may also suspend or discontinue the ESPP at any time.

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2007 Stock Incentive Plan

Our Stock Incentive Plan provides for grants of equity-based and cash-based awards. Directors, officers and other employees of us and our subsidiaries are eligible for grants under the plan. The purpose of the Stock Incentive Plan is to provide these individuals with incentives to maximize stockholder value and otherwise contribute to our success and to enable us to attract, retain and reward the best available persons for positions of responsibility.

The Stock Incentive Plan contains the following important features:


	•	The plan will permit the awards of stock options, stock appreciation rights (“SARs”), restricted stock, deferred stock (including restricted stock units), performance awards, and other stock-based awards as described below. Awards and grants under the Stock Incentive Plan are referred to as “Benefits.”

	•	Those eligible for Benefits under the Stock Incentive Plan are referred to as “Participants.” Participants include our directors, officers and other employees and the directors, officers and other employees of our subsidiaries.

	•	The plan has a ten-year term with a fixed number of shares authorized for issuance. It is not an “evergreen” plan.

	•	A total of 7,470,000 shares of our common stock, representing approximately 9.8% of our currently outstanding common stock on a fully-diluted basis, are available for issuance under the Stock Incentive Plan. The shares available for issuance under the plan may be, in whole or in part, authorized and unissued or held as treasury shares.

	•	Under the plan, stock options and SARs must be granted with an exercise price that is not less than 100% of the fair market value on the date of grant.

	•	Repricing of stock options and SARs without the approval of our stockholders is prohibited.

The terms and provisions of the Stock Incentive Plan are summarized below. This summary, however, does not purport to be a complete description of the plan. The Stock Incentive Plan has been filed with the SEC as an exhibit to this prospectus.

Administration and Eligibility

The Stock Incentive Plan will be administered by our Compensation Committee or a subset thereof, each director of which will satisfy the requirements established: (1) for administrators acting under plans intended to qualify for exemption under Rule 16b-3 under the Exchange Act, (2) for outside directors acting under plans intended to qualify for exemption under Section 162(m) of the Code, and (3) for independent directors required under the applicable listing requirements of the NYSE. Our board also has the authority to administer the plan and to take all actions that the Compensation Committee is otherwise authorized to take under the plan. The Compensation Committee may also delegate some of its authority under the plan in accordance with the terms of the plan. All references herein to the Compensation Committee shall include our board or any such delegate as appropriate.

Our directors, officers and other employees, or persons to whom we have extended an offer of employment, are eligible to receive grants under the Stock Incentive Plan. However, only employees may receive grants of incentive stock options. In each case the Compensation Committee will select the grantees to participate in the Stock Incentive Plan.

Benefits

The Compensation Committee may grant equity awards without payment therefor as additional compensation for service to us or our subsidiaries. The various types of awards are described below and may be subject to other terms and conditions, which may vary from time to time and among employees, as the Compensation Committee determines to be appropriate.

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Stock Options. Under the Stock Incentive Plan, the Compensation Committee may award grants of incentive stock options (“ISOs”) conforming to the provisions of Section 422 of the Code, and other, non-qualified stock options (“NSOs”). The plan provides that we may not, however, award to any one person in any calendar year options to purchase common stock equal to more than 10% of the shares reserved for issuance under the Stock Incentive Plan.

The exercise price of an option granted under the plan may not be less than 100% of the fair market value of a share of common stock on the date of the grant. For purposes of the plan, fair market value shall be determined in such manner as the Compensation Committee may deem equitable, or as required by applicable law or regulation. The plan prohibits repricing of stock options without stockholder approval. The Compensation Committee will determine the term of each option in its discretion. However, no term may exceed ten years from the date of grant.

Stock Appreciation Rights. SARs entitle a participant to receive a payment equal to the amount by which the fair market value of a share of our common stock on the date of exercise exceeds the grant price of the SARs. The grant price and the term of SARs will be determined by the Compensation Committee, except that the price of a SAR may never be less than the fair market value of a share of our common stock subject to the SAR on the date the SAR is granted (other than with respect to SARs issued in substitution for stock options (as discussed in the following paragraph)). The Compensation Committee will determine the term of each SAR in its discretion. However, no term may exceed ten years from the date of grant. The plan prohibits repricing of SARs without stockholder approval.

The Compensation Committee also may, in its discretion, substitute SARs which can be settled only in our common stock for outstanding stock options. The terms and conditions of any substitute SAR shall be substantially the same as those applicable to the stock option that it replaces and the term of the substitute SAR shall not exceed the term of the stock option that it replaces.

Restricted Stock. Restricted stock consists of shares which we transfer or sell to a Participant, but is subject to substantial risk of forfeiture and to restrictions on its sale or other transfer by the Participant. Under the Stock Incentive Plan, the Compensation Committee may award restricted stock subject to the conditions and restrictions, and for the duration, that it determines in its discretion. Unless the Compensation Committee determines otherwise, if termination of employment or service occurs for any other reason, all of a grantee’s restricted stock as to which the applicable restrictions have not lapsed will be forfeited immediately.

Deferred Stock and Restricted Stock Units. Deferred stock provides a Participant a right to receive common stock or other awards upon the expiration of a specified deferral period. Restricted stock units are deferred stock that is subject to a risk of forfeiture and provide the Participant with the right to receive stock or other awards at a future date after vesting upon the attainment of certain conditions and restrictions. Under the Stock Incentive Plan, the Compensation Committee may award deferred stock and restricted stock units, subject to the conditions and restrictions, and for the duration that it determines in its discretion. Unless the Compensation Committee determines otherwise, if termination of employment or service occurs for any other reason, all of a grantee’s shares of deferred stock or restricted stock units as to which the applicable restrictions have not lapsed will be forfeited immediately.

Performance Awards. Under the Stock Incentive Plan, the Compensation Committee may grant performance awards contingent upon achievement of set goals and objectives, as designated by the Compensation Committee, relating to one or more business criteria within the meaning of Section 162(m) of the Code, including, but not limited to: gross revenue; operating revenues; operating income; cash flow; profit before tax; earnings before taxes; earnings before interest, depreciation and amortization; operating earnings; economic value added; free cash flow; net income; price of our common stock; return on assets; return on investments; return on capital; return on equity; operating margin; or total return to stockholders (together the “Performance Criteria”). Performance Criteria may be used to measure our performance as a whole or any of our business units and may be measured relative to a peer group or index.

Performance awards may be denominated as a cash amount, number of shares of our common stock, or other awards under the Stock Incentive Plan (or a combination thereof). The Compensation Committee shall

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specify the circumstances in which performance awards shall be paid or forfeited in the event of termination of employment of a Participant or other event (including a change in control) prior to the end of a performance period or settlement of such performance awards.

Withholding Taxes and Transferability of All Awards

We may elect to withhold from any award, any payment relating to an award under the plan, including a distribution of shares of common stock, or any payroll or other payment to a Participant, amounts necessary in order to satisfy our withholding obligations or other taxes due in connection with any exercise, grant or vesting of an award. No award made under the Stock Incentive Plan will be transferable other than by will or the laws of descent and distribution, except that awards and other rights (other than incentive stock options and stock appreciation rights in tandem therewith) may be transferred to one or more transferees during the lifetime of the Participant for purposes of estate-planning, and may be exercised by such transferees in accordance with the terms of such award, but only if and to the extent such transfers are permitted by the Compensation Committee and the transfer is not to a third party for value, and subject to any terms and conditions which the Compensation Committee may impose thereon.

Amendment and Termination of the Stock Incentive Plan

Our board may amend or terminate the Stock Incentive Plan in its discretion, except that no amendment will become effective without prior approval of our stockholders if such approval is required by any federal or state law or regulation or is necessary for continued compliance with applicable stock exchange listing requirements. Furthermore, the Compensation Committee may amend any outstanding awards. Nonetheless, any such amendment or termination may not materially and adversely affect any outstanding rights or obligations under the Stock Incentive Plan without the affected Participant’s consent. If not previously terminated by the board, the Stock Incentive Plan will terminate on the tenth anniversary of its adoption.

Change in Control

Upon the occurrence of a Change in Control (as defined below), unless otherwise provided by the Compensation Committee, with respect to non-performance based awards, all such awards shall become vested and exercisable and all forfeiture conditions, deferral of settlement and other vesting restrictions shall lapse. With respect to performance based awards, all performance goals shall be deemed to be met or exceeded to the extent provided by the Compensation Committee in the applicable award document. Any award carrying a right to exercise shall remain exercisable for the balance of the term of the award. All other awards shall be fully payable and settleable as of the time of the Change in Control.

For purposes of the Plan, the term “Change in Control” is defined as: (i) the acquisition, directly or indirectly, of our securities representing at least 30% of the combined voting power of our outstanding securities (other than by us, or any of our employee benefit plans); (ii) certain changes in the majority of our board of directors during any two consecutive-year period; (iii) the consummation of certain mergers, consolidations, recapitalizations or reorganizations of USPowerGen, or the consolidations or reverse stock splits involving USPowerGen; and (iv) the approval of liquidation of USPowerGen or an agreement for the sale or disposition of substantially all of USPowerGen’s assets by its stockholders.

Adjustments

The number of shares available for issuance under the Stock Incentive Plan is subject to adjustment in the event of a reorganization, stock split, merger or similar change in the corporate structure or the outstanding shares of common stock. In the event of any of these occurrences, we may make any adjustments we consider appropriate to, among other things, the number and kind of shares, options or other property available for issuance under the plan or covered by grants previously made under the plan.

To the extent an award is canceled, expired, forfeited, settled in cash, settled by fewer shares than the number underlying the award or otherwise terminated without delivery of shares to the Participant, the shares covered by such Benefits will again be available for use under the plan. Shares covered by a Benefit granted

151

under the plan will not be counted as used unless and until they are actually issued and delivered to a Participant. Shares withheld or surrendered by a Participant as full or partial payment of an exercise price or purchase price, or taxes relating to a Benefit will not be counted as used. Furthermore, any substitute awards granted under the plan shall not count against the share limitations set forth herein.

Million Dollar Deduction Limit

We may not deduct compensation of more than $1,000,000 that is paid to an individual who, on the last day of the taxable year, is either our chief executive officer or is among one of the four other officers for that taxable year as reported in our proxy statement. The limitation on deductions does not apply to certain types of compensation, including qualified performance-based compensation. We believe that Benefits in the form of stock options, SARs, performance-based restricted stock and restricted stock units and performance awards constitute qualified performance-based compensation and, as such, will be exempt from the $1,000,000 limitation on deductible compensation.

Non-Qualified Deferred Compensation

We have adopted a non-qualified deferred compensation plan in which certain of our employees, including our named executive officers, participate.


	Executive		Company		Aggregate			Aggregate		Aggregate Balance
	Contributions		Contributions in		Earnings			Withdrawals/		at December 31,
Name	in 2007		2007		in 2007			Distributions		2007

Jacob J. Worenklein		—	$	90,500	$	2,200			—	$	175,315
Mark R. Sudbey		—	$	80,000	$	(730	)		—	$	127,831
Jeff D. Hunter	$	17,860	$	70,000	$	468			—	$	136,890
Belinda Foxworth	$	75,000	$	37,067	$	(507	)		—	$	111,559
Craig Hart		—	$	51,502	$	(437	)		—	$	83,439
Donna Brandin		—		—		—			—		—
Ian Nutt		—		—		—			—		—

Participants in the non-qualified deferred compensation plan, including the above-named executive officers, received company contributions amounting to 10% of their 2007 total cash compensation (nominal base salary plus actual bonus paid in March, 2007). Participants in the plan also have the option to elect deferrals of their base salary and bonus compensation in amounts ranging from 2% to 50%. Both USPowerGen and employee contributions are credited to an account in the participant’s name, and invested according to the individual’s own investment direction, the gains or losses of which are noted in the table above. Ms. Brandin and Mr. Nutt did not make any contributions to the plan in 2007. Deferred compensation is payable upon termination or retirement.

Employment and Other Arrangements

We plan to enter into an employment agreement with our Chairman and Chief Executive Officer, Jacob J. Worenklein, prior to the consummation of this offering. We currently anticipate that this agreement will have a term of three years, unless terminated earlier by Mr. Worenklein or by us, and thereafter will renew automatically for successive one-year terms. The agreement will provide for a base salary in 2008 of $800,000, as well as for a bonus to be determined pursuant to the AIP. It will also provide that Mr. Worenklein is eligible to participate in our Stock Incentive Plan, and that he will receive an initial grant of 200,000 SARs. Mr. Worenklein is also eligible to participate in all bonus, stock incentive, pension, savings, and health and welfare benefit plans provided to our senior executives, except that we will provide Mr. Worenklein short-term disability coverage equal to 100% of his base salary, long-term disability coverage equal to 60% of his based salary, and life insurance coverage equal to three times his base salary, regardless of the level of benefits we provide to other senior executives.

We currently plan to enter into employment agreements with our other named executive officers prior to the consummation of this offering, the specific terms of which will be similar to Mr. Worenklein’s agreement,

152

other than the specific amounts pertaining to base salary, incentive compensation, awards under our Stock Incentive Plan, certain change-in-control arrangements and the short-term disability, long-term disability and life insurance coverage described herein.

Potential Payments Upon Termination and Change in Control

The tables below reflect the amount of compensation payable to each of the named executive officers upon (a) voluntary termination without cause or good reason, (b) involuntary termination for cause and (c) a change in control. The amounts shown assume that such termination or change in control was effective as of December 31, 2007, and thus are estimates of the amounts that would be paid out to the executives upon their termination. The actual amounts to be paid out can only be determined at the time of such executive’s separation from USPowerGen and its affiliates or upon a change in control.

Named executive officers may, at the discretion of Astoria’s chief executive officer, be awarded cash severance and/or have their Series B Units repurchased pursuant to the Executive Purchase Agreements that each of the named executive officers entered into when such Series B Units were issued to them. Named executive officers are also entitled, based on general company policy applicable to all employees, to receive accrued vacation pay and insurance benefits upon a termination without cause or for good reason (each as defined below). The Series B Units held by named executive officers are subject to accelerated vesting upon a change in control. We anticipate that the named executive officers will enter into employment agreements prior to the completion of this offering that will contain severance and separation arrangements following a change in control, as well as other provisions that may impact the overall severance payments that the named executive officers will receive. We have not included such payment amounts for either Ms. Brandin or Mr. Nutt as their employment with USPowerGen terminated prior to December 31, 2007.

The Executive Purchase Agreements provide that the Series B Units issued pursuant to such agreements are subject to vesting, with 66.67% of each participant’s Series B Units vesting ratably over a five-year period and the remaining using vesting upon a substantial liquidity event at New Astoria, if the named executive officer is employed by Astoria as of such date. The time vesting units are subject to accelerated vesting, and will fully vest upon a change in control so long as the named executive officer was employed by Astoria at such vesting date. A change in control is defined as the acquisition by an unaffiliated third party of more than 50% of New Astoria’s voting power or the sale of all or substantially all of Astoria’s assets on a consolidated basis. In connection with the Combination, the terms of the Series B Units were modified such that upon the occurrence of an initial public offering of USPowerGen, 100% of the New Series B Units will vest over a five-year period retroactively back to the date of issuance, on a daily basis, and will be subject to accelerated vesting if distributions to Madison Dearborn equal the aggregate amount of its investment in Astoria, together with an 8% per annum return (compounded semi-annually).

Pursuant to the Executive Purchase Agreements, Astoria and Madison Dearborn are required (if the CEO so elects) to repurchase Series B Units held by the named executive officers following a termination without cause or resignation with good reason. If vested Series B Units are repurchased, their purchase price is their fair market value (except in the case of a termination for cause). If unvested Series B Units are repurchased (except in the case of termination for cause), their purchase price is their original cost (which for the named executive officers would be $0.00). In the event that a named executive officer’s employment is terminated for cause (as defined below) the purchase price for all Series B Units shall be the original cost thereof. No Series B Units may continue to vest after a termination; however, in the event any unvested Series B Units are not repurchased after a termination, such unvested Series B Units shall be deemed vested.

Pursuant to the Executive Purchase Agreements:

(a) if a named executive officer’s employment is terminated without “Cause,” which is defined as a (i) conviction of, or plea of no contest to, a felony or other crime involving fraud, malfeasance or dishonesty or (ii) gross negligence or willful failure to perform the named executive officer’s obligations and duties to USPowerGen;

153

(b) or he or she resigns with “Good Reason,” which is defined as a resignation from employment within 30 days after the occurrence of anyone of the following: (i) relocation of the named executive officer’s principal location for the provision of services to a location greater than 50 miles outside the city limits of New York, New York, unless the named executive officer agrees to such relocation; (ii) a material reduction in title, responsibilities, reporting obligations, base salary or bonus opportunity, with respect to Astoria and its affiliates (including USPowerGen) in any case without the named executive officer’s consent; and (iii) a material breach by Astoria of the Executive Purchase Agreement, which is not cured within 30 days after written notice;

then, at the election of the chief executive officer of Astoria, Astoria may:

(i) repurchase 50% of unvested Series B Units at fair market value as of the scheduled date of repurchase and pay the named executive officer his base salary at a rate per annum equal to his base salary as in effect on the termination date for a period equal to two years or 18 months (as provided below); or

(ii) repurchase 100% of unvested Series B Units at fair market value as of the scheduled date of repurchase and to pay the named executive officer his base salary at a rate per annum equal to his base salary as in effect on the termination date for a period equal to one year or nine months (as provided below).

The Executive Purchase Agreements provide that the determination of the chief executive officer of Astoria to pay amounts pursuant to either of the options set forth above (or at all) shall be based on (i) the extent to which the termination of the executive was based on his or her unsatisfactory performance and (ii) other economic and equitable factors deemed relevant by the Astoria chief executive officer.

Jacob Worenklein

Termination

Without Cause or

Resignation

Termination

With Good

for Cause or

Reason on

Without

12/31/2007

Good Reason

Change in

(at one times

(at two times

Control on

Payments Upon Separation

base salary)

12/31/2007

Vested Series B Units⁽¹⁾

6,943,952

—

Unvested Series B Units⁽²⁾

21,175,972

—

Cash Severance⁽³⁾

480,000

—


(1)		Represents the total value of 65.7 vested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, in accordance with the pre-initial public offering vesting schedule described above.

(2)		Represents the total value of 200.3 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit in accordance with the pre-initial public offering vesting schedule described above.

(3)		Mr. Worenklein is entitled to receive one year’s salary cash severance upon termination and repurchase of 100% of his vested B Units upon termination without cause or resignation with good reason. However, Astoria is required to repurchase his Series B Units and provide him the other severance benefits described above.

154

Mark Sudbey

Termination

Without Cause

or Resignation

Termination

With Good

for Cause or

Reason on

Without

12/31/2007

Good Reason

Change in

(at one times

(at two times

Control on

Payments Upon Separation

base salary)

12/31/2007

Vested Series B Units⁽¹⁾

2,375,563

—

Unvested Series B Units⁽²⁾

7,244,411

3,622,206

—

Cash Severance⁽³⁾

450,000

900,000

—


(1)		Represents the total value of 22.5 vested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, in accordance with the pre-initial public offering vesting schedule described above.

(2)		Represents the total value of either (a) 68.5 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit or (b) 34.3 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, both cases in accordance with the pre-initial public offering vesting schedule described above.

(3)		Mr. Sudbey is entitled to receive either one or two year’s salary cash severance upon termination. However, Astoria could, at its option, repurchase his Series B Units and provide him the other severance benefits described above.

Jeff Hunter


	Termination		Termination
	Without Cause		Without Cause		Termination
	or With		or With		for Cause or
	Good Reason on		Good Reason		Without Good
	12/31/2007		on 12/31/2007		Reason		Change in
	(at one times		(at two times		on		Control on
Payments Upon Separation	base salary)		base salary)		12/31/2007		12/31/2007

Vested Series B Units⁽¹⁾	$	2,375,563	$	2,375,563		—		—
Unvested Series B Units⁽²⁾	$	7,244,411	$	3,622,206		—		—
Cash Severance⁽³⁾	$	375,000	$	750,000		—		—


(1)		Represents the total value of 22.5 vested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, in accordance with the pre-initial public offering vesting schedule described above.

(2)		Represents the total value of either (a) 68.5 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit or (b) 34.3 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, both cases in accordance with the pre-initial public offering vesting schedule described above.

(3)		Mr. Hunter is entitled to receive either one or two year’s salary cash severance upon termination. However, Astoria could, at its option, repurchase his Series B Units and provide him the other severance benefits described above.

Belinda Foxworth


	Termination		Termination
	Without Cause		Without Cause
	or With		or With		Termination
	Good Reason		Good Reason		for Cause or
	on 12/31/2007		on 12/31/2007		Without Good		Change in
	(at one times		(at two times		Reason on		Control on
Payments Upon Separation	base salary)		base salary)		12/31/2007		12/31/2007

Vested Series B Units⁽¹⁾	$	441,199	$	441,199		—		—
Unvested Series B Units⁽²⁾	$	2,201,651	$	1,100,825		—		—
Cash Severance⁽³⁾	$	225,000	$	450,000		—		—


(1)		Represents the total value of 4.2 vested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, in accordance with the pre-initial public offering vesting schedule described above.

(2)		Represents the total value of either (a) 20.8 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit or (b) 10.4 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, both cases in accordance with the pre-initial public offering vesting schedule described above.

(3)		Ms. Foxworth is entitled to receive either 9 or 18 months’ salary cash severance upon termination. However, Astoria could, at its option, repurchase her Series B Units and provide her the other severance benefits described above.

155

Craig Hart


	Termination		Termination
	Without Cause		Without Cause
	or With		or With		Termination
	Good Reason		Good Reason		for Cause or
	on 12/31/2007		on 12/31/2007		Without		Change in
	(at one times		(at two times		Good Reason		Control on
Payments Upon Separation	base salary)		base salary)		on 12/31/2007		12/31/2007

Vested Series B Units⁽¹⁾	$	913,678	$	913,678		—		—
Unvested Series B Units⁽²⁾	$	2,786,312	$	1,393,156		—		—
Cash Severance⁽³⁾	$	206,250	$	412,500		—		—


(1)		Represents the total value of 8.6 vested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, in accordance with the pre-initial public offering vesting schedule described above.

(2)		Represents the total value of either (a) 26.4 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit or (b) 13.2 unvested Series B Units as of December 31, 2007 at a value of $105,714 per Series B Unit, both cases in accordance with the pre-initial public offering vesting schedule described above.

(3)		Mr. Hart is entitled to receive either 9 or 18 months’ salary cash severance upon termination. However, Astoria could, at its option, repurchase his Series B Units and provide him the other severance benefits described above.

Director Compensation

Prior to and following the completion of this offering, the non-employee members of our board are entitled to receive $150,000 per year for their service as a director and $1,000 per committee meeting attended (with the exception of the IPO Committee for which no compensation is paid), payable quarterly. The listed committee chairmen receive the following yearly fees:


	•	Audit Committee Chairman: $25,000

	•	Compensation Committee Chairman: $15,000

	•	Governance Committee Chairman: $10,000

Directors who are also our employees will receive no compensation for serving as directors. Following this offering, non-employee directors will be entitled to receive up to 50% of their annual compensation in the form of equity grants. We also expect to reimburse all directors for reasonable out-of-pocket expenses they incur in connection with their service as directors, including those incurred in connection with attending all board and other committee meetings. Our directors will also be eligible to receive other equity-based awards when, as and if determined by the Compensation Committee.

The following table summarizes compensation paid to our directors in 2007 following the Combination:


								Change in Pension
								Value and
	Fees Earned					Non-Equity		Nonqualified
	or Paid	Stock		Option		Incentive Plan		Deferred		All Other
	in Cash	Awards		Awards		Compensation		Compensation		Compensation		Total
Name	($)	($)		($)		($)		Earnings		($)		($)

Zaid F. Alsikafi	Fees Waived⁽¹⁾		—		—		—		—		—		—
Patrick C. Eilers	Fees Waived⁽¹⁾		—		—		—		—		—		—
Kip Horton	$89,500		—		—		—		—		—	$	89,500
Hunter Hunt	Fees Waived⁽²⁾		—		—		—		—		—		—
Jacob J. Worenklein	Fees Not Paid⁽³⁾		—		—		—		—		—		—
Michael Kramer	$90,500		—		—		—		—		—	$	90,500
Thomas S. Souleles	Fees Waived⁽¹⁾		—		—		—		—		—		—
Barry Sullivan	$87,500		—		—		—		—		—	$	87,500
Jerry Thurmond	$89,500		—		—		—		—		—	$	89,500


(1)		Messrs. Alsikafi, Eilers and Souleles, as employees of Madison Dearborn, have waived their director fees.

(2)		Mr. Hunt waived his 2007 director fees and USPowerGen made a charitable donation in his honor to All Star Project, Inc.

(3)		Mr. Worenklein, as an employee of USPowerGen, is not entitled to any director fees.

156

Director and Officer Indemnification and Limitation on Liability

Our certificate of incorporation provides that, to the fullest extent permitted by the Delaware General Corporation Law, as amended (“DGCL”), and except as otherwise provided in our by-laws, none of our directors shall be liable to us or our stockholders for monetary damages for a breach of fiduciary duty. In addition, our certificate of incorporation provides for indemnification of any person who was or is made, or threatened to be made, a party to any action, suit or other proceeding, whether criminal, civil, administrative or investigative, because of his or her status as a director or officer of us or service, while a director or officer of us, as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise at our request to the fullest extent permitted by applicable law against all expenses, liabilities and losses reasonably incurred by such person. Further, our certificate of incorporation provides that we may purchase and maintain insurance on our own behalf and on behalf of any other person who is or was a director, officer, employee or agent of us or was serving at our request as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise.

157

PRINCIPAL AND SELLING STOCKHOLDERS

Unless otherwise noted, the following table sets forth, as of August 8, 2008, and after giving effect to the conversion of our outstanding Class B common stock into Class A common stock and the reclassification of our Class A common stock as common stock upon completion of this offering, the beneficial ownership of our common stock by:


	•	each person that is a beneficial owner of 5% of more of our outstanding shares of common stock;

	•	each of our named executive officers;

	•	each of our directors;

	•	all of the executive officers, directors and director nominees as a group; and

	•	each selling stockholder.

Beneficial ownership is determined under SEC rules and generally includes voting or investment power over securities. Except as disclosed in the footnotes to this table and subject to applicable community property laws, we believe that each stockholder identified in the table possesses sole voting and investment power over all shares of common stock shown as beneficially owned by the stockholder. Percentage of beneficial ownership is based on shares of common stock outstanding as of the date of this prospectus and gives effect to the conversion of all of our outstanding Class B common stock upon completion of this offering. Unless otherwise indicated in the footnotes below, the address for each beneficial owner is c/o US Power Generating Company, 505 Fifth Avenue, 21st Floor, New York, New York 10017.

Shares

Shares Beneficially

Being

Shares Beneficially

Owned Prior to the

Sold in

Owned After

Offering

the

the Offering

Name

Number

Percent

Offering

Number

Percent

5% Stockholders:

New Astoria Generating Company Holdings, L.L.C.⁽¹⁾

35,339,290

46.3

Sandell Asset Management Funds⁽³⁾

6,309,700

8.3

Harbinger Capital Funds⁽²⁾

5,584,972

7.3

Hunt Generation Investments, L.P.⁽⁴⁾

Directors and Executive Officers:

Jacob J. Worenklein⁽⁵⁾

Mark R. Sudbey⁽⁵⁾

Jeff D. Hunter⁽⁵⁾

Belinda Foxworth⁽⁵⁾

Craig Hart⁽⁵⁾

Ian Nutt⁽⁶⁾

Donna Brandin⁽⁷⁾

Zaid F. Alsikafi⁽⁸⁾

Patrick C. Eilers⁽⁸⁾

Kip Horton

Hunter Hunt⁽⁴⁾

Michael Kramer⁽⁹⁾

Thomas S. Souleles⁽⁸⁾

Barry Sullivan⁽¹⁰⁾

Jerry D. Thurmond

All directors, director nominee and executive officers as a group (15 persons)

Other Selling Stockholders:

158


*		Less than 1%


(1)		Represents all of the shares held by New Astoria. New Astoria is a privately held limited liability company controlled by Madison Dearborn Partners IV, L.P. (“MDP IV”). Madison Dearborn Partners IV, LLC (“MDP IV LLC”) is the sole general partner of MDP IV and, as a result, may be deemed to have indirect voting and investment power over the shares held by New Astoria. Messrs. John A. Canning, Jr., Paul J. Finnegan and Samuel M. Mencoff, each of which is a Managing Director of Madison Dearborn, are the sole members of a limited partner committee of MDP IV LLC and may be deemed to have indirect voting and investment power over the shares held by New Astoria. The Board of Directors of New Astoria is comprised of Messrs. Alsikafi, Eilers, Hunt, Souleles and Worenklein and, in such capacity, exercise direct voting and investment power over the shares held by New Astoria. The address for New Astoria is c/o US Power Generating Company at the address listed above and the address for MDP IV, MDP LLC and Messrs. Canning, Finnegan and Mencoff is Three First National Plaza, Suite 3800, 70 West Madison Street, Chicago, Illinois 60602.

(2)		Beneficial ownership information prior to the offering includes 2,449,214 shares held by Boston Harbor Power, LLC (“Harbor”), 1,861,765 shares held by Harbinger Capital Partners Special Situations Fund, L.P. (“Special Fund”) and 1,273,993 shares held by Power Management Financing, LLC (“Financing”). Harbor and Financing are indirect, wholly-owned subsidiaries of Harbinger Capital Partners Master Fund I, Ltd. (“Master Fund”). The address for Master Fund is c/o International Fund Services (Ireland) Limited, Third Floor, Bishop’s Square, Redmond’s Hill, Dublin 2, Ireland. The address for Harbor and Financing is c/o Harbert Management Corporation, Concord Center, 2100 Third Avenue North, Suite 600, Birmingham, AL 35203. The address for Special Fund is 555 Madison Avenue, 16th Floor, New York, New York, 10022.

(3)		Beneficial ownership information prior to the offering includes 5,525,870 shares held by CMI Holdings Investments Ltd. (“CMI”) and 783,830 shares held by Castlerigg Partners, L.P. (“Castlerigg”). CMI and Castlerigg are controlled by Sandell Asset Management Corp. (“SAMC”). Thomas Sandell is the sole shareholder of SAMC and may be deemed to have voting and dispositive power over the shares owned by CMI and Castlerigg. The address of CMI, Castlerigg and SAMC is 40 West 57th Street, 26th Floor, New York, New York 10019.

(4)		Hunter Hunt is President and Managing Director of Hunt Power, L.P., which controls Hunt Generation. Hunt Generation is an investor in New Astoria and the shares listed in the table represent Hunt Generation’s proportionate ownership interest in the shares held by New Astoria based on an assumed initial public offering price of $ per share, which represents the midpoint of the range set forth on the cover page of this prospectus. The address for Hunt Generation is 1900 North Akard Street, Dallas, Texas 75201.

(5)		Each of Messrs. Worenklein, Sudbey, Hunter and Hart and Ms. Foxworth is an investor in New Astoria and the shares listed in the table represent such executive officer’s proportionate ownership interest in the shares held by New Astoria based on an assumed initial public offering price of $ per share, which represents the mid-point of the range set forth on the cover page of this prospectus. Mr. Worenklein serves as a member of the Board of Directors of New Astoria.

(6)		Mr. Nutt ceased to be an executive officer for our company on June 30, 2007.

(7)		Ms. Brandin ceased to be an executive officer of our company on November 30, 2007.

(8)		Mr. Alsikafi is employed by Madison Dearborn and has an indirect pecuniary interest in the shares held by New Astoria. Mr. Alsikafi expressly disclaims beneficial ownership in these shares except to the extent of his pecuniary interest therein. Messrs. Eilers and Souleles are Managing Directors of Madison Dearborn, which is the ultimate sole general partner of MDP IV, which controls New Astoria. As a result, Messrs. Eilers and Souleles may be deemed to share beneficial ownership of the shares owned by New Astoria. Messrs. Eilers and Souleles expressly disclaim beneficial ownership of the shares owned by New Astoria except to the extent of their pecuniary interest therein. The address of Messrs. Eilers and Souleles is c/o Madison Dearborn Partners, LLC, Three First National Plaza, Suite 3800, 70 West Madison Street, Chicago, Illinois 60602.

(9)		Mr. Kramer is affiliated with Perella Weinberg Partners L.P., a registered broker-dealer.

(10)		Mr. Sullivan is the Vice Chairman, Chief Operating Officer and a member of K Road Power Management, LLC. Mr. Sullivan is affiliated with Hilliard Farber & Co., Inc. and Liati Capital, LLC, both of which are registered broker-dealers.

159

Over-Allotment Option

The following table sets forth certain information regarding our equity ownership as of the date of this prospectus, assuming the underwriters’ option to purchase additional shares is exercised in full:

Shares Being

Shares Beneficially Owned

Sold

After the Offering

Name

in the Offering

Number

Percent

5% Stockholders:

New Astoria Generating Company Holdings, L.L.C.

Harbinger Capital Funds

Sandell Asset Management Funds

Hunt Generation Investments, L.P.

Directors, Director Nominee and Executive Officers:

Jacob J. Worenklein

Mark R. Sudbey

Jeff D. Hunter

Craig Hart

Belinda Foxworth

Zaid F. Alsikafi

Patrick C. Eilers

Kip Horton

Hunter Hunt

Michael Kramer

Thomas S. Souleles

Barry Sullivan

Jerry D. Thurmond

All directors, director nominees and executive officers as a group (15 persons)

Other Selling Stockholders:

Material Relationships with Selling Stockholders

We have agreed to pay all of the expenses of the selling stockholders in this offering other than underwriting discounts and commissions. In the event the underwriters’ option is not exercised in full, the number of shares to be sold by the selling stockholders named above will be reduced proportionally.

See “Certain Relationships and Related Party Transactions” for a description of any material relationships between us and the selling stockholders.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Related Party Transactions Policy and Procedure

Our legal and finance departments are primarily responsible for developing and implementing processes and controls to obtain information from our directors, executive officers and significant stockholders regarding related-party transactions and then determining, based on the facts and circumstances, whether we or a related party has a direct or indirect material interest in these transactions. The Audit Committee is responsible for review, approval, or ratification of “related-person transactions” between USPowerGen or its subsidiaries and related persons. Under SEC rules, a related person is a director, officer, nominee for director, or 5% stockholder of our company since the beginning of the last fiscal year and their immediate family members. In the course of its review and approval or ratification of a related-party transaction, the Audit Committee considers:


	•	the nature of the related party’s interest in the transaction;

	•	the material terms of the transaction, including the amount involved and type of transaction;

	•	the importance of the transaction to the related party and to our company;

	•	whether the transaction would impair the judgment of a director or executive officer to act in our best interest and the best interest of our stockholders; and

	•	any other matters the Audit Committee deems appropriate.

Any member of the Audit Committee who is a related-party with respect to a transaction under review may not participate in the deliberations or vote on the approval or ratification of the transaction. However, such a director may be counted in determining the presence of a quorum at a meeting of the committee that considers the transaction.

Since June 1, 2007, the date of the Combination, we have not been a party to, and we have no plans to be a party to, any transaction or series of similar transactions in which the amount involved exceeded or will exceed $120,000 and in which any current director, executive officer, holder of more than 5% of our capital stock, or any member of the immediate family of any of the foregoing, had or will have a direct or indirect material interest, other than in connection with the transactions described below.

The Combination

On June 1, 2007, USPowerGen acquired EBG and Astoria through a series of mergers.

Agreements Related to the Combination

Merger Agreement. As described above, we acquired Astoria and EBG in a series of stock for unit transactions. Holders of EBG’s limited liability company units (“EBG Units”) received ten (10) shares of Class A common stock for each EBG Unit. Holders of warrants in EBG LLC (“EBG Warrants”) were converted into a warrant to purchase of a number of shares of Class A common stock equal to the number of shares of Class A common stock for which the EBG Warrants would have been converted to pursuant to the Combination had such warrants been exercised immediately prior to the Combination. New Astoria, in its capacity as the sole holder of Astoria’s limited liability company units (“Astoria Units”), received thirty five thousand five hundred thirty-nine (35,539) shares of Class B Common Stock for each Astoria Unit. Any treasury units held by either EBG and Astoria were cancelled. Following the Combination, former holders of EBG Units hold all of our outstanding shares of Class A common stock and 54% of our total shares of common stock. New Astoria holds all of the outstanding shares of our Class B common stock and 46% of the total shares of common stock of our company. The Merger Agreement contains a “true up” provision that is intended to ensure that the percentage of shares of common stock issued to Astoria’s holder and EBG’s holders (including warrant holders) pursuant to Merger Agreement equal 46% and 54% of the outstanding common stock of USPowerGen, respectively.

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The Merger Agreement contains customary representations, warranties and covenants, including a covenant relating to the indemnification of directors and officers of USPowerGen and its subsidiaries and for the maintenance, for a period of six years after the consummation of the Combination, of current levels of directors’ and officers’ liability insurance. The Merger Agreement provided that both EBG and Astoria, which at the time of the agreement were controlled by different owners, agreed to reasonably cooperate to take such reasonable action as is necessary or desirable to complete an initial public offering as promptly as reasonably practicable. The Merger Agreement does not provide for the survival of representations, warranties and covenants other than for the “true up” provision, indemnification of directors and officers of USPowerGen, Astoria and their respective subsidiaries, and certain other general provisions.

Investor Rights Agreement. In connection with the Combination on June 1, 2007, we, New Astoria and its respective members and certain former holders of EBG Units (“EBG Investors”) entered into an Investor Rights Agreement. This agreement provides that we will use reasonable best efforts to cause an initial public offering to occur as soon as reasonably practicable (after giving effect to, and subject to compliance with, the requirements of the SEC with respect to financial statements for such offering and timing required to prepare such statements). Pursuant to the terms of the Investor Rights Agreement, holders of a majority of our Class B common stock who are a party thereto or a majority of the EBG Investors may demand registration of all or a portion of their registrable securities on Form S-1 as long as the aggregate offering price related to the request for an initial public offering equals at least $300,000,000.

Following the completion of this initial public offering each of the New Astoria majority holders or holders of 25% of the EBG Investor’s registrable securities may demand up to three (3) additional long-form registrations or an unlimited number of registration of some or all of their registrable securities on forms S-2 or S-3 or other similar short-form registration. Such requests for long-form registrations must be for at least $150,000,000. We are responsible for nearly all expenses associated with such demand registrations. We are not obligated to effect a demand registration (i) within 180 days of the effective date of a previous long-form demand registration and (ii) within 90 days of a short-form demand registration. In the event that our board of directors determines that a demand registration would reasonably be expected to have a material adverse effect on our ability to engage in an acquisition of assets or stock or any merger, reorganization, consolidation or similar transaction, we may delay a demand registration for sixty (60) days without the consent of a majority of the holders of a majority of the registrable securities plus an additional sixty (60) days in the event such consent is provided.

Our IPO committee, as further described below, has the right to select the underwriters for this initial public offering. For piggyback registrations (as defined below) other than this initial public offering, we have the right to select the underwriters. For all other underwritten offerings that are demand offerings, we and holders of a majority of registrable securities included in the offering will jointly select an underwriter. We cannot include non-registrable securities in a demand registration unless holders of at least 75% of the registrable securities in such registration provide prior written consent. The Investor Rights Agreement provides for further priority for the sale of securities in the event the underwriters to a demand registration advise us in writing that the number of securities sought to be sold would adversely affect the marketability of this offering.

In the event that we propose to register any equity securities and the registration form to be used by us also may be used to register registrable securities, we must provide “piggyback” rights to holders of registrable securities. Such “piggyback” registrations are subject to priority of sale restrictions for both primary and secondary offerings in the event that underwriters inform us in writing that the number of securities sought to be sold would adversely affect the marketability of this offering.

We are obligated to target this initial public offering to generate at least $500 million in gross proceeds. For an initial public offering completed within twenty-four (24) months of November 30, 2007 (unless delayed by a force majeure), we must first include registrable shares held by EBG Investors until sales from such securities equal $300 million (and if the gross proceeds of the IPO are less than $500 million, then at least 60% of the common stock to be included in the IPO must be shares held by EBG Investors). In a primary offering such as this initial public offering, the sale of shares of common stock in excess of $500 million will

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occur in the following order (assuming we receive written notice from the underwriters that the number of securities sought to be sold in this offering would adversely affect the marketability of this offering): (i) shares of common stock to be sold by us, (ii) pro rata, on the basis of the amount owned, among EBG Investors, New Astoria and certain others who request to include shares of common stock in this offering and (iii) other shares of common stock requested to be included in this offering, pro rata on the basis of the amount of the shares owned, by each holder.

Holders of registrable securities are subject to certain holdback provisions and will not be able to sell their stock for periods to be determined by the IPO committee or us and the underwriters following our initial public offering (which period will not exceed 180 days) or an underwritten demand or piggyback registration (which period will not exceed 90 days).

We have agreed to indemnify each selling stockholder for certain violations of federal or state securities laws by us in connection with any registration statement in which the selling stockholder sells its shares of our common stock pursuant to the investor rights agreement. Each selling stockholder has in turn agreed to indemnify us for federal or state securities law violations that occur in reliance upon written information it provides to us in the registration statement.

The Investor Rights Agreement further provides that our board of directors establish an IPO committee composed of two (2) directors selected by holders of Class A Common Stock and two (2) directors selected by holders of Class B Common Stock. This committee has been in place since 2007. The IPO committee is responsible for preparing for our initial public offering and all of its decisions must be unanimous.

The Investor Rights Agreement provides that holders of the majority of New Astoria registrable securities have the right to designate a percentage of the directors equal to the percentage of our outstanding common stock held by them. Subject to fiduciary duties of our board members, we are required to nominate the New Astoria director nominees for election and otherwise take all necessary action to cause them to be elected. These rights terminate if New Astoria and its direct and indirect equityholders and affiliates hold less than 7.5% of the voting power of all of our capital stock. We are obligated to use reasonable best efforts to cause each committee of our board of directors to have a number of directors nominated by New Astoria in proportion to the number of directors nominated by New Astoria on our board.

The Investor Rights Agreement prohibits us from granting registration rights to any other persons without the prior written consent of holders of more than 75% of the registrable securities then outstanding.

Transaction Fees in Connection with the Combination. In connection with the consummation of the Combination, Astoria paid certain transaction fees in the amount of $14.6 million to Madison Dearborn Capital Partners I.V., L.P. and $4.3 million to APGLLC, a limited liability company in which Mr. Worenklein is a member.

Consulting Agreement with K Road BG Management, LLC

Upon consummation of the Combination, we entered into a consulting agreement with K Road BG Management, LLC, pursuant to which K Road BG Management, LLC provides advisory services to us in connection with our initial public offering. As consideration for such services, K Road BG Management, LLC will receive a one-time fee equal to 1% of the aggregate gross proceeds from the initial public offering, provided that the fee will not be less than $3 million. Upon completion of this offering, pursuant to this agreement, we expect to pay K Road BG Management, LLC a fee in the amount of $ .

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DESCRIPTION OF CAPITAL STOCK

The following descriptions are summaries of material terms of our certificate of incorporation and by-laws. They may not contain all of the information that is important to you. To understand them fully, you should read our certificate of incorporation and by-laws, copies of which are filed with the SEC as exhibits to the registration statement of which this prospectus is a part. The following descriptions are qualified in their entirety by reference to the certificate of incorporation and by-laws and to the applicable provisions of the DGCL.

General

As of August 8, 2008, our authorized capital stock consists of 500,000,000 shares of Class A common stock, par value $0.00001 per share, 50,000,000 shares of Class B common stock, par value $0.00001 per share and 1,000,000 shares of preferred stock, par value $0.0001 per share. As of August 8, 2008, we had 41,069,600 shares of Class A common stock outstanding, 35,339,290 shares of Class B common stock outstanding and no shares of preferred stock outstanding. Upon the closing of this offering, each outstanding share of Class B common stock will automatically convert into one fully paid and nonassessable share of Class A common stock. At the close of business on August 8, 2008, we had 79 stockholders of record.

Prior to the consummation of this offering, we will amend and restate our certificate of incorporation to provide that, upon the consummation of this offering, our Class A common stock will be reclassified as common stock and to provide for a -to-1 split of our common stock. Following this amendment, our authorized capital stock will consist of shares of common stock, par value $0.00001 per share and 1,000,000 shares of preferred stock, par value $0.00001 per share.

Upon the closing of this offering and this effectiveness of the amendments to our certificate of incorporation described above, we will have shares of common stock issued and outstanding and no shares of preferred stock issued and outstanding.

Common Stock

All of our existing common stock is validly issued, fully paid and nonassessable. Set forth below is a brief discussion of the principal terms of our common stock that will be outstanding upon the closing of this offering and the effectiveness of our amended and restated certificate of incorporation.

Dividend Rights. Subject to preferences that may apply to shares of preferred stock outstanding at the time, holders of outstanding shares of common stock are entitled to receive dividends out of assets legally available at the times and in the amounts as the board of directors may from time to time determine. See “Dividend Policy.”

Voting Rights. Each outstanding share of our common stock is entitled to one vote on all matters submitted to a vote of stockholders. However, except as required by applicable law, holders of common stock will not be entitled to vote on any amendment to USPowerGen’s certificate of incorporation that relates solely to the terms of one or more outstanding series of preferred stock.

Board Rights. Our certificate of incorporation provides that, following the consummation of this offering, persons who held a majority of the Class B common stock immediately prior to this offering will be entitled to require any directors previously nominated by holders of Class A common stock pursuant to the Investor Rights Agreement to resign, and such vacancies shall be filled by independent directors appointed by the persons who held a majority of the Class B common stock immediately prior to this offering. Holders of our common stock will be entitled to vote on all nominees for election as directors.

Preemptive or Similar Rights. Our common stock is not entitled to preemptive or other similar subscription rights to purchase any of our securities.

Conversion Rights. Our common stock is not convertible into any of our other equity securities.

Right to Receive Liquidation Distributions. Upon our liquidation, dissolution or winding up, the holders of our common stock are entitled to receive pro rata our assets which are legally available for distribution,

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after payment of all debts and other liabilities and subject to the prior rights of any holders of preferred stock then outstanding.

Listing. We have applied to list our common stock on the NYSE under the trading symbol “UPR.”

Class B Common Stock

Upon the closing of the offering, each outstanding share of Class B common stock will automatically convert into one fully paid and nonassessable share of Class A common stock, and each share of Class A common stock will be reclassified as common stock. There will be no shares of our Class B common stock outstanding and we do not expect any shares of Class B common stock to be issued following the completion of this offering.

Preferred Stock

Following this offering, our board of directors may, without further action by our stockholders, from time to time, direct the issuance of up to 1,000,000 shares of preferred stock in series and may, at the time of issuance, determine the rights, preferences and limitations of each series. Satisfaction of any dividend preferences of outstanding shares of preferred stock would reduce the amount of funds available for the payment of dividends on shares of common stock. Holders of shares of preferred stock may be entitled to receive a preference payment in the event of our liquidation, dissolution or winding-up before any payment is made to the holders of shares of common stock. Under specified circumstances, the issuance of shares of preferred stock may render more difficult or tend to discourage a merger, tender offer or proxy contest, the assumption of control by a holder of a large block of our securities or the removal of incumbent management. Upon the affirmative vote of a majority of the total number of directors then in office, our board of directors, without stockholder approval, may issue shares of preferred stock with voting and conversion rights which could adversely affect the holders of shares of common stock. Upon consummation of this offering, there will be no shares of preferred stock outstanding, and we have no present intention to issue any shares of preferred stock.

Warrants

As of August 8, 2008, there were outstanding warrants to purchase 650,000 shares of our Class A common stock, all of which were currently exercisable as of such date. The warrants to purchase our Class A common stock expire on October 10, 2013 and have an exercise price of $11.88 per share. Sigma Capital Associates, LLC owns warrants to purchase 150,000 shares of our Class A common stock and Bear, Stearns & Co. Inc. owns the remaining warrants to purchase 500,000 shares of our Class A common stock.

Transfer Restrictions Set Forth in the Certificate of Incorporation

No transfer of any shares of our capital stock will be effected unless, if the proposed transferee will be a 5% stockholder after the transfer, the proposed transferee delivers to the transfer agent (i) an updated certificate of compliance with certain regulatory matters if such proposed transferee was a 5% holder prior to the transfer or (ii) a certificate of compliance with certain regulatory matters if such proposed transferee was not a 5% stockholder prior to the transfer. Additionally, a transfer will not be effective from the date of any determination by FERC or any state agency that the approval of FERC or such state agency, as applicable, is required to effect such transfer until such approval is obtained.

Antitakeover Effects of Delaware Law and Our Certificate of Incorporation and By-laws

Provisions of the DGCL and our certificate of incorporation and by-laws could make it more difficult to acquire us by means of a tender offer, a proxy contest or otherwise or to remove incumbent officers and directors. These provisions, summarized below, are expected to discourage certain types of coercive takeover practices and inadequate takeover bids and to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging takeover or acquisition proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

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Action by Written Consent; Special Meeting of Stockholders. Our certificate of incorporation provides that stockholder action can be taken only at an annual or special meeting of stockholders and cannot be taken by written consent in lieu of a meeting. Our certificate of incorporation and by-laws also provide that, except as provided by law, special meetings of our stockholders may be called only by (i) a majority of our board of directors or (ii) our President, upon written request of the holders entitled to cast at least twenty-five percent (25%) of the votes at the meeting (provided that New Astoria owns, directly or indirectly, twenty-five percent (25%) or more of the stock entitled to vote generally in the election of directors (voting together as a single class)).

Advance Notice Procedures. Our by-laws establish an advance notice procedure for stockholder proposals to be brought before an annual meeting of our stockholders, including proposed nominations of persons for election to our board of directors. Stockholders at an annual meeting may only consider proposals or nominations specified in the notice of meeting or brought before the meeting by or at the direction of our board of directors or by a stockholder who was a stockholder of record on the record date for the meeting, who is entitled to vote at the meeting and who has given our Secretary timely written notice, in proper form, of the stockholder’s intention to bring that business before the meeting.

In the case of an annual meeting of stockholders, notice by a stockholder, in order to be timely, must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the anniversary of the date on which the corporation first mailed its proxy materials for the preceding year’s annual meeting of stockholders. In the event that the annual meeting is called for a date that is not within 30 days of the anniversary date, in order to be timely, notice by a stockholder must be received not earlier than 120 days nor later than the later of 90 days prior to the annual meeting of stockholders or the tenth day following the date on which notice of the annual meeting was publicly disclosed.

In the case of a special meeting of stockholders called for the purpose of electing our directors, notice by the stockholder, in order to be timely, must be received not earlier than the close of business on the 120th day prior to the date of the special meeting at which directors are to be elected not later than the close of business on the later of the (i) 90th day prior to such special meeting or (ii) the tenth day following the date on which notice of the date of the initial public announcement of the date of the special meeting and the of the nominees proposed by the board of directors (or authorized committee of the board of directors) to be elected at such meeting was made.

Although our by-laws do not give our board of directors the power to approve or disapprove stockholder nominations of candidates or proposals regarding other business to be conducted at a special or annual meeting, our by-laws may have the effect of precluding the conduct of certain business at a meeting if the proper procedures are not followed or may discourage or deter a potential acquiror from conducting a solicitation of proxies to elect its own slate of directors or otherwise attempting to obtain control of us.

Authorized but Unissued Shares. Our authorized but unissued shares of common stock and preferred stock are available for future issuance without your approval. We may use additional shares for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued shares of common stock and preferred stock could render more difficult or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise.

Supermajority Provisions. The DGCL provides generally that the affirmative vote of a majority of the shares entitled to vote on any matter is required to amend a corporation’s certificate of incorporation or by-laws, unless either a corporation’s certificate of incorporation or by-laws require a greater percentage. Our certificate of incorporation and by-laws provide that the affirmative vote of holders of at least 662/3% of the total votes eligible to be cast in the election of our directors will be required to remove directors from office or to amend, alter, change or repeal our by-laws and specified charter provisions. This requirement of a super-majority vote to approve amendments to our certificate of incorporation and by-laws could enable a minority of our stockholders to exercise veto power over any such amendments.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is The Bank of New York.

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DESCRIPTION OF PRINCIPAL INDEBTEDNESS

Background

Our principal indebtedness consists of outstanding borrowings under three separate credit facilities. The principal terms of these facilities are summarized below. We have maintained these separate credit facilities following the Combination due to the substantial costs associated with refinancing any of these facilities. Each of these credit facilities contain covenants that limit the ability of the respective obligors and their subsidiaries to engage in transactions with affiliates and to make investments. As a result, these credit facilities limit our ability to transfer cash between Astoria and EBG. In addition, these credit facilities impose significant limitations on the ability of Astoria and EBG to dividend or make other restricted payments to USPowerGen.

Astoria Credit Facilities

General. In connection with the MDP Acquisition, Astoria Generating Company Acquisitions, L.L.C. (the “Astoria borrower”), entered into a first lien credit facility, a second lien credit facility and a special letter of credit facility, of which the first lien and second lien facilities were amended on June 2, 2006 and again on May 18, 2007 in connection with the Combination (as so amended, the “Astoria credit facilities”).

Available Borrowings. The first lien credit facility provides for: (i) a $430.0 million term loan facility (“Astoria term loan B”); (ii) a $120.0 million term loan facility (“Astoria term loan LC”); and (iii) a $100.0 million working capital revolving facility (“Astoria revolver”). The Astoria term loan LC was fully repaid and terminated on December 22, 2006. The second lien credit facility provides for a $300 million term loan facility (“Astoria term loan C”). The special letter of credit facility, which matured on October 31, 2007, provided for a $150.0 million first lien senior secured letter of credit facility (“Astoria special letter of credit”). The table below sets forth certain information with respect to the amounts outstanding under the Astoria credit facilities as of March 31, 2008:


			Weighted
			Average
	Amount		Interest Rate/
Name of Facility	Outstanding		Letter of Credit Fee
	($ in millions)

Astoria term loan B	$	326.4		4.35	%
Astoria term loan LC		—		NA
Astoria revolver		—		NA
Astoria term loan C	$	300.0		6.35	%

Interest Rates. Borrowings under the first lien credit facility bear interest at the London Interbank Offered Rate (“LIBOR”) plus 2% or (at our option) base rate plus 1%. Upon repayment or prepayment of an aggregate principal amount of $100.0 million of the Astoria term loan B, the interest rate on the first lien credit facility will decrease to LIBOR plus 1.75% (at our option) or base rate plus 0.75%, as applicable. Borrowings under the second lien credit facility bear interest at LIBOR plus 3.75% or (at our option) base rate plus 2.75%, as applicable.

Amortization and Maturity. The Astoria term loan B matures on February 23, 2013, the Astoria term loan LC was to mature on February 23, 2011 and the Astoria revolver matures on February 23, 2012. The Astoria term loan B amortizes in an aggregate principal amount equal to 1% per annum with such amortization commencing on May 23, 2006. The Astoria term loan C matures on August 23, 2013 and is not subject to scheduled amortization prior to such date. The Astoria special letter of credit matured on October 31, 2007.

Dividend Restrictions. The Astoria credit facilities contain covenants restricting the ability of the borrower to declare or pay dividends except, subject to certain conditions and among other exceptions, for dividends payable in the common stock of the borrower, the payment of cash dividends to the borrower or its subsidiaries by any subsidiaries, the payment of certain cash dividends to USPowerGen in an amount not to

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exceed the available excess cash flow (after satisfying voluntary and mandatory prepayment under the Astoria credit facilities) as determined from time to time.

Interest Rate Hedging Requirements. Pursuant to the Astoria credit facilities, Astoria borrower is required to maintain until February 23, 2009, interest rate hedge agreements covering a notional amount of at least 50% of the consolidated debt for borrowed money of Astoria and its subsidiaries, such that at least such amount of indebtedness bears interest at a fixed rate (taking into account any indebtedness that by its terms accrues interest at a fixed rate). As of March 31, 2008, these obligations had been satisfied.

Boston Generating Credit Facilities

General. On December 21, 2006, BG (in such capacity, the “BG borrower”) entered into a first lien credit facility and a second lien credit facility (collectively, “BG credit facilities”).

Available Borrowings. The first lien credit facility provides for: (i) a $1,130.0 million term loan facility (“BG term loan B”); (ii) a $250.0 million synthetic letter of credit facility (“BG synthetic LC”); and (iii) a $70.0 million synthetic working capital revolving credit facility (“BG revolver”). The second lien credit facility provides for a $350.0 million term loan facility (“BG second lien loan”). The table below sets forth certain information with respect the amounts outstanding under the BG credit facilities as of March 31, 2008:


			Weighted
			Average
	Amount		Interest Rate/
Name of Facility	Outstanding		Letter of Credit Fee
	($ in millions)

BG term loan B	$	1,115.9		4.95	%
BG synthetic LC (issued LCs)⁽¹⁾		250.0		2.38	%
BG revolver		41.5		4.95	%
BG second lien loan	$	350.0		6.95	%


(1)		$197.5 million of LC’s were outstanding under the BG synthetic LC on March 31, 2008.

Interest Rates. Borrowings under the BG term loan B bear interest at LIBOR plus 2.25% or (at our option) base rate plus 1.25%. Borrowing under the BG second lien loan bear interest at LIBOR plus 4.25% or (at our option) base rate plus 3.25%. On account of the BG synthetic LC facility and BG revolver, BG pays a per annum participation fee equal to the applicable margin for LIBOR loans plus a 0.125% administration fee, in each case on the full amount of the synthetic LC facility and on the full amount of the BG revolver. Amounts drawn upon from a synthetic letter of credit must be reimbursed immediately by BG, and if not reimbursed, such amounts become borrowings under the synthetic LC facility accruing interest as LIBOR Loans. Borrowings under the BG revolver bear interest at LIBOR less 0.125%. Additional customary issuance, fronting and other fees and expenses also apply.

Amortization and Maturity. The loans under the first lien credit facility mature on December 20, 2013, with the aggregate amount then outstanding under the BG synthetic LC and the BG revolver due on such date. The BG term loan B amortizes in an aggregate principal amount equal to 1% per annum and such amortization commenced on March 30, 2007. The BG second lien loan matures on June 20, 2014, with the aggregate amount then outstanding under the loan due on such date.

Dividend Restrictions. The BG credit facilities contain covenants restricting the ability of BG borrower to declare or pay dividends unless such dividends are made for the benefit of BG borrower or any of the subsidiary parties to the loan to which BG borrower has control. These covenants restrict the payment of dividends and the making of other restricted payments by BG borrower to USPowerGen, but allow for distributions in respect of certain tax liabilities associated with the ownership interest of USPowerGen in BG and certain taxes, costs, fees and expenses permitted by the cash management arrangements agreed upon with the lenders.

Interest Rate Hedging Requirements. BG borrower is required to have at least until three and a half years after December 21, 2006 an interest rate hedge agreement covering a notional amount of at least 50% of

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the term loans under its first lien credit facility. As of March 31, 2008, BG borrower’s obligations had been satisfied.

EBG Credit Facility

General. On December 21, 2006, EBG Holdings LLC (in such capacity, the “EBG borrower”) entered into a $300.0 million mezzanine loan facility (“EBG mezzanine loan facility”). Under the EBG mezzanine loan facility, interest may be capitalized and added to the principal amount of the term loan. To date, the EBG borrower has elected to pay interest by increasing the amount of the term loan. At March 31, 2008, there was approximately $350.7 million outstanding under the EBG credit facility at an average interest rate of 9.7%.

Interest Rates. Borrowings under the EBG mezzanine loan facility bears interest at LIBOR plus 7.00% or (at our option) base rate plus 6.00%.

Amortization and Maturity. The loans under the EBG mezzanine loan facility mature on December 20, 2016, with the aggregate amount then outstanding under the loan due on such date.

Guarantees and Security. Borrowings under the EBG mezzanine loan facility are unsecured obligations and are not guaranteed by any parent or subsidiaries of the EBG borrower.

Dividends. The EBG mezzanine loan facility contains covenants restricting the ability of EBG borrower to declare or pay dividends except in connection with certain issuances of equity in EBG borrower, certain transactions resulting in the purchase, redemption or acquisition of equity interests (up to $25,000,000 in the aggregate) and certain purchases of unit appreciation rights (up to $1,000,000 per fiscal year). These covenants will restrict the payment of dividends and the meeting of other restricted payments by EBG borrower to us.

Guarantees and Security

Guarantees. All obligations of the BG borrower under the BG credit facilities are unconditionally guaranteed by each of its existing and subsequently acquired or organized majority-owned domestic subsidiaries (“BG subsidiary guarantors”). All obligations of the Astoria borrower under the amended Astoria credit facilities are unconditionally guaranteed by each of its existing and subsequently acquired or organized majority-owned domestic subsidiaries (“Astoria subsidiary guarantors”) and its parent company, Astoria (in such capacity, the “parent guarantor”).

Security. The obligations of the Astoria borrower, its parent guarantor and its Astoria subsidiary guarantors under the amended first lien credit facility and the obligations of BG borrower and its BG subsidiary guarantors under the first lien credit facility will be secured by substantially all the assets of each borrower, its Astoria subsidiary guarantors or BG subsidiary guarantors and its parent guarantor, as applicable, whether owned on the closing date or thereafter acquired (the “collateral”), including but not limited to: (i) a perfected first priority pledge of all the equity interests in the respective borrower and its subsidiary guarantors, (ii) a perfected first priority pledge of all the equity interests held by the respective borrower, any of its domestic subsidiary guarantors and its parent guarantor, as applicable, and (iii) perfected first priority security interests in, and mortgages on, substantially all tangible and intangible assets of the respective borrower, each of its domestic subsidiary guarantors and parent guarantor, as applicable (including but not limited to accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property, cash, deposit and securities accounts, commercial tort claims, letter of credit rights, intercompany notes and proceeds of the foregoing).

The obligations of the Astoria borrower, its parent guarantor and its subsidiary guarantors under the amended second lien credit facility and the obligations of BG borrower and its subsidiary guarantors under the second lien credit facility will be secured by substantially all the assets of each borrower, subsidiary guarantor and parent guarantor, as applicable, whether owned on the closing date or thereafter acquired (the “collateral”), including but not limited to (i) a second priority pledge of all the equity interests in the respective borrower and its subsidiary guarantors, (ii) a second priority pledge of all the equity interests held by the respective borrower, any of its domestic subsidiary guarantors and its parent guarantor, as applicable, and (iii) perfected second priority security interests in, and mortgages on, substantially all tangible and

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intangible assets of the respective borrower, each of its domestic subsidiary guarantors and its parent guarantor, as applicable (including but not limited to accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property, cash, deposit and securities accounts, commercial tort claims, letter of credit rights, intercompany notes and proceeds of the foregoing).

In each case, however, the collateral does not include such assets customarily carved-out from a secured lenders’ security interest, certain additional assets described in the EBG credit facility or the Astoria credit facilities (as applicable), and with respect to the Astoria credit facilities, certain assets of the Astoria borrower securing obligations in respect of energy management agreements in place with Sequent.

Representations and Warranties, Covenants and Events of Default

Representations and Warranties. The BG credit facilities, EBG mezzanine loan facility and Astoria credit facilities (collectively, the “credit facilities”) contain customary representations and warranties, including, without limitation, with respect to corporate status; legal, valid and binding documentation; accuracy of financial statements and forecasts; absence of litigation and investigations; and compliance with laws (including environmental laws and permits, margin regulations, payment of taxes, inapplicability of the Investment Company Act, solvency, effectiveness of governmental approvals, employee benefit and other regulatory matters).

Affirmative Covenants. The credit facilities contain customary affirmative covenants, including, without limitation, with respect to maintenance of corporate existence and rights; maintenance of separateness of parent and subsidiaries; delivery of consolidated financial statements and other information; delivery of notices of certain collateral matters, default, litigation and Employee Retirement Income Security Act (“ERISA”) events; compliance with laws; receipt and maintenance of governmental authorizations; inspection of books and properties; and payment of taxes.

Negative Covenants. The credit facilities contain customary negative covenants, including, without limitation, limitations on dividends on and redemptions and repurchases of, equity interests and other restricted payments; limitations on liens; limitations on investments; limitations on debt; limitations on mergers, acquisitions and asset sales; limitations on changes in business conducted by us and our subsidiaries; limitations on the formation of new subsidiaries; and limitations on changes to accounting policies and constitutive documents, in each case, subject to certain exceptions.

Financial Covenants. The credit facilities contain financial covenants specifying maximum total leverage ratios (the ratio of interest-bearing debt to EBITDA) and minimum interest coverage ratios (the ratio of EBITDA to interest payable) for each fiscal quarter. Under the BG first lien credit facility, the maximum total leverage ratio was set at 11.0 times interest-bearing debt to EBITDA for the first fiscal quarter of 2007, and decreases incrementally to 6.0 times interest-bearing debt to EBITDA by 2013. The minimum interest coverage ratio was 1.05 times EBITDA to interest payable for the first fiscal quarter of 2007 and increases to 2.00 times EBITDA to interest payable by 2013. Under the BG second lien credit facility, the maximum total leverage ratio decreases from 12.0 times interest-bearing debt to EBITDA in 2007 to 7.0 times interest-bearing debt to EBITDA in 2013, while the minimum interest coverage ratio increases from 1.00 to 1.75 times EBITDA to interest payable in that period.

The BG credit facilities required us to establish an RMR revenue reserve account, which is carried on our balance sheet as restricted cash. The purpose of this reserve account was to ensure that sufficient working capital was available to meet certain obligations anticipated at the closing of the BG credit facilities. Those obligations related to the settlement of an RMR dispute with ISO-NE and the Distrigas litigation related to the natural gas supply contract at certain of our facilities.

At the time the BG credit facilities were closed it was anticipated that we would be required to make a refund of revenues collected under the RMR arrangement we had with ISO-NE that was terminated in December 2006. Also, at that time we were potentially required to make payments of liquidated damages under the Distrigas contract which amounts were in dispute. Both contingencies were resolved with final payments made to ISO-NE and Distrigas pursuant to their respective settlement agreements. The RMR

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settlement was finalized in April 2007 and the Distrigas settlement was finalized in April 2008. At March 31, 2008, the reserve account had a balance, in excess of the settlement payments, of approximately $67.6 million, which is available for inclusion in calculating compliance EBITDA. The transfer of excess amounts from the reserve account is eligible, under the BG credit facilities, to be used in the determination of covenant compliance.

While we were within the limits of the financial covenants at December 31, 2007 without funding from the reserve account, we did require the transfer of approximately $2.5 million from the reserve account to be within the limits at March 31, 2008. We anticipate additional transfers from the reserve account in the future to ensure covenant compliance under the BG credit facilities.

The Astoria first lien credit facility and the special letter of credit facility’s maximum total leverage ratios are set at 7.5 times interest-bearing debt to EBITDA in 2006 and decreases to 5.0 times interest-bearing debt to EBITDA by 2011, while the minimum interest coverage ratios starts at 1.20 times EBITDA to interest payable in 2006 and increases to 2.00 times EBITDA to interest payable by 2011. Under Astoria’s second lien credit facility, the maximum total leverage ratio decreases from 9.0 times interest-bearing debt to EBITDA in 2006 to 6.0 times interest-bearing debt to EBITDA in 2011, while the minimum interest coverage ratio goes from 1.00 times EBITDA to interest payable to 1.60 times EBITDA to interest payable in that period. As of March 31, 2008, we were in compliance with these covenants.

Both Astoria and BG credit facilities contain an equity cure provision that allows additional capital invested by the respective parents of Astoria and BG to be included in the calculation of EBITDA for purposes of compliance with the financial covenants contained in the respective credit facilities. The equity cure provision of the BG credit facilities may only be used once every four quarters. The equity cure provision of the Astoria credit facilities may not be used in consecutive quarters.

Events of Default. The credit facilities contain customary events of default (with customary grace periods), including, without limitation, with respect to nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross default and cross acceleration; violations under other loan documents; bankruptcy; material judgments; and ERISA events.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of substantial amounts of our common stock in the public market, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. No prediction can be made as to the effect, if any, future sales of shares, or the availability of shares for future sales, will have on the market price of our common stock prevailing from time to time. The sale of substantial amounts of our common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of our common stock.

Sale of Restricted Shares

Upon completion of this offering, we will have shares of common stock outstanding. Of these shares of common stock, the shares of common stock being sold in this offering, plus any shares issued upon exercise of the underwriters’ option to purchase additional shares, will be freely tradable without restriction under the Securities Act, except for any such shares which may be held or acquired by an “affiliate” of ours, as that term is defined in Rule 144 promulgated under the Securities Act, which shares will be subject to the volume limitations and other restrictions of Rule 144 described below. The remaining shares of common stock held by our existing stockholders upon completion of this offering will be “restricted securities,” as that phrase is defined in Rule 144, and may be resold only after registration under the Securities Act or pursuant to an exemption from such registration, including, among others, the exemptions provided by Rule 144 and 701 under the Securities Act, which rules are summarized below. These remaining shares of common stock held by our existing stockholders upon completion of this offering will be available for sale in the public market after the expiration of the lock-up agreements described in “Underwriting,” taking into account the provisions of Rules 144 and 701 under the Securities Act.

Rule 144

The SEC has recently adopted amendments to Rule 144 which became effective on February 15, 2008. Under these amendments, persons who became the beneficial owner of shares of our common stock prior to the completion of this offering may not sell their shares until the earlier of (i) the expiration of a six-month holding period, if we have been subject to the reporting requirements of the Exchange Act and have filed all required reports for at least 90 days prior to the date of the sale, or (ii) a one-year holding period.

At the expiration of the six-month holding period, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock provided current public information about us is available, and a person who was one of our affiliates at any time during the three months preceding a sale would be entitled to sell within any three-month period only a number of shares of common stock that does not exceed the greater of either of the following:


	•	1% of the number of shares of our common stock then outstanding, which will equal approximately shares immediately after this offering, based on the number of shares of our common stock outstanding as of ; or

	•	the average weekly trading volume of our common stock on the NYSE during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

At the expiration of the one-year holding period, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock without restriction. A person who was one of our affiliates at any time during the three months preceding a sale would remain subject to the volume restrictions described above.

Sales under Rule 144 by our affiliates are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us.

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Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchased shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering, or who purchased shares from us after that date upon the exercise of options granted before that date, are eligible to resell such shares in reliance upon Rule 144 beginning 90 days after the date of this prospectus. If such person is not an affiliate, the sale may be made subject only to the manner-of-sale restrictions of Rule 144. If such a person is an affiliate, the sale may be made under Rule 144 without compliance with its one-year minimum holding period, but subject to the other Rule 144 restrictions.

Lock-Up Agreements

We and our directors, executive officers and stockholders have entered into lock-up agreements with the underwriters. Under these agreements, subject to exceptions, we may not issue any new shares of common stock, and those persons may not, directly or indirectly, offer, sell, contract to sell, pledge or otherwise dispose of or hedge any common securities convertible into or exchangeable for shares of our common stock, or publicly announce the intention to do any of the foregoing, without the prior written consent of Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co., until the expiration of the lock-up agreements. This consent may be given at any time without public notice. Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co. have advised us that there is no specific criteria for the waiver of lock-up restrictions.

Registration Rights

As described above in “Certain Relationships and Related Party Transactions — Agreements Related to the Combination — Investor Rights Agreement,” following the completion of this offering, subject to the lock-up period described above, certain parties to our Investor Rights Agreement will be entitled, subject to certain exceptions, to demand the filing of, and the inclusion of their shares in, registration statements relating to our securities. If this right is exercised, holders of up to shares will be entitled to participate in such a registration. By exercising their registration rights and causing a large number of shares to be registered and sold in the public market, these holders could cause the price of our common stock to fall. In addition, any demand to include such shares in our registration statements could reduce our ability to raise needed capital through a public offering of common stock.

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CERTAIN MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

The following is a general discussion of certain material U.S. federal income tax consequences to holders of our common stock. This discussion is a summary for general information purposes only and does not consider all aspects of U.S. federal income taxation that may be relevant to holders in light of their particular investment circumstances or to certain types of holders subject to special tax rules, including partnerships, banks, financial institutions or other financial services entities, broker-dealers, insurance companies, tax-exempt organizations, regulated investment companies, real estate investment trusts, retirement plans, individual retirement accounts or other tax-deferred accounts, persons who use or are required to use MTM accounting, persons that hold shares of our common stock as part of a “straddle,” a “hedge” or a “conversion transaction,” investors in partnerships and other pass-through entities, persons with a functional currency other than the U.S. dollar and persons subject to the alternative minimum tax. This discussion also does not address any non-U.S. tax considerations or any U.S. federal non-income, state or local tax considerations. This discussion assumes that holders hold their shares as “capital assets” within the meaning of Section 1221 of the Code. This discussion is based on the Code and applicable U.S. Treasury Regulations, rulings, administrative pronouncements and decisions as of the date hereof, all of which are subject to change or differing interpretations at any time with possible retroactive effect. The authorities on which this discussion is based are subject to various interpretations, and any views expressed within this discussion are not binding on the U.S. Internal Revenue Service (“IRS”), or the courts. No assurance can be given that the IRS or the courts will agree with the tax consequences described herein.

For purposes of this discussion, a “U.S. Holder” is a beneficial owner of shares of our common stock that is


	•	a citizen or individual resident of the United States,

	•	a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized, or treated as created or organized, in or under the laws of the U.S. or any political subdivision of the U.S.,

	•	an estate the income of which is subject to U.S. federal income taxation regardless of its source or

	•	a trust (1) if a court within the U.S. is able to exercise primary supervision over the trust’s administration and one or more U.S. persons have authority to control all substantial decisions of the trust or (2) that has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.

For purposes of this discussion, a “Non-U.S. Holder” means a beneficial owner of our common stock that is neither a U.S. Holder nor a partnership (or other entity or arrangement that is taxable as a partnership for U.S. federal income tax purposes).

If a partnership (or other entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner and the activities of the partnership.

Accordingly, partnerships that hold our common stock and partners in such partnerships are urged to consult their own tax advisors regarding the specific U.S. federal income tax consequences to them.

EACH PROSPECTIVE PURCHASER OF OUR STOCK IS URGED TO CONSULT ITS OWN TAX ADVISOR REGARDING THE SPECIFIC FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX CONSIDERATIONS OF PURCHASING, OWNING AND DISPOSING OF OUR COMMON STOCK. THIS SUMMARY OF TAX CONSEQUENCES IS FOR GENERAL INFORMATION PURPOSES ONLY AND IS NOT TAX ADVICE.

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Consequences to U.S. Holders

Dividends

As discussed under the section entitled “Dividend Policy” above, we do not currently anticipate paying dividends. In the event that we do make a distribution of cash or property with respect to our common stock, any such distributions will be taxable as a dividend for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits (as determined under U.S. federal income tax principles).

A U.S. Holder generally will be subject to U.S. federal income tax on any dividends received in respect of our common stock at a maximum federal income tax rate of 15% if the U.S. Holder is an individual and certain holding period and other requirements are satisfied, and a maximum federal income tax rate of 35% otherwise. If the amount of a distribution exceeds our current and accumulated earnings and profits, such excess will be allocated ratably among each share of common stock with respect to which the distribution is paid and treated first as a tax-free return of capital to the extent of the U.S. Holder’s adjusted tax basis in each such share, and thereafter as capital gain from a sale or other disposition of each such share of common stock that is taxed to the U.S. Holders as described below.

Under current law, the 15% maximum federal income tax rate on dividends is scheduled to expire effective for taxable years beginning after December 31, 2010, and dividends received in subsequent taxable years are scheduled to be taxed at a maximum federal income tax rate of 39.6%.

Gain on Disposition of Common Stock

A U.S. Holder that sells or otherwise disposes of our common stock in a taxable transaction will recognize capital gain or loss equal to the amount of cash plus the fair market value of property received in exchange for the common stock minus the U.S. Holder’s adjusted tax basis in the common stock. Any capital gain or loss recognized by the U.S. Holder will be long-term capital gain or loss if the U.S. Holder has held our common stock for more than one year at the time of the sale or other disposition and short-term capital gain or loss otherwise. Long-term capital gains recognized by non-corporate taxpayers are taxable under current law at a maximum federal income tax rate of 15%. Long-term capital gains recognized by corporations and short-term capital gains recognized by corporations or individuals are taxable under current law at a maximum federal income tax rate of 35%. A U.S. Holder’s ability to use any capital loss to offset other income or gain is subject to certain limitations.

Under current law, the maximum federal income tax rate applicable to long-term capital gains is scheduled to increase to 20% for non-corporate taxpayers for taxable years beginning after December 31, 2010.

Consequences to Non-U.S. Holders

Dividends

As with distributions to U.S. Holders, in the event that we do make a distribution of cash or property with respect to our common stock to any Non-U.S. Holder, any such distributions will be taxable as a dividend for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). A Non-U.S. Holder generally will be subject to U.S. federal income tax on any dividends received in respect of our common stock at a 30% rate (or such lower rate as prescribed by an applicable income tax treaty as discussed below) unless the dividend is effectively connected with the conduct of a U.S. trade or business. As discussed below, this tax is generally collected through withholding on the dividend payment to the Non-U.S. Holder.

If a Non-U.S. Holder receives a dividend that is effectively connected with the conduct of a U.S. trade or business, then the dividend payment will not be subject to withholding (provided that the certification requirements described below are satisfied). However, the dividends received by the Non-U.S. Holder will be subject to tax under current law at a maximum federal income tax rate of 15% if the Non-U.S. Holder is an individual and certain holding period and other requirements are satisfied, and a maximum federal income tax rate of 35% otherwise. A Non-U.S. Holder that is a corporation may also be subject to a 30% federal branch

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profits tax on after-tax profits effectively connected with a U.S. trade or business to the extent that such after-tax profits are not reinvested and maintained in a U.S. business.

If the amount of a distribution exceeds our current and accumulated earnings and profits, such excess will be allocated ratably among each share of common stock with respect to which the distribution is paid and treated first as a tax-free return of capital to the extent of the Non-U.S. Holder’s adjusted tax basis in each such share, and thereafter as capital gain from a sale or other disposition of each such share of common stock that is taxed to the Non-U.S. Holders as described below.

Under current law, the 15% maximum federal income tax rate on dividends effectively connected with the conduct of a U.S. trade or business is scheduled to expire effective for taxable years beginning after December 31, 2010, and dividends received in subsequent taxable years that are effectively connected with the conduct of a U.S. trade or business are scheduled to be taxed at a maximum federal income tax rate of 39.6%.

Gain on Disposition of Common Stock

A Non-U.S. Holder that sells or otherwise disposes of our common stock in a taxable transaction generally will not be subject to U.S. federal income taxation unless


	•	gain resulting from the disposition is effectively connected with the conduct of a U.S. trade or business or, where a relevant tax treaty applies, is attributable to a U.S. permanent establishment; or

	•	(i) we are or have been a U.S. real property holding corporation (“USRPHC”) as defined in Section 897 of the Code at any time within the five-year period preceding the disposition, (ii) the Non-U.S. Holder owned more than 5% of our common stock at any time within that five-year period and (iii) certain other conditions are satisfied.

In general, a corporation is a USRPHC if the fair market value of its “U.S. real property interests” equals or exceeds 50% of the sum of the fair market value of its worldwide (domestic and foreign) real property interests and its other assets used or held for use in a trade or business. We believe that we are not a USRPHC on the date hereof and currently do not anticipate becoming a USRPHC. Even if we become a USRPHC, gain on the sale or other disposition of our common stock by a Non-U.S. Holder generally would not be subject to United States federal income tax provided the common stock was “regularly traded on an established securities market” and such holder did not actually or constructively own more than 5% of such class of common stock during the shorter of (1) the five-year period preceding the disposition or (2) such holder’s holding period.

If a Non-U.S. Holder is subject to U.S. federal income taxation upon the disposition of our common stock, the Non-U.S. Holder generally will be taxable in the same manner as a U.S. Holder, although a Non-U.S. Holder that is a corporation may also be subject to a 30% branch profits tax on after-tax profits effectively connected with a U.S. trade or business to the extent that such after-tax profits are not reinvested and maintained in the U.S. business. A Non-U.S. Holder’s ability to use any capital loss to offset other income or gain subject to U.S. federal income taxation is subject to certain limitations.

Under certain circumstances, a Non-U.S. Holder who is present in the U.S. for 183 days or more in the individual’s taxable year in which the sale or other disposition of our common stock occurs may be subject to a 30 percent tax on the gross amount of the gain on such sale or disposition unless such gain is already subject to tax as effectively connected with the conduct of a U.S. trade or business. In this case, the Non-U.S. Holder’s ability to use other losses to offset the gain on our common stock will be limited.

Income Tax Treaties

If a Non-U.S. Holder is eligible for treaty benefits under an income tax treaty entered into by the U.S., the Non-U.S. Holder may be able to reduce or eliminate certain of the U.S. federal income taxes discussed above, such as the tax on dividends and the branch profits tax, and the Non-U.S. Holder may be able to treat gain, even if effectively connected with a U.S. trade or business, as not subject to U.S. federal income taxation unless the U.S. trade or business is conducted through a permanent establishment located in the

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U.S. Non-U.S. Holders are urged to consult their tax advisors regarding possible relief under an applicable income tax treaty.

Withholding and Information Reporting

We generally must report annually to the IRS and to you the amount of dividends paid to you and the tax withheld with respect to those dividends, regardless of whether withholding was required, together with other information. We may also be required to comply with information reporting requirements under the Code with respect to proceeds from a sale or other taxable disposition of our common stock. Copies of the information returns reporting such information may also be made available to the tax authorities in the country in which a Non-U.S. Holder resides under the provisions of an applicable income tax treaty or other applicable agreements.

A U.S. Holder may be subject to backup withholding (currently at a rate of 28%) on the gross amount of any dividend or other distribution on our common stock and on the proceeds from a sale or other taxable disposition of our common stock, unless the U.S. Holder is exempt from backup withholding and, when required, demonstrates that status, or provides a correct taxpayer identification number on a form acceptable under U.S. Treasury Regulations (generally an IRS Form W-9) and otherwise complies with the applicable requirements of the backup withholding rules.

A Non-U.S. Holder generally will be subject to withholding at a rate of 30% of the gross amount of any dividend or other distribution on our common stock unless the Non-U.S. Holder qualifies for a reduced rate of withholding or an exemption from withholding under an applicable tax treaty or the dividend or other distribution is effectively connected with a U.S. trade or business (in which case the dividend or other distribution will be exempt from withholding but the Non-U.S. Holder will nonetheless be liable for any applicable U.S. federal income tax as described above). The Non-U.S. Holder may be required to demonstrate its qualification for a reduced rate of withholding or an exemption from withholding on a form acceptable under applicable U.S. Treasury Regulations (generally an IRS Form W-8BEN or W-8ECI) and otherwise comply with the applicable requirements of the backup withholding rules.

In addition, a Non-U.S. Holder may be subject to backup withholding on the proceeds from a sale or other taxable disposition of our common stock effected by or through a broker, unless the Non-U.S. Holder provides certification that it is not a United States person or otherwise establishes an exemption from withholding on a form acceptable under U.S. Treasury Regulations (generally an IRS Form W-8BEN or W-8ECI) or unless the transaction is through a foreign office of a broker who is itself not subject to U.S. information reporting requirements.

The backup withholding tax is not an additional tax. Any amounts withheld under the backup withholding rules generally will be allowed as a refund or credit against a holder’s United States federal income tax liability provided the required information is furnished in a timely manner to the IRS. Holders are advised to consult their tax advisers to ensure compliance with the procedural requirements to reduce or avoid withholding (including backup withholding) or, if applicable, to file a claim for a refund of withheld amounts in excess of the holder’s U.S. federal income tax liability.

THE U.S. FEDERAL INCOME TAX DISCUSSION SET FORTH ABOVE IS INCLUDED FOR GENERAL INFORMATION PURPOSES ONLY. POTENTIAL PURCHASERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS TO DETERMINE THE FEDERAL, STATE, LOCAL, FOREIGN AND OTHER TAX CONSIDERATIONS OF PURCHASING, OWNING AND DISPOSING OF OUR COMMON STOCK.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated , we and the selling stockholders have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. Incorporated are acting as representatives, the following respective numbers of shares of common stock:


		Number
Underwriter		of Shares

Credit Suisse Securities (USA) LLC
Goldman, Sachs & Co
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Morgan Stanley & Co. Incorporated

Total

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

The selling stockholders have granted to the underwriters a 30-day option to purchase on a pro rata basis an aggregate of additional outstanding shares from the selling stockholders at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $ per share. After the initial public offering the representatives may change the public offering price and concession.

The following table summarizes the compensation and estimated expenses we and the selling stockholders will pay:

Per Share

Total

Without

With

Without

With

Over-allotment

Underwriting Discounts and Commissions paid by us

Expenses payable by us

Underwriting Discounts and Commissions paid by selling stockholders

We estimate that our out-of-pocket expenses for this offering will be approximately $ , and will include the expenses of the selling stockholders which will be paid by us.

The representatives have informed us that they do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the shares of common stock being offered.

We have agreed that we will not offer, sell, issue, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co. for a period of 180 days after the date of this prospectus except (1) issuances pursuant to the exercise of employee stock options outstanding on the date hereof, (2) issuances pursuant to the conversion or exchange of securities or the exercise of warrants and options, in each case outstanding as of the date of this

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prospectus, (3), the filing of a registration statement on Form S-8 relating to shares of our common stock issuable upon the conversion or exchange of employee stock options or other securities pursuant to the terms of a plan in effect on the date hereof or a plan described herein and (4) any offer or agreement to sell or otherwise dispose of shares of our common stock in connection with a plan of merger, asset purchase, acquisition of a business or subdivision of a business, strategic alliance or joint venture; provided that, with respect to this clause (4), we will not offer to sell or enter into an agreement to sell or otherwise dispose of shares of our common stock in excess of 5% of the shares of our common stock outstanding on the date of the consummation of such transaction; and provided further, that the shares issued under this clause (4) are unregistered, and the recipients of any shares issued under this clause (4) are restricted from selling, transferring or requiring registration of such shares during the “lock-up” period. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co. waive, in writing, such an extension.

Our officers and directors and beneficial owners have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge, disposition, purchase or grant or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co. for a period of 180 days after the date of this prospectus. In addition, such officers and directors and beneficial owners have agreed that, without the prior written consent of Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co., they will not, during the “lock-up” period, make any demand for or exercise any right with respect to, the registration of any shares of our common stock or any security convertible into or exercisable or exchangeable for shares of our common stock. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co. waive, in writing, such an extension. Notwithstanding the foregoing, such officers, directors and stockholders may transfer such securities (i) as a bona fide gift or gifts, (ii) to any trust for the direct or indirect benefit of such person or the immediate family of such person, provided that the trustee of the trust agrees to be bound in writing by the restrictions set forth in the “lock-up,” (iii) in the case of a corporation, partnership, limited liability company or other business entity, to any subsidiary, stockholder, partner, member or affiliate, as the case may be or (iv) to the underwriters pursuant to the underwriting agreement, provided that in the case of (i), (ii) and (iii), (A) the transferee agrees to be bound in writing by the terms of the “lock-up” prior to such transfer, (B) no filing by any party (donor, donee, transferor or transferee) under the Exchange Act shall be required or shall be voluntarily made in connection with such transfer (other than a filing on a Form 5 made after the expiration of the “lock-up” period) and (C) such transfer shall not involve a disposition for value. Notwithstanding the foregoing, clause (B) shall not apply to the distribution (which may be a liquidating distribution) by New Astoria to its members on a pro rata basis of the securities it holds immediately prior to the date of this offering. For purposes of the “lock-up,” “immediate family” shall mean any relationship by blood, marriage or adoption, not more remote than first cousin.

We and the selling stockholders have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

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We have applied to list the shares of common stock on the New York Stock Exchange.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions, and penalty bids in accordance with Regulation M under the Exchange Act.


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.

	•	Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Prior to this offering, there has been no public market for our common stock. The initial public offering price will be determined by negotiations between us and the representatives. In determining the initial public offering price, we and the representatives expect to consider a number of factors including:


	•	the information set forth in this prospectus and otherwise available to the representatives;

	•	our earnings and other financial operating information in recent periods;

	•	our future prospects and the history and prospects of our industry in general;

	•	an assessment of our management;

	•	our prospects for future earnings;

	•	the price-earnings ratios, market prices of shares, as well as financial and operating information, of other companies engaged in businesses similar to those of our company;

	•	the general condition of the securities markets, and the initial public offering market in particular, at the time of the offering; and

	•	other factors deemed relevant by the representatives and us.

Neither we nor the representatives can assure you that an active market will develop for our common stock or that the common stock will trade in the public market at or above the initial offering price.

180

A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

In the ordinary course, the underwriters and their affiliates have provided, and may in the future provide, investment banking, commercial banking, investment management, or other financial services to us and our affiliates for which they have received customary compensation and may receive compensation in the future. In particular, since December 31, 2006 Credit Suisse Securities (USA) LLC acted as sole advisor to Astoria in connection with the Combination and was joint lead arranger along with Goldman, Sachs & Co. for the EBG Refinancing. Credit Suisse Securities (USA) LLC is administrative agent for the EBG mezzanine loan facility and the BG credit facilities. Morgan Stanley Senior Funding, Inc. serves as administrative agent in connection with the Astoria credit facilities. Each of Credit Suisse Energy LLC and Morgan Stanley Capital Group Inc. is a counterparty to a derivative instrument to which we are a party.

Each underwriter has represented, warranted and agreed that:


	•	it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (“FSMA”)) received by it in connection with the issue or sale of any stock in circumstances in which Section 21(1) of the FSMA does not apply to us; and

	•	it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the stock in, from or otherwise involving the United Kingdom.

The common stock may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), and no advertisement, invitation or document relating to the common stock may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to common stock which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the common stock may not be circulated or distributed, nor may the common stock be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the common stock is subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that

181

corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the common stock under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

The common stock has not been and will not be registered under the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended) (“FIEL”) and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the FIEL and any other applicable laws, regulations and ministerial guidelines of Japan.

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a Relevant Member State), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the Relevant Implementation Date), it has not made and will not make an offer of common stock to the public in that Relevant Member State prior to the publication of a prospectus in relation to the common stock which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of common stock to the public in that Relevant Member State at any time:

(1) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(2) to any legal entity which has two or more of (a) an average of at least 250 employees during the last financial year; (b) a total balance sheet of more than €43,000,000 and (c) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

(3) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

(4) in any other circumstances which do not require the publication by the issuer of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of common stock to the public” in relation to any common stock in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the common stock to be offered so as to enable an investor to decide to purchase or subscribe the common stock, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

182

NOTICE TO CANADIAN RESIDENTS

Resale Restrictions

The distribution of the shares in Canada is being made only on a private placement basis exempt from the requirement that we and the selling stockholders prepare and file a prospectus with the securities regulatory authorities in each province where trades of shares are made. Any resale of the shares in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the shares.

Representations of Purchasers

By purchasing the shares in Canada and accepting a purchase confirmation a purchaser is representing to us, the selling stockholders and the dealer from whom the purchase confirmation is received that:


	•	the purchaser is entitled under applicable provincial securities laws to purchase the shares without the benefit of a prospectus qualified under those securities laws,

	•	where required by law, that the purchaser is purchasing as principal and not as agent,

	•	the purchaser has reviewed the text above under Resale Restrictions, and

	•	the purchaser acknowledges and consents to the provision of specified information concerning its purchase of the shares to the regulatory authority that by law is entitled to collect the information.

Further details concerning the legal authority for this information is available on request.

Rights of Action — Ontario Purchasers Only

Under Ontario securities legislation, certain purchasers who purchase a security offered by this prospectus during the period of distribution will have a statutory right of action for damages, or while still the owner of the shares, for rescission against us and the selling stockholders in the event that this prospectus contains a misrepresentation without regard to whether the purchaser relied on the misrepresentation. The right of action for damages is exercisable not later than the earlier of 180 days from the date the purchaser first had knowledge of the facts giving rise to the cause of action and three years from the date on which payment is made for the shares. The right of action for rescission is exercisable not later than 180 days from the date on which payment is made for the shares. If a purchaser elects to exercise the right of action for rescission, the purchaser will have no right of action for damages against us or the selling stockholders. In no case will the amount recoverable in any action exceed the price at which the shares were offered to the purchaser and if the purchaser is shown to have purchased the securities with knowledge of the misrepresentation, we and the selling stockholders will have no liability. In the case of an action for damages, we and the selling stockholders will not be liable for all or any portion of the damages that are proven to not represent the depreciation in value of the shares as a result of the misrepresentation relied upon. These rights are in addition to, and without derogation from, any other rights or remedies available at law to an Ontario purchaser. The foregoing is a summary of the rights available to an Ontario purchaser. Ontario purchasers should refer to the complete text of the relevant statutory provisions.

183

LEGAL MATTERS

The validity of the common stock offered hereby will be passed upon for us by Kirkland & Ellis LLP, a limited liability partnership that includes professional corporations, Chicago, Illinois. Certain partners of Kirkland & Ellis LLP are members of a limited liability company that is an investor in one or more investment funds affiliated with Madison Dearborn. Kirkland & Ellis LLP represents entities affiliated with Madison Dearborn and its affiliates in connection with legal matters. Milbank, Tweed, Hadley & McCloy LLP will act as counsel to the underwriters.

EXPERTS

The consolidated and combined financial statements of US Power Generating Company and subsidiaries as of December 31, 2007 (Successor) and December 31, 2006 (Successor), and for the year ended December 31, 2007 (Successor), the period February 24, 2006 through December 31, 2006 (Successor), the period January 1, 2006 through February 23, 2006 (Predecessor), and the year ended December 31, 2005 (Predecessor), have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon authority of said firm as experts in accounting and auditing. The audit report covering the December 31, 2006 financial statements refers to the adoption of Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share-Based Payment and SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132 (R).

The consolidated financial statements of EBG Holdings LLC and subsidiaries as of May 31, 2007 and December 31, 2006 and for the five months ended May 31, 2007, and each of the two years in the two-year period ended December 31, 2006, have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act that registers the shares of our common stock to be sold in this offering. The registration statement, including the attached exhibits, contains additional relevant information about us and our common stock. The rules and regulations of the SEC allow us to omit from this document certain information included in the registration statement.

You may read and copy the reports and other information we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N. E., Room 1580, Washington, D.C. 20549. You may also obtain copies of this information by mail from the public reference section of the SEC, 100 F Street, N.E., Washington, D.C. 20549, at prescribed rates. You may obtain information regarding the operation of the public reference room by calling 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy statements and other information about issuers, like us, who file electronically with the SEC. The address of that website is http://www.sec.gov. This reference to the SEC’s website is an inactive textual reference only and is not a hyperlink.

185

INDEX TO FINANCIAL STATEMENTS

US POWER GENERATING COMPANY AND SUBSIDIARIES

Consolidated Financial Statements

Table of Contents


US Power Generating Company — As of March 31, 2008 and for the three months ended March 31, 2008 and 2007
Consolidated Balance Sheets			F-2
Consolidated Statements of Operations			F-3
Consolidated Statements of Stockholders’ Equity and Comprehensive Income			F-4
Consolidated Statements of Cash Flows			F-5
Notes to Consolidated Financial Statements			F-6
US Power Generating Company — As of and for the year ended December 31, 2007
Astoria Generating Company Holdings, LLC — As of December 31, 2006 and the period February 24, 2006 through December 31, 2006
Astoria Generating Company, L.P. and Orion Power Operating Services Astoria, Inc. Combined — for the period January 1, 2006 through February 23, 2006 and the year ended December 31, 2005
Independent Auditors Report			F-18
Consolidated Balance Sheets			F-19
Consolidated Statements of Operations			F-20
Consolidated Statements of Stockholders’ Equity, Members’ Equity, Owners’ Net Investment, and Comprehensive Income			F-21
Consolidated Statements of Cash Flows			F-22
Notes to Consolidated Financial Statements			F-23
EBG Holdings, LLC — As of May 31, 2007 and December 31, 2006, for the five months ended May 31, 2007 and the years ended December 31, 2006 and 2005
Independent Auditors Report			F-78
Consolidated Balance Sheets			F-79
Consolidated Statements of Operations			F-80
Consolidated Statement of Members’ Capital (Deficit) and Comprehensive Income			F-81
Consolidated Statements of Cash Flows			F-82
Notes to Consolidated Financial Statements			F-83

F-1

US Power Generating Company and Subsidiaries

Consolidated Balance Sheets
Unaudited

(Dollars in thousands, except per share data)


	March 31,		December 31,
	2008		2007

ASSETS
Current assets:
Cash and cash equivalents	$	11,296		34,409
Restricted cash		95,912		100,856
Accounts receivable		176,117		153,785
Derivative assets		8,509		16,439
Fuel inventory, materials and supplies		34,603		35,579
Deferred income taxes		28,055		28,055
Prepaid expenses and other current assets		35,988		22,677

Total current assets		390,480		391,800
Property, plant, and equipment, net		3,496,226		3,515,857
Other assets:
Goodwill		579,026		829,093
Other intangibles, net		78,105		80,498
Emissions allowances, net		130,441		131,784
Derivative assets		90		13,419
Deferred financing costs		21,625		22,633
Other long-term assets		19,225		19,382

Total assets	$	4,715,218		5,004,466


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	91,334		95,704
Fuel payable		98,844		94,859
Accrued transaction costs		32,400		32,400
Other current liabilities		5,268		8,962
Derivative liabilities		45,251		49,114
Revolving line of credit		41,500		29,500
Current portion of long-term debt		15,600		15,600

Total current liabilities		330,197		326,139
Other liabilities:
Derivative liabilities		62,887		63,817
Pension and postretirement obligations		19,283		18,964
Deferred income taxes		679,990		686,234
Asset retirement obligations		9,112		8,956
Other long-term liabilities		5,201		4,771
Long-term debt		2,471,744		2,486,589

Total liabilities		3,578,414		3,595,470
Stockholders’ equity:
Class A common stock, $.00001 par value; non-voting; 500,000,000 shares authorized; 41,069,600 issued and outstanding		—		—
Class B common stock, $.00001 par value; voting; 50,000,000 shares authorized; 35,539,000 issued and 35,339,290 outstanding		—		—
Preferred stock, $0.0001 par value; voting rights may be designated upon issuance; 1,000,000 shares authorized; no shares issued and outstanding		—		—
Stockholders’ equity		1,136,804		1,408,996

Total liabilities and stockholders’ equity	$	4,715,218		5,004,466

See accompanying notes to these consolidated financial statements.

F-2

US Power Generating Company and Subsidiaries

Consolidated Statements of Cash Flows

Unaudited

(Dollars in thousands)


	Three months ended March 31,
	2008			2007

Cash flows from operating activities:
Net loss	$	(263,970	)		(1,805	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		30,403			7,086
Amortization of emissions allowances		606			888
Amortization of contractual rights and obligations, net		2,393			1,625
Amortization of deferred financing costs		1,008			1,016
Amortization of debt premium		(1,108	)		—
Accrued interest expense on Mezzanine Facility		10,163			—
Accretion of asset retirement obligations		156			73
Loss on disposal of assets		(738	)		—
Net unrealized loss on derivative contracts		8,524			17,263
Non-cash share-based compensation		595			2,190
Impairment of goodwill		250,067			—
Changes in assets and liabilities:
Restricted cash		4,944			—
Accounts receivable		(22,332	)		9,752
Fuel inventory, materials and supplies		(2,414	)		261
Prepaid expenses and other current assets		(13,311	)		(8,958	)
Other long-term assets		(144	)		701
Accounts payable and accrued expenses		(1,589	)		(5,987	)
Fuel payable		3,985			(4,601	)
Other current liabilities		(2,042	)		(1,175	)
Deferred income taxes		(4,378	)		(509	)
Pension and postretirement obligations		716			3,104
Other long-term liabilities		32			(18	)

Net cash provided by operating activities		1,566			20,906

Cash flows from investing activities:
Capital expenditures		(13,761	)		(14,358	)
Cash paid for merger related costs		(1,142	)		—
Proceeds from sales of emissions allowances		4,865			—

Net cash used in investing activities		(10,038	)		(14,358	)

Cash flows from financing activities:
Distributions to members		(2,741	)		(2,392	)
Payments of long-term debt		(23,900	)		(21,075	)
Proceeds from revolving line of credit		12,000			—

Net cash used in financing activities		(14,641	)		(23,467	)

Net change in cash and cash equivalents		(23,113	)		(16,919	)
Net cash and cash equivalents at beginning of period		34,409			44,507

Net cash and cash equivalents at end of period	$	11,296			27,588

Supplemental cash flow information:
Cash paid for interest	$	44,026			13,137
Cash paid for income taxes		1,607			—

See accompanying notes to these consolidated financial statements.

F-5

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements

March 31, 2008

(Dollars in thousands, except as otherwise indicated)


(1)	Nature of Business

US Power Generating Company (USPowerGen or the Company), is a wholesale power generation company that owns and operates power generation facilities in the New York City and Boston metropolitan areas. As of March 31, 2008, the Company has a total portfolio of 58 generation units at six power generation facilities with generation capacity of approximately 5,223 megawatts (MWs).

On February 28, 2007, EBG Holdings LLC (EBG) and Astoria Generating Company Holdings, L.L.C. (Astoria) announced that they had entered into a definitive merger agreement, under which the companies would be combined (the Combination). Under the merger agreement, EBG and Astoria were combined to form USPowerGen, a Delaware corporation. The Combination was completed on June 1, 2007. In order to effect the Combination, USPowerGen and its two subsidiaries EBG Merger LLC (EBG Merger) and Astoria Merger LLC (Astoria Merger) were formed. Immediately prior to the Combination, each of the members of Astoria exchanged their Astoria units for units of New Astoria Generating Company Holdings, L.L.C. (New Astoria), a shareholder of USPowerGen; and each of the members of EBG exchanged their EBG units for shares in USPowerGen. Astoria then merged with Astoria Merger and EBG merged with EBG Merger. Both Astoria Merger and EBG Merger ceased to exist, thereby leaving Astoria and EBG as direct subsidiary companies of USPowerGen.


(2)	Summary of Significant Accounting Policies


*(a)*	*Principles of Consolidation and Basis of Presentation*

The consolidated financial statement information presented as of and for the three months ended March 31, 2008 and as of December 31, 2007, reflects the consolidation of USPowerGen, Astoria, EBG and their subsidiaries. The consolidated financial statement information presented for the quarter ended March 31, 2007 reflects the consolidation of Astoria, and its subsidiaries. Accordingly, all material intercompany transactions and balances by and between members of the consolidated group for the respective periods have been eliminated.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make a number of estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

The unaudited interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission’s rules, regulations and guidelines regarding interim financial information, and, in the opinion of management, include all material normal and recurring accruals and adjustments necessary to present fairly the Company’s consolidated financial position as of March 31, 2008, and the results of operations and cash flows for the three months ended March 31, 2008 and March 31, 2007, respectively.

While the Company believes that the disclosures are adequate to make the information presented not misleading, certain information normally included in footnote disclosures of financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) has been condensed or omitted pursuant to such rules, regulations, and guidelines. As such, the interim unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements for the year ended December 31, 2007, and the footnotes thereto. Further, the results of operations for the three months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the twelve months ending December 31, 2008.

F-6

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)


*(b)*	*Derivatives and Hedging Activities*

The Company uses derivative instruments that hedge its exposure to various energy commodity and credit market risks to which it is exposed in the ordinary course of its commercial activities. The Company does not engage in speculative derivative trading activities. As such, USPowerGen accounts for its derivative portfolio in accordance with Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended.

As of March 31, 2008, December 31, 2007, and during the three months ended March 31, 2008 and March 31 2007, none of the Company’s derivative positions were eligible for hedge accounting under SFAS No. 133.

As such, all of the Company’s derivative positions were considered economic hedges, which under SFAS No. 133, were accounted for and reported utilizing mark to market accounting. Under this method, the fair value of the derivative portfolio is reflected in the consolidated statements of financial position, with changes in fair value recognized on a current basis in the consolidated statements of operations.

In September, 2006, the FASB issued Statement of Financial Accounting Standards No. 157 — Fair Value Measurements (SFAS No. 157), effective at the beginning of the first fiscal year after November 15, 2007. In February 2008, FASB issued FASB Staff Position No. FAS 157-2 (FSP 157-2), which deferred the effective date of SFAS 157 until fiscal years beginning after November 15, 2008 for non-financial assets and nonfinancial liabilities not typically recognized or disclosed at fair value in the financial statements on a recurring basis. In summary, SFAS No. 157 promulgated the following:


	•	Established a framework for measuring fair value under GAAP and expanded disclosure about fair value measurement, requiring companies to disclose the fair value of their financial instruments according to a fair value hierarchy (i.e., levels 1, 2 and 3 as defined);

	•	Outlined enhanced disclosure regarding fair value measurements in the level 3 category, including a reconciliation of the beginning and ending balances separately for each major category of assets and liabilities accounted for at fair value;

	•	Clarified that fair value should be measured at the exit price, which is the price at which an asset may be sold or a liability may be transferred, regardless of a company’s intent or ability to sell the asset or transfer the liability at the measurement date. Such exit price may or may not equal the transaction price;

	•	Required that credit default risk, including both that of the company and its contractual counter parties, be considered explicitly when measuring the fair value of liabilities and assets, respectively;

	•	Precluded the use of a block discount when measuring instruments traded in an actively quoted market at fair value;

	•	Requires that costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred;

	•	Required that fair value measurements reflect the assumptions market participants would use in pricing an asset or liability, based on the best available information; and

	•	Nullified a portion of the guidance in EITF 02-3. Under EITF 02-3, the transaction price presumption prohibited recognition of a day-one gain or loss at the inception of a derivative contract unless the fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs. Day-one gains or losses on transactions that had been deferred under EITF 02-3 were recognized in the period that valuation inputs became observable or when the contract was performed.

F-7

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)

The provisions of SFAS 157 are applied prospectively, except for the initial effect on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price presumption under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price, and (3) blockage factor discounts. For such items, SFAS No. 157 requires a retrospective transition adjustment, the purpose of which is to restate the adoption date carrying value at the fair value as measured under the newly adopted standard, with any change increase or decrease in carrying value offset by a decrease or increase in the beginning retained earnings balance of the adoption period.

USPowerGen adopted SFAS 157 as of January 1, 2008, applying the standard to financial assets and liabilities typically recognized or disclosed at fair value in the financial statements on a recurring basis, including its derivative instruments, while deferring application to any nonfinancial assets and nonfinancial liabilities not typically recognized or disclosed at fair value in the financial statements on a recurring basis, as permitted by FSP 157-2. Upon adoption of SFAS 157, the Company recorded a transition adjustment with respect to a derivative instrument which had been accounted for under EITF 02-3. The net effect of the transition adjustment resulted in a decrease in the value of the derivative of $7,942 and an offsetting decrease in beginning retained earnings and deferred taxes of $6,076 and $1,866, respectively. As of March 31, 2008, the explicit consideration of credit default risk in the fair value measurements of the Company’s derivative instruments resulted in an increase in fair value of approximately $14,078. Historically, the Company has measured fair value using the mid-point of the bid and ask prices obtained from third party quotation sources. Upon adoption of SFAS 157, the Company has continued to use the bid-ask mid-point as an approximation of exit price, but will, on an ongoing basis, assess the validity of this assumption in each of its fair value measurements in future periods.

On April 30, 2007, the FASB issued FASB Staff Position, No. 39-1, Amendment of FASB Interpretation No. 39 (FIN No. 39), Offsetting of Amounts Related to Certain Contracts — an Interpretation of APB No. 10 and FASB Statement No. 105 (FSP No. 39-1), to indicate that the following fair value amounts could be offset against each other if certain conditions of FIN No. 39 are otherwise met: (a) those recognized for derivative instruments executed with the same counterparty under a master netting arrangement and (b) those recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. In addition, a reporting entity is not precluded from offsetting the derivative instruments if it determines that the amount recognized upon payment or receipt of cash collateral is not a fair value amount. FSP No. 39-1 is effective at the beginning of the first fiscal year after November 15, 2007. The adoption of FSP No. 39-1 requires retrospective application for all financial statements presented as a change in accounting principle. The Company adopted FSP No. 39-1 on January 1, 2008, and elected to continue to recognize the risk management assets and liabilities subject to master netting agreements on a gross basis. The adoption of FSP No. 39-1 has no effect on the Company’s financial position or results of operations.


*(c)*	*Impairment of Goodwill*

In accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS No. 142), the Company tests goodwill for impairment at the reporting unit level at least annually or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. SFAS No. 142 requires a two-step impairment test. Step 1 of the test is a screen used to identify whether a goodwill impairment may exist. In Step 1, an entity compares the fair value of a reporting unit with its carrying amount. If a reporting unit’s carrying amount exceeds its fair value, a goodwill impairment may exist. Step 2 of the test must then be performed to measure the amount of impairment, if any. In Step 2, an entity compares the implied fair value of goodwill with its carrying amount. An impairment loss is measured by the excess of the carrying amount of goodwill over its implied fair value.

F-8

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)

During the quarter ended March 31, 2008, ISO New England (ISO-NE) completed the first Forward Capacity Market (FCM) auction. The auction closed at a market clearing price less than had been projected in the Company’s valuation analyses performed in connection with the allocation of the Combination purchase price as of June 1, 2007. The Company performed an interim goodwill impairment assessment using a discounted cash flow approach, and recognized an impairment charge of $250,067 for the three months ended March 31, 2008 (Note 4).


*(d)*	*Income Taxes*

The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 of FIN 48, on January 1, 2007 (FIN 48). FIN 48 specifies the way public companies are to account for uncertainty in income tax reporting, and prescribes the methodology for recognizing, reversing, and measuring the tax benefits of a tax position taken, or expected to be taken, in a tax return. The Company’s adoption of FIN 48 did not result in any change to the level of our liability for uncertain tax positions, and there was no adjustment to the Company’s retained earnings for the cumulative effect of an accounting change. At January 1, 2008, the total liability for uncertain tax positions recorded in the Company’s balance sheet in accrued other liabilities was $0.0 million, and the Company expects the balance to remain unchanged at December 31, 2008.

Interest and penalties related to tax positions taken in the Company’s tax returns are recorded in interest expense and general and administrative expenses, respectively, in the Company’s consolidated statement of operations. At January 1, 2008, the combined amount of accrued interest and penalties related to tax positions taken on our tax returns was zero. There was no significant change to this amount during the first quarter of 2008.


*(e)*	*Recent Financial Accounting Standards Not Previously Discussed Herein*

In February 2008, the Financial Accounting Standards board (FASB) issued FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (FSP No. 157-2), which permitted delayed application of this statement for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company adopted SFAS No. 157 on January 1, 2008, delaying application for nonfinancial assets and nonfinancial liabilities as permitted. The adoption of SFAS No. 157 resulted in an increase in the Company’s derivative fair value estimate of approximately $6,125. The Company is currently evaluating the impact of the deferred portion of SFAS No. 157 on the Company’s financial position or results of operations.

In March 2008, the FASB issued Statement of Financial Accounting Standard No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133 (SFAS No. 161). This Statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting: (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption, and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company believes its disclosures are largely compliant with the requirements outlined in the standard, and thus does not anticipate its adoption to have a material impact in future periods.

F-9

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)


(3)	Accounting for Derivative and Hedging Activities

The Company is engaged in the generation and sale of electricity, which fundamentally involves the conversion of energy from various fuel sources into salable electrical energy. In connection with these operations, the Company’s financial performance is subject to the impact of fluctuations in the market price of electricity, fuel oil, and natural gas, the market prices of which can, at times, be volatile and move independently of each other. Additionally, the Company’s capital structure included LIBOR-based variable interest rate debt of $2,528,844 and $2,531,689 as of March 31, 2008 and December 31, 2007, respectively. As such, changes in LIBOR will, in the absence of any hedging instruments executed by the Company, have an impact on the Company’s reported cash flows.

The Company defines risk as the exposure it faces to factors that have the potential to negatively impact cash flow and profitability. Such factors, or risks, primarily include the fluctuations in commodity prices (power and fuel) and interest rates. As a component of its risk management strategy, the Company utilizes a variety of contractual arrangements to hedge its exposure to these risks in order to enhance its budgeting and planning activities, and ultimately to reduce volatility from projected cash flow and profitability due to non-controllable fluctuations in spot market prices of both energy-related commodities and debt capital. The Company does not enter into any derivative contracts or any similar arrangements for speculative or trading purposes.


*(a)*	*USPowerGen Derivative Hedge Portfolio*

As of March 31, 2008 and December 31, 2007, the Company’s derivative portfolio did not include any positions designated as accounting hedges. In each of the periods reported herein, changes in the fair value of the Company’s derivatives have been recognized in income on a current basis net of the amounts realized on both derivative contract settlements and amounts recognized in connection with the underlying hedged transactions. As of the end of each period noted above, other comprehensive income (OCI) did not include any unrealized gains or losses related to the Company’s hedging portfolio.

The Company’s derivative portfolio includes a variety of contracts held to manage its exposure to commodity price and interest rate fluctuations. While the Company considers these agreements to be viable hedges of market risks outside its direct control, hedge accounting was not utilized because the contracts did not satisfy the requisite criteria outlined in SFAS No. 133 for such treatment. As such, for the quarters ended March 31, 2008 and 2007, all of the Company’s derivatives have been accounted for and reported as economic hedges. The Company’s economic hedge portfolio can be segregated into two main categories based upon the type of exposure against which it intended to provide hedge protection: (a) hedges of risks associated with the Company’s power generation activities and assets, or operating activity hedges; and (b) hedges against increases in the Company’s cost of capital due to changes in short-term interest rates, or interest rate hedges.

Operating Activity Hedges

Fair Value and Recognized Gains & Losses: The fair value of USPowerGen’s operating activity hedges as of March 31, 2008 was ($12,877). As of December 31, 2007 the fair value of USPowerGen’s operating activity hedges, excluding the impact of the “day-one loss” of $12,638 (discussed in detail below) was ($29,841). For the quarters ended March 31, 2008 and March 31, 2007, unrealized mark-to-market gains/(losses) attributable to changes in the fair value of operating activity hedges totaled $24,905 and ($15,415), respectively, while realized gains on operating activity hedges attributable to settlement payments received totaled $27,851 and $19,849, respectively. As discussed in more detail in the paragraphs below entitled, “Day-One Loss — Capacity Contract,” the unrealized gain attributable to changes in the fair value of operating activity hedges for the quarter ended March 31, 2008 reflected the impact of the retrospective transition

F-10

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)

adjustment required upon adoption of SFAS No. 157. This adjustment reduced the carrying value of the capacity contract by $7,492 as of January 1, 2008, and thus resulted in an increase in the unrealized gain recognized on USPowerGen’s operating activity hedges during the quarter ended March 31, 2008 of $7,492 relative to the amount that would have been recognized under the methodologies employed prior to the adoption of SFAS No. 157.

Day-One Loss-Capacity Contract: On January 10, 2006, the Astoria Generating Company Acquisitions, L.L.C. (an entity formed to facilitate the MDP Acquisition), entered into a financially settled, “floating for fixed” International Swaps and Derivatives Association, Inc. (ISDA) Master Agreement covering unforced capacity (Capacity Agreement) with a major U.S. financial institution. At inception, the Capacity Agreement, a Level 3 derivative instrument, had a three-year term ending on April 30, 2009, a notional quantity of 1,800,000 kW-month of in-city unforced capacity, and a fixed price of $7.07/kW-month. Management determined that the Capacity Agreement had a negative fair value at inception of $12,638.

In accordance with EITF 02-03, the negative fair value at inception was considered a “day-one loss,” which could not be substantiated by comparison to comparable market transactions. As proscribed by EITF 02-03, the day-one loss of ($12,638) was not recognized as a component of income, but was instead deferred, resulting in a difference between the Company’s estimated fair value, and the fair value at which the contract was reported from inception through the year ended December 31, 2007.

During the quarter, USPowerGen adopted SFAS No. 157, which among other things, nullified the guidance promulgated by footnote 3 of EITF Issue No. 02-03 requiring the deferral of day-one losses on certain energy derivative instruments, and changed various aspects of the definition of and methodologies used to measure and report the fair value of assets and liabilities. In accordance with SFAS No. 157, USPowerGen recorded a retrospective transition adjustment to the carrying value of the capacity contract at the adoption date, January 1, 2008. The impact of the change in accounting method, as required by SFAS No. 157, for day-one losses previously deferred under EITF Issue No. 02-03, reduced the carrying value of the contract by $7,942.


	At January 1, 2008
	Capacity
	contract			Deferred			Retained
	value			Taxes			earnings

Net decrease attributable to retrospective transition adjustment upon adoption of SFAS No. 157	$	(7,942	)		(1,866	)		(6,076	)

Beginning with the quarter ended March 31, 2008, and continuing until termination or expiration of the capacity swap contract in April 2009, the reported fair value will equal the Company’s estimated fair value of the contract. For all periods ended prior to January 1, 2008, the reported contract value exceeded the Company’s fair value estimate by the amount of the deferred loss of $12,638. As a result of changes in the in-city New York Unforced Capacity hedge (UCAP) market implemented by the NYISO, the Company believed that the contract counterparty was likely to assert contract re-pricing. The Company’s fair value estimate as of March 31, 2008 included zero value for projected settlements occurring subsequent to April 30, 2008.

Interest Rate Hedges

The LIBOR-based, variable rate debt facilities issued by USPowerGen’s Astoria and EBG subsidiaries expose the Company’s cost of capital to fluctuations in market interest rates. To hedge against the interest rate risk attributable to these facilities, the Company has entered into several derivative contracts, which provide interest rate protection on a portion of its variable rate obligations. The aggregate notional value of the Company’s interest rate hedge portfolio as of March 31, 2008 and December 31, 2007 was $1,715,000 and

F-11

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)

$1,975,000, respectively. The Company’s outstanding LIBOR-based variable interest rate debt facilities as of March 31, 2008 and December 31, 2007 was $2,528,844 and $2,531,689, respectively.

Fair Value and Recognized Gains & Losses: The fair value of the Company’s interest rate hedge portfolio was ($86,662) and ($53,232), as of March 31, 2008, and December 31, 2007, respectively. For the quarters ended March 31, 2008 and March 31, 2007, unrealized mark-to-market (losses) attributable to changes in the fair value of interest rate hedges totaled ($33,430), and ($1,848), respectively, while realized gains/(losses) on interest rate hedges attributable to settlement payments received/(made) totaled ($1,248), and $392, respectively.


*(b)*	*Fair Value of Economic Hedge Derivatives — Summary of Balance Sheet Presentation*

The fair value of the Company’s derivative instruments, including both operating activity hedge derivatives and interest rate hedge derivatives, have been aggregated and then classified in the balance sheets included herein based upon the fair value of anticipated settlements over the next twelve months and then over the remaining tenor of the various contracts. Derivative contracts for which the present value of anticipated settlement over the twelve months following the balance sheet date and/or the remaining tenor is positive have been recognized as current and/or non-current derivative assets, respectively. Derivative contracts for which the present value of anticipated settlement over the twelve months following the balance sheet date and/or the remaining tenor is negative have been recognized as current and/or non-current derivative liabilities respectively.

The following tables summarize the fair value and balance sheet classification of the Company’s derivative portfolio, including both its operating activity and interest rate hedge derivatives, as of March 31, 2008 and 2007:


At March 31, 2008
	Current		Noncurrent		Current			Noncurrent			Total			SFAS No. 157
Hedge Description	asset		asset		liability			liability			fair value			hierarchy

Capacity Agreement	$	6,814		—		—			—			6,814			Level 3
Conversion spread		1,695		90		(7,916	)		(13,560	)		(19,691	)		Level 3

Subtotal — operating activity hedges		8,509		90		(7,916	)		(13,560	)		(12,877	)
Interest rate		—		—		(37,335	)		(49,327	)		(86,662	)		Level 2

Total economic hedges	$	8,509		90		(45,251	)		(62,887	)		(99,539	)


At December 31, 2007
	Current		Noncurrent		Current			Noncurrent			Total			SFAS No. 157
Hedge Description	asset		asset		liability			liability			fair value			hierarchy

Capacity Agreement	$	12,818		6,415		—			—			19,233			Level 3
Conversion spread		—		7,002		(29,130	)		(25,500	)		(47,628	)		Level 3
Power		1,776		—		(1,789	)		—			(13	)		Level 2
Fuel		1,845		—		(3,278	)		—			(1,433	)		Level 2

Subtotal — operating activity hedges		16,439		13,417		(34,197	)		(25,500	)		(29,841	)
Interest rate		—		2		(14,917	)		(38,317	)		(53,232	)		Level 2

Total economic hedges	$	16,439		13,419		(49,114	)		(63,817	)		(83,073	)

F-12

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)


*(c)*	*Realized & Unrealized Gains & Losses on Economic Hedge Derivatives — Statement of Operations Presentation*

The aggregate impact of the operating activity and interest rate hedges, including both the unrealized mark-to-market gains and losses attributable to changes in the fair value, and the realized gains and losses attributable to contract settlements of both the operating activity hedge derivatives and interest rate hedge derivatives, have been aggregated and recognized on a current basis along with the amounts recognized in connection with the hedged transactions. As such, gains and losses on the economic hedge derivatives have been recognized in the statements of operations as follows: capacity, conversion spread, and power hedges have been recognized as a component of revenues; fuel hedges have been recognized as a component of fuel expense; and interest rate hedges have been recognized as a component of interest expense.

The tables below summarize the aggregate gains and losses recognized on the Company’s economic hedges, both realized and unrealized, and the classification of amounts recognized within the statements of operations covering the three months ended March 31, 2008 and March 31, 2007:


Three months ended March 31, 2008
	Operating activity hedges
				Conversion														Total
	Capacity			spread		Power			Fuel						Interest rate			economic
	(Level 3)			(Level 3)		(Level 2)			(Level 2)			Total			(Level 2)			hedges

Realized & unrealized gains (losses)
Change in fair value	$	(12,420	)		27,937		13			1,433			16,963			(33,430	)		(16,467	)
Contract settlements		15,876			13,626		(182	)		(1,469	)		27,851			(1,248	)		26,603

Total gains (losses)	$	3,456			41,563		(169	)		(36	)		44,814			(34,678	)		10,136

Statement of Operations Recognition:
Revenue	$	11,398			41,563		(169	)					52,792			—			52,792
Fuel					—		—			(36	)		(36	)		—			(36	)
Interest expense					—		—			—			—			(34,678	)		(34,678	)

Total gains (losses)		11,398			41,563		(169	)		(36	)		52,756			(34,678	)		18,078
Balance Sheet Recognition
Deferred taxes — SFAS No. 157 implementation		(1,866	)		—		—			—			(1,866	)		—			(1,866	)
Retained earnings — SFAS No. 157 implementation adjustment		(6,076	)		—		—			—			(6,076	)		—			(6,076	)

Total financial statement impact	$	3,456			41,563		(169	)		(36	)		44,814			(34,678	)		10,136


(1)		Of the ($12,420) decrease in the capacity contract fair value, ($7,942) was attributable to the previously discussed transition adjustment recorded as of January 1, 2008, required by SFAS No. 157. For the three-month period ended March 31, 2008, an unrealized loss on the capacity contract of ($4,478) was recognized as a component of revenue in the consolidated statement of operations.

F-13

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)


Three months ended March 31, 2007
	Operating activity hedges
				Conversion						Interest Rate			Total
	Capacity			spread						hedges			economic
	(Level 3)			(Level 3)			Total			(Level 2)			hedges

Realized & unrealized gains (losses)
Change in fair value	$	(4,587	)		(10,828	)		(15,415	)		(1,848	)		(17,263	)
Contract settlements		7,182			12,667			19,849			392			20,241

Total gains (losses)	$	2,595			1,839			4,434			(1,456	)		2,978

Statement of Operations Recognition
Revenue		2,595			1,839			4,434			—			4,434
Fuel		—			—			—			—			—
Interest expense		—			—			—			(1,456	)		(1,456	)

Total gains (losses)	$	2,595			1,839			4,434			(1,456	)		2,978


Three months ended March 31, 2008
	Change in fair value attributable to												Total realized &
	Roll-off			Change in value			Unrealized						unrealized			SFAS No. 157
	prior estimates			remaining tenor			gain/(loss)			Settlements			gains/(losses)			hierarchy

Capacity Agreement	$	(9,042	)		4,564			(4,478	)		15,876			11,398			Level 3
Conversion spread		43,459			(15,522	)		27,937			13,626			41,563			Level 3
Power		13			—			13			(182	)		(169	)		Level 2
Fuel		1,433			—			1,433			(1,469	)		(36	)		Level 2

Total operating hedges		35,863			(10,958	)		24,905			27,851			52,756
Interest rate		1,273			(34,703	)		(33,430	)		(1,248	)		(34,678	)		Level 2

Total economic hedges	$	37,136			(45,661	)		(8,525	)		26,603			18,078


Three months ended March 31, 2007
												Total
	Change in fair value attributable to											realized &
	Roll-off			Change in value			Unrealized					unrealized			SFAS No. 157
	prior estimates			remaining tenor			gain/(loss)			Settlements		gains/(losses)			hierarchy

Capacity Agreement	$	(4,274	)		(313	)		(4,587	)		7,182		2,595			Level 3
Conversion spread		(8,484	)		(2,344	)		(10,828	)		12,667		1,839			Level 3

Total operating hedges		(12,758	)		(2,657	)		(15,415	)		19,849		4,434
Interest rate		(388	)		(1,460	)		(1,848	)		392		(1,456	)		Level 2

Total economic hedges	$	(13,146	)		(4,117	)		(17,263	)		20,241		2,978

In accordance with SFAS No. 157, the following table provides disclosure information regarding the estimated fair value of USPowerGen’s Level 3 derivative instruments, the impact of such estimates on USPowerGen’s earnings for the quarter ended March 31, 2008, the reconciliation of changes in the reported fair value of USPowerGen’s Level 3 derivative instruments as of March 31, 2008 to the amounts recognized in USPowerGen’s

F-14

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)

earnings during the three months ended March 31, 2008, separately presenting changes during the period attributable to the following:


	•	Total realized and unrealized gains or losses, in aggregate and segregated between derivatives recognized as a component of revenues, operating costs, non-operating items, such as interest expense, and those amounts not recognized currently as a component of USPowerGen’s earnings;

	•	The net impact of derivative instruments purchased, sold, settlements and expirations;

	•	Transfers in or out of Level 3; and

	•	The portion of total gains or losses attributable to the change in unrealized gains or losses of derivative instruments still held at the reporting date in aggregate and segregated between derivatives recognized as a component of revenues, operating costs, non-operating items, such as interest expense, and those amounts not recognized currently as a component of USPowerGen’s earnings:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)


	Total

Balance — December 31, 2007	$	(28,395	)
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		52,962
Included in other comprehensive income		—
Purchases, issuances, and settlements (net)		(29,502	)
Transfers in and/or out of Level 3		—
Retrospective transition adjustment upon adoption of SFAS No. 157		(7,942	)

Balance — March 31, 2008		(12,877	)

The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	23,459


(4)	Impairment of Goodwill

On February 8, 2008, ISO New England (ISO-NE) completed the first FCM auction for the Capacity Commitment Period of June 1, 2010 to May 31, 2011. The market cleared at the floor price of $4.50/kW month, with an excess of 2,047 MWs. The revenue will be prorated among all of the MWs. All of the Company’s available capacity was sold along with and an additional 31.3 MW of winter only capacity.

With the initial FCM Auction clearing at the floor price of $4.50/kW-month, the Company believes that future revenues derived from the sale of its Boston capacity will likely fall short of amounts previously projected used to calculate the initial goodwill. The Company has determined that the initial FCM Auction represents a trigger event, as defined under Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS No. 142), requiring an interim assessment of goodwill impairment. The Company completed an assessment of goodwill using a discounted cash flow approach for impairment and concluded that the Company’s goodwill was impaired at March 31, 2008. Accordingly, the Company recorded a goodwill impairment charge of $250,067 during the three months ended March 31, 2008.

F-15

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)


(5)	Segment Reporting

The Company manages and evaluates its business on the basis of the geographic regions, New York and Boston, in which its wholesale power generation facilities operate. These segments have distinct operating results and management structures under which senior management evaluate their performance. The following tables summarize the results of operations and financial position of the Company’s segments along with its corporate expenses and any eliminating items. All revenues are from external customers and there were no significant corporate allocations or intercompany transactions.


	Statement of Consolidated Operations for the three months ended
	March 31, 2008
	New York			Boston			Corporate			Eliminations		USPowerGen
Revenues	$	160,758			328,556			—			—		489,314
Operating expenses:
Fuel		93,683			240,232			—			—		333,915
Operations and maintenance		16,636			13,020			—			—		29,656
General and administrative		6,526			8,667			(591	)		—		14,602
Taxes, other than income		7,245			5,231			125					12,601
Depreciation		7,213			23,190			—			—		30,403
Impairment of goodwill		—			250,067								250,067

Operating income (loss)		29,455			(211,851	)		466			—		(181,930	)
Other (income) expense:
Interest expense, net		24,042			62,936			53			—		87,031
Other (income) expense, net		(1	)		(714	)		—			—		(715	)

Net income (loss) before income tax		5,414			(274,073	)		413			—		(268,246	)
Income tax expense (benefit)		330			(4,696	)		90			—		(4,276	)

Net income (loss)	$	5,084			(269,377	)		323			—		(263,970	)


	Select Balance Sheet information as of March 31, 2008
	New York		Boston		Corporate		Eliminations			USPowerGen
Property, plant and equipment, net		888,953		2,606,598		675		—			3,496,226
Goodwill		21,679		557,347		—		—			579,026
Total assets	$	1,126,720		3,669,109		69,088		(149,699	)		4,715,218
Long term debt		626,400		1,860,944		—		—			2,487,344
Total liabilities		761,883		2,840,649		73,924		(98,042	)		3,578,414
Capital expenditures		7,859		5,227		675		—			13,761


(6)	Subsequent Events

Subsequent to March 31, 2008 and through August 12, 2008, the following occurred:


*(a)*	*Natural Gas Supply Contract — (Distrigas Agreement)*

The Company executed (i) a Settlement and Release Agreement entered into as of April 18, 2008 to settle all the claims, (ii) an Amended and Restated Firm Gas Sales and Purchase Agreement (ARGA) effective April 11, 2008 and (iii) a Non-Firm Gas Sales and Purchase Agreement.


i)	*Settlement and Release Agreement*

As of December 31, 2007, the Company was in litigation with Distrigas in Suffolk County, Massachusetts, Superior Court with respect to two 20-year fuel agreements. Under the original agreements,

F-16

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

March 31, 2008

(Dollars in thousands, except as otherwise indicated)

the Company was required to purchase at least 1,400,000 MMBtu of gas per week from Distrigas. Distrigas alleged that the Company was liable for approximately $40,100 in liquidated damages, unpaid gas invoices and late payment fees as of December 31, 2007. The Company has agreed to pay $18,175 plus accrued interest of $91 in full satisfaction of the amounts past due for liquidated damages and disputed gas invoices. The Company had $37,458, and $29,900 accrued for this purpose as of May 31, 2007 and December 31, 2006, respectively. The Company recorded an adjustment to reduce the accrual to the agreed upon settlement and reflected the adjustment as an increase to goodwill as of June 1, 2007, the date of the Combination.


*ii)*	*Amended and Restated Firm Gas Sales and Purchase Agreement*

The ARGA amends and replaces the existing Firm Gas and Purchase Agreement. The terms of the new agreement are as follows:


	•	Term is extended to December 3, 2027.

	•	Allows the Company to purchase firm weekly quantities (FWQs) at a price determined by the TETCO M3 pricing point, with additional gas volumes priced at the Algonquin City Gate for the first five years of the agreement. The price reverts to the Algonquin City Gate less $0.20 per MMBtu for the remaining term of the contract. FWQs are adjusted on a monthly basis to reflect seasonal operations and are subject to certain provisions that allow the Company to reduce FWQ’s up to 350,000 MMBtu per week with proper notification.

	•	The Company also has a weekly balancing tolerance of up to plus or minus 10,000 MMBtu without incurring liquidated damages.

	•	The Company provided a letter of credit in the amount of $50,000 subject to an adjustment five months after the execution of the ARGA based on the Company’s credit rating, and terms of the existing loan documents in any case the amount of the letter of credit is not to exceed $75,000 and not to be less than $35,000.


*iii)*	*Non-Firm Gas Sales and Purchase Agreement*

The Company and Distrigas entered into a Non-Firm Gas Agreement, which provides Distrigas with the right but not the obligation to supply up to 100% of the natural gas required at Mystic 7. This agreement also contains certain option rights for Distrigas that had been in the previous gas agreement.


*(b)*	*Energy Management Agreement Termination*

Effective April 1, 2008, the Energy Management Agreement under which Sempra had provided various energy management services to EBG was terminated by mutual agreement of the parties. Prospectively, the Company will provide the energy management services related to physically settled power sales transactions and physically settled fuel purchase transactions. Financially settled transactions previously executed in connection with the Company’s economic hedging activities have been largely replaced by the conversion spread derivative hedge contract executed by EBG and Sempra in December 2007.


*(c)*	*New York Conversion Spread Derivative Contract*

On June 2, 2008, Astoria executed a new conversion spread contract. The contract is a floating for fixed power — natural gas swap (Zone J — Transco zone 6), with a notional quantity of 300 - 600 MW during the summer months, June through September, of both 2008 and 2009. The contract is an economic hedge derivative, which will be classified as a Level 2 derivative instrument under the classification hierarchy promulgated under SFAS No. 157, and will not be accounted for using cash flow hedge accounting as defined by, and in accordance with SFAS No. 133, as amended. The contract had an inception value of zero, but will be included in and will be marked to market along with the Company’s existing conversion spread derivative portfolio as of June 30, 2008.

F-17

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

US Power Generating Company and Subsidiaries:

We have audited the accompanying consolidated balance sheets of US Power Generating Company and subsidiaries as of December 31, 2007 (Successor) and December 31, 2006 (Successor), and the related consolidated statements of operations, stockholders’ and members’ equity and comprehensive income, and cash flows for the year ended December 31, 2007 (Successor), the period February 24, 2006 through December 31, 2006 (Successor), the combined statements of operations, owners’ net investment and comprehensive income, and cash flows for the period January 1, 2006 through February 23, 2006 (Predecessor) and for the year ended December 31, 2005 (Predecessor). These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and 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 consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of US Power Generating Company and subsidiaries as of December 31, 2007 (Successor) and December 31, 2006 (Successor), and the results of their operations and their cash flows for the year ended December 31, 2007 (Successor), the period February 24, 2006 through December 31, 2006 (Successor), the period January 1, 2006 through February 23, 2006 (Predecessor) and for the year ended December 31, 2005 (Predecessor), in conformity with U.S. generally accepted accounting principles.

As discussed in note 9 to the consolidated and combined financial statements, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment, on January 1, 2006. Additionally, as discussed in note 8 to the consolidated and combined financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132 (R) on December 31, 2006.

/s/ KPMG LLP

New York, New York

August 12, 2008

F-18

US Power Generating Company and Subsidiaries

Consolidated Balance Sheets

(Dollars in thousands, except per share data)


	Successor
	US Power		Astoria Generating
	Generating		Company
	Company		Holdings, LLC
	December 31,		December 31,
	2007		2006

ASSETS
Current assets:
Cash and cash equivalents	$	34,409		44,507
Restricted cash		100,856		—
Accounts receivable		153,785		54,084
Derivative assets		16,439		6,730
Fuel inventory, materials and supplies		35,579		14,383
Deferred income taxes		28,055		—
Prepaid expenses and other current assets		22,677		2,187

Total current assets		391,800		121,891
Property, plant, and equipment, net		3,515,857		888,314
Other assets:
Goodwill		829,093		21,679
Other intangibles, net		80,498		12,588
Emissions allowances, net		131,784		24,040
Derivative assets		13,419		2,028
Deferred financing costs		22,633		26,707
Other long-term assets		19,382		7,328

Total assets	$	5,004,466		1,104,575


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	95,704		29,074
Fuel payable		94,859		19,236
Accrued transaction costs		32,400		—
Other current liabilities		8,962		2,367
Derivative liabilities		49,114		—
Revolving line of credit		29,500		—
Current portion of long-term debt		15,600		4,300

Total current liabilities		326,139		54,977
Other liabilities:
Derivative liabilities		63,817		2,828
Pension and postretirement obligations		18,964		18,070
Deferred income taxes		686,234		118
Asset retirement obligations		8,956		6,267
Other long-term liabilities		4,771		8,030
Long-term debt		2,486,589		687,475

Total liabilities		3,595,470		777,765
Stockholders’ equity:
Class A common stock, $0.00001 par value; non-voting; 500,000,000 shares authorized; 41,069,600 issued and outstanding		—		—
Class B common stock, $0.00001 par value; voting; 50,000,000 shares authorized; 35,539,000 issued and 35,339,290 outstanding		—		—
Preferred stock, $0.0001 par value; voting rights may be designated upon issuance; 1,000,000 shares authorized; no shares issued and outstanding		—		—
Stockholders’ equity		1,408,996		326,810

Total liabilities and stockholders’ equity	$	5,004,466		1,104,575

See accompanying notes to these consolidated financial statements.

F-19

US Power Generating Company and Subsidiaries

Consolidated Statements of Operations

(Amounts in thousands, except earnings per share data)


	Successor					Predecessor
				Feb 24, 2006		Jan 1, 2006
	Year ended			through		through		Year ended
	December 31,			December 31,		Feb 23,		December 31,
	2007			2006		2006		2005

Revenues	$	1,182,719			480,511		104,721		1,014,045
Operating expenses:
Fuel		778,986			258,949		50,686		555,227
Operations and maintenance		106,208			63,143		21,731		94,005
General and administrative		64,395			26,016		1,350		6,628
Taxes, other than income		41,571			35,826		5,696		33,782
Depreciation		82,285			22,923		5,897		38,816

Total operating expenses		1,073,445			406,857		85,360		728,458

Operating income		109,274			73,654		19,361		285,587
Other expense (income):
Interest expense (income), net		203,475			55,199		164		(2,135	)
Other expense, net		3,944			881		—		(1	)

(Loss) income before income tax		(98,145	)		17,574		19,197		287,723
Income tax (benefit) expense		(35,879	)		651		748		11,530

Net (loss) income	$	(62,266	)		16,923		18,449		276,193

Basic and diluted EPS	$	(0.15	)		0.07		0.07		1.10
Weighted average shares outstanding		423,223			252,231		252,231		252,231

See accompanying notes to these consolidated financial statements.

F-20

US Power Generating Company and Subsidiaries

Consolidated Statements of Stockholders’ Equity, Members’ Equity, Owners’
Net Investment, and Comprehensive Income
(Dollars in thousands)


					Total
	Owners’		Retained		owners’		Comprehensive
	investment		earnings		net investment		income

Predecessor:
Balance, December 31, 2004	$	1,281,281		431,726		1,713,007		—
Non-cash contribution of general and administrative expenses		4,400		—		4,400		—
Non-cash federal income tax contribution		25		—		25		—
Non-cash state income tax contribution		13,074		—		13,074		—
Net income		—		276,193		276,193		276,193

Balance, December 31, 2005		1,298,780		707,919		2,006,699		276,193

Non-cash contribution of general and administrative expenses		651		—		651
Net income		—		18,449		18,449		18,449

Balance, February 23, 2006	$	1,299,431		726,368		2,025,799		18,449


																								Accumulated			Total			Total
															Additional						Stockholders’/			other			stockholders’/			comprehensive
	Class A				Class B					Units					paid-in			Retained			members’			comprehensive			members’			income
	Shares		Amount		Shares			Amount		Shares			Amount		capital			earnings			equity			income			equity			(loss)

Successor:
Capital Contribution		—	$	—		—		$	—		31,441		$	—	$	314,400		$	—		$	314,400		$	—		$	314,400		$	—
Impact upon adoption of SFAS No. 158, net of tax of $87		—		—		—			—		—			—		—			—			—			2,392			2,392			—
Distributions to members		—		—		—			—		—			—		—			(7,182	)		(7,182	)		—			(7,182	)		—
Net income		—		—		—			—		—			—		—			16,923			16,923			—			16,923			16,923
Share-based compensation		—		—		—			—		—			—		277			—			277			—			277

Balance, December 31, 2006		—	$	—		—		$	—		31,441		$	—	$	314,677		$	9,741		$	324,418		$	2,392		$	326,810		$	16,923

Defined benefit plans, net of tax of $1,349		—		—		—			—		—			—		—			—			—			(840	)		(840	)		(840	)
Distribution to members		—		—		—			—		—			—		—			(5,425	)		(5,425	)		—			(5,425	)		—
Exchange of Units for stock in connection with Combination		—		—		35,539			—		(31,441	)		—		—			—			—			—			—			—
Issuance of stock in connection with the Combination		41,070		—		—			—		—			—		1,151,772			—			1,151,772			—			1,151,772			—
Share-based compensation		—		—		(200	)		—		—			—		(969	)		—			(969	)		—			(969	)		—
Other		—		—		—			—		—			—		—			—			—			(86	)		(86	)		(86	)
Net loss		—		—		—			—		—			—		—			(62,266	)		(62,266	)		—			(62,266	)		(62,266	)

Balance, December 31, 2007		41,070	$	—		35,339		$	—		—		$	—	$	1,465,480		$	(57,950	)	$	1,407,530		$	1,466		$	1,408,996		$	(63,192	)

See accompanying notes to these consolidated financial statements

F-21

US Power Generating Company and Subsidiaries

Consolidated Statements of Cash Flows
(Dollars in thousands)


	Successor						Predecessor
				Feb 24, 2006			Jan 1, 2006
	Year ended			through			through			Year ended
	December 31,			December 31,			Feb 23,			December 31,
	2007			2006			2006			2005

Cash flows from operating activities:
Net (loss) income	$	(62,266	)		16,923			18,449			276,193
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation		82,285			22,923			5,897			38,816
Amortization of emissions allowances		4,666			6,148			512			4,162
Amortization of contractual rights and obligations, net		6,713			5,571			1,855			(1,125	)
Amortization of deferred financing costs		4,074			8,052			—			—
Amortization of debt premium		(2,555	)		—			—			—
Accrued interest expense on Mezzanine Facility		23,632			—			—			—
Write-down of emissions allowances		4,964			—			—			—
Accretion of asset retirement obligations		466			312			26			—
Loss on disposal of assets		3,806			1,344			—			—
Net unrealized loss (gain) on derivative contracts		104,687			(3,521	)		(21,895	)		(83,988	)
Non-cash contribution of general and administrative expense		—			—			651			4,400
Non-cash federal income tax contribution		—			—			—			25
Other		—			—			112			4,324
Non-cash Share-based compensation		5,031			277			—			—
Changes in assets and liabilities net of acquisition and merger effects:
Restricted cash		13,228			—			—			—
Accounts receivable		(50,213	)		(13,129	)		15,392			(9,224	)
Fuel inventory, materials and supplies		1,497			24,121			740			(10,413	)
Prepaid expenses and other current assets		(5,553	)		17,381			7,163			(4,611	)
Other long-term assets		2,266			—			1,778			(889	)
Accounts payable and accrued expenses		43,799			17,076			(2,824	)		5,362
Fuel payable		5,441			19,236			—			—
Other current liabilities		226			(934	)		2,202			(5,690	)
Income taxes payable		2,670			356			2,077			10,016
Payable to affiliate, net		—			—			(5,208	)		(39	)
Other taxes payable		—			—			(1,204	)		—
Deferred income taxes		(39,572	)		14			(1,310	)		1,489
Pension and postretirement obligations		548			4,799			610			—
Asset retirement obligations		(957	)		(739	)		—			—
Other long-term liabilities		(7,266	)		(6,260	)		(308	)		1,975

Net cash provided by operating activities		141,617			119,950			24,715			230,783

Cash flows from investing activities:
Capital expenditures		(49,035	)		(39,415	)		(5,474	)		(17,639	)
Cash paid for merger related costs, net of cash acquired		(48,599	)		—			—			—
Acquisitions		—			(1,001,893	)		—			—
Proceeds from sales of assets		—			182			—			—
Proceeds from sales of emissions allowances		3,619			1,450			—			—

Net cash used in investing activities		(94,015	)		(1,039,676	)		(5,474	)		(17,639	)

Cash flows from financing activities:
Contributions from members		—			314,400			—			—
Receivable from affiliates, net		—			—			(18,779	)		(214,688	)
Distributions to members		(5,425	)		(7,182	)		—			—
Proceeds from long-term debt		—			865,000			—			—
Payments of long-term debt		(52,775	)		(173,225	)		—			—
Proceeds from revolving line of credit		40,500			—			—			—
Payments of revolving line of credit		(37,000	)		—			—			—
Payment of deferred financing costs		—			(34,760	)		—			—
Cash paid for Series B Units		(3,000	)		—			—			—

Net cash (used) in/provided by financing activities		(57,700	)		964,233			(18,779	)		(214,688	)

Net change in cash and cash equivalents		(10,098	)		44,507			462			(1,544	)
Cash and cash equivalents at beginning of period		44,507			—			15			1,559

Cash and cash equivalents at end of period	$	34,409			44,507			477			15

Supplemental cash flow information:
Cash paid for interest	$	152,150			55,212			—			—
Cash paid for income taxes		1,607			710			—			—

See accompanying notes to these consolidated financial statements.

F-22

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2007

(Dollars in thousands)


(1)	Nature of Business

US Power Generating Company (USPowerGen or the Company), is a wholesale power generation company that owns and operates power generation facilities in the New York City and Boston metropolitan areas. As of December 31, 2007, the Company has a total portfolio of 58 generation units at six power generation facilities with generation capacity of approximately 5,223 megawatts (MWs).

On February 28, 2007, EBG Holdings LLC (EBG) and Astoria Generating Company Holdings, L.L.C. (Astoria) announced that they had entered into a definitive merger agreement, under which the companies would be combined (the Combination). Under the merger agreement, EBG and Astoria would combine to form USPowerGen, a Delaware corporation. The Combination was completed on June 1, 2007. In order to effect the Combination, USPowerGen and its two subsidiaries EBG Merger LLC (EBG Merger) and Astoria Merger LLC (Astoria Merger) were formed. Immediately prior to the Combination, each of the members of Astoria exchanged their Astoria units for units of New Astoria Generating Company Holdings, L.L.C. (New Astoria), a shareholder of USPowerGen; and each of the members of EBG exchanged their EBG units for shares in USPowerGen. Astoria then merged with Astoria Merger and EBG merged with EBG Merger. Both Astoria Merger and EBG Merger ceased to exist thereby leaving Astoria and EBG as direct subsidiary companies of USPowerGen.


(2)	Summary of Significant Accounting Policies


*(a)*	*Principles of Consolidation and Basis of Presentation*

The accompanying consolidated financial statements of USPowerGen and its wholly-owned subsidiaries have been prepared in accordance with U.S. generally accepted accounting principles (GAAP). These financial statements are presented, on a consolidated basis, and include Astoria and its subsidiaries and EBG and its subsidiaries.

The financial statements of USPowerGen, as presented, cover a period during which two significant transactions occurred. On June 1, 2007, USPowerGen was formed in connection with the combination of Astoria and EBG, and Astoria was determined to be the accounting acquirer in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS No. 141) (Note 3). On February 23, 2006, Astoria acquired Astoria Generating Company L.P. and Orion Power Operating Services Astoria, Inc. (the MDP Acquisition) from Orion Power Holdings, Inc., a wholly-owned subsidiary of Reliant Energy, Inc. (Reliant) (Note 3). The financial statements as of and for the year ended December 31, 2007 reflect the consolidation of USPowerGen, Astoria, EBG and their subsidiaries. These financial statements along with the consolidated financial statements of Astoria as of December 31, 2006 and for the period of February 24, 2006 through December 31, 2006 appear under the caption “Successor.” The “Predecessor” financial statements consist of the combined financial statements of Astoria Generating Company, L.P. and Orion Power Operating Services Astoria, Inc. (Astoria Orion) for the period of January 1, 2006 through February 23, 2006, and the year ended December 31, 2005.

The MDP Acquisition of Astoria Orion was accounted for pursuant to SFAS No. 141, with acquired assets and liabilities recorded at their estimated fair market values. The fair value adjustments primarily related to property, plant, and equipment, and intangible assets. Also pursuant to SFAS No. 141, the Combination was accounted for by the Company as a business combination with acquired assets and liabilities recorded at their estimated fair market values. The fair value adjustments related to the Combination primarily include adjustments to property, plant, and equipment; goodwill and intangible assets; and the recording of a deferred tax liability (Note 3).

All significant intercompany transactions and balances have been eliminated.

F-23

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


*(b)*	*Use of Estimates and Market Risks*

The preparation of consolidated financial statements in conformity with GAAP requires management to make a number of estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The Company’s critical accounting estimates include:


	•	Mark-to-market (MTM) valuations of derivative contracts;

	•	Determination of the Company’s asset retirement obligations;

	•	Estimated future cash flows in determining the valuation of long-lived assets, goodwill, and intangible assets and related impairment testing;

	•	Estimating the expected rate of return on plan assets, rate of compensation increases and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities;

	•	Estimating losses to be recorded for contingent liabilities; and

	•	Estimating the provision for income taxes.

The Company is subject to risks associated with, but not limited to, price movements of energy commodities and credit associated with its commercial activities. The Company is subject to risks relating to the reliability of the systems, procedures, and other infrastructure necessary to operate the business. The Company is also subject to risks relating to changes in laws and regulations; the outcome of material pending litigation (Note 13); the availability of adequate fuel supplies and transportation; weather conditions; financial market conditions and access to capital; the creditworthiness or financial distress of its counterparties; and the successful operation of deregulated power markets.


*(c)*	*Revenue Recognition*

The Company recognizes revenue from the sale of electricity when earned and collection is reasonably assured. The Company recognizes revenue when electric power is delivered to a customer pursuant to contractual commitments that specify volume, price, and delivery requirements. Some sales of electricity are based on economic dispatch or “as-ordered” by an Independent System Operator (ISO), based on member participation agreements, but without an underlying contractual commitment. ISO revenues and revenues from sales of electricity based on economic dispatch are recorded on the basis of megawatt hours (MWh) delivered, at the relevant day-ahead or real-time prices. When a long-term electric power agreement conveys to the buyer of the electric power the use of the generating capacity of the Company’s plants, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power. None of USPowerGen’s capacity arrangements qualify as leases. Capacity revenues are recognized when contractually earned on a straight-line basis in accordance with Emerging Issues Task Force (EITF) 91-6, Revenue Recognition of Long-Term Power Sales Contracts, and consist of revenues received from third parties at either the market or negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.

F-24

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


*(d)*	*Customer Concentration*

In each of the reporting periods, the Company earned a significant portion of its operating revenue from three customers. The revenue as a percentage of the Company’s total revenues related to these customers is as follows:


	Successor						Predecessor
				Feb 24, 2006
	Year ended			through			Jan 1, 2006			Year ended
	December 31,			December 31,			through			December 31,
	2007			2006			Feb 23, 2006			2005

NYISO		46.4	%		95.7	%		64.0	%		91.0	%
Sempra Energy		57.5	%		—	%		—	%		—	%
Morgan Stanley Financial		2.0	%		—	%		35.0	%		—	%

The New York ISO (NYISO) is an independent not-for-profit organization regulated by the Federal Energy Regulatory Commission (FERC). Among other things, NYISO administers a market to facilitate fair and open competition in the wholesale power market and creates an electricity commodity market in which power is purchased and sold on the basis of competitive bidding. As part of its market administration role, NYISO sets out creditworthiness requirements for all market participants. The NYISO credit policy sets a minimum investment grade debt rating of BBB- and Baa3 as determined by Standard & Poors (S&P) and Moody’s Investor Service (Moody’s), respectively. All market participants not meeting the requirements for unsecured credit must provide collateral in an amount equal to or greater than its operating requirements, which measure the economic value of a participants market activities. Finally, NYISO places an overall cap on credit exposure to unsecured credit that limits the amount outstanding from any one participant to 20% of its total accounts receivable.

The Company is party to an energy management agreement with Sempra Energy Trading Corporation (Sempra) which is guaranteed by Sempra’s parent, Sempra Energy under which the Company’s Boston facilities sell 100% of its electric energy, capacity, and ancillary services (Note 13). As a result, the Company has significant customer concentration and counterparty risk to Sempra and its parent. The Company monitors the creditworthiness of Sempra in order to ensure collection is probable. As of December 31, 2007, Sempra’s parent carried an investment grade credit rating of Baa1 by Moody’s and BBB+ by S&P. Subsequent to December 31, 2007 this agreement was terminated by mutual agreement of the parties (Note 13).


*(e)*	*Credit Risk*

Cash accounts, accounts receivable, and derivative instruments are subject to credit risk. Cash accounts are generally held by highly rated, federally insured banks. Accounts receivable and derivative instruments are concentrated within entities engaged in the energy industry, certain financial institutions, and ISOs. The credit worthiness of ISOs is based on the collective credit worthiness of its market participants. All market participants must meet stringent reporting and ratings requirements and each is required to allocate unsecured credit and/or provide collateral in an amount sufficient to secure monthly operating requirements. In lieu of collateral, market participants of the ISO may also elect to prepay amounts owed. Derivative counterparties are typically large financial institutions with high investment grade ratings.

USPowerGen has a credit policy that governs management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The Company’s policy is to only enter into transactions with counterparties that have investment grade credit ratings. The financial condition of counterparties is reviewed periodically by management. USPowerGen tries to mitigate credit risk by entering into contracts that permit netting and allow for termination upon the occurrence of certain events of default.

F-25

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

The Company believes that its credit policy allows it to mitigate credit risk resulting from industry concentrations. However, economic, industry, or other conditions could impact its statement of financial position or results of operations either positively or negatively.


*(f)*	*Concentration of Labor Subject to Collective Bargaining Agreements*

As of December 31, 2007, approximately 67.4% of the Company’s employees were subject to collective bargaining agreements.


*(g)*	*Derivatives and Hedging Activities*

The Company accounts for its derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended.

The Company uses derivative contracts that provide for settlement in cash or by delivery of commodities for its hedging activity. As of December 31, 2007, the Company’s derivatives were not elected or did not qualify as hedges under SFAS No. 133. Therefore, the Company’s derivatives were accounted under MTM accounting. The fair values of derivative activities are determined by: (a) prices actively quoted; (b) prices provided by other external sources; or (c) prices based on models and other valuation methods.


*(h)*	*Cash and Cash Equivalents*

Cash and Cash Equivalents consist of demand deposits and funds invested in highly liquid, short-term investments with original maturities of three months or less.


*(i)*	*Restricted Cash*

USPowerGen is required to maintain cash balances that are restricted by provisions of certain long-term financing agreements (Note 5). These funds are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as operating costs, capital expenditures, and debt service. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value.


*(j)*	*Fuel Inventory, and Materials and Supplies*

The Company has entered into a fuel management agreement with Sequent Energy Management (Sequent) (Note 13). This agreement is a full requirements fuel supply agreement for Astoria’s entire generating fleet. Under the agreement, Astoria purchases fuel from Sequent on an as-burned basis and, as such, no fuel inventory is owned at Astoria’s facilities. Fuel inventory at EBG is valued at the weighted average cost of the stored oil. Fuel inventory of $11,649 at December 31, 2007 is valued on a weighted average cost basis. The Company had no oil inventory as of December 31, 2006.

Materials and supplies, which consisted of maintenance and repair inventory, of $23,930 and $14,383 at December 31, 2007 and December 31, 2006, respectively, are valued at the lower of average cost or market and are expensed when they are used for repairs, maintenance, or capital projects.

F-26

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


*(k)*	*Property, Plant, and Equipment, and Depreciation Expense*

Property, plant, and equipment is recorded at cost. Cost of property, plant, and equipment includes Astoria’s and EBG’s purchase price allocation based on the asset’s fair market value as of the MDP Acquisition and Combination, respectively (Note 3).

The Company expenses all repair and maintenance costs as incurred, including planned annual maintenance. Depreciation is computed using the straight-line method over the estimated useful lives commencing when assets, or major components thereof, are available for their intended use or acquired, as appropriate. Leasehold improvements are amortized on a straight-line method over the shorter of the term of the lease or the useful life of the related asset. Useful lives range from three to thirty-six years.

Property, plant, and equipment includes the following:


	Estimated		Successor
	useful lives		December 31,			December 31,
	(in years)		2007			2006

Land		—	$	94,208			74,368
Land improvements		3-7		37,082			37,082
Power generation facilities		30-36		3,447,585			765,648
Construction in progress		—		38,431			31,563
Leasehold improvements		5-10		3,759			2,576

Total property, plant, and equipment				3,621,065			911,237
Accumulated depreciation				(105,208	)		(22,923	)

Net property, plant, and equipment			$	3,515,857			888,314

Depreciation expense was $82,285, $22,923, $5,897 and $38,816 for the periods ending December 31, 2007, December 31, 2006, February 23, 2006 and December 31, 2005, respectively.


*(l)*	*Capitalized Interest and Project Development Costs*

USPowerGen expenses development costs during the preliminary stages of a project. Once a project is deemed to be commercially viable, development costs are capitalized. Indications of commercial viability include approval by the Company’s board of directors, formal project plans, and significant future commitments of the Company. When a project is available for its intended use, the Company discontinues capitalization of costs and reclassifies the project costs to property, plant, and equipment. Project costs are then depreciated over the estimated useful life of the assets. Should the Company decide to abandon or discontinue development, previously capitalized costs are charged to expense in the period that such determination is made.

Additionally, to the extent material, the Company capitalizes interest on borrowed funds used to finance capital projects pursuant to Statement of Financial Accounting Standards No. 34, Capitalization of Interest Costs (SFAS No. 34). Capitalization is discontinued when a project is ready for its intended use or when construction ceases or is terminated. Capitalized interest was $1,918 for the year ended December 31, 2007. No interest was capitalized in the other periods presented.


*(m)*	*Major Maintenance Activities*

The Company accounts for major maintenance activities in accordance with Financial Accounting Standards Board (FASB) Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance

F-27

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Activities (FSP AUG). Pursuant to FSP AUG, the Company does not accrue in advance for planned major maintenance activities, but rather expenses maintenance costs as incurred.

The Company has two long-term service agreements (LTSAs) with Mitsubishi Power Systems Americas, Inc. (MPS) to provide all major maintenance services, including refurbishment of spare parts for gas turbine generators and related equipment at certain of its Boston facilities (the Covered Units). Under the LTSAs, MPS receives a fixed fee for monitoring the Covered Units and a variable fee based on number of equivalent operating hours incurred by each of the Covered Units. The Company charges to expense the fixed fee monthly when it is incurred. However, the variable fee paid monthly is recorded as a prepaid expense and subsequently charged to expense when MPS performs the major maintenance on the Covered Units. Prepaid expense related to the LTSAs was $13,602 at December 31, 2007 and the total expenses related to the LTSAs for the seven months ended December 31, 2007 were $9,632.


*(n)*	*Asset Impairments*

In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144), the Company evaluates long-lived assets when changes in events or circumstances indicate potential for impairment. Impairment for assets held for use is evaluated based upon a comparison of the carrying value and the estimated total future undiscounted cash flows of the asset. If the carrying amount of an asset exceeds its estimated total future undiscounted cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. The Company recognized an impairment loss of $4,964 related to emissions allowances for the year ended December 31, 2007 that is recorded in fuel expense (Note 7).


*(o)*	*Asset Retirement Obligations*

The Company accounts for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), which requires an entity to recognize the fair value of a liability for an Asset Retirement Obligation (ARO) in the period in which it is incurred if a reasonable estimate of fair value can be made. Upon the initial recognition of an ARO, SFAS No. 143 requires an entity to capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its present value each period, while the capitalized cost is depreciated over the useful life of the related asset. AROs associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

The Company’s AROs are associated primarily with hazardous substance removal and fuel storage tanks retirement.

F-28

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

The following table represents the balances of the AROs for the periods presented for the Company and its Predecessors:


	Total

Predecessor:
Balance at December 31, 2005	$	1,135
Accretion		26

Balance at February 23, 2006		1,161
Successor:
Additions — purchase accounting adjustments		5,533
Reductions — asbestos abatement		(739	)
Accretion		312

Balance at December 31, 2006		6,267
Additions — from business combination		3,180
Reductions — adjustments to estimate		(957	)
Accretion		466

Balance at December 31, 2007	$	8,956

Determination of AROs requires a significant number of assumptions and estimates that impact the valuation of the obligation. These estimates can change as the result of various factors including new developments or better information. As such, the Company periodically re-evaluates these estimates.


*(p)*	*Environmental Remediation Expenditures*

USPowerGen charges to expense or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Company expenses amounts that relate to an existing condition caused by past operations and that do not have future economic benefit. USPowerGen records liabilities related to expected future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated (Note 15).


*(q)*	*Emissions Allowances*

Emissions allowances have a limited life and were recorded as intangibles at estimated fair value as of the MDP Acquisition and the Combination. Emissions allowances are amortized on a basis of units of production as they are used in operations. Sales of emissions allowances to third parties are recorded in the consolidated statements of operations as a gain or loss on disposal of assets. Net emissions allowance expense, which is recorded as fuel expense in the consolidated statements of operations, was as follows for the periods presented (Note 7):


	Total

Predecessor:
Year ended December 31, 2005	$	4,162
January 1, 2006 to February 23, 2006		512
Successor:
February 24, 2006 to December 31, 2006		6,148
Year ended December 31, 2007		4,666

F-29

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


*(r)*	*Income Taxes*

The Company accounts for income taxes using the liability method in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS No. 109), which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

The Company has two categories of income tax expense or benefit — current and deferred, as follows:


	•	Current income tax expense or benefit consists solely of regular tax less applicable tax credits; and

	•	Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.

The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes resulting in temporary and permanent differences between the Company’s consolidated financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company’s consolidated balance sheets. The Company measures deferred income tax assets and deferred income tax liabilities using enacted tax laws and rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded to reduce the Company’s net deferred tax assets to an amount that is more likely than not to be realized.

The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 of FIN 48, on January 1, 2007. FIN 48 specifies the way public companies are to account for uncertainty in income tax reporting, and prescribes the methodology for recognizing, reversing, and measuring the tax benefits of a tax position taken, or expected to be taken, in a tax return. Our adoption of FIN 48 did not result in any change to the level of our liability for uncertain tax positions, and there was no adjustment to our retained earnings for the cumulative effect of an accounting change.

The Company’s policy for classification of interest and penalties on income taxes is to record such amounts as a component of the provision for income taxes. The Company and its Predecessors did not have any interest and penalties on income taxes in the periods presented (Note 10).


*(s)*	*Goodwill and Intangible Assets*

The Company accounts for goodwill and intangible assets in accordance with SFAS No. 141 and Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS No. 142). SFAS No. 141 requires that the purchase method of accounting be used for all business combinations. It specifies the criteria that intangible assets acquired in a business combination must meet in order to be recognized and reported apart from goodwill. SFAS No. 142 requires that goodwill and intangible assets determined to have indefinite lives no longer be amortized, but instead be tested for impairment at least annually and whenever events or circumstances occur that indicate impairment might have occurred.

SFAS No. 142 also requires that intangible assets with estimable useful lives be amortized over their respective estimated useful lives and reviewed for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable.

The Company performs annual impairment testing of goodwill at the end of each fiscal year, and when events warrant an assessment. The Company compares the fair value of the reporting unit with its carrying

F-30

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

value, using a combination of market, replacement cost, and discounted cash flow approaches. The results of this assessment did not indicate impairment at December 31, 2007.

Separable intangible assets that are deemed to have finite lives are amortized over their estimated useful lives. Specifically, identifiable intangible assets with finite lives include emissions allowances, unmitigated capacity sales contracts, and gas transportation contracts. The Company has no intangible assets with indefinite lives as of December 31, 2007 (Note 7).


*(t)*	*Debt Issuance Costs*

Debt issuance costs are capitalized and amortized as interest expense on a basis that approximates the effective-interest method over the term of the related debt.

As of December 31, 2007 and December 31, 2006, deferred financing costs included:


	December 31,			December 31,
	2007			2006

Deferred financing costs, gross	$	34,760			34,760
Accumulated amortization		(12,127	)		(8,053	)

Deferred financing costs, net	$	22,633			26,707


*(u)*	*Pensions*

USPowerGen offers pension benefits to its employees through either a defined benefit pension plan or a cash balance plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158). SFAS No. 158 was effective for publicly-traded companies with fiscal years ending after December 15, 2006 and for privately-held companies no later than fiscal years ending after June 15, 2007. The Company’s financial statements reflect the adoption of SFAS No. 158 as if it had been a public company at December 31, 2006. USPowerGen recognizes the funded status of the Company’s defined benefit plans in the statement of financial position and records an offset to other comprehensive income. In addition, the Company also recognizes on an after tax basis, as a component of other comprehensive income, gains, and losses as well as all prior service costs that have not been included as part of the Company’s net periodic benefit cost. The determination of USPowerGen’s obligation and expenses for pension and postretirement benefits is dependent on the selection of certain assumptions. These assumptions include the discount rate, expected rate of return on plan assets, retirement age, healthcare trend rate, and the rate of future compensation increases. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension and postretirement obligation or expense recorded by the Company (Note 8).


*(v)*	*Equity-Based Compensation*

The Company accounts for equity-based compensation under Statement of Financial Accounting Standards No. 123(R), Share-Based Payments (SFAS No. 123(R)). SFAS No. 123(R) requires that the Company recognize as compensation expense the grant-date fair value of certain equity instruments. Compensation expense is determined by estimating the fair value of the equity instrument as of the grant date and recognizing it over the period earned which primarily reflects the vesting period. The fair value of the Company’s equity is estimated using a binomial lattice model (Note 9).

F-31

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


*(w)*	*Shareholders’ Equity*

Prior to the Combination, the Company had authority to issue two classes of membership interests: 32,000,000 Series A Voting Common Units (Series A Units), of which 31,440,000 were issued and outstanding at December 31, 2006, and 1,086 Series B Nonvoting Common Units (Series B Units), of which 1,058 were issued and outstanding at December 31, 2006. One Series A Unit was issued for each $10 of capital contributed on February 23, 2006. The Series B Units were issued to certain Series A Unit holders and certain employees and management of the Company in 2007 and 2006. The value of the Series B Unit could only be determined upon the occurrence of certain liquidity or material events as set forth in the Executive Purchase Agreements (EPAs), to which all management and employee Series B Unit holders were parties, and only after certain specified rates of return thresholds for Series A Unit were met. The rights of the Series A Unit holders and nonemployee and nonmanagement Series B Unit holders were governed by Astoria’s Limited Liability Company Operating Agreement.

In connection with the Combination, the Series A Units and Series B Units were exchanged for units of New Astoria (Note 3).

In 2007, prior to the Combination, $5.4 million was distributed to holders of Series A Units, representing calculated income taxes payable by each unitholder with respect to their Series A Units in 2007. No other dividends or distributions were paid with respect to either series of Astoria common units or USPowerGen common stock during 2007.

The Company has 650,000 Class A common stock warrants outstanding. The warrants are exercisable in whole or part at any time or time to time until their expiration date on October 10, 2013. The unit exercise price for the Class A common stock issuable is $11.88.


*(x)*	*Reclassifications*

Certain reclassifications have been made to prior period financial statements in order to conform to the current year presentation. These reclassifications have not changed the results of operations or members’ equity.


*(y)*	*(Loss) Earnings Per Share*

Basic (loss) earnings per share is calculated by dividing net (loss) income by the weighted average number of common shares outstanding. Diluted (loss) earnings per share is computed using the weighted average number of common shares and dilutive potential common shares, including common shares from warrants using the treasury stock method.

Weighted average common shares outstanding were derived based on IPO-split share equivalent basis for the Successor periods. For the Predecessor periods, IPO-split adjusted weighted average common shares outstanding at the time of the MDP Acquisition were used.


*(z)*	*Recent Financial Accounting Standards Not Previously Discussed Herein*

In February 2006, the FASB issued Statement of Financial Accounting Standards No. 155, Accounting for Certain Hybrid Financial Instruments — an amendment of SFAS No. 133 and SFAS No. 140 (SFAS No. 155). This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that would otherwise be required to be bifurcated from its host contract. The election to measure a hybrid financial instrument at fair value, in its entirety, is irrevocable and all changes in fair value are to be recognized in earnings. This Statement also clarifies and amends certain provisions of SFAS No. 133 and

F-32

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

SFAS No. 140. This Statement was effective beginning January 1, 2007 and did not have an impact on the Company’s financial position or results of operations.

On September 15, 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (SFAS No. 157). The statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 also requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy. The fair value hierarchy defines certain levels of valuation inputs (i.e., 1, 2, and 3) based upon their ability to be observed in the marketplace with level 3 inputs as those that are not readily observable. For the level 3 category, additional disclosures, including a reconciliation of the beginning and ending balances for each major category of assets and liabilities accounted for at fair value, are required. SFAS No. 157 also affects the accounting for inception gains and losses that are currently deferred under EITF 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Risk Management Activities (EITF 02-03). Adoption of SFAS No. 157 is required for fiscal years beginning after November 15, 2007 with earlier application encouraged.

In February 2008, the FASB issued FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (FSP No. 157-2), which permitted delayed application of this statement for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company partially adopted SFAS No. 157 on January 1, 2008, delaying application for nonfinancial assets and nonfinancial liabilities as permitted. The partial adoption of SFAS No. 157 resulted in an aggregate net increase in fair value of $6,125, primarily attributable to the express consideration of credit default risk of both USPowerGen and its contract counter-parties. The Company is currently evaluating the impact of the deferred portion of SFAS No. 157 on the Company’s financial position or results of operations.

In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (SAB 108). SAB 108 expresses the SEC staff’s views on the appropriate approach for determining materiality as it relates to misstatements. The approach requires that a public registrant consider the impact of an unadjusted error on each financial statement and related financial statement disclosure presented. It requires that a public registrant consider both the effects of correcting the error in the current year income statement and the effects of correcting the current year balance sheet misstatement that originated in prior years. The Company has implemented SAB 108, which did not have an effect on the, Company’s financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Liabilities — including an amendment to FASB Statement No. 115 (SFAS No. 159). This Statement creates a fair value option under which an entity may irrevocably elect fair value as the initial and subsequent measurement attribute for certain assets and liabilities, on an instrument by instrument basis. If the fair value option is elected for an instrument, all subsequent changes in fair value for that instrument shall be reported in earnings. This statement is effective for the Company for the fiscal year beginning January 1, 2008 and corresponding interim periods. The Company does not intend to apply this standard to any of its eligible assets or liabilities; therefore there was no impact on USPowerGen’s consolidated financial position, results of operations, or cash flows.

F-33

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

against each other if certain conditions of FIN No. 39 are otherwise met: (a) those recognized for derivative instruments executed with the same counterparty under a master netting arrangement and (b) those recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. In addition, a reporting entity is not precluded from offsetting the derivative instruments if it determines that the amount recognized upon payment or receipt of cash collateral is not a fair value amount. FSP No. 39-1 is effective at the beginning of the first fiscal year after November 15, 2007. The adoption of FSP No. 39-1 requires retrospective application for all financial statements presented as a change in accounting principle. The Company adopted FSP No. 39-1 on January 1, 2008, and elected to continue to recognize the risk management assets and liabilities subject to master netting agreements on a gross basis. The adoption of FSP No. 39-1 had no effect on the Company’s financial position or results of operations.


(3)	Business Combinations

Combination

On June 1, 2007, USPowerGen was formed in connection with the merger of Astoria and EBG, and Astoria was determined to be the accounting acquirer in accordance with SFAS No. 141. USPowerGen owns and operates 58 active operating generation units at six power generation facilities with generation capacity of approximately 5,223 MWs. USPowerGen sells its energy and capacity into the NYISO and the ISO New England (ISO-NE) deregulated markets. In connection with the foregoing transaction the following occurred:


	•	EBG members exchanged their EBG units for a total of 41.1 million shares of USPowerGen Class A non-voting common stock plus warrants to purchase an additional 650,000 shares of class A non-voting common stock;

	•	Astoria members exchanged Astoria units for units of New Astoria, a shareholder of USPowerGen. New Astoria received 35.5 million shares of USPowerGen Class B voting common stock;

	•	USPowerGen entered into an agreement which provides among other things, that it use its reasonable best efforts to effect a registration of its shares (IPO) as soon as practicable. Consequently, approximately $32,400 related to certain of the estimated issuance costs associated with the IPO have been included as part of the purchase price allocation and recognized as an accrued liability in the consolidated balance sheet as of December 31, 2007; and

	•	The then-existing management agreements between EBG and an affiliate of K Road BG LLC (K Road BG) were terminated, without any payment and USPowerGen entered into a consulting agreement to have K Road BG Management, LLC (K Road) provide advisory services to USPowerGen in connection with an initial public offering. As consideration for such services, K Road will receive a

F-34

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


		one-time fee equal to one percent (1.0%) of the aggregate gross proceeds of an initial public offering, provided that the fee shall not be less than $3,000.

In accordance with SFAS No. 141, the Combination was accounted for using the purchase method of accounting and a purchase price of $1,203,300.

The Combination was done in furtherance of USPowerGen’s business strategy to grow its portfolio of generating facilities in locations with well-developed, competitive markets that have established capacity payment markets and are characterized by a tight or tightening supply and demand profile.

The Combination was accounted for using the purchase method of accounting and, accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on the estimated fair value of such assets and liabilities as of June 1, 2007. The excess of purchase price over fair value of the net tangible and identified intangible assets acquired was recorded as goodwill.

The following table summarizes the fair value of the assets acquired and liabilities assumed at the date of the Combination:


Current assets:	$	214,654
Property, plant, and equipment		2,667,036
Intangible assets		199,423
Goodwill		807,414
Other assets		20,318

Total assets		3,908,845

Current liabilities		(172,024	)
Deferred tax liability		(696,693	)
Long-term liabilities		(1,836,828	)

Total liabilities assumed		(2,705,545	)

Net assets acquired	$	1,203,300

Of the $199,423 of intangible assets, $124,800 was assigned to air emissions allowances and $74,623 to a natural gas supply agreement (Note 7).

F-35

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Unaudited Supplemental Pro Forma Information

The following pro forma information represents the results of operations as if the Combination occurred at the beginning of the representative reporting periods:


	Year ended December 31,
	2007			2006

Revenues	$	1,647,906			1,453,112
Operating expenses		1,492,735			1,450,618

Operating income		155,171			2,494
Other expense		271,248			153,248

Loss before income tax		(116,077	)		(150,754	)
Income tax benefit		(41,259	)		(57,264	)

Net loss		(74,818	)		(93,490	)

MDP Acquisition

On February 23, 2006, Astoria acquired Astoria Orion, wholly-owned subsidiaries of Reliant for $1,000,000. The results of Astoria Orion have been included in Astoria’s operating results since February 23, 2006.

The MDP Acquisition was accounted for using the purchase method of accounting and accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on the estimated fair value of such assets and liabilities as of February 23, 2006. The excess of purchase price over fair value of the net tangible and identified intangible assets acquired was recorded as goodwill. The following table summarizes the fair value of the assets acquired and liabilities assumed at the date of the MDP Acquisition and the resultant goodwill:


Current assets	$	94,713
Property, inventory, and equipment		872,292
Goodwill		26,015
Intangible assets		50,797
Other assets		2,411

Total assets acquired		1,046,228

Current liabilities		(10,667	)
Noncurrent liabilities		(33,668	)

Total liabilities assumed		(44,335	)

Total acquisition costs	$	1,001,893

Of the $50,797 of intangible assets, $32,638 was assigned to air emissions allowances and $18,159 to natural gas transportation and unmitigated capacity sales contracts (Note 7).

The primary reason for the MDP Acquisition was to acquire power-generating assets in congested markets. The Company believes that wholesale generation assets, such as the Astoria assets, that are located within highly transmission constrained areas with limited opportunities for new greenfield in-city generation should benefit from shrinking reserve margins, expanding market heat rates and favorable capacity market

F-36

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

regimes. Therefore, the Company paid approximately 2.4% over the estimated appraised fair value of the net assets at February 23, 2006 creating $26.0 million of goodwill from the transaction.

The MDP Acquisition had an outstanding working capital purchase price adjustment of $4.5 million, which was subsequently resolved as of December 31, 2007.

Unaudited Supplemental Pro Forma Information

The following pro forma information represents the results of operations as if the MDP Acquisition occurred at the beginning of the respective reporting periods. Prior to the MDP Acquisition, Astoria Orion operated as a business unit of Reliant. As a result, the pro forma financial information does not necessarily reflect what results of operations would have been had the business operated as a separate, stand-alone entity during those periods.


	Year ended December 31,
	2006		2005

Revenues	$	585,232		1,014,045
Operating expenses		490,902		719,872

Operating income		94,330		294,173
Other expense, net		66,064		48,201

Income before income tax		28,266		245,972
Income tax expense		1,399		11,530

Net income	$	26,867		234,442


(4)	Accounting for Derivative and Hedging Activities

The Company is engaged in the generation and sale of electricity, which fundamentally involves the conversion of energy from various fuel sources into salable electrical energy. In connection with these operations, the Company’s financial performance is subject to the impact of fluctuations in the market price of electricity, fuel oil and natural gas, the market prices of which can, at times, be both volatile and independent of each other. Additionally, the Company’s capital structure included LIBOR-based variable rate debt of $2,531,689 and $691,775 as of December 31, 2007 and December 31, 2006, respectively (Note 5). As such, changes in LIBOR will, in the absence of any hedging instruments executed by the Company, have an impact on the Company’s reported cash flows.


*(a)*	*Derivative Accounting*

SFAS No. 133 outlines (a) the criteria used to ascertain whether or not a given position or contractual arrangement is a derivative instrument and (b) the accounting and disclosure requirements for both non-hedge derivative positions (trading or speculative derivative positions) and three broad categories of hedge derivative positions; normal purchase-normal sales, economic hedges, and accounting hedges. The following is a brief

F-37

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

description of each derivative hedge category and the related accounting treatment as outlined by SFAS No. 133:

Normal Purchase-Normal Sale

Normal purchase-normal sales contracts are forward purchase or sales agreements which settle through physical delivery of a product or commodity typically sold or used in the ordinary course of business, involve quantities likely to be sold or used in the ordinary course over a reasonable period, and either contain no net settlement provisions or involve underlying assets or liabilities for which no market mechanism exist by which net settlements may be reasonably achieved. Such contracts qualify for the “normal purchase-normal sale” exemption from the periodic MTM valuation adjustments required by SFAS No. 133. Changes in fair value of such contracts are recognized in income only when realized.

As of Decembers 31, 2007, USPowerGen held four normal purchase-normal sale contracts. These contracts expired on January 1, 2008 or January 2, 2008, and had an aggregate notional value of $13. As of December 31, 2006, the Company did not hold any normal purchase-normal sale contracts.

Derivatives Held as Hedge Positions

All derivative contracts not deemed to be normal purchase-normal sales transactions must be recognized and reported on the balance sheet at fair value, with the resulting unrealized gains and losses recognized either as a component of net income currently, or for those derivatives qualifying for hedge accounting treatment under SFAS No. 133, deferred and matched with the recognition of realized results of the related hedge transaction. Hedging positions that qualify for hedge accounting treatment are considered to be “accounting hedges,” while those that do not meet the SFAS No. 133 criteria, are deemed to be “economic hedges.”


	•	Accounting Hedges: Changes in the fair value of accounting hedge derivatives, including those which have (a) been designated as accounting hedges and (b) satisfied all of the criteria outlined in SFAS No. 133 are eligible for deferral treatment, with the extent of such deferral determined by the degree of hedge effectiveness. For each derivative instrument, any unrealized gain or loss is apportioned into an “effective component” and “an ineffective component.” Changes in fair value allocated to the ineffective component are recognized currently, while changes in fair value attributable to the effective portion of the hedge are generally deferred until the timing of recognition can be matched to the statement of operations recognition of the related hedge transaction.

	•	Economic Hedges: Changes in the fair value of economic hedge derivatives are recognized as a component of net income on a current basis. The classification of such recognition is determined by and reported with the revenue or expense recognized in connection with the hedged transaction. As such, the realized gains and losses on periodic cash settlements and at contract maturity or expiration and the unrealized gains and losses on MTM adjustments are aggregated and reported on a net basis.


*(b)*	*USPowerGen Derivative Hedge Portfolio*

Accounting Hedges

As of December 31, 2007 and December 31, 2006, the Company’s derivative portfolio did not include any positions designated as accounting hedges. In each of the periods reported herein, changes in the fair value of the Company’s derivatives have been recognized in income on a current basis net of the amounts realized on both derivative contract settlements and amounts recognized in connection with the underlying hedged transactions. As of the end of each period noted above, other comprehensive income (OCI) did not include any unrealized gains or losses related to the Company’s hedging portfolio.

F-38

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

During the five-month period preceding the culmination of the Combination, EBG executed a $1,000,000 3-month LIBOR interest rate swap, which EBG had designated at inception and had accounted for as an accounting hedge with no ineffectiveness, in accordance with SFAS No. 133. Through May 31, 2007, EBG had recognized unrealized gains of $3,954 as a component of OCI. In conjunction with the adjustments required to allocate the Combination purchase price to the opening balance sheet of the consolidated entities, the OCI balance of $3,954 was eliminated along with other pre-combination equity balance components, and as a result was not and will not be recognized as a component of net income of the consolidated group.

Economic Hedges

The Company’s derivative portfolio includes a variety of contracts held to manage its exposure to commodity price and interest rate fluctuations. While the Company considers these agreements to be viable hedges of market risks outside its direct control, hedge accounting was not utilized because the contracts did not satisfy the requisite criteria outlined in SFAS No. 133 required to qualify for such treatment. As such, for each of the reporting dates included herein, December 31, 2007, December 31, 2006, February 23, 2006 and December 31, 2005, all of the Company’s derivatives have been accounted for and reported as economic hedges. The Company’s economic hedge portfolio can be segregated into two main categories based upon the type of exposure against which it intended to provide hedge protection: (a) hedges of risks associated with the Company’s power generation activities and assets, or operating activity hedges; and (b) hedges against increases in the Company’s cost of capital due to changes in short-term interest rates, or interest rate hedges.

Additionally, the Company deems it useful to further segregate its operating activity hedges into the following sub-segments, which reflect the statement of operations classification of the realized and unrealized gains and losses recognized on such positions:

(i) Risk management hedges, which includes contracts intended to hedge the variability of capacity market prices, and conversion spread contracts which are executed to mitigate potential fluctuations in the Company’s spark spread caused by the variability of market prices for both the Company’s generated power and incurred fuel costs in connection with the Company’s power generation activities;

(ii) Power hedges, which are executed to mitigate the impact of negative fluctuations in the market price of wholesale power generated in the Company’s various markets; and

(iii) Fuel hedges, which are executed to mitigate the impact of negative fluctuations in the market prices of source fuels, such as fuel oil and natural gas, utilized to operate the Company’s power generation assets.

Operating Activity Hedges: The Company utilizes a variety of derivative instruments to achieve the hedging results desired. Depending upon market conditions, the Company’s operating activity hedge portfolio may include some or all of the following derivative instruments; options, futures, forward purchase or sales contracts, and commodity price or basis swap agreements.

F-39

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Description of Portfolio Positions: The table below provides a general summary of USPowerGen’s operating activity hedges as of December 31, 2007 and December 31, 2006, along with those of the Predecessor as of February 23, 2006 and December 31, 2005:


		Successor		Predecessor
Contract Description:		December 31, 2007	December 31, 2006	February 23, 2006	December 31, 2005

Capacity Hedge Contracts:
Financially settled fixed for variable capacity hedge	New York:
	*Number of contracts:*	1	1	—	—
	*Notional amount:*	1,800,000 kW/Mth	1,800,000 kW/Mth	—	—
	*Term of agreement(s):*	May 1, 2006 to April 30, 2009	May 1, 2006 to April 30, 2009	—	—
Conversion Spread Hedge Contracts:
Financially settled, fixed for variable, structured/synthetic conversion spread swap, with embedded fuel switching option	New York:
	*Number of contracts:*	1	1	1	1
	*Notional amount:*	May-Feb.: 1,100 MW/Hr; Mar.-Apr.: 700 MW/Hr	May-Feb.: 1,100 MW/Hr; Mar.-Apr.: 700 MW/Hr	May-Feb.: 1,100 MW/Hr; Mar.-Apr.: 700 MW/Hr	May-Feb.: 1,100 MW/Hr; Mar.-Apr.: 700 MW/Hr
	*Term of agreement(s):*	Jan. 1, 2006 to Dec. 31, 2007	Jan. 1, 2006 to Dec. 31, 2007	Jan. 1, 2006 to Dec. 31, 2007	Jan. 1, 2006 to Dec. 31, 2007
Financially settled fixed for variable conversion spread hedge (power vs single fuel-natural gas)	Boston – Hedge #1:
	*Number of contracts:*	4	—	—	—
	*Notional amount:*	Oct. – May: 1,600 MW/Hr Jun.-Sep.: 1,500 MW/Hr	—	—	—
	*Term of agreement(s):*	Jan. 1, 2007 to Dec. 31, 2010	—	—	—
	Boston – Hedge #2:
	*Number of contracts:*	1
	*Notional amount:*	Max: 600 MW/Day – Summer; 675 MW/Day – Winter; Min: 480 MW/Day	—	—	—
	*Term of agreement(s):*	Jan. 1, 2008 to Dec. 31, 2010	—	—	—
	Power Hedge Contracts: Boston:
Financially settled, fixed-price for floating price, single commodity-electricity swaps	*Number of contracts:*	23	—	—	—
	*Notional amount:*	3,200 MW/KHR	—	—	—
	*Term of agreement(s):*	Jan 1, 2008 to Aug 31, 2008	—	—	—
Fuel Hedge Contracts: Boston:
Financially settled, fixed-price for floating price, single commodity swaps - Source fuels: Natural Gas & Fuel Oil	*Number of contracts:*	35	—	—	—
	*Notional amount:*	150,000 MMBtu/Day	—	—	—
	*Term of agreement(s):*	Jan 1, 2008 to Aug 31, 2008	—	—	—
	Boston:
	*Number of contracts:*	1	—	—	—
	*Notional amount:*	100,000 BBL/Month	—	—	—
	*Term of agreement(s):*	Jan 1, 2008 to Jan 31, 2008	—	—	—

Operating Activity Hedge Portfolio — Fair Value and Recognized Gains & Losses: The fair value of USPowerGen’s operating activity hedges, excluding the impact of the “day-one loss” deferred at the inception of the Capacity hedge as described in more detail below, was ($29,841) and $7,898, as of December 31, 2007, and December 31, 2006, respectively. The fair value of the Predecessor’s operating activity hedge as of February 23, 2006 and December 31, 2005 was $105,882 and $83,987, respectively. For the periods ended December 31, 2007, December 31, 2006, February 23, 2006 and December 31, 2005, unrealized MTM gains/(losses) attributable to changes in the fair value of operating activity hedges totaled ($48,744), $5,488, $21,895 and

F-40

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

$83,988, respectively, while realized gains/(losses) on operating activity hedges attributable to settlement payments received/(made) totaled ($2,053), ($16,607), $14,601 and $0, respectively.

Day-One Loss-Capacity Contract: On January 10, 2006, the Astoria Generating Company Acquisitions, L.L.C. (an entity formed to facilitate the MDP Acquisition), entered into a financially settled, “floating for fixed” International Swaps and Derivatives Association, Inc. (ISDA) Master Agreement covering unforced capacity (Capacity Agreement) with a major U.S. financial institution. At inception, the Capacity Agreement had a three-year term ending on April 30, 2009, a notional quantity of 1,800,000 kW-month of in-city unforced capacity, and a fixed-price of $7.07/kW-month. The Company estimated the fair value at inception of $(12,638).

In accordance with EITF 02-03, the negative fair value at inception was considered a “day-one loss,” which could not be substantiated by comparison to comparable market transactions. As proscribed by EITF 02-3, the day-one loss of ($12,638) was not recognized as a component of income, but was instead deferred, resulting in a difference between the Company’s estimated fair value, and the fair value at which the contract was reported from inception through the year ended December 31, 2007.

As of January 1, 2008, USPowerGen will adopt SFAS No. 157, which among other things, nullified the guidance promulgated by footnote 3 of EITF Issue No. 02-3 requiring the deferral of day-one losses on certain energy derivative instruments, and changed various aspects of the definition of and methodologies used to measure and report the fair value of assets and liabilities. In accordance with SFAS No. 157, USPowerGen recorded a retrospective transition adjustment to the carrying value of the capacity contract at the adoption date, January 1, 2008. The impact of the change in accounting method, as required by SFAS No. 157, for day-one losses previously deferred under EITF Issue No. 02-03, reduced the carrying value of the contract by $7,942.


	At January 1, 2008
	Capacity
	contract			Deferred			Retained
	value			taxes			earnings

Net decrease attributable to retrospective transition adjustment upon adoption of SFAS No. 157	$	(7,942	)		(1,866	)		(6,076	)

Interest Rate Hedges

The LIBOR-based, variable rate debt facilities issued by USPowerGen’s Astoria and EBG subsidiaries expose the Company’s cost of capital to fluctuations in market interest rates. To hedge against the interest rate risk attributable to these facilities, the Company has entered into several derivative contracts, which provide interest rate protection on a portion of its variable rate obligations (Note 5). The aggregate notional value of the Company’s interest rate hedge portfolio as of December 31, 2007 and December 31, 2006 was $1,975,000 and $585,000, respectively. The Company’s outstanding LIBOR-based variable interest rate debt facilities as of December 31, 2007 and December 31, 2006 were $2,531,689 and $691,775, respectively.

F-41

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Description of Portfolio Positions: The table below provides a general summary of USPowerGen’s interest rate hedge portfolio:


		Successor		Predecessor
Contract Description:		December 31, 2007	December 31, 2006	February 23, 2006	December 31, 2005

Astoria Interest Rate Swap:
Financially settled, floating for fixed LIBOR swap	*Number of contracts*	8	10	—	—
	*Notional amount*	$ 575,000	$ 585,000	—	—
	*Term of agreement*	Feb 23, 2006 to Mar 31, 2011	Feb 23, 2006 to Mar 31, 2011	—	—
		(Annual Maturities Commencing March 23, 2007)	(Annual Maturities Commencing March 23, 2007)
EBG Interest Rate Swap:
Financially settled, floating for fixed LIBOR swap
	*Number of contracts*	1	—	—	—
	*Notional amount*	$ 1,000,000	—	—	—
	*Term of agreement*	Feb 27, 2007 to	—	—	—
		Dec 31, 2010
Financially settled, LIBOR interest rate cap option	*Number of contracts*	1	—	—	—
	*LIBOR Cap*	5.50%	—	—	—
	*Notional amount*	$ 200,000	—	—	—
	*Term of agreement*	Dec 30, 2005 to	—	—	—
		Dec 31, 2008
	*Number of contracts*	1	—	—	—
	*LIBOR Cap*	5.00%	—	—	—
	*Notional amount*	$ 200,000	—	—	—
	*Term of agreement*	December 31, 2005 to	—	—	—
		December 31, 2007

Interest Rate Hedge Portfolio — Fair Value and Recognized Gains & Losses: The fair value of the Company’s interest rate hedge portfolio was ($53,232) and ($1,968), as of December 31, 2007, and December 31, 2006, respectively. The Predecessor did not hold any interest rate contracts as of February 23, 2006 and December 31, 2005. For the periods ended December 31, 2007, December 31, 2006, February 23, 2006 and December 31, 2005, unrealized MTM gains/(losses) attributable to changes in the fair value of interest rate hedges totaled ($55,943), ($1,967), $0 and $0, respectively, while realized gains/(losses) on interest rate hedges attributable to settlement payments received totaled $3,445, $798, $0 and $0, respectively.


*(c)*	*Fair Value of Economic Hedge Derivatives — Summary of Balance Sheet Presentation*

The fair value of the Company’s derivative instruments, including both operating activity hedge derivatives and interest rate hedge derivatives, have been aggregated and then classified in the consolidated balance sheets included herein based upon the fair value of anticipated settlements over the next twelve months and then over the remaining tenor of the various contracts. Derivative contracts for which the present value of anticipated settlement over the twelve months following the balance sheet date and/or the remaining tenor is positive have been recognized as current and/or noncurrent derivative assets, respectively. Derivative contracts for which the present value of anticipated settlement over the twelve months following the balance sheet date and/or the remaining tenor is negative have been recognized as current and/or noncurrent derivative liabilities, respectively.

F-42

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


	At December 31, 2007
	Current		Noncurrent		Current			Noncurrent			Total
Hedge Description	asset		asset		liability			liability			fair value

Capacity Agreement	$	12,818		6,415		—			—			19,233
Conversion spread		—		7,002		(29,130	)		(25,500	)		(47,628	)

Subtotal — risk management hedges		12,818		13,417		(29,130	)		(25,500	)		(28,395	)
Power		1,776		—		(1,789	)		—			(13	)
Fuel		1,845		—		(3,278	)		—			(1,433	)

Subtotal — operating activity hedges		16,439		13,417		(34,197	)		(25,500	)		(29,841	)
Interest rate		—		2		(14,917	)		(38,317	)		(53,232	)

Total economic hedges	$	16,439		13,419		(49,114	)		(63,817	)		(83,073	)


	At December 31, 2006
	Current		Noncurrent		Current		Noncurrent			Total
Hedge Description	asset		asset		liability		liability			fair value

Capacity Agreement	$	—		2,028		—		—			2,028
Conversion spread		5,870		—		—		—			5,870

Subtotal — risk management hedges		5,870		2,028		—		—			7,898
Power		—		—		—		—			—
Fuel		—		—		—		—			—

Subtotal — operating activity hedges		5,870		2,028		—		—			7,898
Interest rate		860		—		—		(2,828	)		(1,968	)

Total economic hedges	$	6,730		2,028		—		(2,828	)		5,930


*(d)*	*Realized & Unrealized Gains & Losses on Economic Hedge Derivatives — Statement of Operations Presentation*

The aggregate impact of the operating activity and interest rate hedges, including both the unrealized MTM gains and losses attributable to changes in the fair value, and the realized gains and losses attributable to contract settlements of both the operating activity hedge derivatives and interest rate hedge derivatives, have been aggregated and recognized on a current basis along with the amounts recognized in connection with the hedged transactions. As such, gains and losses on the economic hedge derivatives have been recognized in the statements of operations as follows: capacity, conversion spread, and power hedges have been recognized as a component of revenues; fuel hedges have been recognized as a component of fuel expense; and interest rate hedges have been recognized as a component of interest expense.

F-43

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

statements of operations covering the year ended December 31, 2007, and the period from February 24, 2006 through December 31, 2006:


	Year ended December 31, 2007
	Operating activity hedges																		Total
				Conversion												Interest			economic
	Capacity			spread			Power			Fuel			Total			rate hedges			hedges

Realized & unrealized (losses) gains
Change in fair value	$	17,205			(65,369	)		(243	)		(337	)		(48,744	)		(55,943	)		(104,687	)
Contract settlements		(44,028	)		39,227			20,520			(17,772	)		(2,053	)		3,445			1,392

Total (losses) gains		(26,823	)		(26,142	)		20,277			(18,109	)		(50,797	)		(52,498	)		(103,295	)

Statement of operations recognition
Revenue		(26,823	)		(26,142	)		20,277			—			(32,688	)		—			(32,688	)
Fuel		—			—			—			(18,109	)		(18,109	)		—			(18,109	)
Interest expense		—			—			—			—			—			(52,498	)		(52,498	)

Total (losses) gains	$	(26,823	)		(26,142	)		20,277			(18,109	)		(50,797	)		(52,498	)		(103,295	)


	Period February 24, 2006 through December 31, 2006
	Operating activity hedges															Total
				Conversion									Interest			economic
	Capacity			spread		Power		Fuel		Total			rate hedges			hedges

Realized & unrealized (losses) gains
Change in fair value	$	2,028			3,460		—		—		5,488			(1,967	)		3,521
Contract settlements		(53,748	)		37,141		—		—		(16,607	)		798			(15,809	)

Total (losses) gains		(51,720	)		40,601		—		—		(11,119	)		(1,169	)		(12,288	)

Statement of operations recognition
Revenue		(51,720	)		40,601		—		—		(11,119	)		—			(11,119	)
Fuel		—			—		—		—		—			—			—
Interest expense		—			—		—		—		—			(1,169	)		(1,169	)

Totals (losses) gains	$	(51,720	)		40,601		—		—		(11,119	)		(1,169	)		(12,288	)

F-44

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

The tables below summarize the aggregate gains and losses recognized, both realized and unrealized, and the classification of amounts recognized within the consolidated statements of operations of the Predecessor, during the 54 day period from January 1, 2006 to February 23, 2006 and the year ended December 31, 2005:


	January 1, 2006 through February 23, 2006
	Operating activity hedges										Total
	Conversion								Interest		economic
	spread		Power		Fuel		Total		rate hedges		hedges

Realized & unrealized gains
Change in fair value	$	21,895		—		—		21,895		—		21,895
Contract settlements		14,601		—		—		14,601		—		14,601

Total gains		36,496		—		—		36,496		—		36,496

Statement of operations recognition
Revenue		36,496		—		—		36,496		—		36,496

Total gains	$	36,496		—		—		36,496		—		36,496


	Year ended December, 31, 2005
	Operating activity hedges										Total
	Conversion								Interest		economic
	spread		Power		Fuel		Total		rate hedges		hedges

Realized & unrealized gains
Change in fair value	$	83,988		—		—		83,988		—		83,988
Contract settlements		—		—		—		—		—		—

Total gains		83,988		—		—		83,988		—		83,988

Statement of operations recognition
Revenue		83,988		—		—		83,988		—		83,988

Total gains	$	83,988		—		—		83,988		—		83,988

F-45

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

The tables below provide a roll-forward analysis of hedging results recognized by the Company during the year ended December 31, 2007 and the period from February 24, 2006 through December 31, 2006, including settlements and expirations, portfolio additions and dispositions, and changes in the fair value of the estimated cash flows over the remaining contract tenor:


	Year ended December 31, 2007
	Change in fair value attributable to:
	Roll-off			Change in value
Contract Type	prior estimates			remaining tenor			Settlements			Total

Capacity Agreement	$	6,880			10,325			(44,028	)		(26,823	)
Conversion spread		(7,227	)		(58,142	)		39,227			(26,142	)
Power		(230	)		(13	)		20,520			20,277
Fuel		1,096			(1,433	)		(17,772	)		(18,109	)

Subtotal — operating risk hedges		519			(49,263	)		(2,053	)		(50,797	)
Interest rate		(2,342	)		(53,601	)		3,445			(52,498	)

Total economic hedges	$	(1,823	)		(102,864	)		1,392			(103,295	)


	February 24, 2006 to December 31, 2006
	Change in fair value attributable to:
	Roll-off			Change in value
Contract Type	prior estimates			remaining tenor			Settlements			Total

Capacity Agreement	$	—			2,028			(53,748	)		(51,720	)
Conversion spread		(9,676	)		13,136			37,141			40,601

Subtotal — risk management hedges		(9,676	)		15,164			(16,607	)		(11,119	)
Power		—			—			—			—
Fuel		—			—			—			—

Subtotal — operating risk hedges		(9,676	)		15,164			(16,607	)		(11,119	)
Interest rate		—			(1,967	)		798			(1,169	)

Total economic hedges	$	(9,676	)		13,197			(15,809	)		(12,288	)

The tables below provide roll-forward analyses of the hedging portfolio results recognized by the Predecessor during the period from January 1, 2006 to February 23, 2006 and the year ended December 31, 2005, including settlements and expirations, portfolio additions and dispositions, and changes in the fair value of the estimated cash flows over the remaining contract tenor:


	January 1, 2006 to February 23, 2006
	Change in fair value attributable to:
	Roll-off			Change in value
Contract Type	prior estimates			remaining tenor		Settlements		Total

Conversion spread	$	(12,426	)		34,321		14,601		36,496

Subtotal — operating risk hedges		(12,426	)		34,321		14,601		36,496

Total economic hedges	$	(12,426	)		34,321		14,601		36,496

F-46

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


	Year ended December 31, 2005
	Change in fair value attributable to:
	Roll-off		Change in value
Contract Type	prior estimates		remaining tenor		Settlements		Total

Conversion spread	$	—		83,988		—		83,988

Subtotal — operating risk hedges		—		83,988		—		83,988

Total economic hedges	$	—		83,988		—		83,988


*(e)*	*EBG Holdings, LLC — Acquired Derivative Portfolio*

On June 1, 2007, the Company completed the Combination (Note 3). Among the assets acquired and liabilities assumed were the pre-acquisition derivatives held by EBG. Similar to those of Astoria, EBG’s derivative positions were all executed and maintained to mitigate or hedge risks associated with: (i) the Company’s power generation assets and operations, or (ii) its variable interest rate debt financing obligations, or variable interest rate debt obligations. Prior to the Combination EBG held a $1,000,000 floating-for-fixed interest rate swap, which was designated and qualified as an accounting hedge of future cash flows. The remainder of EBG’s derivative portfolio was historically comprised of economic hedge positions, which were marked to market at each reporting date, with changes in fair value recognized currently as a component of net income. After the Combination, the Company did not re-designate the EBG interest rate swap as an accounting hedge of future cash flows for the following reasons:


	•	Short-cut hedge effectiveness treatment was not available, as the fair value of the position was not zero as of the date of the Combination. As such, the Company would have been required to bifurcate unrealized gains and losses on the swap between interest expense and other comprehensive income, complicating the presentation of results for the financial statement users; and

	•	As of the Combination date, the Company had not yet finalized its plans to integrate the post-acquisition debt capital and associated interest rate derivative portfolios.

The following tables provide a summary of the amounts included in the December 31, 2007 consolidated balance sheet and statement of operations and on the date of the Combination, attributable to the acquired EBG hedge portfolio:


	December 31, 2007
	Current		Noncurrent		Current			Noncurrent			Total
Hedge Description	asset		asset		liability			liability			fair value

Conversion spread	$	—		7,002		(29,130	)		(25,500	)		(47,628	)
Power		1,776		—		(1,789	)		—			(13	)
Fuel		1,845		—		(3,278	)		—			(1,433	)

Subtotal — operating activity hedges		3,621		7,002		(34,197	)		(25,500	)		(49,074	)
Interest rate		—		2		(10,344	)		(25,191	)		(35,533	)

Total economic hedges	$	3,621		7,004		(44,541	)		(50,691	)		(84,607	)

F-47

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


	June 1, 2007
	Current		Noncurrent		Current			Noncurrent		Total
Hedge Description	asset		asset		liability			liability		fair value

Conversion spread	$	5,797		6,073		—			—		11,870
Power		672		—		(442	)		—		230
Fuel		435		—		(1,531	)		—		(1,096	)

Subtotal — operating activity hedges		6,904		6,073		(1,973	)		—		11,004
Interest rate		4,480		199		—			—		4,679

Total economic hedges	$	11,384		6,272		(1,973	)		—		15,683


	Seven months ended December 31, 2007
										Operating						Total
	Conversion									activity						economic
	spread			Power			Fuel			hedges			Interest rate			hedges

Realized & unrealized (losses) gains
Change in fair value	$	(59,499	)		(242	)		(337	)		(60,078	)		(40,212	)		(100,290	)
Settlements		(17,691	)		20,520			(17,772	)		(14,943	)		2,084			(12,859	)

Total hedging (losses) gains		(77,190	)		20,278			(18,109	)		(75,021	)		(38,128	)		(113,149	)

Statement of operations recognition
Revenue		(77,190	)		20,278			—			(56,912	)		—			(56,912	)
Fuel		—			—			(18,109	)		(18,109	)		—			(18,109	)
Interest expense		—			—			—			—			(38,128	)		(38,128	)

Total recognized	$	(77,190	)		20,278			(18,109	)		(75,021	)		(38,128	)		(113,149	)

F-48

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


(5)	Long-Term Debt

Long-term debt consists of the following:


	December 31,			December 31,
	2007			2006			Interest rate⁽¹⁾

*Astoria:*
Revolving line of credit due 2012	$	—			—		LIBOR + 2.00%
Term Loan B due 2013		347,475			391,775		LIBOR + 2.00%
Term Loan C due 2013		300,000			300,000		LIBOR + 3.75%
*EBG:*
Secured Obligations
Revolving line of credit due 2013		29,500			—		LIBOR — 0.125%⁽²⁾
Term Loan B due 2013		1,118,700			—		LIBOR + 2.25%
Term Loan C due 2014		350,000			—		LIBOR+ 4.25%
Unsecured Obligations
Mezzanine Loan due 2016		340,557			—		LIBOR + 7.00%
Add: Unamortized premium on debt		45,457			—

Total long-term debt		2,531,689			691,775
Less current maturities		(15,600	)		(4,300	)
Current credit facility		(29,500	)		—

Total	$	2,486,589			687,475


(1)		The Company’s long-term debt is LIBOR-based with the option to elect a base rate plus applicable margin in lieu of LIBOR. The base rate is based on the prime rate or federal funds rate.

(2)		Interest rate on the drawn portion of the Revolving credit facility is LIBOR minus 0.125%. The fee associated with the undrawn portion of the total commitment of $70,000 is 2.375% per annum.

The Company’s Astoria debt is secured by the power generation facilities of its New York operations while the EBG debt (excluding the Mezzanine Loan due 2016) is secured by the power generation facilities of its Boston operations.

Astoria Debt

The Astoria Revolving Credit Facility and the Term Loan B are secured by a first lien priority and the Term Loan C is secured by a second lien position on the New York power generation facilities. The Revolving Credit Facility and Term Loan B have ratings of BB- by S&P’s and B1 by Moody’s. The Term Loan C has a credit rating of B by S&P and B3 by Moody’s. The Term Loan B requires the prepayment of a portion of the outstanding principal balance twice a year, in addition to scheduled principal repayments, based on an earnings before interest, taxes, depreciation, and amortization (EBITDA) calculation to determine excess free cash flows. Scheduled principal payments are paid on a quarterly basis and equal 1% of the original principal balance, or $4,300 per annum. In the event that Term Loan B has been repaid, the excess cash flow payments described above will be applied to Term Loan C. Additionally, at any time over the tenor of the Term Loan B, Astoria can make optional prepayments which would be applied against the excess cash flow payments.

F-49

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

The Astoria Revolving Credit Facility is a revolving facility with a syndicate of financial institutions providing for aggregate borrowings of $100,000. The Astoria Revolving Credit Facility provides for the issuance of up to $60,000 in standby letters of credit. At December 31, 2007 and December 31, 2006, there were no outstanding borrowings under this revolving credit facility. At December 31, 2007 and December 31, 2006, there were $3,000 and $4,900 in letters of credit outstanding, respectively.

The Astoria Debt contains certain nonfinancial and financial covenants. These covenants require that Astoria maintain certain derivatives that provide both operational and interest rate protection (Note 4) as well as limit the annual amount of capital expenditures incurred and dividends paid in a given calendar year. Furthermore, the Astoria Debt includes the following financial ratio covenants which are calculated on an EBITDA basis as defined in each respective debt agreement:


	Leverage ratio		Interest coverage ratio
	First lien	Second lien	First lien	Second lien
	priority	priority	priority	priority

Present to March 30, 2008	7.50:1.00	9.00:1.00	1.20:1.00	1.00:1.00
March 31, 2008 to March 30, 2009	6.50:1.00	7.80:1.00	1.50:1.00	1.20:1.00
March 31, 2009 to March 30, 2010	6.00:1.00	7.20:1.00	1.75:1.00	1.40:1.00
March 31, 2010 and thereafter	5.00:1.00	6.00:1.00	2.00:1.00	1.60:1.00

EBG Debt

The EBG debt was assumed by the Company in connection with the Combination (Note 3). The EBG Revolving Credit Facility, Term Loan B, and standby letter of credit facility have credit ratings of B+ by S&P and B1 by Moody’s. The EBG Term Loan C has credit ratings of B- by S&P and B3 by Moody’s. The Mezzanine Loan is not rated.

Secured Obligations

The EBG Revolving Credit Facility and the Term Loan B are secured by a first lien priority and the Term Loan C is secured by a second lien priority on the Boston power generation facilities. The Term Loan B requires quarterly scheduled principal repayments of $11,300 per annum. The Revolving Credit Facility and Term Loan C have no scheduled principal repayments. At its election, the Company can prepay the EBG debt subject to certain prepayment penalties. Optional prepayments on Term Loan B do not require a prepayment premium, and optional prepayments on Term Loan C require a prepayment premium of 1.0% from December 21, 2007 through December 20, 2008, and no prepayment penalty thereafter. The Revolving Credit Facility and Term Loan B must be prepaid prior to any prepayment on Term Loan C.

The EBG Revolving Credit Facility is a revolving facility with a syndicate of financial institutions providing for aggregate borrowings of $70,000. At December 31, 2007 there were $29,500 in outstanding borrowings under the facility. In addition to the Revolving Credit Facility, EBG also has a synthetic standby letter of credit facility secured by a first lien priority for up to $250,000. As of December 31, 2007 $207,146 in standby letters of credit were outstanding under this facility.

The EBG Debt contains certain nonfinancial and financial covenants. These covenants require that EBG maintain certain derivatives that provide both operational and interest rate protection (Note 4) as well as covenants that limit the annual amount of capital expenditures incurred and dividends paid in a given calendar

F-50

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

year. Furthermore, the EBG Debt includes the following financial ratio covenants which are calculated on an EBITDA basis as defined in each respective debt agreement:

Leverage ratio

Interest coverage ratio

First lien

Second lien

First lien

Second lien

priority

Current to December 31, 2008

11.00:1.00

12.00:1.00

Current to June 30, 2008

1.05:1.00

1.00:1.00

January 1, 2009 to December 31, 2009

10.00:1.00

11.00:1.00

July 1, 2008 to December 31, 2009

1.10:1.00

1.05:1.00

January 1, 2010 to December 31, 2010

9.00:1.00

10.00:1.00

January 1, 2010 to December 31, 2010

1.25:1.00

1.10:1.00

January 1, 2011 to December 31, 2011

8.00:1.00

9.00:1.00

January 1, 2011 to December 31, 2011

1.50:1.00

1.25:1.00

January 1, 2012 to December 31, 2012

7.00:1.00

8.00:1.00

January 1, 2012 to December 31, 2012

1.75:1.00

1.50:1.00

January 1, 2013 to December 31, 2013

6.00:1.00

7.00:1.00

January 1, 2013 to December 31, 2013

2.00:1.00

1.75:1.00

The EBG debt also requires certain restricted cash deposits for debt service, operating reserves, and capital expenditures. The restricted cash balance was $100,856 at December 31, 2007.

Unsecured Obligations

The EBG Mezzanine Loan due 2016 is an unsecured obligation of a subsidiary of the Company and parent of the Boston power generation assets. Interest payable on the Mezzanine Loan is not required to be paid current and is therefore added to the outstanding balance. It has no scheduled principal repayments prior to final maturity. At its option, the Company may make prepayments on the Mezzanine Loan that require make whole payments determined by the spread between the basis of a swap-equivalent fixed rate and a discount rate determined by a reference U.S. Treasury Securities. If terminated prior to December 20, 2008, the Company is subject to a make-whole provision. Thereafter, the call premium is 3.0% of the principal amount prepaid prior to December 2009, 2.0% from December 2009 through December 2010, 1.0% from December 2010 through December 2011, and no make whole premium thereafter. Upon the repayment of the EBG secured obligations described above, the Mezzanine Loan requires the semi-annual mandatory prepayments as follows:


	Required prepayment
				Cash proceeds
				from permitted
	Excess cash flow⁽¹⁾			dispositions⁽²⁾			Net equity proceeds

Leverage ratio > 2.50:1.00		100	%		100	%		100	%
Leverage ratio < 2.50:1.00		50	%		50	%		25	%


(1)		Excess cash flows not reinvested in operations as defined.

(2)		Permitted disposition proceeds in excess of $10,000 not reinvested, as defined.

Additionally, the Mezzanine Loan requires prepayment upon a change of control (unless the proposed acquirer is a qualified buyer, as defined, and upon Moody’s and S&P ratings confirmation).

The Mezzanine Loan contains certain covenants, which include the prohibition, with certain exceptions, of the payment of dividends and incurrence of additional debt or liens.

F-51

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Fair Value Adjustment to Assumed Long-Term Debt

Based on the fair market borrowing rate of 8.7% at the Combination date, the EBG debt required a fair value adjustment in connection with the purchase accounting (Note 3). The fair value adjustment represented a debt premium of $48,012 as of the Combination date and is reflected as an unamortized premium on debt added to the outstanding long-term debt balance. The premium is amortized to interest expense, over the remaining term of the related debt, using the effective interest method. The results of the amortization is a reduction in reported interested expense.

The following table summarizes the change in the unamortized premium on debt balance for the year ended December 31, 2007:


Year ended December 31, 2006	$	—
Unamortized premium on debt from fair value adjustment		48,012
Amortization of premium on debt		(2,555	)

Year ended December 31, 2007	$	45,457

Consolidated Annual Maturities

Scheduled maturities of the Company’s long-term debt, excluding the unamortized premium on debt of $45,457, are:


Year ended December 31, 2008	$	15,600
Year ended December 31, 2009		15,600
Year ended December 31, 2010		15,600
Year ended December 31, 2011		15,600
Year ended December 31, 2012		15,600
Thereafter		2,408,232

Total	$	2,486,232


(6)	Fair Value of Financial Instruments

As of December 31, 2007, the Company’s assets and liabilities included a number of financial instruments, as defined by Statement of Financial Accounting Standards No. 107, Disclosures about Fair Value of Financial Instruments (SFAS No. 107). Such financial instruments primarily included; US currency, dollar denominated short-term or cash equivalents, trade receivables and payables, derivative contracts, and long-term debt financing facilities.


*(a)*	*Short Duration Financial Instruments*

With respect to the Company’s cash, cash equivalents, trade receivables, and trade payables, such instruments are:


	•	Short term in duration and the values are relatively insensitive to changes in market rates; and

	•	Issued by the U.S. government or highly rated financial institutions and domestic corporations, not expected to experience material changes in credit quality in the reasonably foreseeable future or for which adequate reserves would be recognized if required.

F-52

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

As such, the Company believes that the values at which such instruments are reflected in its consolidated balance sheet approximates fair value.


*(b)*	*Long-Duration Financial Instruments*

With the exception of its New York UCAP swap position, the Company’s derivative instruments are carried at fair value, as required by SFAS No. 133 (Note 4). The reported value of the New York UCAP swap contract was $19,233 and $2,028, as of December 31, 2007 and 2006, respectively. At both dates, the reported value of the contract exceeded fair value by the $12,638 day-one loss deferred in accordance with EITF 02-3 (Note 4).

The Company’s long-duration indebtedness includes numerous tranches of variable rate debt instruments (Note 5), with differing levels of priority, security, collateral, as well as different maturity dates and stated rates of interest.


	•	As of June 1, 2007, the variable rate debt instruments issued by EBG and its subsidiaries (the EBG Debt) were recognized at fair value in conjunction with the application of purchase accounting on the opening statement of financial position of EBG (Note 3). As of December 31, 2007, the estimated fair value of the EBG Debt was approximately $1,787,148. The EBG Debt was reflected in the USPowerGen consolidated statements of financial position as of December 31, 2007 at $1,884,214. As such, the carrying value of the EBG Debt exceeded fair value by $97,066.

	•	As of December 31, 2007 and 2006, the Company estimates that the fair value of debt instruments issued by its Astoria subsidiary (the Astoria Debt) was approximately $628,172 and $696,700, respectively. The Astoria Debt was reflected in the USPowerGen consolidated statements of financial position as of December 31, 2007 and December 31, 2006 at $647,475 and $691,775, respectively. As such, the carrying value of the Astoria Debt exceeded fair value by $19,303 as of December 31, 2007, and was exceeded by the fair value at December 31, 2006 by $4,925.

As such, the carrying value of USPowerGen’s consolidated long duration debt exceeded fair value by $116,369 as of December 31, 2007, and was approximately $4,925 less than fair value as of December 31, 2006.

The table below provides a summary of the carrying value and estimated fair value of USPowerGen’s long duration financial instruments as of December 31, 2007 and December 31, 2006:


	December 31, 2007									December 31, 2006
	Fair value			Carrying value			Difference			Fair value			Carrying value		Difference

Derivative instruments	$	(95,711	)		(83,073	)		(12,638	)		(6,708	)		5,930		(12,638	)
EBG Debt		1,787,148			1,884,214			(97,066	)		—			—		—
Astoria Debt		628,172			647,475			(19,303	)		696,700			691,775		4,925

Total long-duration financial instruments	$	2,319,609			2,448,616			(129,007	)		689,992			697,705		(7,713	)


(7)	Goodwill and Intangible Assets

The Company and its Predecessor account for goodwill and other intangible assets in accordance with SFAS No. 141 and SFAS No. 142. As such, Goodwill and intangible assets have been recorded in connection with the Combination and the MDP Acquisition, respectively.

F-53

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Under SFAS No. 142, purchased goodwill and intangible assets with indefinite lives are not amortized, but instead are tested for impairment at least annually. Intangible assets with finite lives, consisting of emissions allowances, unmitigated capacity sales contracts, and fuel supply and transportation contracts, are amortized over their useful lives. SFAS No. 142 requires that goodwill impairment testing be conducted at the reporting unit level, which can be at the operating segment level as defined by Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information (SFAS No. 131), or one level below the operating segment. The Company has determined that the operating segment is the appropriate reporting unit for the purpose of conducting its impairment assessments. In conducting its impairment test, the Company compares the carrying value to the estimated fair value of goodwill capitalized by each operating segment. At any point in time, should the Company determine that the carrying value of goodwill exceeds fair value, it will determine and recognize an appropriate impairment estimate on a current basis. For the periods ended December, 31, 2007, December 31, 2006, and December 31, 2005 the Company did not recognize any charges related to the impairment of capitalized goodwill.


*(a)*	*Goodwill*

The following table summarizes the changes in carrying value of goodwill for the Company:


	Astoria		EBG		Total

Balance at December 31, 2006	$	21,679		—		21,679
Goodwill acquired, net of purchase price adjustments		—		807,414		807,414

Balance at December 31, 2007	$	21,679		807,414		829,093


*(b)*	*Intangible Assets*

The Company and its Predecessor recognize specifically identifiable intangibles when specific rights and contracts are acquired. The Company and its Predecessor have no intangible assets with indefinite lives. Hence, all capitalized intangible assets recognized, which consist of emissions allowances, gas transportation contracts, and unmitigated capacity sales contracts, are amortized over the estimated remaining useful lives of such intangible assets. Emissions allowances are amortized on the basis of units of production while transportation and unmitigated capacity sales contracts are amortized based on contractual volume levels. The amortization of emissions allowances, transportation contracts, and unmitigated capacity sales contracts are recognized as a component of fuel expense.

Pursuant to provisions of both SFAS No. 144 and SFAS No. 142, the Company evaluates its intangible assets for impairment annually, or more frequently upon learning that events or changes in circumstances have occurred, which might indicate that a given intangible asset, or class of intangible asset had been impaired. As a result of the purchase allocation work undertaken to record the Combination, the Company became aware that the market value of various emission allowances had declined which indicated that the carrying value of the emissions allowances may not be recoverable.

The Company tested for recoverability, in accordance with SFAS No. 144, by estimating the future cash flows of emission allowances. Upon concluding that an impairment charge was warranted, the Company determined the fair value of the emission allowances as of December 31, 2007, using the discounted cash flow method. The Company recorded an impairment charge of approximately $4,964 on certain previously capitalized emissions allowances. This impairment charge relates to excess emissions allowances that are held for sale at Astoria and recorded at the lower of carrying value or fair value less cost of disposal. For the

F-54

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

period ended December 31, 2007, the impairment charge was included as a component of fuel expense in the Company’s consolidated statements of operations.

The following table provides a summary of the carrying values of the Company’s intangible assets as of each respective balance sheet date, as well as the transactions recognized during the reporting periods included herein:


				Contracts
	Emissions			Gas			Unmitigated
As of December 31, 2007	allowances			transportation			capacity sales			Total

January 1, 2007	$	30,188			17,040			1,120			48,348
SFAS No. 144 Impairment		(4,964	)		—			—			(4,964	)
Additions/acquisitions		124,800			74,623			—			199,423
Dispositions and expirations		(7,427	)		—			—			(7,427	)

Adjusted gross amount		142,597			91,663			1,120			235,380
Less accumulated amortization		(10,813	)		(11,165	)		(1,120	)		(23,098	)

Net carrying amount	$	131,784			80,498			—			212,282


				Contracts
	Emissions			Gas			Unmitigated
As of December 31, 2006	allowances			transportation			capacity sales			Total

February 24, 2006	$	32,638			17,040			1,120			50,798
Dispositions and expirations		(2,450	)		—			—			(2,450	)

Adjusted gross amount		30,188			17,040			1,120			48,348
Less accumulated amortization		(6,148	)		(5,012	)		(560	)		(11,720	)

Net carrying amount	$	24,040			12,028			560			36,628

The following table presents the amortization of intangible assets recognized as an expense during the periods ended December 31, 2007, February 23, 2006, December 31, 2006, and December 31, 2005:


	Successor				Predecessor
	Year ended		February 24, 2006 —		January 1, 2006 —		Year ended
	December 31, 2007		December 31, 2006		February 23, 2006		December 31, 2005

Emissions Allowances	$	4,666		6,148		512		4,162
Gas Transportation Contracts		6,153		5,012		1,855		(1,125	)
Unmitigated Capacity Sales Contracts		560		560		—		—
SFAS No. 144 Impairment		4,964		—		—		—

Total	$	16,343		11,720		2,367		3,037

F-55

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Based upon the Company’s current intangible assets and the related values estimated as of December 31, 2007, the following amounts are expected to be recognized as amortization expense during the future periods noted:


Years Ended December 31,

2008	$	13,776
2009		6,560
2010		5,971
2011		6,119
2012		6,491
2013 and thereafter		173,365

As of December 31, 2007, the dollar-weighted average amortization period of the Company’s unamortized emissions allowances and capitalized gas transportation contracts were 7.8 and 11.1 years, respectively. In aggregate, the dollar-weighted average of all unamortized intangible assets at December 31, 2007 was approximately 9.1 years.


(8)	Benefit Plans and other Postretirement Benefits

The Company’s employees are eligible to participate in certain defined contribution and defined benefit plans. Additionally, certain groups of employees are eligible for subsidized postretirement medical benefits.


*(a)*	*Defined Contribution*

Substantially all of USPowerGen’s employees are eligible to participate in defined contribution (401(k) or 401(a)) savings plans that are sponsored by the Company. Under these plans, eligible employees may contribute a portion of their compensation which is matched by the Company. In addition to matching, the Company can make a discretionary profit sharing match.

Astoria sponsors the Astoria Generating Co., LP Plan. This employee savings plan is a tax-qualified plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the Code), and includes a cash or deferred arrangement under Section 401(k) of the Code for substantially all of its employees.

Under the Plan, participating employees may contribute a portion of their compensation, pre tax or after-tax, generally up to a maximum of 18% of compensation. The savings plan’s matching contribution of 100% of the first 6% of the participating employee match, plus 2% discretionary profit sharing match and a discretionary annual employer contribution of up to 3%. Union employees may contribute and receive a match based on the terms of their collective bargaining agreement. The savings plan benefit expenses for this plan were $1,359 for the year ended December 31, 2007, $493 for the period from February 24, 2006 to December 31, 2006, and $64 for the period from January 1, 2006 to February 23, 2006.

EBG sponsors the BG Boston Services LLC Union Retirement 401(k) Plan, the BG New England Power Services, Inc. Union Retirement 401(k) Plan (collectively the EBG Union Plans), and the BG New England Power Services, Inc. 401(k) Plan (the EBG non-Union Plan). Under the plans, participating employees may contribute a portion of their compensation, pre tax or after tax, generally up to a maximum of 18% of their compensation. The Union Plans’ matching contribution is 50% of the first 3% of the participating employee match. The non-Union Plan’s matching contribution is 100% of the first 5% of the participating employee match. Union employees may contribute and receive a match based on the terms of their collective bargaining agreement. The savings plan benefit expenses of these plans were $324 for the year ended December 31, 2007.

F-56

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


*(b)*	*Defined Benefit Plans*

In September 2006, the FASB issued SFAS No. 158. This statement requires an employer that sponsors one or more single-employer defined benefit plans to recognize the funded status of a benefit plan in its statement of financial position with an offset to OCI, and to recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. SFAS No. 158 was effective for publicly traded companies with fiscal years ending after December 15, 2006, and for privately held companies no later than fiscal years ending after June 15, 2007. The Company’s financial statements reflect the adoption of SFAS No. 158 as if it had been a public company at December 31, 2006. The following table summarizes the effect of applying SFAS No. 158 at December 31, 2006:


	Before application of						After application of
	SFAS No. 158			Adjustments			SFAS No. 158

Deferred income tax assets	$	—			31			31
Liability for pension and other post employment benefits		(20,549	)		2,479			(18,070	)
Deferred income tax liabilities		—			(118	)		(118	)
Accumulated other comprehensive income		—			(2,392	)		(2,392	)

Total assets	$	1,104,544			31			1,104,575
Total liabilities	$	(780,126	)		2,361			(777,765	)

Total members’ capital	$	(324,418	)		(2,392	)		(326,810	)


*(c)*	*Pension Plans*

In connection with the Combination, the Company assumed responsibility of the assets and liabilities of the BG New England Power Services, Inc. Pension Plan (BG Plan). The BG Plan covers approximately 100 of the Company’s Boston generation facility employees. Approximately 80 of these employees accrue a future service only cash balance benefit equal to 3% of covered pay each year. Approximately 20 of these employees accrue benefits under a traditional defined benefit formula. These benefits were grandfathered as a result of a pre-2004 collective bargaining agreement. The disclosures below includes the BG Plan.

The net periodic pension cost related to USPowerGen and its Predecessor consists of the following components:


	Successor						Predecessor
				February 24,			January 1,
				2006			2006
	Year ended			through			through			Year ended
	December 31,			December 31,			February 23,			December 31,
	2007			2006			2006			2005

Service cost	$	1,751			1,363			268			1,446
Interest cost on benefit obligations		1,657			1,163			235			1,183
Expected return on plan assets		(1,483	)		(931	)		(179	)		(935	)
Net amortization		(23	)		—			31			74

Net periodic benefit cost	$	1,902			1,595			355			1,768

F-57

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

A comparison of the pension benefit obligation and pension assets as of December 31, 2007 and December 31, 2006 is as follows:


				February 24			January 1
	Year ended			through			through
	December 31,			December 31,			February 23,
	2007			2006			2006

Change in benefit obligation:
Beginning of period	$	26,943			26,885			24,645
Service cost		1,751			1,363			268
Interest cost		1,657			1,163			235
Benefits paid		(357	)		(154	)		(28	)
Addition from Combination		1,227			—			—
Actuarial (gain) loss		(2,884	)		(2,314	)		1,765

End of period	$	28,337			26,943			26,885

Change in plan assets:
Beginning of period	$	17,637			14,370			13,818
Actual investment return		1,709			1,570			580
Employer contributions		2,539			1,851			—
Addition from Combination		416			—			—
Benefits paid		(357	)		(154	)		(28	)

End of period	$	21,944			17,637			14,370

Reconciliation of funded status:
Funded status	$	(6,393	)		(9,306	)		(12,515	)
Unrecognized prior service costs		—			—			287
Unrecognized actuarial loss		—			—			5,606

Net amount recognized	$	(6,393	)		(9,306	)		(6,622	)

Amounts recognized in the Company’s consolidated balance sheets were as follows:


	December 31,		December 31,
	2007		2006

Noncurrent liabilities	$	6,393		9,306
Other comprehensive income	$	840		(2,392	)

Amounts recognized in accumulated other comprehensive income that has not yet been recognized as components of net periodic benefit cost were as follows:


	December 31,		December 31,
	2007		2006

Net gain	$	3,002		2,954

F-58

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Other changes in plan assets and benefit obligations recognized in other comprehensive income are as follows:


						January 1, 2006
	Year ended			Year ended		through
	December 31,			December 31,		February 23,
	2007			2006		2006

Current year actuarial gain	$	3,208			3,086		—
Amortization of actuarial gain		(3	)		—		—

Total recognized in other comprehensive income	$	3,205			3,086		—

The estimated net actuarial gain that would be amortized from accumulated other comprehensive income into net periodic benefit cost during the year ended December 31, 2008 for the defined benefit pension plan is $273.

The following table presents the balances of significant components of USPowerGen’s pension plans:


	December 31,		December 31,
	2007		2006

Projected benefit obligation	$	28,337		26,943
Accumulated benefit obligation		23,770		19,766
Fair value of plan assets		21,944		17,637

Estimated benefit payments for the next ten years are as follows:


2008	$	567
2009		697
2010		850
2011		973
2012		1,216
2013 — 2017		9,289

The following table presents the significant assumptions utilized to calculate USPowerGen’s benefit obligations and net periodic benefit cost for the respective periods ending:


	Successor						Predecessor
	December 31,			December 31,			February 23,			December 31,
	2007			2006			2006			2005

*Benefit Obligation:*
Discount rate		6.72	%		6.00	%		5.50	%		5.75	%
Rate of compensation increase		3.05			3.00			3.00			3.00
*Benefit Expense:*
Discount rate		6.01			5.50			5.75			5.75
Rate of compensation increase		3.05			3.00			3.00			3.00
Expected return on plan assets		8.05			7.50			7.50			7.50

USPowerGen and its Predecessor use December 31 of each respective year as the measurement date for the Company’s pension plans. Long-term rates of return on pension plan assets take into consideration expected inflation, current dividend yields, expected corporate earnings growth, and risk premiums based on each asset category. Discount rate assumptions are based upon current rates at which associated liabilities

F-59

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

could be currently settled at the end of each plan year. Underlying rates are based on bond yields that have a rating of Aa or better by Moody’s or a rating of AA or better by S&P.

USPowerGen manages the investments associated with its pension plans with the objective to exceed on a net-of-fee basis the rate of return of certain performance benchmarks. Target investment for the assets are 50% domestic equity, 20% international equities, and 30% fixed income. The Company’s weighted average allocation was as follows at December 31, 2007 and December 31, 2006:


	December 31,			December 31,
Asset class	2007			2006

US equity		44	%		45	%
International equity		29			29
Fixed income		27			26

The Company expects to pay $1,785 in cash contributions in 2008.


*(d)*	*Postretirement*

Certain USPowerGen and Predecessor employees participate in postretirement medical benefits. These benefits include reimbursement for prescription medical costs, etc. The net periodic pension cost related to USPowerGen and its Predecessor consists of the following components:


	Successor				Predecessor
			February 24,		January 1,
			2006		2006
	Year ended		through		through			Year ended
	December 31,		December 31,		February 23,			December 31,
	2007		2006		2006			2005

Service cost	$	282		200		38			236
Interest cost on benefit obligations		524		343		67			395
Net amortization		—		—		(7	)		6

Net periodic benefit cost	$	806		543		98			637

F-60

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

A comparison of the benefit obligation and benefit assets as of December 31, 2007 and December 31, 2006 is as follows:


	Year ended			February 24 to			January 1 to
	December 31,			December 31,			February 23,
	2007			2006			2006

Change in benefit obligation:
Beginning of period	$	8,764			7,496			7,059
Service cost		282			200			38
Interest cost		524			343			67
Participant contributions		16			16			—
Benefits paid		(59	)		(57	)		(13	)
Actuarial loss (gain)		2,288			766			345

End of period		11,815			8,764			7,496

Change in plan assets:
Beginning of period		—			—			—
Employer contributions		43			41			13
Participant contributions		16			16			—
Benefits paid		(59	)		(57	)		(13	)

End of period		—			—			—

Reconciliation of funded status:
Funded status		(11,815	)		(8,764	)		(7,496	)
Unrecognized prior service costs		—			—			(188	)
Unrecognized actuarial loss		—			—			1,041

Net amount recognized	$	(11,815	)		(8,764	)		(6,643	)

Amounts recognized in the Company’s consolidated balance sheets were as follows:


	December 31,		December 31,
	2007		2006

Noncurrent liabilities	$	11,815		8,764

Amounts recognized in accumulated other comprehensive income that have not yet been recognized as components of net periodic benefit cost were as follows:


	December 31,		December 31,
	2007		2006

Net loss	$	2,288		766

F-61

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Other changes in plan assets and benefit obligations recognized in other comprehensive income are as follows:


					January 1,
	Year ended		Year ended		2006 to
	December 31,		December 31,		February 23,
	2007		2006		2006

Net loss	$	1,653		694		—

Total recognized in other comprehensive income	$	1,653		694		—

The estimated net actuarial loss that would be amortized from accumulated other comprehensive income into net periodic benefit cost during the year ended December 31, 2008 for the defined benefit pension plan is $142.

The following table presents the significant assumptions for the respective periods ending:


	Successor						Predecessor
	December 31,			December 31,			February 23,			December 31,
	2007			2006			2006			2005

*Benefit Obligation:*
Discount rate		6.75	%		6.00	%		5.50	%		5.75	%
Rate of compensation increase		3.00			3.00			3.00			3.00
Health care trend rates assumed for next year		7.25			7.50			9.00			9.00
Rate to which the cost trends are assumed to gradually decline		5.50			5.50			5.50			5.50
Year that the rate reaches the rate to which it is assumed to decline		2015			2015			2011			2011
*Benefit Expense:*
Discount rate		6.00			5.50			5.75			5.75
Rate of compensation increase		3.00			3.00			3.00			3.00

The Company took into consideration expected inflation, current dividend yields, expected corporate earnings growth and risk premium in determining its postretirement benefits.


	Increase		Decrease

Impact on service and interest costs	$	275	$	(211	)
Impact on accumulated postretirement benefit obligation		2,461		(1,936	)

The Company expects to pay $105 in cash contributions in 2008.

Estimated benefit payments for the next ten years are as follows:


2008	$	105
2009		159
2010		217
2011		283
2012		370
2013 — 2017		3,243

F-62

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


(9)	Equity-Based Compensation

In connection with the MDP Acquisition, Astoria granted 1,086 Series B Units to various parties, including 700 Series B Units to certain employees, including the named executive officers. The issuance of the Series B Units was governed by Astoria’s Amended and Restated Operating Agreement and the provisions relevant to participating employees were governed under the terms of an Executive Stock Purchase Agreement. The Series B Units, being profit interests for tax purposes, were issued to participants for no consideration and generally provide that the holder thereof is not entitled to participate in any distribution by Astoria until holders of the Series A Units have received their investment amount plus a specified rate of return on their investment. The aggregate percentage of distributions to which holders of Series B Units are entitled vary based on the aggregate internal rate of return of the Series A Unit holders. The Series B Units are subject to vesting, with two-thirds of such Series B Units vesting ratably over a five-year period and subject to accelerated vesting in certain circumstances and the remaining one-third of such Series B Units vesting upon the occurrence of a substantial liquidity event, in each case as long as the executive officer was employed by Astoria at such vesting date.

In connection with the Combination, each holder of Series B Units exchanged them for an equal number of New Series B Units of New Astoria. The New Series B Units are subject to vesting, with two-thirds of such New Series B Units vesting ratably over a five-year period. Upon the occurrence of certain events, 100.00% of the New Series B Units would then be subject to a modified five-year schedule, vesting on a daily basis, and subject to accelerated vesting in certain circumstances. Upon completion of certain liquidity events, all unvested New Series B Units will commence vesting in accordance with the schedule set forth above, subject to upwards adjustment in accordance with the increase from 66.67% to 100.00% of the New Series B Units then available for vesting, in each case as long as the executive officer was employed by Astoria at such vesting date. New Astoria is a shareholder of USPowerGen. Pursuant to SFAS No. 123(R), the Company accounts for the New Series B Units (and previously the Series B Units) as compensation expense. The New Series B Units (and Series B Units) reflect share-based payments from a related party to employees of the Company for services provided to the Company. No incremental compensation cost was recognized as a result of this modification. The number of authorized New Series B Units as of December 31, 2007 were 1,037.5.

The fair value of the Series B Units was estimated on the date of grant using a binomial lattice option pricing model. The following table shows the change in the outstanding balance for the Company:


				Weighted average
				grant date
	Units			fair value
	(actual)			per unit

Granted — February 23, 2006		567		$	4
Granted — December 31, 2006		105			122

Outstanding as of December 31, 2006		672			23
Granted — February 16, 2007		28			130
Repurchased		(48.5	)		16
Cancelled		(28.5	)

Outstanding as of December 31, 2007		623			29

Vested at December 31, 2007		83

During 2007, the Company repurchased 48.5 New Series B Units and cancelled 28.5 New Series B Units in connection with the departure of an executive officer. The 28.5 New Series B Units that were cancelled will be available for granting by the Company. The Company repurchased the 48.5 New Series B Units for $6,000.

F-63

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

As a result of the repurchase of 48.5 units and cancellation of 28.5 units, $1,200 of expense was recognized due to the modification, of which $241 had already been recognized up to the point of modification. As part of the transaction involving the executive officer’s departure, the Company paid $3,000 to the executive during the twelve months ended December 31, 2007 and became obligated to pay $1,500 on July 30, 2008 and $1,500 on July 30, 2009. Excluding the cash outflow of $3,000, the New Series B Units did not have any further impact on the Company’s consolidated statements of cash flow.

The fair value of the New Series B Units was calculated by utilizing the purchase price of the MDP Acquisition as a basis for the February 23, 2006 grant, and an income approach for the December 31, 2006, and February 16, 2007 grants. The income approach was based upon discounted cash flow models. In determining the allocation between Series A Units, and New Series B Units, an option pricing methodology was utilized. The key assumptions in determining the option pricing methodology are as follows:


	Grant date			Grant date			Grant date
	February 23,			December 31,			February 16,
	2006			2006			2007

Expected volatility		40.00	%		33.00	%		32.00	%
Risk-free rate		4.70			5.00			4.94
Expected term (in years)		2.60			1.80			1.60
Dividend yield		—			—			—
Discount for lack of marketability		31.50			19.40			18.20

Expected volatility was based on implied volatilities from traded shares of publicly owned stock within the independent power generation industry. The expected term of the New Series B Units was based on management’s expectation of an exit event in September 2008. The risk free rate reflects the yield on U.S. Treasury constant maturities for the corresponding expected term. The discount for lack of marketability was computed using a multi-period binomial option pricing model utilizing the assumptions above where the discount is expressed as a ratio of the put option value to the exercise price.

The following table summarizes the Company’s compensation expense recognized as well as the total nonvested compensation expense not yet recognized as of December 31, 2007, and 2006. The stock compensation expense is included as part of general and administrative expenses:

Non-vested

Weighted average

Compensation

compensation expense

period of expected

expense

yet to be recognized⁽²⁾

recognition

Predecessor:

January 1 to February 23, 2006

—

Successor:

February 24, 2006 to December 31, 2006

277

15,065

4.2 years

Year ended December 31, 2007

5,031

⁽¹⁾

13,628

3.2 years

⁽³⁾


(1)		Includes $969 related to the departure of an executive.

(2)		Includes one-third of New Series B Units that vest only upon the occurrences of a substantial liquidity event.

(3)		33.3% of the New Series B Units begin vesting on a daily basis upon the occurrence of a substantial liquidity event.

F-64

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


(10)	Income Taxes

The Company accounts for income taxes in accordance with Statement of Financial Standards No. 109, Accounting for Income Taxes (SFAS No. 109). As wholly-owned subsidiaries of USPowerGen resulting from the Combination, Astoria and EBG file a combined federal income tax return with USPowerGen.

Prior to June 1, 2007, Astoria was a limited liability company and therefore items of income and expense were allocated to its members in their respective tax returns.

Through March 30, 2006, EBG was a limited liability company and therefore items of income and expense were allocated to its members in their respective tax returns. EBG made an election, on March 30, 2006 and the Internal Revenue Service approved the election on May 15, 2006, to be taxed as a C corporation under the Internal Revenue Code for all periods beginning on and after March 31, 2006.

For the period ended February 23, 2006 the Predecessor’s taxable income is included in the consolidated tax returns of Reliant Energy. The Predecessor recorded tax expense of $748 related to New York City unincorporated business tax.

For the period from June 1 to December 31, 2007, Astoria became a disregarded entity for federal income taxes. USPowerGen and its subsidiaries intend to establish a tax sharing agreement whereby the subsidiaries will be reimbursed for taxes and federal net operating losses (NOLs) that they may generate. The income taxes presented here for 2007 reflect the combined entities. The 2006 presentation is for Astoria as a limited liability company. All of the Company’s operations and taxable income is generated within the United States of America (U.S.).

The Company’s provision (benefit) for income taxes consists of the following:


	Current		Deferred			Total

US PowerGen Consolidated Year ended December 31, 2007:
U.S. Federal	$	—		(34,675	)		(34,675	)
State & local		3,888		(5,092	)		(1,204	)

	$	3,888		(39,767	)		(35,879	)


	Current		Deferred			Total

Astoria — Successor Year ended December 31, 2006:
U.S. Federal	$	—		(56	)		(56	)
State & local		530		177			707

	$	530		121			651

Astoria — Predecessor Period ended February 23, 2006:
U.S. Federal	$	—		—			—
State & local		748		—			748

	$	748		—			748

F-65

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Current and noncurrent deferred tax assets and liabilities consist of the following:


	December 31,
	2007
	USPowerGen			2006
	consolidated			Astoria

Deferred tax assets:
Accrued vacation	$	395			83
Accrued bonus		491			—
Derivatives assets and liabilities, net		12,103			1
Distrigas liquidated damages and late fees dispute		7,129			—
Premium on debt		17,831			—
Deferred financing costs		17,196			—
SFAS No. 158 adjustment to pension and postretirement benefits		—			31
Other		2			—
Applicable high yield discount obligation		13,296			—
Book amortization of deferred charges		11,054			94
Derivatives assets and liabilities, net		29,202			—
Impairment of emissions allowances		2,271			—
Net operating loss carryforward (federal and state)		34,195			—
Other		2,169			12

Gross deferred tax assets		147,334			221
Valuation allowance		(34,195	)		—

Net deferred tax assets		113,139			221

Deferred tax liabilities:
Derivatives assets and liabilities, net		(5,879	)		—
Other		(1,437	)		—
Depreciable assets		(673,634	)		(169	)
Intangible assets		(14,702	)		—
Derivative assets and liabilities, net		(2,942	)		(138	)
Distrigas liquidated damages and late fees dispute		(22,834	)		—
Emissions allowances		(47,771	)		—
Capitalized interest rate amortization		(760	)		—
Other		(1,359	)		(121	)

Total deferred tax liabilities		(771,318	)		(428	)

Net deferred tax liabilities	$	(658,179	)		(207	)

For the year ended December 31, 2007, the Company’s net deferred tax liability increased by $657,972 which was primarily the result of the liability established through the purchase accounting recorded in connection with the Combination. As of December 31, 2007, the Company had an income tax payable of $2,317.

Pursuant to a proposed intercompany tax sharing agreement, federal NOLs can be used to offset taxable income generated by USPowerGen’s Astoria subsidiary. The federal and state NOLs that were assumed as part of the Merger are limited pursuant to IRC Section 382 and therefore a full valuation allowance has been taken on these NOLs. After assessment of the positive and negative evidence, the Company believes that it is not more likely than not that the Company will be able to utilize the federal NOLs in excess of USPowerGen’s federal taxable income and the full state NOLs generated since June 1 and therefore, a valuation allowance of $34,195 is recorded at December 31, 2007.

F-66

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

The following is a reconciliation of the U.S. federal statutory rate of 35% to the Company’s effective income tax rate:


	USPowerGen — Successor
	December 31, 2007

Tax computed at statutory rate	$	(34,350	)	35.0	%
State and local income tax provision, net of federal income tax effect		(2,094	)	2.2
Nondeductible interest expense on Mezzanine Facility		1,358		(1.4	)
Effect of change in taxable entity		(4,896	)	4.9
Effect of change in tax rate		(3,200	)	3.2
Valuation allowance on net deferred tax assets		6,020		(6.0	)
Nondeductible compensation expense and other permanent differences		1,283		(1.3	)

	$	(35,879	)	36.6


(11)	Net (Loss) Income Per Common Share

Basic net (loss) income per common share is net (loss) income available to common shareholders divided by the weighted average of common shares outstanding during the period. Diluted net (loss) income per common share is calculated using the weighted average of common shares outstanding adjusted to include the effect that would occur if the 650,000 warrants were exercised.

The computation of basic and diluted net (loss) income per common share is as follows:


	Successor									Predecessor
	Year ended					February 24, 2006 through				January 1, 2006 through				Year ended
	December 31, 2007					December 31, 2006				February 23, 2006				December 31, 2005
	Income			Shares		Income		Shares		Income		Shares		Income		Shares

Net (loss) income	$	(62,266	)		—		16,923		—		18,449		—		276,193		—
Net (loss) income available for common stockholders		(62,266	)		423,223		16,923		252,231		18,449		252,231		276,193		252,231
Basic and diluted net (loss) income per common share	$	(0.15	)		—		0.07		—		0.07		—		1.10		—


(12)	Segment Reporting

The Company manages and evaluates its business on the basis of the geographic regions, New York and Boston, in which its wholesale power generation facilities operate. These segments have distinct operating results and management structures under which senior management evaluates their performance. Prior to the Combination (Note 3), the Company and its Predecessors operated in one operating segment, New York, whose operations are reflected in the consolidated financial statements. The following tables summarize the results of operations and financial position of the Company’s segments along with its corporate expenses and

F-67

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

any eliminating items. All revenues are from external customers and there were no significant corporate allocations or intercompany transactions.


	Statement of consolidated operations
	for the year ended December 31, 2007
	New York		Boston⁽¹⁾			Corporate			Eliminations		Consolidated

Revenues	$	582,114		600,605			—			—		1,182,719
Operating expenses:
Fuel		269,912		509,074			—			—		778,986
Operations and maintenance		67,477		38,731			—			—		106,208
General and administrative		10,149		17,137			37,109			—		64,395
Taxes, other than income		29,124		12,447			—			—		41,571
Depreciation and amortization		28,480		53,805			—			—		82,285

Operating income (loss)		176,972		(30,589	)		(37,109	)		—		109,274
Other (income) expense:
Interest expense, net		71,793		131,594			88			—		203,475
Other expense, net		3,552		392			—			—		3,944

Net income (loss) before income tax		101,627		(162,575	)		(37,197	)		—		(98,145	)
Income tax expense (benefit)		24,871		(57,022	)		(3,728	)		—		(35,879	)

Net income (loss)	$	76,756		(105,553	)		(33,469	)		—		(62,266	)


(1)		The Boston segment reflects results of operations from the Combination date (Note 3).


	Select balance sheet information
	as of December 31, 2007
	New York		Boston		Corporate		Eliminations			Consolidated

Goodwill	$	21,679		807,414		—		—			829,093
Property, plant and equipment	$	891,597		2,624,260		—		—			3,515,857
Total assets	$	1,141,922		3,930,860		64,479		(132,795	)		5,004,466
Total long-term debt	$	647,475		1,854,714		—		—			2,502,189
Total liabilities	$	774,009		2,833,025		69,574		(81,138	)		3,595,470
Capital expenditures	$	38,007		11,028		—		—			49,035

F-68

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


(13)	Commitments and Contingent Liabilities


*(a)*	*Commitments*

The Company has the following estimated future contractual commitments, primarily related to fuel procurement and transportation services, as of December 31, 2007 (in millions):


	2008		2009		2010		2011		2012		Thereafter

Natural gas supply agreement	$	129.1		129.1		129.1		129.1		129.1		1,279.8
Long-term service agreements		27.2		27.2		27.2		23.7		—		—
Transportation services — fuel		28.6		18.0		18.0		18.0		18.0		75.6
Energy management agreements		0.8		—		—		—		—		—
Operating leases		2.0		1.9		1.7		0.9		1.0		3.7

Total	$	187.7		176.2		176.0		171.7		148.1		1,359.1

Natural Gas Supply Agreements — The Company has an agreement with Sequent under which it procures all day-ahead natural gas and all fuel for its New York facilities. Pricing for natural gas and fuel oil purchases from Sequent pursuant to this agreement is based on published indices for natural gas and fuel oil. Additionally, Sequent provides management services related to the procurement, transportation and delivery of natural gas and fuel oil to these facilities. Sequent is compensated for its services through a fee per unit of natural gas and fuel oil delivered, which is added to the price paid by the Company for natural gas and fuel oil. Sequent is paid monthly through a secured account into which certain of the Company’s electric energy revenues from the NYISO are transferred pursuant to a security agreement. Sequent has a first priority lien on these revenues. The Company receives net electric energy revenues from the secured account as long as Sequent has been paid amounts owed, to the extent the amounts due are not disputed. In the event of a dispute, the Company may nevertheless receive such revenues if it posts a letter credit for the benefit of Sequent in the disputed amount. The term of the Sequent agreement is through October 1, 2009, with automatic one-year extensions unless either party provides notice of termination at least six months prior to any such extension.

The Company has an agreement with Distrigas of Massachusetts, LLC (Distrigas) to supply Mystic 8&9 with a firm supply of natural gas from Distrigas’ natural gas facility located adjacent to those facilities (Note 17).

Long-term service agreements — The Company has two long-term services agreements with Mitsubishi Power Systems Americas, Inc. (MPS) under which MPS provides all major maintenance services, including refurbishment of spare parts, for gas turbine generators and related equipment at the Company’s Mystic 8&9, and Fore River facilities. Under these agreements, MPS receives a fixed fee (which is currently $30 per month) for monitoring this equipment and a variable fee based on the number of equivalent operating hours incurred by this equipment, and each of these fees is paid on a monthly basis. Major maintenance services are required to be performed by MPS at intervals of no more than every 8,800 equivalent operating hours for each service. The agreements also provide that MPS shall receive minimum variable fees for at least 8,600 equivalent hours for each major maintenance service. The MPS agreement expires on the earlier of the completion of the required number of planned maintenance outages or 11 years. The table above reflects the fixed payment obligations under this agreement. The Company recorded expense under this agreement of $9,632 for the year ended December 31, 2007.

Transportation services — fuel — The Company is party to agreements with Iroquois Gas Transmission System, L.P. (Iroquois) for its New York facilities under which Iroquois transports up to 50,000 dekatherms

F-69

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

per day of natural gas from Waddington to Hunts Point, New York, and up to 10,000 dekatherms per day from Brookfield to Hunts Point, New York. The contracts expire on February 1, 2013, but automatically renew for one-year terms thereafter.

The Company’s Fore River facility which is located in the Boston area is party to an agreement with Algonquin Gas Transmission Company (Algonquin) that provides natural gas transportation. This contract has a primary term of twenty years commencing September 1, 2001, and continuing on a year-to-year basis after the primary term. The agreement provides that Algonquin will transport a maximum of 140,000 dekatherms per day of natural gas from the intersection of Algonquin’s Q and I-3 systems and the inter connection of the AGT and Maritimes & Northeast pipelines to the Fore River facility. All pricing under this agreement is subject to FERC filed tariff rates.

Energy management agreements — The Company’s Boston facilities sell 100% of the electric energy, capacity and ancillary services supplied by their facilities to Sempra pursuant to an Energy Management Agreement. Under this agreement, Sempra performs all energy management services related to the power plants at our Boston Facilities, including nominating, scheduling and adjusting schedules for electricity, fuel and other related services. Electric energy, capacity and ancillary services are sold to Sempra at the same prices that Sempra receives from the sales of these products into the ISO-NE market and from other customers under bilateral contracts. Sempra receives a fixed monthly fee of $275 and a variable fee based on our Boston Facilities’ net operating margin. The table above includes the fixed rate obligations of the Company. The Company recorded an expense under this agreement of $4,712 for the year ended December 31, 2007. This agreement was terminated by mutual agreement of the parties effective April 1, 2008.

Operating Leases — The Company leases office space under operating leases, some of which are subject to rental abatements as well as escalation and cost-sharing arrangements for real estate taxes, maintenance and other operating expenses. USPowerGen recognizes the effects of scheduled rent increases, leasehold incentives and rent concessions on a straight-line basis over the lease term. Rental expense under operating leases was $1,270 for the year ended December 31, 2007, $1,130 for February 24, 2006 to December 31, 2006, $0 for January 1, 2006 to February 23, 2006, and $0 for the period ended December 31, 2005.

Other — USPowerGen also has several ongoing contracts that are paid on a retainer basis. These contracts primarily relate to certain public relations, regulatory advisors and accounting services.


*(b)*	*Contingent Liabilities*

In accordance with Statement of Financial Accounting Standards No. 5, Accounting for Contingencies (SFAS No. 5) and related guidance, USPowerGen records reserves for loss contingencies when available information indicates that the loss is probable and reasonably estimable. Due to the inherent uncertainty of litigation or threatened litigation, there can be no assurance that the Company will not incur additional charges related to the items discussed below or future adverse rulings, changes, or unfavorable developments. Such events could have a material impact on the results of operations or financial position of USPowerGen. (Note 16).

The Company and its subsidiaries are party to litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely effect USPowerGen’s consolidated financial position, results of operations or cash flows.

F-70

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


(14)	Regulatory Matters

As an independent power provider, USPowerGen’s operations are not regulated operations subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). As such, the Company does not record assets or liabilities from the regulated ratemaking processes. However, USPowerGen does operate in a highly regulated environment and is subject to various federal, state, and local regulations. Significant changes within the regulatory environment could have a material impact on the Company’s consolidated results of operations and statement of financial position.

NYISO Changes to Market Structure

On March 7, 2008, FERC approved most of NYISO’s previously proposed market power mitigation plan that sought to prevent sellers of electric energy and capacity in the NYISO market with market power from artificially raising capacity prices and also to prevent net purchasers of capacity, including the local load serving entities that provide electricity to end-users, from artificially depressing capacity prices by building uneconomic generation facilities. These measures will apply to market participants, such as the Company, that own or control more than 500 MW of New York in-city capacity (which are considered to be “pivotal suppliers” by NYISO). Under the terms of the approved plan, the bid and revenue cap previously imposed on the Company’s New York Facilities as a result of its status as a DGO, or an owner of facilities divested in 1999 by Con Ed, have been removed. However, the approved plan imposes a new bid cap on the Company’s New York Facilities. The new bid cap is equal to the higher of: (i) the market clearing price on NYISO’s administratively set installed capacity demand curve on the basis of which all qualified in-city capacity is sold; and (ii) the marginal generating unit’s net avoided costs achieved by removing the unit from operations but maintaining the unit in operating condition. Additionally, NYISO implemented market power mitigation measures to discourage future construction of uneconomic generation capacity that would artificially reduce capacity prices below just and reasonable levels. The revised market rules are being implemented prospectively, without refunds to market participants.

In the near term, the Company believes the market changes may substantially reduce capacity prices in Zone J within New York City because the new market rules ignore the 1,000 MW of recently constructed facilities in Zone J. However, the Company also believes the expected retirement in 2010 of the 885 MW New York Power Authority Poletti power generation station is likely to reduce the current surplus of capacity, leading to an increase in Zone J capacity prices at that time. The Company believes the market changes are likely to produce a more predictable capacity market, and that the removal of the DGO revenue caps will in the future increase the prices at which capacity is permitted to be sold by the Company’s New York Facilities.

In addition, the Company is party to a capacity swap that effectively exchanges a substantial portion of its installed capacity spot market auction payments for a fixed payment. The fixed payment to the Company from the counterparty on an annual basis is substantially higher than the payments that would likely result from the projected NYISO market clearing price. This contract has a stated maturity of April 30, 2009, and contains provisions that provide for modification or early termination upon certain significant regulatory changes. On May 7, 2008, the Company received notification from the counterparty that it interprets recent regulatory developments to trigger modification of the pricing provisions within the contract, and the counterparty has adjusted its payments to Astoria effective May 1, 2008. As a result of these modifications, the Company may be exposed to the NYISO market clearing price for capacity.

F-71

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


(15)	Environmental


*(a)*	*Air Initiatives*

On May 12, 2005, the EPA published the Clean Air Interstate Rule (CAIR). This rule applies to 28 eastern states, and the District of Columbia, and caps SO₂ and NO_x emissions from power plants in two phases — 2010 and 2015 for SO₂, and 2009 and 2015 for NO_x. On August 24, 2005, the EPA published a proposed Federal Implementation Plan (FIP), to ensure that generators affected by CAIR reduce emissions on schedule. In parallel actions in late 2005, the EPA proposed the second phase of the 8-hour ozone rule relating to NO_x emissions, and signed proposed revisions to address attainment of National Ambient Air Quality Standards (NAAQS) for “fine particulates” (PM2.5), which will require affected states to implement further rules to address SO₂ and NO_x emissions. Numerous environmental groups, states, and industry organizations challenged aspects of the CAIR. The challenges were consolidated into the proceeding titled South Coast Air Quality Management District v. EPA. In December 2006, the U.S. Circuit Court for the D.C. Circuit overturned portions of the EPA’s Phase I CAIR implementation rule for the new 8-hour ozone standard holding that the EPA could revoke the 1-hour standard as long as there was no backsliding from more stringent control measures. This ruling may result in the imposition of fees under Section 185 of the Clean Air Act (CAA), on volatile organic hydrocarbon (VOC) and NO_x emissions in severe ozone nonattainment areas. The fees could be as high as $7,700 per ton for emissions above 80% of baseline emissions levels. Depending on the determination of baseline emission levels, the Company’s operations may be materially affected by the 8-hour ozone standard. On July 11, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated both CAIR and its associated Federal Implementation Plan in their entirety and remanded them to the EPA. The impact of this ruling is unknown as of the date of the consolidated financial statements.

Ten Northeast, and Mid Atlantic states, including New York and Massachusetts, have agreed to participate in a mandatory regional cap and trade program known as the Regional Greenhouse Gas Initiative (RGGI). RGGI applies to electricity generator units that have a nameplate capacity of at least 25 MW, and whose use of fossil fuels is greater than 50%. From 2009 to 2015, RGGI aims to stabilize annual power sector emissions of CO₂ at the level of average annual emissions from 2000 to 2004, and from 2015 to 2018, RGGI would impose a 2.5% annual reduction to achieve an overall 10.0% reduction in CO₂ emissions.

In August 2006, a final model rule was issued that each RGGI signatory state was asked to promulgate. While there are many commonalities, RGGI will allow each state the flexibility in the distribution of its CO₂ allocations. At least 25% of each state’s allocation budget must be held toward consumer benefits such as end-use energy efficiency programs. This is generally interpreted to mean that these allowances will be auctioned for any entity (even nonpower plants) to procure. Whether through auction or allocation, companies will then be allowed to trade their allowances in a secondary market. Those facilities, which emit less CO₂ than what they have in allocations can sell those excess allowances, while those facilities, which emit more than their allocations will need to procure sufficient allowances to balance their books. One additional option that affected facilities will have is reducing CO₂ emissions from outside the plant, by what is known as obtaining offsets. However, RGGI restricts offsets to certain projects performed in certain states, and to certain total quantities below a threshold. The vast majority of CO₂ reductions are intended under RGGI to occur in-house. RGGI will run on three-year cycles (2009 through 2011; 2012 through 2014; etc.) to adjust for any particular higher-than-expected demand year.

RGGI applies to electricity generator units that have a capacity of at least 25 MW and whose use of fossil fuels (such as coal or fuel oil) is greater than 50%. The Company’s Gowanus and Narrows, Astoria GT-1 and Mystic Jet units will be exempt from RGGI because they fall below the 25 MW threshold. However, the Company’s other units, which operate using either natural gas or fuel oil, both of which emit CO₂, will be subject to RGGI which, together with other similar proposed regulations, could affect the Company’s costs of

F-72

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

operations. Under the proposed RGGI rules, affected sources will be required to purchase allowances corresponding to 100% of their CO₂ emissions beginning in January 2009. The Company may obtain a portion of its RGGI allowances through offset projects or other projects designed to reduce emissions. The Company cannot predict the effect such requirements would have on its operations, although the Company manages its operations with a goal of minimizing its emissions and supporting long-term solutions.

Massachusetts has adopted final rules and New York has issued draft rules with respect to RGGI requiring that 100% of available allowances be allocated through an open auction scheduled for September 2008. The floor price of the initial auction is $1.86 per short ton and the Company may be able to reduce costs by available offsetting activities. Companies will subsequently be allowed to trade their allowances in a secondary market. The Company’s generating portfolio includes oil- and gas-fired plants covered by RGGI that emitted approximately 7.5 million tons of CO₂, a GHG, in the year ended December 31, 2007. The majority of the Company’s generating capacity will be subject to regulation under RGGI and this will likely result in material costs associated with compliance. The Company’s power generating facilities in Massachusetts and New York are already subject to existing state-level GHG regulations. There are numerous additional proposals regarding GHG pending at the federal, state and local level. In addition, the EPA issued an Advance Notice of Proposed Rulemaking on July 11, 2008 for a request for public comment on how to respond to the U.S. Supreme Court’s decision in Massachusetts v. Environmental Protection Agency, in which the Supreme Court ruled that the Clean Air Act authorizes regulation of greenhouse gases. The Company cannot accurately predict the outcome of such Federal, State and local proposals, and many of them could adversely affect its business.

The Company’s facilities are subject to a cap-and-trade program governing NO_x emissions during the ozone season, typically from May 1 through September 30 of each year. These rules require that one NO_x allowance be held for each ton of NO_x emitted. Each of the facilities that is subject to these rules has been allocated NO_x emissions allowances. The Company estimates that the NO_x allowance portfolio total is currently sufficient to cover operations at these facilities through 2011. However, if at any point emissions allowances are insufficient for the anticipated operation of each of these facilities, the Company would be required to purchase NO_x allowances to cover any deficit, and this obligation could result in material costs.

Most of the facilities are also subject to a cap-and-trade program governing SO₂ emissions under Phase II of the Federal Acid Rain Program. The Astoria (with the exception of Astoria GT-1), Mystic (with the exception of Mystic Jet) and Fore River facilities are subject to the SO₂ emissions regulated allowance program. Similar to the NO_x program, this program requires affected units to hold adequate allowances to cover all SO₂ emissions and one SO₂ allowance must be held for each ton of SO₂ emitted over a calendar year. The Company estimates that the current SO₂ allowance is sufficient to cover operations at these facilities. However, if at any point emissions allowances are insufficient for the anticipated operation of each of these facilities, the Company would be required to purchase SO₂ allowances to cover any deficit, and the cost could be material.

In addition to these Federal cap-and-trade programs, the units at Astoria (except for GT-1) are also subject to New York state-level NO_x and SO₂ cap-and-trade programs. The NO_x program is governed by the Acid Deposition Reduction NO_x Budget Trading Program (Part 237) and is only applicable during the non-ozone season. The state-level SO₂ program is regulated under the Acid Deposition Reduction SO₂ Budget Trading Program (Part 238). Similar to the federal programs, one NO_x or SO₂ allowance must be held for each ton emitted during the relevant compliance period. We believe that our current allowances are sufficient to cover operations at these facilities. However, if at any point emissions allowances are insufficient for the anticipated operation of each of these facilities, the Company would be required to purchase NO_x or SO₂ allowances to cover any deficit, and the cost could be material.

F-73

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

The Ozone Transport Commission (OTC) was established by Congress, and governs ozone, and the NO_x budget program in states along the U.S. eastern seaboard, from Maine to Virginia. The OTC proposes to implement a regional plan containing emission reduction targets for power plants. OTC targets and timelines are yet to be implemented although additional SO₂ and NO_x reductions remain in discussion. Current attention is focused on NO_x emissions from units run primarily on High Energy Demand Days (HEDD). While it is not possible to predict the outcome of this regional effort, to the extent that the OTC is successful in implementing emission requirements that are more stringent than existing regimes, the Company could be materially affected.


*(b)*	*Water Initiatives*

The Clean Water Act requires that cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impact. In July 2004, the EPA published regulations governing cooling water intake structures at large existing power plants that withdraw more than 50 million gallons of cooling water per day. The regulations would apply to our Astoria and Mystic 7 facilities. The regulations required implementation of the BTA for minimizing adverse environmental effects and provided generating facilities with several options for achieving the required BTA. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit vacated key portions of the regulation. In July 2007, the EPA suspended the regulation. A new round of rulemaking has not been announced and it may be several years before a revised cooling water intake structure regulation is finalized.

How we implement BTA will depend upon the options provided in the EPA’s new rulemaking, and they vary for each of our affected facilities. Possibilities include upgrades of existing water intake structures and/or equipment to the construction and installation of new, extensive water intake structures and/or equipment or reducing intake water flows. Until the EPA proposes new regulations it is not possible to estimate with certainty the capital costs that will be required to comply with BTA. However, if BTA requires significant changes to the cooling water intake systems at our Astoria and Mystic 7 facilities, our costs to implement these changes may be material.

Our New York Facilities are a party to an Order on Consent with the New York State Department of Environmental Conservation (NYSDEC) pursuant to which we agreed to undertake, over time, certain environmental remediation obligations relating to historical releases of hazardous substances at those facilities. In addition, we are required to modify our cooling water intake system at the Astoria facility to minimize adverse environmental impact to marine life. These modifications are expected to result in capital and other expenditures that could be material.


*(c)*	*Domestic Site Remediation Matters*

Environmental laws, and regulations impose liability on the owner or operator of any facility, including an electric generating facility, for releases of hazardous or toxic substances or petroleum products at the facility. These laws impose liability without regard to whether the owner knew of or caused the release.

F-74

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

Assessment and Selected Remedy), remediation in a portion of Area 4 of our Astoria facility has been completed. Remedial plans for the remainder of Area 4 will be prepared and submitted to NYSDEC for approval and implementation. Selected areas at our Astoria facility have groundwater wells in which NAPL contamination has been detected. NAPL removal in seven groundwater wells is continuing as an interim remedial measure pending completion of the site-wide characterization efforts. Prior to our ownership, spills of No. 2 and No. 6 fuel oil occurred in the area of the Fuel Oil Tank Farm. In 2007, we proposed to NYSDEC to perform a remedial investigation of the Fuel Oil Tank Farm in order to determine the potential for contamination of soil and groundwater. The potential for additional groundwater clean-up obligations will not be known until the remedial investigation is completed. We have an insurance policy in place to address aggregate remediation costs at the Astoria facility. The insurance policy expires in 2009 and covers remediation costs if the cumulative total of remediation expenses exceeds a $10,000 deductible. The policy is subject to an overall limit of $100,000.

Known environmental contamination at the Narrows facility includes NAPL downgradient of that facility’s storage tanks. Prior to our ownership of this facility, a spill of No. 2 fuel oil resulted in levels of NAPL in four on-site and two off-site groundwater monitoring wells. Remediation of NAPL is in progress, in accordance with the Site Investigation and Remediation Plan via the use of vacuum enhanced fluids recovery and manual bailing. Continued removal and recovery of NAPL is required for wells with greater than 0.1 feet of NAPL in accordance with an August 23, 2002 agreement with NYSDEC.

(16) Related Parties

For the years ended December 31, 2007 and December 31, 2006, the Company engaged in the following transactions or agreements with its principal shareholders, directors, officers and affiliates. As of December 31, 2007, and December 31, 2006, there were no receivables or payables to related parties.

(a) Payments or Distributions to Principal Shareholders

The Company made payments of $18,717 and $14,743 to MDP for the years ended December 31, 2007 and December 31, 2006, respectively. The payments primarily reflected sponsor fees related to the Combination, tax distributions, and reimbursement of certain out-of-pocket expenses.

Additionally, USPowerGen made certain tax distributions and reimbursements for accounting services to Hunt Generation Investments and affiliates, also principal shareholders of the Company. For the years ended December 31, 2007 and December 31, 2006, these payments were $915 and $821, respectively. These expenses primarily related to reimbursement of management as well as tax distributions.

(b) Payments Made to Affiliates

For the years ended December 31, 2007 and December 31, 2006, the Company made payments of $5,012 and $850, respectively, to a related-party affiliation controlled by its Chairman and Chief Executive Officer. These payments related to a management agreement whereby the entity provided certain management-related services as well as a sponsor fee related to the Combination.

(c) Material Agreements with Related Parties

Upon consummation of the Combination, the Company entered into a consulting agreement with K Road (EBGs’ management company prior to the Combination), pursuant to which K Road provides advisory services to the Company in connection with its initial public offering (IPO). As consideration for such services, K Road will receive a one-time fee equal to 1% of the aggregate gross

F-75

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)

proceeds from the planned IPO, provided that the fee will not be less than $3,000. The Company has accrued $4,600 at December 31, 2007 as accrued IPO fees related to this matter.

(d) Other

Certain of the Company’s stockholders with equity ownership in excess of 5% are also investors in the Company’s debt securities.


(17)	Subsequent Events

Subsequent to December 31, 2007, and through August 12, 2008, the following occurred:


*(a)*	*New York Capacity Market Event*

On August 23, 2007, the State of New York Public Service Commission issued an order authorizing the acquisition of one of USPowerGen’s competitors, which among other things required the divestiture of a major generating facility serving the New York City marketplace, and required the acquirer to offer its unmitigated capacity in the NYISO ICAP spot auctions at an offer price of $0.00 per MWh, commencing with the March 2008 spot auction, and continuing until the divestiture is completed. On February 26, 2008, the NYISO concluded the March 2008 spot market auctions at the Rest of State market clearing prices of $1.05 per MWh. Historically, the locational market clearing prices for the New York City market had closed at prices in excess of the Rest of State equilibrium.


*(b)*	*Natural Gas Supply Contract — (Distrigas Agreement)*

The Company executed (i) a Settlement and Release Agreement entered into as of April 18, 2008 to settle all the claims, (ii) an Amended and Restated Firm Gas Sales and Purchase Agreement (ARGA) effective April 11, 2008, and (iii) a Non-Firm Gas Sales and Purchase Agreement.


i.	Settlement and Release Agreement

As of December 31, 2007, the Company was in litigation with Distrigas in Suffolk County, Massachusetts, Superior Court with respect to two 20-year fuel agreements. Under the original agreements, the Company was required to purchase at least 1,400,000 MMBtu of gas per week from Distrigas. Distrigas alleged that the Company was liable for approximately $40,100 in liquidated damages, unpaid gas invoices and late payment fees as of December 31, 2007. The Company has agreed to pay $18,175 plus accrued interest of $91 in full satisfaction of the amounts past due for liquidated damages and disputed gas invoices. The Company had $18,175, $37,458, and $29,900 accrued for this purpose as of December 31, 2007, June 1, 2007 and December 31, 2006, respectively. On June 1, 2007, the Company recorded an adjustment to reduce the accrual to the agreed upon settlement and reflected the adjustment as an increase to goodwill as of June 1, 2007, the date of the Combination.


ii.	Amended and Restated Firm Gas Sales and Purchase Agreement (ARGA)

The ARGA amends and replaces the existing Firm Gas and Purchase Agreement. The terms of the new agreement are as follows:


	•	Term is extended to December 3, 2027.

	•	Allows the Company to purchase firm weekly quantities (FWQs) at a price determined by the TETCO M3 pricing point, with additional gas volumes priced at the Algonquin City Gate for the first five years

F-76

US POWER GENERATING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

December 31, 2007

(Dollars in thousands)


		of the agreement. The price reverts to the Algonquin City Gate less $0.20 per MMBtu for the remaining term of the contract. FWQs are adjusted on a monthly basis to reflect seasonal operations and are subject to certain provisions that allow the Company to reduce FWQ’s up to 350,000 MMBtu per week with proper notification.


	•	The Company also has a weekly balancing tolerance of up to plus or minus 10,000 MMBtu without incurring liquidated damages.

	•	The Company provided a letter of credit in the amount of $50,000 subject to an adjustment five months after the execution of the ARGA based on the Company’s credit rating, and terms of the existing loan documents. In any case, the amount of the letter of credit is not to exceed $75,000, and not to be less than $35,000.


iii.	Non-Firm Gas Sales and Purchase Agreement

The Company and Distrigas entered into a Non-Firm Sales and Purchase Gas Agreement, which provides Distrigas with the right but not the obligation to supply up to 100% of the natural gas required at Mystic 7. This agreement also contains certain option rights for Distrigas that had been in the previous gas agreement.

The net intangible value of the agreement as of December 31, 2007 is $74,312. The Company recorded the impact of the new agreement as of June 1, 2007, the date of the Combination.


*(c)*	*Boston Capacity Market Event*

On December 1, 2006, ISO-NE implemented changes in the capacity market whereby companies could sell capacity as part of the FERC-approved Forward Capacity Market (FCM) structure. The structure has two main components, a settlement period and forward capacity auctions. During the settlement period, power generators supplying capacity will receive fixed transition payments of $3.05/kW-month from June 1, 2007 through May 31, 2008, $3.75/kW-month from June 1, 2008 through May 31, 2009, and $4.10 /kW-month from June 1, 2009 to May 31, 2010.

The first FCM auction covering the period June 1, 2010 through May 31, 2011 was held on February 2008. The market cleared at the floor price of $4.50/ kW-month with an excess of 2,047 MWs. The revenue will be prorated among all of the MWs. All of the Company’s available capacity was sold along with an additional 31.3 MW of winter only capacity.

With the initial FCM auction clearing at the floor price of $4.50/kW-month, the Company believes that future revenues derived from the sale of its Boston capacity will likely fall short of amounts previously projected. As such, the Company has determined that the initial FCM auction represents a trigger event, as defined under SFAS No. 142 requiring an interim assessment of goodwill impairment. As such, the Company evaluated: (i) the impact of the FCM auction results on its capacity revenue projections through May 31, 2011; (ii) the potential impact of subsequent FCM auctions on its capacity revenues beyond May 31, 2011; and (iii) the resultant impact on its estimate of the Company’s enterprise value. The Company recorded a goodwill impairment of $250,067 during the quarter ended March 31, 2008.

F-77

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

EBG Holdings, LLC and Subsidiaries:

We have audited the accompanying consolidated balance sheets of EBG Holdings LLC and subsidiaries as of May 31, 2007 and December 31, 2006, and the related consolidated statements of operations, members’ capital and comprehensive income, and cash flows for the five months ended May 31, 2007 and for each of the years in the two-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EBG Holdings LLC and subsidiaries as of May 31, 2007 and December 31, 2006 and the results of their operations and their cash flows for the five months ended May 31, 2007 and for each of the years in the two-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in note 3 to the accompanying consolidated financial statements, the consolidated balance sheet as of December 31, 2005 and the related consolidated statements of operations, members’ capital, and cash flows for the years ended December 31, 2006 and December 31, 2005 have been restated.

/s/ KPMG LLP

Boston, Massachusetts

August 12, 2008

F-78

EBG HOLDINGS LLC AND SUBSIDIARIES

Consolidated Balance Sheets
May 31, 2007 and December 31, 2006
(Dollars in thousands)


				December 31,
	May 31,			2006
	2007			Restated

ASSETS
Current assets:
Cash and cash equivalents	$	1,952			8,079
Restricted cash		114,084			162,706
Accounts receivable		49,489			61,236
Derivative assets		11,384			33,395
Fuel inventory, materials and supplies		17,712			20,186
Prepaid expenses and other current assets		15,052			10,971

Total current assets		209,673			296,573
Property, plant, and equipment, net		776,166			784,408
Other assets:
Other intangible assets, net		34,340			35,239
Emissions allowances, net		60,000			61,597
Derivative assets		6,272			318
Other long-term assets		48,361			48,998

Total assets	$	1,134,812			1,227,133


LIABILITIES AND MEMBERS’ DEFICIT
Current liabilities:
Account payable and accrued expenses	$	43,378			21,639
Fuel payable		70,182			77,374
Other current liabilities		6,074			57,567
Derivative liabilities		1,973			21,254
Revolving line of credit		26,000			40,000
Current portion of long-term debt		11,300			11,300

Total current liabilities		158,907			229,134
Other liabilities:
Derivative liabilities		—			49,959
Other long-term liabilities		5,369			5,500
Long-term debt		1,782,800			1,769,832

Total liabilities		1,947,076			2,054,425
Members’ deficit		(812,264	)		(827,292	)

Total liabilities and members’ deficit	$	1,134,812			1,227,133

See accompanying notes to these consolidated financial statements.

F-79

EBG HOLDINGS LLC AND SUBSIDIARIES

Consolidated Statement of Members’ Capital (Deficit) and Comprehensive Income

(Amounts in thousands)


																			Other			Total			Total
										Additional						Members’			comprehensive			members’			comprehensive
	Class A Units				Class B Units					paid-in			Retained			capital			income			capital			income
	Units		Amount		Units			Amount		capital			earnings			(deficit)			(loss)			(deficit)			(loss)

Balance, December 31, 2004		—	$	—		—		$	—	$	—		$	(93,857	)	$	(93,857	)	$	—		$	(93,857	)	$	—
Adjustment to beginning retained earnings (see Note 3)		—		—		—			—		—			20,340			20,340			—			20,340			—

Balance December 31, 2004 Restated														(73,517	)		(73,517	)		—			(73,517	)		—
Capital contribution, Class A units		650		—		—			—		65,000			—			65,000			—			65,000			—
Extinguishment of debt		—		—		5,850			—		350,024			—			350,024			—			350,024			—
Financing costs paid in connection with A&B Units		—		—		—			—		(11,631	)		—			(11,631	)		—			(11,631	)		—
Net loss				—		—			—		—			(46,092	)		(46,092	)		—			(46,092	)		(46,092	)

Balance, December 31, 2005 Restated		650		—		5,850			—		403,393			(119,609	)		283,784			—			283,784			(46,092	)

Proceeds from exercise of warrant for Class A units		116		—		—			—		13,726			—			13,726			—			13,726			—
Repurchase of Class A and B units		—		—		(2,721	)		—		(925,018	)		—			(925,018	)		—			(925,018	)		—
Distributions to members		—		—		—			—		—			(34,996	)		(34,996	)		—			(34,996	)		—
Defined benefit plan, net of tax of $62		—		—		—			—		—			—			—			(129	)		(129	)		—
Cashless exercise of warrant for Class A units		212		—		—			—		—			—			—			—			—			—
Repurchase of warrant for Class A units		—		—		—			—		(50,359	)		—			(50,359	)		—			(50,359	)		—
Net loss		—		—		—			—		—			(114,300	)		(114,300	)		—			(114,300	)		(114,300	)

Balance, December 31, 2006 Restated		978		—		3,129			—		(558,258	)		(268,905	)		(827,163	)		(129	)		(827,292	)		(114,300	)

Net income		—		—		—			—		—			11,074			11,074						11,074			11,074
Mark-to-market adjustment on interest rate swap treated as a hedge		—		—		—			—		—			—			—			3,954			3,954			3,954

Balance, May 31, 2007		978	$	—		3,129		$	—	$	(558,258	)	$	(257,831	)	$	(816,089	)	$	3,825		$	(812,264	)	$	15,028

See accompanying notes to these consolidated financial statements.

F-81

EBG HOLDINGS LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For the five months ended May 31, 2007 and

years ended December 31, 2006 and 2005

(Dollars in thousands)


	Five months
	ended			Year ended December 31,
	May 31,			2006			2005
	2007			Restated			Restated

Net income (loss)	$	11,074			(114,300	)		(46,092	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation		11,157			26,737			28,680
Amortization of emissions allowances		727			958			2,538
Amortization of contractual rights and obligations, net		899			2,158			—
Amortization of deferred financing costs		2,825			1,109			476
Amortization of debt premium		—			—			45,138
Accretion of asset retirement obligation		96			216			189
Accrued interest expense on Mezzanine Facility		15,793			1,132			—
Loss on early extinguishment of debt		—			17,460			—
Gain on sale of assets		(980	)		—			—
Net unrealized (gains) losses on derivative contracts		(49,228	)		128,190			(103,231	)
Changes in assets and liabilities:
Restricted cash		48,622			(139,277	)		7,828
Accounts receivable		11,747			33,219			(29,981	)
Fuel inventory, materials and supplies		2,474			(6,625	)		3,129
Prepaid expenses and other assets		(6,269	)		14,162			3,084
Accounts payables and accrued expenses		(36,945	)		18,224			99,029
Other long-term liabilities		(229	)		(2,639	)		(2,799	)

Net cash provided by (used in) operating activities		11,763			(19,276	)		7,988

Cash flows from investing activities:
Capital expenditures		(2,915	)		(7,528	)		(14,488	)
Proceeds from sale of assets		1,850			560			—

Net cash used in investing activities		(1,065	)		(6,968	)		(14,488	)

Cash flows from financing activities:
Issuance of long-term debt		—			1,820,000			157,400
Proceeds from revolving credit facility		—
Restricted cash as collateral on First Lien Facility		—			80,000			(80,000	)
Proceeds from exercise of warrants		—			13,726			—
Payments of long-term debt		(2,825	)		(799,075	)		(127,417	)
Repayments on revolving credit facility		(14,000	)		—			—
Prepayment premiums paid on early extinguishment of debt		—			(13,963	)		—
Cash paid for financing costs		—			(49,882	)		(15,694	)
Other financing		—			(6,822	)		7,301
Repurchase of warrants		—			(50,359	)		—
Distributions to members		—			(34,996	)		—
Repurchase of members’ units		—			(925,018	)		—
Member capital contribution		—			—			65,000

Net cash (used in) provided by financing activities		(16,825	)		33,611			6,590

Net change in cash and cash equivalents		(6,127	)		7,367			90
Cash and cash equivalents at beginning of period		8,079			712			622

Cash and cash equivalents at end of period	$	1,952			8,079			712

Supplemental cash flow information:
Cash paid for interest	$	35,331			74,880			17,596

See accompanying notes to these consolidated financial statements.

F-82

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

May 31, 2007 and December 31, 2006 and 2005

(Dollars in thousands, except as otherwise indicated)


(1)	Organization and Nature of Operations

EBG Holdings LLC (EBG) is a Delaware limited liability company that was formed on May 25, 2004 and is the sole owner of Boston Generating, LLC and its subsidiaries (BG). EBG and BG are collectively referred to herein as the Company. BG is a Delaware limited liability company that was formed in August 2000 and commenced operations on February 1, 2001. The Company owns and operates the 1,600 megawatt (MW) Mystic 8&9 and the 800 MW Fore River electric generation projects (the Projects) as well as the 566 MW Mystic 7 Station (collectively, the Plants or Facilities). The Projects use combined-cycle technology. Mystic 8&9 burn natural gas. Fore River burns either natural gas or ultra-low sulfur distillate oil. Mystic 7 is a conventional electric steam plant and burns natural gas or 1% sulfur residual oil.

BG’s wholly-owned subsidiaries include three operating companies (Mystic Development, LLC; Fore River Development, LLC; and Mystic I, LLC) and two service companies (BG Boston Services, LLC and BG New England Power Services, Inc). Mystic Development, LLC (Mystic Development) is the owner of the Mystic 8&9 projects. Fore River Development, LLC (Fore River) is the owner of the Fore River project. Mystic I, LLC is the owner of the Mystic 7 Station.

Merger with Astoria Generating Company Holdings, LLC

On February 28, 2007, EBG and Astoria Generating Company Holdings, L.L.C. (Astoria) announced that they had entered into a definitive merger agreement, under which the companies would be combined (the Combination). Under the merger agreement, EBG and Astoria would combine to form US Power Generating Company (USPowerGen). The Combination was completed on June 1, 2007.


(2)	Summary of Significant Accounting Policies


*(a)*	*Principles of Consolidation and Basis of Presentation*

The accompanying consolidated financial statements of EBG and its wholly-owned subsidiaries have been prepared in accordance with U.S. generally accepted accounting principles (GAAP).

The accompanying consolidated financial statements present the Company’s consolidated financial position as of May 31, 2007 and December 31, 2006, and the results of its operations for the five months ended May 31, 2007 and years ended December 31, 2006 and 2005. The consolidated financial statements include the accounts of EBG and its wholly-owned subsidiaries. All significant intercompany transactions and balances have been eliminated.


*(b)*	*Use of Estimates and Market Risks*

The preparation of consolidated financial statements in conformity with GAAP requires management to make a number of estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The Company’s critical accounting estimates include:


	•	Mark-to-market (MTM) valuations of derivatives contracts;

	•	Determination of the Company’s asset retirement obligations;

	•	Estimated future cash flows in determining the valuation of long-lived assets, goodwill and indefinite-lived intangible assets and related impairment testing;

F-83

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)


	•	Estimating the expected rate of return on plan assets, rate of compensation increases and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities;

	•	Estimating losses to be recorded for contingent liabilities; and

	•	Estimating the provision for income taxes.

The Company is subject to risks associated with, but not limited to, price movements of energy commodities and credit associated with its commercial activities. The Company is subject to risks relating to the reliability of the systems, procedures and other infrastructure necessary to operate the business. The Company is also subject to risks relating to changes in laws and regulations; the outcome of material pending litigation (Note 12); the availability of adequate fuel supplies and transportation; weather conditions; financial market conditions and access to capital; the creditworthiness or financial distress of its counterparties; and the successful operation of deregulated power markets.


*(c)*	*Revenue Recognition*

The Company records revenue for energy sales and services related to its electric power generation facilities under the accrual method and these revenues are recognized upon delivery.

The Company sells 100% of the electricity, capacity, and ancillary services supplied from its facilities to a third party, Sempra Energy Trading Corp. (Sempra), under an energy management agreement (Note 12). Electricity, capacity, and ancillary services are sold to Sempra at the same prices that Sempra receives from the sales of these products into the electric energy market administered by ISO-NE and from other customers under bilateral contracts. For 2006, Mystic Development operated under a reliability must run agreement with ISO-NE.


*(d)*	*Credit Risk*

The Company has a credit policy that governs management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The Company’s policy is to only enter into transactions with counterparties that have investment grade credit ratings. The financial condition of counterparties is reviewed periodically by management. The Company tries to mitigate credit risk by entering into contracts that permit netting and allow for termination upon the occurrence of certain events of default.


*(e)*	*Concentration of Labor Subject to Collective Bargaining Agreements*

As of May 31, 2007, approximately 76.4% of the Company’s employees are subject to collective bargaining agreements.

F-84

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)


*(f)*	*Derivatives and Hedging Activities*

The Company accounts for derivatives and hedging activities in accordance with SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities (SFAS No. 133), as amended, which requires that all derivative instruments be recorded on the balance sheet at their respective fair values. For derivatives designated as hedges, changes in the fair value are either offset against the change in fair value of the assets and liabilities through earnings, or recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. For all derivative contracts that the Company enters into and intends to designate as a hedge, the Company formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method of measuring ineffectiveness. For all derivative contracts designated as hedges, the Company also formally 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 cash flows of hedged items. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in accumulated other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. The ineffective portion of the change in fair value of a derivative instrument that qualifies as a cash-flow hedge is reported in earnings.

The Company discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a hedging instrument is no longer appropriate. In all situations in which hedge accounting is discontinued and the derivative is retained, the Company continues to carry the derivative at its fair value on the consolidated balance sheet and recognizes any subsequent changes in fair value in earnings. When it is probable that a forecasted transaction will not occur, the Company discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income.

When specific hedge accounting criteria are not met, SFAS No. 133 requires that all changes in a derivative’s fair value be recognized currently in earnings. The Company may enter into derivative transactions in order to hedge its exposure to certain market risks. The Company does not hold or issue derivative instruments for trading purposes.


*(g)*	*Cash and Cash Equivalents*

Cash and Cash Equivalents consist of demand deposits and funds invested in highly liquid, short-term investments with original maturities of three months or less.


*(h)*	*Restricted Cash*

The Company is required to maintain cash balances that are restricted by provisions of certain long-term financing agreements (Note 5). These funds are held by depositary banks in order to comply with the contractual provisions requiring reserves for payments such as operating costs, capital expenditures, and debt service. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value.


*(i)*	*Fuel Inventory, Materials and Supplies*

Inventory is recorded at the lower of cost or market, and provisions are made for excess and obsolete inventory when appropriate.

F-85

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

Fuel Inventory — Fuel inventory of $12,921 and $16,398 at May 31, 2007 and December 31, 2006, respectively, is valued at the weighted average costs of stored oil. The costs of oil are generally included in inventory when purchased and charged to fuel expense when used.

Materials and Supplies — Materials and supplies, which consist of maintenance and repair inventory, of $4,791 and $3,788 at May 31, 2007 and December 31, 2006, respectively, are valued at the average costs of generating plant materials and supplies, or market. Materials and supplies are removed when they are used for repairs, maintenance, or capital projects.


*(j)*	*Property, Plant, and Equipment and Depreciation Expense*

Property, plant, and equipment was recorded at fair value upon the transfer of assets from Exelon New England Holdings, LLC in February 2004. Additions subsequent to the transfer are recorded at cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets, ranging from five to thirty-six years, commencing when assets or major components thereof are either placed in service or acquired, as appropriate. Leasehold improvements are amortized on a straight-line method over the shorter of the term of the lease or the useful life of the related asset. Repairs and maintenance costs are charged to expense as incurred.

At May 31, 2007 and December 31, 2006, property, plant, and equipment include the following:


	Estimated
	useful lives	May 31,			December 31,
	(in years)	2007			2006

Land	-	$	19,840			19,840
Power generation facilities	30 - 36		831,938			829,413
Construction in progress	-		4,046			3,659
Leasehold improvements	5 - 10		449			446

Total property, plant, and equipment			856,273			853,358
Accumulated depreciation			(80,107	)		(68,950	)

Net property, plant, and equipment		$	776,166			784,408

The Company recorded depreciation expense of $11,157, $26,737 and $28,680 for the five months ended May 31, 2007 and the years ended December 31, 2006 and 2005, respectively.


*(k)*	*Capitalized Interest and Project Development Costs*

EBG expenses development costs during the preliminary stages of a project. Once a project is deemed to be commercially viable, development costs are capitalized. Indications of commercial viability include approval by the Company’s Board of Directors, formal project plans, and significant future commitments of the Company. When a project is available for its intended use, the Company discontinues capitalization of costs and reclassifies the project costs to property, plant, and equipment. Project costs are then depreciated over the estimated useful life of the assets. Should the Company decide to abandon or discontinue development, previously capitalized costs are charged to expense in the period that such determination is made.

F-86

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

construction ceases or is terminated. Capitalized interest was $403 for the five months ended May 31, 2007. No interest was capitalized during the years ended December 31, 2006 and 2005.


*(l)*	*Major Maintenance Activities*

The Company accounts for major maintenance activities in accordance with Financial Accounting Standards Board (FASB) Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance Activities (FSP AUG). Pursuant to FSP AUG, the Company does not accrue in advance for planned major maintenance activities, but rather expenses maintenance costs as incurred.

The Company has two long-term service agreements (LTSAs) with Mitsubishi Power Systems Americas, Inc. (MPS) to provide all major maintenance services, including refurbishment of spare parts, for the Projects’ gas turbine generators and related equipment (the Covered Units). Under the LTSAs, MPS receives a fixed fee for monitoring the Covered Units and a variable fee based on number of equivalent operating hours incurred by each of the Covered Units. The Company charges to expense the fixed fee monthly when it is incurred. However, the variable fee paid monthly is recorded as a prepaid expense and subsequently charged to expense when MPS performs the major maintenance on the Covered Units. Prepaid expense related to the LTSAs was $8,121 and $7,954 at May 31, 2007 and December 31, 2006, respectively, and the total expenses related to the LTSAs for the five months ended May 31, 2007 and the years ended December 31, 2006 and 2005 were $8,617, $29,202 and $26,234, respectively.


*(m)*	*Asset Impairment*

In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144), the Company evaluates long-lived assets when events or changes in circumstances indicate potential for impairment. Impairment for assets held for use is evaluated based upon a comparison of the carrying value and the estimated total future undiscounted cash flows of the asset. If the carrying amount of an asset exceeds its estimated total future undiscounted cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value.


*(n)*	*Asset Retirement Obligations*

The Company has adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), which requires an entity to recognize the fair value of a liability for an Asset Retirement Obligation (ARO) in the period in which it is incurred if a reasonable estimate of fair value can be made. Upon the initial recognition of an ARO, SFAS No. 143 requires an entity to capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its present value each period, while the capitalized cost is depreciated over the useful life of the related asset. AROs associated with long-lived assets included within the scope of SFAS 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Company’s AROs are associated primarily with hazardous substance removal and fuel storage tanks retirement.

F-87

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The following table represents the balances of the AROs that are included in other liabilities, for the periods presented:


Balance at December 31, 2004	$	2,033
Accretion		189

Balance at December 31, 2005		2,222
Accretion		216

Balance at December 31, 2006		2,438
Accretion		96

Balance at May 31, 2007	$	2,534

(o) Environmental Remediation Expenditures

The Company charges to expense or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Company expenses amounts that relate to an existing condition caused by past operations and that do not have future economic benefit. The Company records liabilities related to expected future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated (Note 14).

(p) Emissions Allowances

Emissions allowances have a limited life and were recorded as intangibles at an estimated fair value as of May 25, 2004, the date of the transfer of ownership in BG to EBG. Emissions allowances are amortized on a basis of units of production as they are used in operations. Sales of emissions allowances to third parties are recorded in the consolidated statement of operations as a gain or loss on disposal of assets. Net emissions allowance expense, which is recorded as fuel expense in the consolidated statement of operations, was $727, $958, and $2,538 for the five months ended May 31, 2007 and the years ended December 31, 2006 and 2005, respectively.

(q) Income Taxes

The Company is a limited liability company. Through March 30, 2006, it was a pass-through entity for income tax reporting purposes. As such, no income tax expense or benefit has been recorded within the consolidated financial statements for periods prior to that date, when taxable income or benefit was reflected in the taxable income of the Company’s members. One of EBG’s subsidiaries, BG New England Power Services, Inc., is a taxable entity. However, it has no taxable income as its revenues equal its expenses.

On March 30, 2006, by written consents approved by over 80% of each of the Class A unit and Class B unit holders, EBG made an election to be taxed as a corporation under the Internal Revenue Code for all periods beginning on and after March 31, 2006. The Internal Revenue Service approved this election on May 15, 2006. Consequently, the Company’s consolidated financial statements for periods subsequent to March 30, 2006 reflect the effects of income taxes.

Income taxes are accounted for under the deferred tax asset and liability method pursuant to Statement of Financial Accounting Standards, No. 109, Accounting for Income Taxes, (SFAS No. 109). Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial

F-88

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply 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 includes the enactment date.

The Company accounts for uncertain tax positions pursuant to FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN No. 48). FIN No. 48 prescribes a comprehension model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. It was effective for the Company beginning January 1, 2007 and did not have an impact on the Company’s financial position or results of operations.

Interest and penalties related to tax positions taken in our tax returns are recorded in interest expense and general and administrative expenses, respectively, in our consolidated statement of operations. At January 1, 2007, the combined amount of accrued interest and penalties related to tax positions taken on our tax returns was zero.


*(r)*	*Intangible Assets*

The Company accounts for intangible assets in accordance Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS No. 141) and Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS No. 142). SFAS No. 141 requires that the purchase method of accounting be used for all business combinations. It specifies the criteria that intangible assets acquired in a business combination must meet in order to be recognized and reported apart from goodwill. SFAS No. 142 requires that intangible assets determined to have indefinite lives no longer be amortized but instead be tested for impairment at least annually and whenever events or circumstances occur that indicate impairment might have occurred.

Separable intangible assets that are deemed to have finite lives will continue to be amortized over their estimated useful lives. Specifically, identifiable intangible assets with finite lives include emissions allowances, unmitigated capacity sales contracts and gas transportation contracts. The Company has no intangible assets with indefinite lives as of May 31, 2007.


*(s)*	*Debt Issuance Costs*

Debt issuance costs are capitalized and amortized as interest expense on a basis that approximates the effective-interest method over the term of the related debt.


*(t)*	*Pensions*

The Company offers pension benefits to its employees through either a defined benefit pension plan or a cash balance plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with Statement of Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158). SFAS No. 158 was effective for publicly-traded companies with fiscal years ending after December 15, 2006 and for privately-held companies no later than fiscal years ending after June 15, 2007. The Company’s financial statements reflect the adoption of SFAS No. 158 as if it had been a public company at December 31,

F-89

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

2006. USPowerGen recognizes the funded status of the Company’s defined benefit plans in the statement of financial position and records an offset to other comprehensive income. In addition, the Company also recognizes on an after-tax basis, as a component of other comprehensive income, gains, and losses as well as all prior service costs that have not been included as part of the Company’s net periodic benefit cost. The determination of The Company’s obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions include the discount rate, expected rate of return on plan assets, retirement age, healthcare trend rate, and the rate of future compensation increases. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company (Note 8).


*(u)*	*Equity-Based Compensation*

The Company recognizes expense associated with a unit appreciation rights plan using the intrinsic method as provided in Statement of Financial Accounting Standards No. 123R, Share Based Payment (SFAS 123(R)). Under the intrinsic method, expense is measured based on the change in fair value of the unit appreciation rights from the grant date to the end of the period and the unit appreciation rights vesting percentage.


*(v)*	*Reclassifications*

Certain reclassifications considered necessary for a fair presentation have been made to prior period financial statements in order to conform to the current year presentation. These reclassifications have had no impact on the results of operations or members’ capital (deficit).


*(w)*	*Financial Accounting Standards Not Previously Discussed Herein*

F-90

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company partially adopted SFAS No. 157 on January 1, 2008, delaying application for nonfinancial assets and nonfinancial liabilities as permitted. This partial adoption of SFAS No. 157 did not have a material impact on the Company’s financial position or results of operations. The Company is currently evaluating the impact of the deferred portion of SFAS No. 157 on the Company’s financial position or results of operations.

In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (SAB 108). SAB 108 expresses the SEC staff’s views on the appropriate approach for determining materiality as it relates to misstatements. The approach requires that a public registrant consider the impact of an unadjusted error on each financial statement and related financial statement disclosure presented. It requires that a public registrant consider both the effects of correcting the error in the current year income statement and the effects of correcting the current year balance sheet misstatement that originated in prior years. The Company has implemented SAB 108, which did not have an effect on the Company’s financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Liabilities — including an amendment to FASB Statement No. 115 (SFAS No. 159). This Statement creates a fair value option under which an entity may irrevocably elect fair value as the initial and subsequent measurement attribute for certain assets and liabilities, on an instrument by instrument basis. If the fair value option is elected for an instrument, all subsequent changes in fair value for that instrument shall be reported in earnings. This statement is effective for the Company for the fiscal year beginning January 1, 2008 and corresponding interim periods. The adoption of this statement is not expected to have a material impact on the Company’s financial position or results of operations.


(3)	Restatement of Consolidated Financial Statements

Subsequent to the issuance of the Company’s audited consolidated financial statements as of and for the year ended December 31, 2006, the Company determined that its 2005 consolidated financial statements contained three material errors requiring adjustment.

As a result of these adjustments and pursuant to Statement of Financial Accounting Standards No. 154, Accounting changes and error corrections (SFAS No. 154), the Company’s consolidated balance sheets as of December 31, 2006 and 2005 and the related consolidated statements of operations, members’ capital (deficit), and cash flows for years ended December 31, 2006 and 2005 have been restated. The Company believes that its

F-91

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

current procedures, controls and accounting practices are adequate to ensure that future determinations of the asset retirement obligations, accrued interest, and mark-to-market adjustments for its derivative positions are accounted for in accordance with GAAP. The following paragraphs summarize the restatement adjustments:


	•	Recording an asset retirement obligation

During the course of the Company’s analysis it was determined that the Company had not recorded any ARO pursuant to SFAS No. 143 or FIN No. 47. The Company subsequently evaluated whether any ARO obligations exist. The Company estimated the present value of future estimated ARO obligations related to asbestos and tank closures was $2,222 as of December 31, 2005, the earliest period reported herein.


	•	Adjustment to accrued interest

During the course of the Company’s analysis of accrued interest in 2006, the Company determined that accrued interest as of December 31, 2005 was overstated and members’ capital was understated by $13,215. The consolidated statement of operations for the year ended December 31, 2005 was not impacted. This adjustment represented the additional expense accrued during 2004 and was part of the remaining amounts outstanding under BG’s then-existing debt obligations, which were converted into EBG members’ capital on October 11, 2005.


	•	Adjustment to single commodity swap contracts

In order to comply with the “net presentation” methodology advocated by the Securities and Exchange Commission for the presentation of the settlements payments made and received in connection with power and or fuel contracts, the Company undertook an analysis of the unrealized gains and losses on its single commodity swap contracts held as of various reporting periods.

During the course of this analysis, it was determined that a large portion of the Company’s power swap contracts and a small number of power contracts had been excluded from the MTM adjustment recognized as of December 31, 2004. As a result, the fair value of the Company’s derivative portfolio was understated, and the unrealized loss on derivative contracts MTM was overstated by $21,057 for the year ended December 31, 2004.

In 2005, the earliest period reported herein, the Company properly recorded the fair value of its derivative portfolio as of December 31, 2005. In doing so, however, the unrealized gain on the Company’s single commodity swap positions was overstated by the same amount, $21,057, as the overstated unrealized loss in 2004. Additionally the beginning members’ capital (deficit) was understated by $21,057.

Restatement of Our Consolidated Financial Statements

To correct the understatement of the asset retirement obligation, other long-term liabilities were increased by $2,222. Net plant, property and equipment increased by $1,270, and retains earnings decreased by $952 representing the portion of the accretion and depreciation expense that should have been recognised in 2003 and 2004.

To correct the overstatement of accrued interest as of December 31, 2005, members’ capital was reduced and accrued interest liability was decreased by $13,215.

To correct the overstatement of unrealized MTM gains on derivative instruments during the twelve months ended December 31, 2005, which was the result of a 2004 accounting error, the unrealized gain recognized was reduced by $21,057. Beginning retained earnings was increased by $21,057, representing the portion of the change in fair value of the single commodity swap derivatives which should have been recognized during the year ended December 31, 2004. The impact of these adjustments have been reflected in

F-92

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The following table presents the effects of the restatement adjustments upon the Company’s previously reported consolidated balance sheet:


	December 31, 2006
	As previously
	reported			Adjustments			Restated

ASSETS
Current assets:
Cash and cash equivalents	$	8,079			—			8,079
Restricted cash		162,706			—			162,706
Accounts receivable		61,236			—			61,236
Derivative assets		33,395			—			33,395
Fuel inventory, materials and supplies		20,186			—			20,186
Prepaid expenses and other current assets		10,971			—			10,971

Total current assets		296,573			—			296,573

Property, plant, and equipment, net		783,185			1,223			784,408
Other assets:
Other intangible assets, net		35,239			—			35,239
Emissions allowances, net		61,597			—			61,597
Derivative assets		318			—			318
Other long-term assets		48,998			—			48,998

Total assets	$	1,225,910			1,223			1,227,133


LIABILITIES AND MEMBERS’ CAPITAL (DEFICIT)
Current liabilities:
Account payable and accrued expenses	$	21,639			—			21,639
Fuel payable		77,374			—			77,374
Other current liabilities		57,567			—			57,567
Derivative liabilities		21,254			—			21,254
Revolving line of credit		40,000			—			40,000
Current portion of long-term debt		11,300			—			11,300

Total current liabilities		229,134			—			229,134

Other liabilities:
Derivative liabilities		49,959			—			49,959
Other long-term liabilities		3,063			2,437			5,500
Long-term debt		1,769,832			—			1,769,832

Total liabilities		2,051,988			2,437			2,054,425
Members’ capital (deficit)		(826,078	)		(1,214	)		(827,292	)

Total liabilities and members’ capital (deficit)	$	1,225,910			1,223			1,227,133

F-94

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The following table presents the effects of the restatement adjustments upon the Company’s previously reported consolidated statement of cash flows:


	Year ended December 31, 2006
	As previously
	reported			Adjustments			Restated

Cash flows from operating activities:
Net loss	$	(114,037	)		(263	)		(114,300	)
Adjustments to reconcile net loss to net cash (used in) operating activities:
Depreciation		26,690			47			26,737
Amortization of emissions allowances		958			—			958
Amortization of contractual rights and obligations, net		2,158			—			2,158
Amortization of deferred financing costs		1,109			—			1,109
Accretion of asset retirement obligation		—			216			216
Accrued interest expense on Mezzanine Facility		1,132			—			1,132
Loss on early extinguishment of debt		17,460			—			17,460
Net unrealized loss on derivative contracts		128,190			—			128,190
Changes in assets and liabilities:
Restricted cash		(139,277	)		—			(139,277	)
Accounts receivable		33,219			—			33,219
Fuel inventory, materials and supplies		(6,625	)		—			(6,625	)
Prepaid expenses and other current assets		14,162			—			14,162
Accounts payables and accrued expenses		18,224			—			18,224
Other long-term liabilities		(2,639	)		—			(2,639	)

Net cash used in operating activities		(19,276	)		—			(19,276	)

Cash flows from investing activities:
Capital expenditures		(7,528	)		—			(7,528	)
Proceeds from sale of assets		560			—			560

Net cash used in investing activities		(6,968	)		—			(6,968	)

Cash flows from financing activities:
Issuance of long-term debt		1,820,000			—			1,820,000
Restricted cash as collateral on First Lien Facility		80,000			—			80,000
Proceeds from exercise of warrants		13,726			—			13,726
Payments of long-term debt		(799,075	)		—			(799,075	)
Prepayment premiums paid on early extinguishment of debt		(13,963	)		—			(13,963	)
Cash paid for financing costs		(49,882	)		—			(49,882	)
Other financing		(6,822	)		—			(6,822	)
Repurchase of warrants		(50,359	)		—			(50,359	)
Distributions to members		(34,996	)		—			(34,996	)
Repurchase of members’ units		(925,018	)		—			(925,018	)

Net cash provided by financing activities		33,611			—			33,611

Net increase in cash and cash equivalents		7,367			—			7,367
Cash and cash equivalents at beginning of year		712			—			712

Cash and cash equivalents at end of year	$	8,079			—			8,079

Supplemental cash flow information:
Cash paid for interest	$	74,880			—			74,880

F-96

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The following table presents the effects of the restatement adjustments upon the Company’s previously reported consolidated balance sheet as of December 31, 2005:


	December 31, 2005
	As previously
	reported		Adjustments			Restated

ASSETS
Current assets:
Cash and cash equivalents	$	712		—			712
Restricted cash		23,429		—			23,429
Accounts receivable		94,454		—			94,454
Derivative assets		257,869		—			257,869
Fuel inventory, materials and supplies		13,562		—			13,562
Prepaid expenses and other current assets		20,413		—			20,413

Total current assets		410,439		—			410,439
Property, plant, and equipment, net		802,907		1,270			804,177
Other assets:
Other intangibles, net		37,397		—			37,397
Emissions allowances, net		64,075		—			64,075
Derivative assets		1,463		—			1,463
Other long-term assets		85,733		—			85,733

Total assets	$	1,402,014		1,270			1,403,284

LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	151,982		(13,215	)		138,767
Other current liabilities		5,567		—			5,567
Derivative liabilities		168,327		—			168,327
Current portion of long-term debt		3,700		—			3,700

Total current liabilities		329,576		(13,215	)		316,361
Other liabilities:
Other long-term liabilities		5,542		2,222			7,764
Long-term debt		795,375		—			795,375

Total liabilities		1,130,493		(10,993	)		1,119,500
Members’ capital		271,521		12,263			283,784

Total liabilities and members’ capital	$	1,402,014		1,270			1,403,284

See accompanying notes to these consolidated financial statements.

F-97

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The following table presents the effects of the restatement adjustments upon the Company’s previously reported consolidated statement of cash flows for year ended December 31, 2005:


	Year ended December 31, 2005
	As previously
	reported			Adjustment			Restated

Cash flows from operating activities:
Net loss	$	(24,800	)		(21,292	)		(46,092	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation		28,634			46			28,680
Amortization		2,538			—			2,538
Amortization of deferred financing costs		476			—			476
Amortization of debt discount		45,138			—			45,138
Accretion of asset retirement obligation		—			189			189
Net unrealized loss on derivative contracts		(124,288	)		21,057			(103,231	)
Changes in assets and liabilities:
Restricted cash		7,828			—			7,828
Accounts receivable		(29,981	)		—			(29,981	)
Fuel inventory, materials and supplies		3,129			—			3,129
Prepaid expenses and other current assets		3,084			—			3,084
Accounts payables and accrued expenses		99,029			—			99,029
Other long-term liabilities		(2,799	)		—			(2,799	)

Net cash provided by operating activities		7,988			—			7,988

Cash flows from investing activities:
Capital expenditures		(14,488	)		—			(14,488	)

Net cash used in investing activities		(14,488	)		—			(14,488	)

Cash flows from financing activities:
Issuance of long-term debt		157,400			—			157,400
Restricted cash as collateral on First Lien Facility		(80,000	)		—			(80,000	)
Payments of long-term debt		(127,417	)		—			(127,417	)
Cash paid for financing costs		(15,694	)		—			(15,694	)
Other financing		7,301			—			7,301
Member capital contribution		65,000			—			65,000

Net cash provided by financing activities		6,590			—			6,590

Net increase in cash and cash equivalents		90			—			90
Cash and cash equivalents at beginning of year		622			—			622

Cash and cash equivalents at end of year	$	712			—			712

Supplemental cash flow information:
Cash paid for interest	$	17,596			—			17,596

F-99

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)


(4)	Accounting for Derivative and Hedging Activities

The Company is engaged in the generation and sale of electricity, which fundamentally involves the conversion of energy from various fuel sources into salable electrical energy. As such, the Company’s spark spread, and cash flow are highly dependent on the market clearing prices for wholesale electricity and the source fuels, natural gas and fuel oil, used to generate the power produced. The market prices of these energy commodities are highly volatile, and in the short term are influenced by very different local and global market forces. As such, power and fuel prices can, at times, fluctuate independent of each other in terms of both magnitude and direction. The Company’s risk management activities involve the use of derivative and non-derivative arrangements, to minimize the risk inherent in the business of wholesale power generation and distribution.

In addition to the energy commodity price risk inherent in the Company’s line of business, its capital structure includes $1,820,100 of variable interest rate debt. As such, the Company’s cost of capital can fluctuate with changes in market interest rates.

The Company defines risk as the exposure it faces to factors which have the potential to negatively impact cash flow and profitability. Such factors, or risks, primarily include the fluctuations in commodity prices (power and fuel) and interest rates. As a component of its risk management strategy, the Company utilizes a variety of contractual arrangements to hedge its exposure to these risks in order to enhance its budgeting and planning activities, and ultimately to reduce variances from projected cash flow and profitability due to noncontrollable fluctuations in spot market prices of both energy related commodities and debt capital. The Company does not enter into any derivative contracts or any similar arrangements for speculative or trading purposes.

(a) Derivative Accounting

SFAS No. 133 outlines (a) the criteria used to ascertain whether or not a given position or contractual arrangement is a derivative instrument, and (b) the accounting and disclosure requirements for both non-hedge derivative positions (trading or speculative positions), and three broad categories of hedge derivative positions; normal purchase-normal sale economic hedges, and accounting hedges. The following is a brief description of each derivative hedge category and the related accounting treatment as outlined by SFAS No. 133:

Normal Purchase-Normal Sale

Normal purchase-normal sales contracts are forward purchase or sales agreements which settle through physical delivery of product or commodity typically sold or used in the ordinary course of business, involve quantities likely to be sold or used in the ordinary course over a reasonable period, and either contain no settlement provisions or involve underlying assets or liabilities for which no market mechanism exist by which net settlements may be reasonably achieved. Such contracts qualify for the “normal purchase-normal sale” exemption from the periodic MTM valuation adjustments required by SFAS No. 133. Changes in fair value of such contracts are recognized in income only when realized. The Company does not have any contracts that qualify for the normal purchase-normal sale exemption.

Derivatives Held as Hedge Positions

All derivatives not deemed to be normal purchase-normal sales transactions must be recognized and reported on the balance sheet at fair value, with the resulting unrealized gains and losses recognized either as a component of net income currently, or for those qualifying for hedge accounting treatment under SFAS No. 133, deferred and matched with the recognition of realized results of the related hedge transaction.

F-100

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

Hedging positions that qualify for hedge accounting treatment are considered to be “accounting hedges,” while those that do not meet the SFAS No. 133 criteria, are deemed to be “economic hedges.”


	•	Accounting Hedges: Changes in the fair value of accounting hedge derivatives, including those which have been (a) designated as accounting hedges, and (b) satisfied all of the criteria outlined in SFAS No. 133, are eligible for deferral treatment, with the extent of such deferral determined by the degree of hedge effectiveness. For each derivative instrument, any unrealized gain or loss is apportioned into an “effective component” and “an ineffective component.” Changes in fair value allocated to the ineffective component are recognized currently, while changes in fair value attributable to the effective portion of the hedge are generally deferred until the timing of recognition can be matched to the income statement recognition of the related hedge transaction.

	•	Economic Hedges: Changes in the fair value of economic hedge derivatives are recognized as a component of net income on a current basis. The classification of such recognition is determined by and reported with the revenue or expense recognized in connection with the hedged transaction. As such, the realized gains and losses on periodic cash settlements and at contract maturity or expiration and the unrealized gains and losses on mark-to-market adjustments are aggregated and reported on a net basis.

(b) EBG Derivative Hedge Portfolio

Accounting Hedges

On February 14, 2007, EBG executed a $1,000,000, 3 month LIBOR interest rate swap, which EBG had designated at inception and had accounted for as an accounting hedge with no effectiveness, in accordance with SFAS No. 133. Through May 31, 2007, EBG had recognized unrealized gains of $3,954 as a component of other comprehensive income (OCI).

Economic Hedges

The Company’s derivative portfolio includes a variety of contracts held to manage its exposure to commodity price and interest rate fluctuations. While the Company considers these agreements to be viable hedges of market risks outside its direct control, hedge accounting was not utilized because the contracts did not satisfy the requisite criteria outlined in SFAS No. 133 required to qualify for such treatment. As such, for each of the reporting dates included herein, May 31, 2007, December 31, 2006 and December 31, 2005, all of the Company’s derivatives, other than the $1,000,000 interest rate Swap Contract, have been accounted for as economic hedges. The Company’s economic hedge portfolio can be segregated into two main categories based upon the type of exposure against which it intended to provide hedge protection: (a) hedges of risks associated with the Company’s power generation activities and assets, or operating activity hedges; and (b) hedges against increases in the Company’s cost of capital due to changes in short-term interest rates, or interest rate hedges.

(i) Risk management hedges, which includes contracts intended to hedge the variability of capacity market prices, and conversion spread contracts, which are executed to mitigate potential fluctuations in the Company’s spark spread caused by the variability of market prices for both the Company’s generated power and incurred fuel costs in connection with the Company’s power generation activities;

(ii) Power hedges, which are executed to mitigate the impact of negative fluctuations in the market price of wholesale power generated in the Company’s various markets; and

F-101

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

Operating Activity Hedges: The Company utilizes a variety of derivative instruments to achieve the hedging results desired. Depending upon market conditions, the Company’s operating activity hedge portfolio may include some or all of the following derivative instruments: options, futures, forward purchase or sales contracts, and commodity price or swap agreements.

Description of Portfolio Positions: The table below provides a general summary of the Company’s operating activity hedges as of May 31, 2007, December 31, 2006 and December 31, 2005:


			December 31, 2005
	May 31, 2007	December 31, 2006	(restated)

Power Contracts:
Derivative description
Financially settled floating for fixed commodity swaps -- Peak & Off-Peak Electricity
Number of contracts	36	42	196
Notional amount	779 MW/KHR (Peak)	168 MW/KHR (Peak)	7,804 MW/KHR (Peak)
	527 MW/KHR (Off-Peak)	74 MW/KHR (Off-Peak)	2,582 MW/KHR (Off-Peak)
Term of agreement	June 1, 2007 to September 30, 2007	January 1, 2007 to February 28, 2007	January 1, 2006 to June 30, 2006
Fuel Contracts:
Derivative description
Financially settled floating for fixed commodity swap - Natural Gas/Fuel Oil
Number of contract	64	25	277
Notional amount	• 10,928 MM BTU • 175 BBL	1,830 BBL	• 20,270 MM BTU • 1,350 BBL
Term of agreement	June 1, 2007 to September 30, 2007	January 1, 2007 to March 31, 2007	January 1, 2006 to June 30, 2006
Conversion Spread Hedge Contracts:
Derivative description	2 Financially settled floating for fixed swaps — Synthetic EBG Spark Spread	—	—
	• 1Bundled NEMA-Tetco NGas Puts & Swap
	• 1Bundled Internal Hub-Tetco NGas Puts & Swap
Number of contracts	4	—	—
Notional amount	Oct — May: 1,600 MW/Hr	—	—
	Jun — Sep: 1,500 MW/Hr	—	—
Term of agreement	January 1, 2007 to December 31, 2010	—	—

Operating Activity Hedge Portfolio — Fair Value and Recognized Gains & Losses: The fair value of the Company’s operating activity hedges was $11,004 and ($38,439) as of May 31, 2007 and December 31, 2006, respectively. For the five-month period ended May 31, 2007, and the years ended December 31, 2006 and 2005, unrealized MTM gains/(losses) attributable to changes in the fair value of operating activity hedges totaled $49,442, ($127,666), and $103,231 respectively, while realized gains/(losses) on operating activity hedges attributable to settlement payments received/(made) totaled $32,067, $34,162, and ($69,002).

Interest Rate Hedges

The LIBOR-based, variable rate debt facilities issued by EBG and its subsidiaries expose the Company’s cost of capital to fluctuations in market interest rates. To hedge against the interest rate risk attributable to

F-102

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

these facilities, the Company has entered into derivative contracts, which provide interest rate protection on a portion of its variable rate obligations (Note 5). The aggregate notional value of the Company’s interest rate hedge portfolio was $400,000 as of May 31, 2007, December 31, 2006, and December 31, 2005. The aggregate principal balance outstanding under the Company’s variable interest rate debt facilities as of May 31, 2007 and December 31, 2006 was $1,820,100 and $1,821,132, respectively.

Description of Portfolio Positions: The table below provides a general summary of the Company’s interest rate hedge portfolio:


Contract Description:	May 31, 2007	December 31, 2006	December 31, 2005

Interest Rate Swap:
Financially settled, floating for fixed LIBOR swap
*Number of contracts*	1	—	—
*Notional amount*	$1,000,000	—	—
*Terms of agreements*	February 27, 2007 to December 31, 2010	—	—
Financially settled, LIBOR interest rate cap option:
*Number of contracts*	2	2	2
*LIBOR Cap*	5.0%	5.0%	5.0%
	5.5%	5.5%	5.5%
*Notional amount*	$ 400,000	$ 400,000	$ 400,000
*Term of agreements*	December 31, 2005 to December 31, 2007	December 31, 2005 to December 31, 2007	December 31, 2005 to December 31, 2007
	December 30, 2005 to December 31, 2008	December 30, 2005 to December 31, 2008	December 30, 2005 to December 31, 2008

Interest Rate Hedge Portfolio — Fair Value and Recognized Gains & Losses: The fair value of the Company’s interest rate hedge portfolio was $725 and $939 at May 31, 2007 and December 31, 2006, respectively. For the five-month period ended May 31, 2007, and the years ended December 31, 2006 and 2005, unrealized MTM gains (losses) attributable to changes in the fair of interest rate hedges totaled ($214), ($524) and $0, respectively, while realized MTM gains/(losses) on interest rate hedges attributable to settlement payments received totaled $184, $438, and $0.

(c) Fair Value of Economic Hedge Derivatives — Summary of Balance Sheet Recognition

The fair value of the Company’s derivative instruments, including both operating activity hedge derivatives and interest rate hedge derivatives, have been aggregated and then classified in the balance sheets included herein based upon the fair value of anticipated settlements over the next twelve months and then over the remaining tenor of the various contracts. Derivative contracts for which the present value of anticipated settlement over the twelve months following the balance sheet date and/or the remaining tenor is positive have been recognized as current and/or noncurrent derivative assets, respectively. Derivative contracts for which the present value of anticipated settlement over the twelve months following the balance sheet date and/or the remaining tenor is negative have been recognized as current and/or noncurrent derivative liabilities respectively.

F-103

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)


	Estimated fair value as of May 31, 2007
	Current		Noncurrent		Current			Noncurrent		Total
Hedge Description	asset		asset		liability			liability		fair value

Conversion spread	$	5,797		6,073		—			—		11,870
Power		672		—		(442	)		—		230
Fuel		435		—		(1,531	)		—		(1,096	)

Subtotal-operating activity hedges		6,904		6,073		(1,973	)		—		11,004
Interest rate derivatives — economic hedges		526		199		—			—		725

Total economic hedge derivatives		7,430		6,272		(1,973	)		—		11,729

Interest rate derivatives — accounting hedges		3,954		—		—			—		3,954

Total hedge portfolio	$	11,384		6,272		(1,973	)		—		15,683


	December 31, 2006
	Current		Noncurrent		Current			Noncurrent			Total
Hedge Description	asset		asset		liability			liability			fair value

Conversion spread	$	—		—		(7,388	)		(49,959	)		(57,347	)
Power		22,371		—		(9,014	)		—			13,357
Fuel		10,403		—		(4,852	)		—			5,551

Subtotal — operating activity hedges		32,774		—		(21,254	)		(49,959	)		(38,439	)
Interest rate derivatives — economic hedges		621		318		—			—			939

Total economic hedge derivatives		33,395		318		(21,254	)		(49,959	)		(37,500	)

Total hedge portfolio	$	33,395		318		(21,254	)		(49,959	)		(37,500	)

(d) Realized & Unrealized Gains & Losses on Economic Hedge Derivatives — Statement of Operations Presentation

The aggregate impact of the operating activity and interest rate hedges, including both the unrealized MTM gains and losses attributable to changes in the fair value, and the realized gains and losses attributable to contract settlements the both operating activity hedge derivatives and interest rate hedge derivatives, have been aggregated and recognized on a current basis along with the amounts recognized in connection with the hedged transactions. As such, gains and losses on the economic hedge derivatives have been recognized in the statements of operations as follows: conversion spread and power hedges have been recognized as a component of revenues; fuel hedges have been recognized as a component of fuel expense; and interest rate hedges have been recognized as a component of interest expense.

F-104

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The tables below summarize the aggregate gains and losses recognized on the Company’s economic hedges, both realized and unrealized, and the classification of amounts recognized within the statements of operations covering the five months ended May 31, 2007, and the years ended December 31, 2006 and 2005:


	Amounts recognized for the five months ended May 31, 2007
	Operating activity hedges											Interest			Total
	Conversion											rate			economic			Accounting
	spread		Power			Fuel			Total			hedges			hedges			hedges		Totals

Realized & unrealized gains (losses)

Change in fair value	$	69,216		(13,127	)		(6,647	)		49,442			(214	)		49,228			3,954		53,182
Contract settlements		17,281		9,698			5,088			32,067			184			32,251			198		32,449

Total gains (losses)		86,497		(3,429	)		(1,559	)		81,509			(30	)		81,479			4,152		85,631

Statement of operations recognition
Revenue		86,497		(3,429	)		—			83,068			—			83,068			—		83,068
Fuel		—		—			(1,559	)		(1,559	)		—			(1,559	)		—		(1,559	)
Interest (expense) income		—		—			—			—			(30	)		(30	)		198		168
Other comprehensive income		—		—			—			—			—			—			3,954		3,954

Total gains (losses)	$	86,497		(3,429	)		(1,559	)		81,509			(30	)		81,479			4,152		85,631


	Amounts recognized for the year ended December 31, 2006
	Operating activity hedges												Interest			Total
	Conversion												rate			economic			Accounting
	spread			Power			Fuel			Total			hedges			hedges			hedges		Totals

Realized & unrealized gains (losses)

Change in fair value	$	(60,847	)		(51,526	)		(15,293	)		(127,666	)		(524	)		(128,190	)		—		(128,190	)
Contract settlements		3,500			56,892			(26,230	)		34,162			438			34,600			—		34,600

Total (losses) gains		(57,347	)		5,366			(41,523	)		(93,504	)		(86	)		(93,590	)		—		(93,590	)

Statement of operations recognition
Revenues		(57,347	)		5,366			—			(51,981	)		—			(51,981	)		—		(51,981	)
Fuel		—						(41,523	)		(41,523	)		—			(41,523	)		—		(41,523	)
Interest expense		—			—			—			—			(86	)		(86	)		—		(86	)

Total (losses) gains	$	(57,347	)		5,366			(41,523	)		(93,504	)		(86	)		(93,590	)		—		(93,590	)


	Amounts recognized for the year ended December 31, 2005
	Operating activity hedges										Interest		Total
	Conversion										rate		economic			Accounting
	spread		Power		Fuel			Total			hedges		hedges			hedges		Totals

Realized & unrealized gains (losses)

Change in fair value	$	—		23,605		79,626			103,231			—		103,231			—		103,231
Contract settlements		—		17,560		(86,562	)		(69,002	)		—		(69,002	)		—		(69,002	)

Total gains (losses)		—		41,165		(6,936	)		34,229			—		34,229			—		34,229

Statement of operations recognition
Revenues		—		41,165		—			41,165			—		41,165			—		41,165
Fuel		—		—		(6,936	)		(6,936	)		—		(6,936	)		—		(6,936	)

Total gains (losses)	$	—		41,165		(6,936	)		34,229			—		34,229			—		34,229

F-105

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The total impact of derivative hedging activities recognized in the Company’s consolidated financial statements during the five months ended May 31, 2007 and the years ended December 31, 2006 and December 31, 2005 has been disaggregated, in the tables below, into the three main components which determine the net results of EBG’s hedging activities; (i) the roll-off of previously projected settlements included in the prior period fair value measurements, (ii) the change in estimated value of projected settlements for the remaining tenor of the contracts from those of the prior period, and (iii) the settlements received or (paid) during the periods reported:


	Five months ended May 31, 2007
	Change in fair value attributable to:
	Roll-off			Change in value
	of prior			of			Total change in
Contract Type	estimates			remaining tenor			fair value			Settlements		Total

Conversion spread	$	(13,283	)		82,499			69,216			17,281		86,497
Power		(13,357	)		230			(13,127	)		9,698		(3,429	)
Fuel		(5,551	)		(1,096	)		(6,647	)		5,088		(1,559	)

Subtotal — Operating risk hedges		(32,191	)		81,633			49,442			32,067		81,509
Interest rate derivatives		—			(214	)		(214	)		184		(30	)

Subtotal — Economic hedges		(32,191	)		81,419			49,228			32,251		81,479
Accounting hedges		—			3,954			3,954			198		4,152

Total hedging activity results	$	(32,191	)		85,373			53,182			32,449		85,631


	Year ended December 31, 2006
	Change in fair value attributable to:
	Roll-off			Change in value
	of prior			of			Total change in
Contract Type	estimates			remaining tenor			fair value			Settlements			Total

Conversion spread	$	—			(60,847	)		(60,847	)		3,500			(57,347	)
Power		(64,883	)		13,357			(51,526	)		56,892			5,366
Fuel		(20,844	)		5,551			(15,293	)		(26,230	)		(41,523	)

Subtotal — Operating risk hedges		(85,727	)		(41,939	)		(127,666	)		34,162			(93,504	)
Interest rate derivatives		—			(524	)		(524	)		438			(86	)

Total economic hedges	$	(85,727	)		(42,463	)		(128,190	)		34,600			(93,590	)


	Year ended December 31, 2005
	Change in Fair Value attributable to:
	Roll-off			Change in value
	of prior			of		Total change in
Contract Type	estimates			remaining tenor		fair value		Settlements			Total

Power	$	(41,278	)		64,883		23,605		17,560			41,165
Fuel		58,782			20,844		79,626		(86,562	)		(6,936	)

Subtotal — Operating risk hedges		17,504			85,727		103,231		(69,002	)		34,229
Interest rate derivatives		—			—		—		—			—

Total economic hedges	$	17,504			85,727		103,231		(69,002	)		34,229

F-106

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)


(5)	Long-Term Debt

Long-term debt consists of the following:


								Balance outstanding as of
	Facility Descriptive Information							May 31,			Dec. 31,
Facility	Borrower		Rate⁽¹⁾			Issued		2007			2006

Secured Obligations:
Revolving line of credit facility due 2013		BG		LIBOR -0.125	%⁽²⁾		2006	$	26,000			40,000
Term loan B due 2013		BG		LIBOR +2.25	%		2006		1,127,175			1,130,000
Term loan C due 2014		BG		LIBOR +4.25	%		2006		350,000			350,000
Unsecured Obligations:
Mezzanine facility due 2016		EBG		LIBOR +7.00	%		2006		316,925			301,132
		Holdings

Total long-term debt									1,820,100			1,821,132
Less current maturities									(11,300	)		(11,300	)
Current credit facility									(26,000	)		(40,000	)

Long-term debt, net of current maturities								$	1,782,800			1,769,832


(1)		The Company’s long-term debt is LIBOR-based with the option to elect a base plus applicable margin in lieu of LIBOR. The base rate is based on the prime rate or federal funds rate.

(2)		Interest rate on the drawn portion of the Revolving credit facility is LIBOR minus 0.125%. The fee associated with the undrawn portion of the total commitment of $70,000 is 2.375% per annum.

The long-term debt of Boston Generating, LLC, and its parent, EBG Holdings, LLC were assumed by USPowerGen in connection with the Combination. In connection with the Combination of the Company’s long-term indebtedness, no additional collateral was made available, nor was any portion guaranteed by USPowerGen.

The Revolving Credit Facility, Term Loan B, and standby letter of credit facility have credit ratings of BB- (Stable) by Standard and Poor’s (S&P) and B1 by Moody’s Investor Service (Moody’s). The Term Loan C has credit ratings of B (Stable) by S&P and B3 by Moody’s. The Mezzanine Loan is not rated.

Secured Obligations

The Revolving Credit Facility and the Term Loan B are secured by a first lien priority and the Term Loan C is secured by a second lien priority on the Boston power generation facilities. The Term Loan B requires quarterly scheduled principal repayments of $11,300 per annum. The Revolving Credit Facility and Term Loan C have no scheduled principal repayments. At its election, the Company can prepay the debt subject to certain prepayment penalties. Optional prepayments on Term Loan B require a prepayment premium of 1.0% if prior to December 20, 2007 and optional prepayments on Term Loan C require a prepayment premium of 1.0% from December 21, 2007 thru December 20, 2008, and no prepayment penalty thereafter. The Revolving Credit Facility and Term Loan B must be prepaid prior to any prepayment on Term Loan C.

The Revolving Credit Facility is a revolving facility with a syndicate of financial institutions providing for aggregate borrowings of $70,000. At May 31, 2007 and December 31, 2006, outstanding borrowings under the facility were $26,000 and $40,000, respectively. In addition to the Revolving Credit Facility, EBG also has a synthetic standby letter of credit facility secured by a first lien priority for up to $250,000. As of May 31, 2007, and December 31, 2006, standby letters of credit issued and outstanding under this facility was $188,012.

F-107

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The debt contains certain nonfinancial and financial covenants. These covenants require that the Company maintain certain derivatives that provide both operational and interest rate protection (Note 4) as well as covenants that limit the annual amount of capital expenditures incurred and dividends paid in a given calendar year. Furthermore, the debt includes the following financial ratio covenants which are calculated on an EBITDA basis as defined in each respective debt agreement:

Leverage ratio

Interest coverage ratio

First lien

Second lien

First lien

Second lien

priority

Current to
December 31, 2008

11.00:1.00

12.00:1.00

Current to
June 30, 2008

1.05:1.00

1.00:1.00

January 1, 2009 to
December 31, 2009

10.00:1.00

11.00:1.00

July 1, 2008 to
December 31, 2009

1.10:1.00

1.05:1.00

January 1, 2010 to
December 31, 2010

9.00:1.00

10.00:1.00

January 1, 2010 to
December 31, 2010

1.25:1.00

1.10:1.00

January 1, 2011 to
December 31, 2011

8.00:1.00

9.00:1.00

January 1, 2011 to
December 31, 2011

1.50:1.00

1.25:1.00

January 1, 2012 to
December 31, 2012

7.00:1.00

8.00:1.00

January 1, 2012 to
December 31, 2012

1.75:1.00

1.50:1.00

January 1, 2013 to
December 31, 2013

6.00:1.00

7.00:1.00

January 1, 2013 to
December 31, 2013

2.00:1.00

1.75:1.00

The debt also requires certain restricted cash deposits for debt service, operating reserves, and capital expenditures. The restricted cash balances were $114,083 and $162,706 as of May 31, 2007 and December 31, 2006, respectively.

Unsecured Obligations

The Mezzanine Loan due 2016 is an unsecured obligation of the Company. Interest payable on the Mezzanine Loan is not required to be paid current and is therefore added to the outstanding balance. It has no scheduled principal repayments prior to final maturity. At its option, the Company may make prepayments on the Mezzanine Loan which require make whole payments determined by the spread between the basis of a swap-equivalent fixed rate and a discount rate determined by reference to U.S. Treasury Securities. If terminated prior to December 20, 2008, the Company is subject to a make whole provision. Thereafter, the call premium is 3.0% of the principal amount prepaid prior to December 2009, 2.0% from December 2009 through December 2010, 1.0% from December 2010 through December 2011, and no make whole premium thereafter. Upon the repayment of the secured obligations described above, the Mezzanine Loan requires semi-annual mandatory prepayments as follows:


	Required prepayment
	Excess			Cash proceeds from			Net equity
	cash flow⁽¹⁾			permitted dispositions⁽²⁾			proceeds

Leverage ratio > 2.50:1.00		100	%		100	%		100	%
Leverage ratio < 2.50:1.00		50	%		50	%		25	%


(1)		Excess cash flows not reinvested in operations as defined.

(2)		Permitted disposition proceeds in excess of $10,000 not reinvested, as defined.

Additionally, the Mezzanine Loan requires prepayment upon a change of control (unless the proposed acquirer is a qualified buyer as defined, and upon Moody’s and S&P ratings confirmation).

F-108

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The Mezzanine Loan contains certain covenants, which include the prohibition, with certain exceptions, of the payment of dividends and incurrence of additional debt or liens.

Consolidated Annual Maturities

Scheduled maturities of the Company’s long-term debt for the seven-month period ended December 31, 2007 are $8,475 and as follows annually thereafter:


Year ended December 31, 2008	$	11,300
Year ended December 31, 2009		11,300
Year ended December 31, 2010		11,300
Year ended December 31, 2011		11,300
Year ended December 31, 2012		11,300
Thereafter		1,755,125

Total	$	1,811,625

2006 debt refinancing

On December 21, 2006, the Company completed a refinancing of all the outstanding debt and repaid all of its outstanding debt. On December 15, 2006, the Company prepaid the remaining amounts owed for the purchase of two outstanding interest rate caps. In connection with the refinancing, the Company recognized a loss of $17,500, consisting of $14,000 of applicable prepayment premiums paid, the write-off of $3,300 of remaining unamortized deferred financing costs and $200 associated with the interest rate cap prepayment, which has been reported as a loss on early extinguishment of debt in the Company’s 2006 consolidated statement of operations.


(6)	Fair Value of Financial Instruments

As of May 31, 2007, the Company’s assets and liabilities included a number of financial instruments, as defined by Statement of Financial Accounting Standards No. 107, Disclosures about Fair Value of Financial Instruments (SFAS No. 107). Such financial instruments primarily included; U.S. currency, dollar-denominated short-term or cash equivalents, trade receivables and payables, derivative contracts, and long-term debt financing facilities.


*(a)*	*Short-Duration Financial Instruments*

With respect to the Company’s cash, cash equivalents, trade receivables, and trade payables, such instruments are:

• Short term in duration and the values are relatively insensitive to changes in market rates; and

• Issued by the U.S. government or highly rated financial institutions and domestic corporations, not expected to experience material changes in credit quality in the reasonably foreseeable future, or for which adequate reserves could be recognized, if required. The values at which such instruments are reflected in its consolidated balance sheet approximates fair value.


*(b)*	*Long-Duration Financial Instruments*

The Company’s derivative instruments are carried at fair value, as required by SFAS No. 133 (Note 4). The Company’s long duration indebtedness includes numerous tranches of variable rate debt instruments

F-109

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

(Note 5), with differing levels of priority, security, collateral, as well as different maturity dates and stated rates of interest.


	•	As of May 31, 2007, the estimated fair value of the EBG’s long-term debt facilities was approximately $1,868,112, exceeding the carrying value of $1,820,100 by approximately $48,012. As of December 31, 2006, the estimated fair value of EBG’s long-term debt facilities was approximately $1,857,200, exceeding the carrying value of $1,821,132 by approximately $36,068.


	•	As of May 31, 2007 and December 31, 2006, the fair value of EBG’s derivative instruments was equal to the carrying value of $15,683 and ($37,500), respectively.

The table below provides a summary of the carrying value and estimated fair value of the Company’s long duration financial instruments as of May 31, 2007 and December 31, 2006:


	May 31, 2007						December 31, 2006
	Fair value		Carrying value		Difference		Fair value			Carrying value			Difference

Derivative instruments	$	15,683		15,683		—		(37,500	)		(37,500	)		—
EBG debt		1,868,112		1,820,100		48,012		1,857,200			1,821,132			36,068

Total long duration financial instruments	$	1,883,795		1,835,783		48,012		1,819,700			1,783,632			36,068


(7)	Intangible Assets

The Company recognizes specifically identifiable intangibles when specific rights and contracts are acquired. The Company has no intangible assets with indefinite lives. Hence, all capitalized intangible assets recognized, which consist of emissions allowances and gas transportation contracts are amortized over the estimated remaining useful lives of such intangible assets. Emissions allowances are amortized on the basis of units of production, while gas transportation contracts are amortized based on contractual volume levels. The amortization of emissions allowances and gas transportation contracts are recognized as a component of fuel expense.


				Gas
	Emissions			transportation
	allowances			contracts			Total
As of December 31, 2006
January 1, 2006	$	66,383			37,397			103,780
Dispositions and expirations		(1,195	)		—			(1,195	)

Adjusted gross amount		65,188			37,397			102,585
Less: accumulated amortization		(3,591	)		(2,158	)		(5,749	)

Net carrying amount	$	61,597		$	35,239			96,836

F-110

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)


				Gas
	Emissions			transportation
	allowances			contracts			Total
As of May 31, 2007
January 1, 2007	$	65,188			37,397			102,585
Dispositions and expirations		(870	)		—			(870	)

Adjusted gross amount		64,318			37,397			101,715
Less: accumulated amortization		(4,318	)		(3,057	)		(7,375	)

Net carrying amount	$	60,000		$	34,340			94,340

The following table presents the amortization of intangible assets recognized as an expense during the five month period ending May 31, 2007 and the years ended December 31, 2006 and 2005:


	Five months
	ended		Year ended		Year ended
	May 31,		December 31,		December 31,
	2007		2006		2005

Emissions allowances	$	727		958		2,538
Gas transportation contracts		899		2,158		—

	$	1,626		3,116		2,538

Based upon the Company’s current intangible assets and the related values estimated as of May 31, 2007, the amount, expected to be recognized as amortization expense during the seven-month period ending December 31, 2007 is $1,903. Annually, expected amortization of intangible assets is summarized in the following table:


Year Ended December 31,

2008	$	3,531
2009		3,531
2010		3,531
2011		3,531
2012 and thereafter		78,313

As of May 31, 2007, the dollar-weighted average amortization period of the Company’s unamortized emissions allowances and capitalized gas transportation contracts were 8.8 and 11.8 years, respectively. In aggregate, the dollar-weighted average of all unamortized intangible assets at December 31, 2007 was approximately 9.9 years.


(8)	Benefit Plans and other Postretirement Benefits


*(a)*	*Defined Contribution Plans*

Substantially all of the Company’s employees are eligible to participate in defined contribution (401(k) or 401(a)) savings plans that are sponsored by the Company. Under these plans, eligible employees may contribute a portion of their compensation which is matched by the Company. In addition to matching, the Company can make a discretionary profit sharing match.

EBG sponsors the BG Boston Services LLC Union Retirement 401(k) Plan, the BG New England Power Services, Inc. 401(k) Plan, and the BG New England Power Services, Inc. Union Retirement 401(k) Plan (the

F-111

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

EBG Plans). Under the EBG Plans, participating employees may contribute a portion of their compensation, pre tax or after tax, generally up to a maximum of 18% of their compensation. The savings plan’s matching contribution of 100% of the first 5% of the participating employee match. Union employees may contribute and receive a match based on the terms of their collective bargaining agreement. The savings plan benefit expenses of this plan was $254 and $646 for the five months ended May 31, 2007 and year ended December 31, 2006, respectively.


*(b)*	*Defined Benefit Plan*

In September 2006, the FASB issued SFAS No. 158. The statement requires an employer that sponsors one of more single-employer defined benefit plans to recognize the funded status of a benefit plan in its statement of financial position with an offset to OCI, and recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. SFAS No. 158 was effective for publicly traded companies with fiscal years ending after December 15, 2006, and for privately held companies no later than fiscal years ending after June 15, 2007. The Company’s financial statements reflect the adoption of SFAS No. 158 as if it had been a public company at December 31, 2006. The following table summarizes the effect of applying SFAS No. 158 at December 31, 2006:


	Before application of						After application of
	SFAS No. 158			Adjustments			SFAS No. 158

Liability for pension and other post employment benefits	$	(666	)		(129	)		(795	)
Other comprehensive income		—			129			129

Total assets	$	1,225,910			—			1,225,910
Total liabilities	$	(2,051,859	)		(129	)		(2,051,988	)

Total members’ capital	$	825,949			129			826,078

(c) Pension Plan

The Company Plan covers approximately 100 of the Company’s Boston generation facility employees. Approximately 80 of these employees accrue a future service only cash balance benefit equal to 3% of covered pay each year. Approximately 20 of these employees accrue benefits under a traditional defined benefit formula. These benefits were grandfathered as a result of a pre-2004 collective bargaining agreement. The disclosures below includes the BG plan.

The net periodic pension cost related to the Company consists of the following components:


	Five months
	ended			Year ended
	May 31,			December 31,
	2007			2006

Service cost	$	127			302
Interest cost on benefit obligations		34			58
Expected return on plan assets		(16	)		(17	)
Net amortization		3			9

Net periodic benefit cost	$	148			352

F-112

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

A comparison of the pension benefit obligation and pension assets as of May 31, 2007 and December 31, 2006 is as follows:


	Five months
	ended			Year ended
	May 31,			December 31,
	2007			2006

Change in benefit obligation:
Beginning of period	$	1,056			747
Service cost		127			302
Interest cost		34			58
Benefits paid		—			(12	)
Actuarial loss (gain)		10			(39	)

End of period		1,227			1,056

Change in plan assets:
Beginning of period		262			180
Actual investment return		21			18
Employer contributions		134			75
Benefits paid		—			(12	)

End of period		417			261

Reconciliation of funded status:
Funded status		(810	)		(795	)

Net amount recognized	$	(810	)		(795	)

Amounts recognized in the Company’s balance sheets were as follows:


	May 31,		December 31,
	2007		2006

Noncurrent liabilities	$	810		795
Other comprehensive income	$	1		(129	)

Amounts recognized in accumulated other comprehensive income that has not yet been recognized as components of net periodic benefit cost were as follows:


	May 31,		December 31,
	2007		2006

Net loss	$	129		129

Other changes in plan assets and benefit obligations recognized in other comprehensive income are as follows:


	Five months		Year ended
	ended May 31,		December 31,
	2007		2006

Current year actuarial loss	$	129		129
Amortization of actuarial loss		—		—

Total recognized in other comprehensive income	$	129		129

F-113

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

The following table presents the balances of significant components of the Company’s pension plans:


	May 31, 2007		December 31, 2006

Projected benefit obligation	$	1,227		1,056
Accumulated benefit obligation	$	963		768
Fair value of plan assets	$	416		262

Estimated benefit payments for the seven-month period ended December 31, 2007 are $24 and as follows for the next ten years:


Year

2008	$	37
2009		56
2010		87
2011		81
2012		141
2013 — 2017	$	1,026

The following table presents the significant assumption utilized to calculate the Company’s benefit obligations and net periodic benefit for the respective periods ending:


	May 31,			December 31,
	2007			2006

*Benefit Obligation:*
Discount rate		6.10	%		5.85	%
Rate of compensation increase		4.00	%		4.00	%
*Benefit Expense:*
Discount rate		5.85	%		5.60	%
Rate of compensation increase		4.00	%		4.00	%
Expected return on plan assets		9.00	%		9.00	%

The Company uses December 31 of each respective year as the measurement date for the Company’s pension plans. Long-term rates of return on pension plan assets take into consideration expected inflation, current dividend yields, expected corporate earnings growth, and risk premiums based on each asset category. Discount rate assumptions are based upon current rates at which associated liabilities could be currently settled at the end of each plan year. Underlying rates are based on bond yields that have a rating of Aa or better by Moody’s or a rating of AA or better by S&P.

The Company manages the investments associated with its pension plans with the objective to exceed on a net-of-fee basis the rate of return of certain performance benchmarks. Target investment for the assets are

F-114

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

48%-66% equity securities, 34%-46% debt securities, and other 0%-6%. The Company’s weighted average allocation was as follows for the periods presented:


	May 31,			December 31,
Asset Class	2007			2006

Equity securities		62	%		61	%
Debt securities		36	%		38	%
Other		2	%		1	%

The Company expects to pay $591 in cash contributions during the seven months ended December 31, 2007.


(9)	Equity-Based Compensation

Effective March 30, 2006, the Company adopted the EBG Holdings LLC 2006 Unit Appreciation Rights Plan (the UAR Plan) to provide the independent directors on the Company’s board of directors (the Board) with the opportunity to receive grants of Unit Appreciation Rights (the UARs). The Company believes that the Plan will encourage the participants to contribute materially to the growth of the Company, thereby benefiting the Company’s members, and will align the economic interests of the participants with those of the members.

Under the UAR Plan, up to 75,000 UARs may be granted, as determined by the Board or a committee established to administer the UAR Plan. UARs, when exercised, entitle the grantee to receive a cash payment equal to the fair value of the Company’s Class A Units on the exercise date less the base amount per Class A Unit on the grant date. Participants in the UAR Plan are not entitled to receive Class A Units and no additional Class A Units will be issued by the Company under the UAR Plan. UARs granted under the UAR Plan will become vested 331/3% six months after grant date, 662/3% twelve months after grant date and 100% eighteen months after grant date, provided that the grantee remains on the Board. Under certain circumstances, including a merger, vesting of UARs will be accelerated.

An initial grant of 1,500 UARs at a base amount of $250 per UAR was made to each of the Company’s five independent directors upon their election to the Board on March 30, 2006, as authorized by the Company’s nominating committee under the Company’s LLC Agreement. Upon vesting, these 7,500 UARs are exercisable through October 10, 2013. The base amount on the grant date was the average of the bid and ask prices of the Company’s Class A Units on March 30, 2006, as quoted by a major U.S. broker-dealer, which represented the fair value of the Company’s Class A Units.

The Company recognizes expense associated with the UAR Plan using the intrinsic method as provided in SFAS No. 123(R), Share - Based Payment. Under the intrinsic method, expense is measured based on the change in fair value of the UARs from the grant date to the end of the period and the UAR vesting percentage. For purposes of expense under the UAR Plan, the Company determines fair value of UARs based on the average of bid and ask prices for the Company’s Class A Units as quoted by major U.S. broker-dealers. As provided by the UAR Plan, the base price of the March 30, 2006 UARs was adjusted to $244.71 to reflect the Distribution. At December 31, 2006 there were 7,500 UARs granted, 2,500 of which were exercisable with a fair value of $367,000. For the year ended December 31, 2006, the Company recognized $367,000 of expense for the UAR Plan, which has been accrued in other current liabilities on the consolidated balance sheet at December 31, 2006.

F-115

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

(10) Members’ Equity

In December 2006, the Company completed a series of transactions collectively referred to as the Recapitalization, which consist of the following:

A distribution of $5.29 per unit, or approximately $35,000, on December 26, 2006 to the Company’s members of record as of December 26, 2006 (the Distribution).

The purchase of 2,720,641 units, or approximately 41.125% of the Company’s outstanding Class A and Class B Units, for $340 per unit, or approximately $925,000, on December 27, 2006 (the Offer).

The repurchase of 222,759 warrants, or approximately 41.125% of the outstanding warrants to purchase units held by affiliates of K Road BG LLC (K Road BG) (the K Road Warrants) for $226.07 per warrant, or approximately $50.4 million, on December 22, 2006. The price paid per warrant was equal to the spread between the price paid for units in the Offer and the K Road Warrant exercise price as adjusted for the Distribution, in accordance with the terms of the K Road Warrants.

The Company also amended the K Road Warrants to permit a cashless exercise concurrently with the purchase of units pursuant to the Offer based on the price per unit paid in the Offer, resulting in the cashless exercise of 318,907 K Road Warrants and the issuance of 212,045 Class A units on December 28, 2006.

On October 11, 2005, the Company and its Lenders/Owners consummated a restructuring of the Company’s outstanding debt and accrued interest obligations with an aggregate book value of approximately $1,200,000. The restructuring included the repayment of approximately $126,500 of existing debt and the conversion of approximately $650,000 of existing debt obligations into the $350,000 2005 Series A First Lien and the $300,000 2005 Second Lien. All remaining amounts due under the BG Facility and Interest Rate Swap liability, including principal and interest, were converted into 5,850,000 Class B Units of members’ capital of the Company, with a book value of approximately $350,000.

In connection with the 2005 restructuring, the Company completed the sale of 650,000 Class A units of the Company and a warrant to purchase an additional 722,222 Class A units (the Warrant) to K Road BG for $65,000. The Company contributed this $65,000 of capital to BG, where it was utilized to repay outstanding debt obligations under the BG Facility as described above.

The Warrant is exercisable in whole or in part at any time through October 10, 2013. The initial exercise price was $118.78 per Class A unit through October 10, 2007. Under the terms of the Warrant, the initial exercise price was adjusted to $113.93 per Class A unit as a result of the Distribution. Effective October 11, 2007 and on each October 11 thereafter, the exercise price will be increased by 5% from the previous exercise price then in effect.

From June 7, 2006 through December 11, 2006, portions of the Warrant covering 115,556 Class A units were exercised. The Company received a total of approximately $13,700 in payments of the exercise price and issued 115,556 new Class A units. After these Warrant exercises and the repurchase of a portion of the K Road Warrants and the cashless exercise of a portion of the K Road Warrants during the Recapitalization, 65,000 Warrants for the purchase of 650,000 Class A units remain issued and outstanding as of December 31, 2006.

Under the terms of the Company’s limited liability company agreement, as amended, the Warrant was only transferable by K Road BG to its key officers, directors, or employees and affiliates directly involved with the management or administration of K Road BG’s investment in the Company through March 31, 2006. On April 1, 2006, this restriction on transfers was waived for 25% of the Warrant. In connection with the Recapitalization, the Company amended the EBG LLC Agreement to modify the transfer restrictions applicable to (i) the K Road Warrants and the Units issued thereunder so that 50% of such securities become

F-116

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

freely transferable on April 1, 2007 and the remaining 50% become so on April 1, 2008 and (ii) the other Units held by K Road BG so that 10% of such securities become freely transferable on July 1, 2007, and an additional 10% on each July 1 thereafter through July 1, 2011, when 100% of such securities will become freely transferable.

In the event that the Company sells all or substantially all of its assets or causes to be sold all or substantially all of the Facilities prior to the exercise or termination of the Warrant, then the holder of the Warrant will be entitled to receive the greater of (i) the value that would have been distributed to the Warrant holder as the result of any such contemplated transaction had the Warrant been exercised and the exercise price therefore had been paid by the Warrant holder, or (ii) an option value payment based on the timing of the sale and that shall be reduced on a pro-rata basis based on the percentage of Class A units purchased by the Warrant holder in any previous partial exercise of the Warrant. Based upon the remaining 65,000 Class A units under the Warrant, this option value payment ranges from $1,000 if a transaction occurs prior to October 11, 2008 to $0 if a transaction occurs after October 11, 2012.

(11) Income Taxes

The Company accounts for income taxes in accordance with Statement of Financial Standards No. 109, Accounting for Income Taxes (SFAS No. 109). Through March 30, 2006, EBG was a limited liability company and therefore items of income and expense were allocated to its members in their respective tax returns. EBG made an election, on March 30, 2006, and the Internal Revenue Service approved the election on May 15, 2006, to be taxed as a C corporation under the Internal Revenue Code for all periods beginning on and after March 31, 2006. As a result of the Combination, EBG is included in USPowerGen’s consolidated tax return.


	May 31,			December 31,
	2007			2006

Depreciable assets	$	84,527			92,731
Derivative assets and liabilities, net		(4,601	)		16,275
Distrigas liquidated damages and late fees in dispute		14,693			11,716
Interest paid-in-kind		5,549			—
Net operating loss carryforward		26,469			13,325
Other		1,677			698

Gross deferred tax assets		128,314			134,745
Valuation allowances		(91,309	)		(96,760	)

		37,005			37,985
Emissions allowances		(23,535	)		(24,162	)
Intangible asset		(13,470	)		(13,823	)

Gross deferred tax liabilities		(37,005	)		(37,985	)

Net deferred tax liabilities	$	—			—

At May 31, 2007, the Company has a net operating loss carryforward for Federal income tax purposes of $26,469 which , if unused, will expire on May 31, 2027. In assessing the realizability of gross deferred tax assets and the need for a valuation allowance against these deferred tax assets, management must consider, in its best estimate, whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In determining the need for a valuation allowance against the net deferred tax assets, management considers the scheduled reversal of

F-117

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

deferred tax liabilities, projected future taxable income, and tax planning strategies. Due to its historical book and tax losses, the Company has not relied on projected future income in assessing the need for a valuation allowance as of May 31, 2007. Since realization of these net deferred tax assets is based upon future taxable income, these deferred tax assets have a full valuation allowance reducing their carrying value to zero.

The following is a reconciliation of the U.S. federal statutory rate of 35% to the Company’s effective income tax rate:


	Five months ended					Year ended
	May 31, 2007					December 31, 2006

Tax computed at statutory rate	$	3,916		35.0	%	$	(39,913	)	35.0	%
Income allocated to members January 1, through March 30, prior to the election to be taxed as a corporation		—					18,631		(16.3	)
Deferred tax assets recorded upon the election to be taxed as a corporation effective March 31, 2006		—					(74,964	)	65.7
State income tax provision, net of federal income tax effect		582		5.0			(912	)	0.8
Non-deductible interest expense on Mezzanine Facility		908		8.0			396		(0.3	)
Valuation allowance on net deferred tax assets		(5,407	)	(48.0	)		96,760		(84.9	)
Other, net		1		—			2		—

Income tax expense (benefit)	$	—		—	%	$	—		—	%

(12) Commitments and Contingent Liabilities

(a) Commitments

The Company has the following estimated future contractual commitments, primarily related to fuel procurement and transportation services, as of May 31, 2007 (in millions):


	2008		2009		2010		2011		2012		Thereafter

Natural gas supply agreement	$	113.6		113.6		113.6		113.6		113.6		1,126.7
Long-term service agreements		27.0		27.0		27.0		23.7		—		—
Transportation services — fuel		8.6		8.6		8.6		8.6		8.6		77.6
Energy management agreements		0.8		—		—		—		—		—
Operating leases		0.1		—		—		—		—		—

Total	$	150.1		149.2		149.2		145.9		122.2		1,204.3

Natural Gas Supply Agreement — The Company has an agreement with Distrigas of Massachusetts, LLC (Distrigas) to supply Mystic 8&9 with a firm supply of natural gas from Distrigas’ natural gas facility located adjacent to those facilities (Note 16).

Long-term service agreement — The Company has two long-term services agreements with Mitsubishi Power Systems Americas, Inc. (MPS) under which MPS provides all major maintenance services, including refurbishment of spare parts, for gas turbine generators and related equipment at the Company’s Mystic 8&9 and Fore River facilities. Under these agreements, MPS receives a fixed fee (which is currently $30 per month) for monitoring this equipment and a variable fee based on the number of equivalent operating hours incurred by this equipment, and each of these fees is paid on a monthly basis. Major maintenance services are required to be performed by MPS at intervals of no more than every 8,800 equivalent operating hours for each service. The agreements also provide that MPS shall receive minimum variable fees for at least 8,600 equivalent hours for each major maintenance service. The MPS agreement expires on the earlier of the

F-118

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

completion of the required number of planned maintenance outages or 11 years. The table on the previous page reflects the fixed payment obligations under this agreement. The Company recorded expense under this agreement of $8,617 for the five months ended May 31, 2007.

Transportation services — fuel — The Company’s Fore River facility which is located in the Boston area is party to an agreement with Algonquin Gas Transmission Company (Algonquin) that provides natural gas transportation. This contract has a primary term of twenty years commencing September 1, 2001, and continuing on a year-to-year basis after the primary term. The agreement provides that Algonquin will transport a maximum of 140,000 dekatherms per day of natural gas from the intersection of Algonquins Q and I-3 systems and the inter connection of the AGT and Maritimes & Northeast pipelines to the Fore River facility. All pricing under this agreement is subject to FERC filed tariff rates.

Energy management agreements — The Company’s Boston facilities sell 100% of the electric energy, capacity and ancillary services supplied by their facilities to Sempra pursuant to an Energy Management Agreement. Under this agreement, Sempra performs all energy management services related to the power plants at our Boston Facilities, including nominating, scheduling and adjusting schedules for electricity, fuel and other related services. Electric energy, capacity and ancillary services are sold to Sempra at the same prices that Sempra receives from the sales of these products into the ISO-NE market and from other customers under bilateral contracts. The term of this agreement is through September 30, 2008 and may be terminated by either party upon 60 days’ notice. Sempra receives a fixed monthly fee of $275 and a variable fee based on our Boston Facilities’ net operating margin. The table above includes the fixed rate obligations of the Company. The Company recorded expense under this agreement of $2,612 for the five months ended May 31, 2007. This agreement was terminated by mutual agreement of the parties effective April 1, 2008.

Operating Leases — The Company has a noncancelable operating lease for office space that runs through June 30, 2008. Total rent expense under this lease was $56 for the five months ended May 31, 2007, $229 and $230 for the years ended December 31, 2005 and 2006, respectively.

(b) Contingent Liabilities

In accordance with Statement of Financial Accounting Standards No. 5, Accounting for Contingencies (SFAS No. 5) and related guidance, the Company records reserves for loss contingencies when available information indicates that the loss is probable and reasonably estimable. Due to the inherent uncertainty of litigation or threatened litigation, there can be no assurance that the Company will not incur additional charges related to the items discussed below or future adverse rulings, changes, or unfavorable developments. Such events could have a material impact on the results of operations or financial position of the Company.

The Company and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect the Company’s consolidated financial position, results of operations or cash flows.


(13)	Regulatory Matters

As an independent power provider, the Company’s operations are not regulated operations, and hence are not subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). As such, the Company does not record assets or liabilities from the regulated ratemaking processes. However, the Company does operate in a highly regulatory environment and is subject to various federal, state and local regulations. Significant changes within the regulatory environment could have a material impact on the Company’s results of operations and statement of financial position.

Boston Capacity Market — On December 1, 2006, ISO-NE implemented changes in the capacity market whereby generators could sell capacity as part of the FERC-approved Forward Capacity Market (FCM)

F-119

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

structure. The structure has two main components, a settlement period and forward capacity auctions. During the settlement period, power generators supplying capacity receive fixed transition payments ranging from $3.05/kW-month from June 1, 2007 through May 31, 2008, to $3.75/kW-month from June 1, 2008 through May 31, 2009, to $4.10 /kW-month from June 1, 2009 to May 31, 2010. For the periods after May 2010, the Company will participate in capacity auctions for three years forward to meet its installed capacity requirements. These auctions are expected to begin the first quarter of 2008. At this time, the Company is unable to determine the outcome of the auction process. An unfavorable outcome could have a negative impact on the results of operations of the Company.


(14)	Environmental

(a) Air Initiatives

On May 12, 2005, the EPA published the Clean Air Interstate Rule (CAIR). This rule applies to 28 eastern states, and the District of Columbia, and caps SO₂ and NO_x emissions from power plants in two phases - 2010 and 2015 for SO₂ and 2009 and 2015 for NO_x. On August 24, 2005, the EPA published a proposed Federal Implementation Plan (FIP), to ensure that generators affected by CAIR reduce emissions on schedule. In parallel actions in late 2005, the EPA proposed the second phase of the 8-hour ozone NAAQS rule relating to NO_x emissions and signed proposed revisions to address attainment of National Ambient Air Quality Standards (NAAQS) for “fine particulates,” or (PM2.5), which will require affected states to implement further rules to address SO₂ and NO_x emissions. Numerous environmental groups, states and industry organizations challenged aspects of the CAIR. The challenges were consolidated into the proceeding titled South Coast Air Quality Management District v. EPA. In December 2006, the U.S. Circuit Court for D.C. Circuit overturned portions of EPA’s Phase I CAIR implementation rule for the new 8-hour ozone standard holding that the EPA could revoke the 1-hour standard as long as there was no backsliding from more stringent control measures. This ruling may result in the imposition of fees under Section 185 of the Clean Air Act (CAA) on volatile organic hydrocarbon (VOC) and NO_x emissions in severe ozone non-attainment areas. The fees could be as high as $7,700/ton for emissions above 80% of baseline emissions levels. Depending on the determination of baseline emission levels, the Company’s New York City operations may be materially affected by the 8-hour ozone standard. On July 11, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated both CAIR and its associated Federal Implementation Plan in their entirety and remanded them to the EPA. The impact of this ruling is unknown as of the date of the consolidated financial statements.

The Clean Air Visibility Rule was published by the EPA on July 6, 2005. The rule requires regional haze controls by targeting SO₂ and NO_x (and particulate matter and VOC) emissions from sources including power plants of a certain age through the installation, in certain instances, of Best Available Retrofit Technology, (BART). States must develop implementation plans by December 2007. USPowerGen believes most of its facilities will be in compliance with BART. Mystic Unit 7 has been identified by the Massachusetts Department of Environmental Protection as potentially subject to BART and we may be required to undertake actions with respect to BART compliance of this facility.

Ten Northeast and Mid-Atlantic states, including Massachusetts, have agreed to participate in a mandatory regional cap-and-trade program known as the Regional Greenhouse Gas Initiative (RGGI). RGGI applies to electricity generator units that have a nameplate capacity of at least 25 MW and whose use of fossil fuels is greater than 50%. From 2009 to 2015, RGGI aims to stabilize annual power sector emissions of CO₂ at the level of average annual emissions from 2000 to 2004, and from 2015 to 2018, RGGI would impose a 2.5% annual reduction to achieve an overall 10% reduction in CO₂ emissions.

F-120

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

use energy efficiency programs. This is generally interpreted to mean that these allowances will be auctioned for any entity (even non-power plants) to procure. Whether through auction or allocation, companies will then be allowed to trade their allowances in a secondary market. Those facilities which emit less CO₂ than what they have in allocations can sell those excess allowances, while those facilities which emit more than their allocations will need to procure sufficient allowances to balance their books. One additional option that affected facilities will have is reducing CO₂ emissions from outside the plant, by what is known as obtaining offsets. However, RGGI restricts offsets to certain projects performed in certain states and to certain total quantities below a threshold. The vast majority of CO₂ reductions are intended under RGGI to occur in-house. RGGI will run on three-year cycles (2009 through 2011; 2012 through 2014; etc.) to adjust for any particular higher-than-expected demand year.

The Company’s power generating units are projected to emit approximately 5.9 million tons of CO₂, a GHG, for 2007. All of its facilities will be subject to state regulation under RGGI. The Mystic Jet unit, however, will be exempt from RGGI because it falls below the 25 MW threshold. Under the Massachusetts Department of Environmental Protection RGGI rule, affected sources will be required to purchase allowances corresponding to 100% of their CO₂ emissions beginning in January 2009. We may obtain a portion of our RGGI allowances through offset projects or other projects designed to reduce emissions.

The Company’s facilities are subject to a cap-and-trade program governing NO_x emissions during the ozone season, typically from May 1 through September 30 of each year. These rules require that one NO_x allowance be held for each ton of NO_x emitted. Each of our facilities that is subject to these rules has been allocated NO_x emissions allowances. We estimate that the NO_x allowance portfolio total is currently sufficient to cover operations at these facilities through 2011. However, if at any point emissions allowances are insufficient for the anticipated operation of each of these facilities, the Company would be required to purchase NO_x allowances to cover any deficit, and this obligation could result in material costs.

The Ozone Transport Commission, (OTC), was established by Congress and governs ozone and the NO_x budget program in states along the U.S. eastern seaboard, from Maine to Virginia. The OTC proposes to implement a regional plan containing emission reduction targets for power plants. OTC targets and timelines are yet to be implemented although additional SO₂ and NO_x reductions remain in discussion. Current attention is focused on NO_x emissions from units run primarily on High Energy Demand Days, (HEDD). While it is not possible to predict the outcome of this regional effort, to the extent that the OTC is successful in implementing emission requirements that are more stringent than existing regimes, the Company could be materially affected.

(b) Water Initiatives

The Clean Water Act requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. In July 2004, the EPA published regulations governing cooling water intake structures at large existing power plants that withdraw more than 50 million gallons of cooling water per day. The regulations would apply to the Company’s Mystic 7 facility. The regulations required implementation of the BTA for minimizing adverse environmental effects and provide generating facilities with several options for achieving the required BTA. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit vacated key portions of the regulation. In July 2007, the EPA suspended the regulation. A new round of rulemaking has not been announced and it may be several years before a revised cooling water intake structure regulation is finalized.

F-121

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

certainty the capital costs that will be required to comply with BTA. However, if the BTA requires significant changes to the cooling water intake systems at our Mystic 7 facility, our costs to implement these changes may be material.

(c) Domestic Site Remediation Matters

Environmental laws and regulations impose liability on the owner or operator of any facility, including an electric generating, facility for releases of hazardous or toxic substances or petroleum products at the facility. These laws impose liability without regard to whether the owner knew of or caused the release.

Known remediation matters exist at the Company’s facilities, including the following:


	•	Our Mystic 7 facility has documented subsurface contamination located beneath its active aboveground storage tanks (AST). Under the Massachusetts Contingency Plan (MCP) process, remediation of the soil and groundwater beneath these tanks will be required once these tanks are no longer in use. We do not currently intend to take these tanks out of service. The expected life of these tanks is through 2020 (based on the expected life of the Mystic 7 generating unit). Currently, groundwater monitoring and periodic NAPL recovery is being conducted under an approved remedial plan. Should evidence of contaminant migration be discovered during routine monitoring, further remedial actions will be required even if the aboveground storage tanks are still in use. At the end of the useful life of the Mystic 7 facility, we would either refurbish these ASTs for an allowed alternative use, or remove them from service. Should we decide to remove these ASTs from service, additional investigative activities will be conducted to refine necessary remediation actions.

	•	The Mystic 8&9 facility construction required the investigation and remediation of certain contaminants in accordance with the MCP. In completing the project, an Activity Use Limitation (AUL) was instituted for the remediation area. The AUL, recorded against the property deed for this facility, allows some contaminants to remain on site, with no further remediation required, provided affected soils are not disturbed and the site remains as an industrial use site.

	•	The Fore River facility construction required the investigation and remediation of certain contaminants in accordance with the MCP and the federal Toxic Substance Control Act (TSCA). In completing the project, various AULs were instituted for the remediation area. These AULs, recorded against the property deed for this facility, allowed some contaminants to remain on site, with no further remediation required, provided affected soils are not disturbed and the site remains as an industrial use site. A capped asbestos landfill containing asbestos removed from the former generation facility and capped in accordance with applicable federal and state requirements is located on the property. In addition, several other areas associated with the former generation facility were affected by historic operations and have been either remediated and closed or partially investigated.

With respect to the known remediation matters previously described, it is probable that, at some future date, the Company will incur certain costs in order to complete the remediation required under the environmental regulations and by the Massachusetts Department of Environmental Protection outlined in the preceding paragraphs. Further, the Company believes that certain remediation costs associated with a portion of the environmental contamination liabilities at the Company’s facilities cannot be reasonably estimated at this time, such costs including those associated with soil excavation, LNAPL recovery, capping certain designated areas, and maintaining ground water monitoring activities.

In addition, several other areas associated with the former generation facility have been impacted by historic operations and have been either remediated and closed or partially investigated. The Company is actively quantifying estimated final remediation costs for these remaining impacted and potentially impacted areas. As of May 31, 2007, the Company has accrued $655 related to these remediation costs.

F-122

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

Finally, certain of the Company’s facilities were constructed at a time when asbestos was routinely used as an insulating material. It is not required under any applicable laws or regulations to abate the asbestos containing materials currently present at our facilities. The Company does, however, as a matter of course abate any such materials in connection with any significant facility expansion or improvements.


(15)	Related Parties

In the ordinary course of business, the Company has entered into various transactions with some of its affiliates, principal shareholders, directors and officers (collectively, the Related Parties). The paragraphs below describe the Company’s transactions or agreements with Related Parties. Further, the tables below provide a summary of the related party transactions recognized as receivables and payables as of May 31, 2007, and December 31, 2006, and the revenues and expenses recognized during the five-month period ended May 31, 2007 and the years ended December 31, 2006:


	May 31,		December 31,
	2007		2006

Payables due to Related Parties	$	—		(174	)

Net amount due from Related Parties	$	—		(174	)


	May 31,		December 31,		December 31,
	2007		2006		2005

Expenses — related party transactions	$	2,552		5,994		1,100

Net Related Party Transactions Recognized	$	2,552		5,994		1,100

(a) Transactions and Agreements Involving Affiliates


	•	K Road Management Fees: On October 11, 2005, the Company executed a Management and Operations Agreement with K Road BG Management, LLC (K Road), an affiliate of K Road, for an initial term of eight years. Under the terms of this agreement, K Road was responsible for managing the Company, operating its power plants, and providing services in the areas of regulatory affairs, governmental approvals compliance and monitoring, contractual compliance, finance, accounting and tax, legal affairs, insurance and safety, information technology, energy management services and oversight of the energy manager, and operations and maintenance services. For these services, K Road was entitled to an annual management fee of $600 and reimbursement of its reasonable out-of-pocket costs incurred, not to exceed $5,400 per year. The expense reimbursement cap is subject to an annual increase for inflation commencing January 1, 2007. Fees and reimbursed expenses paid to K Road totaled $2,552, $5,994 and $1,100 for the five-month period ended May 31, 2007, and the years ended December 31, 2006 and 2005, respectively. As of May 31, 2007 and December 31, 2006, $0 and $174, respectively, were owed to K Road. Finally, upon closing of the Combination transaction with Astoria Generating, the Management and Operations Agreements with K Road was terminated without penalty.

(b) Other


	•	Certain of the Company’s shareholders with equity ownership in excess of 5% are also investors in the Company’s debt securities.

F-123

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)


(16)	Subsequent Events

(a) Combination with Astoria

On June 1, 2007. the Company completed the Combination with Astoria to form USPowerGen. Following the Combination, USPowerGen owns and operates six power generation facilities located in the northeastern United States, with a total generating capacity of approximately 5,223 MW. USPowerGen sells its capacity and energy generated into the NYISO and ISO-NE deregulated markets. In connection with the foregoing transaction the following occurred:


	•	The Company’s shareholders exchanged their EBG units for 41.1 million shares of USPowerGen Class A Common Stock plus warrants to purchase an additional 650 shares of Class A Common Stock. The Class A Common Stock held by former EBG shareholders represents approximately 54% of the total equity interests in USPowerGen.

	•	The former Astoria shareholders exchanged 100% of their Astoria limited partnership units for 35.5 million shares of USPowerGen Class B Common Stock. The Class B Common Stock held by the former Astoria shareholders represents approximately 46% of the total equity interest in USPowerGen.

	•	The then-existing management agreement between the Company and K Road was terminated, without any payment and USPowerGen entered into a consulting agreement with K Road to provide advisory services to USPowerGen in connection with an initial public offering. As consideration for such services, K Road will receive a one-time fee equal to one percent (1.0%) of the aggregate proceeds of an initial public offering, provided that fee shall not be less than $3,000.

In accordance with Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS No. 141), it was determined that for financial reporting purposes, the Combination was accounted as an acquisition of EBG by USPowerGen using purchase method accounting. The purchase price was approximately $1,203,300, which represents 54% of the post-Combination equity value of USPowerGen, as determined by management as of June 1, 2007.

In connection with the Combination, the Company’s UAR’s also became fully vested and the holders were paid $1,483 in exchange for the UARS. Upon exchange, the UAR’s were retired.

(b) Derivative Amendment

On October 1, 2007, the Company executed an amendment to the NEMA A Put and Swap contracts, which together with the NEMA B Put and Swap contracts, comprise the conversion spread hedge maintained to fix the spark spread on a portion of the Company’s generating operations. The NEMA A & NEMA B contracts were originally executed on December 20, 2006. Since inception, the conversion spread derivative contracts, either individually or collectively, have been amended three times.

The following is a brief summary of the contract amendments executed to date:

i) Amendment 1 — NEMA A & NEMA B Puts — Executed January 29, 2007:


	•	The exercise periods for the NEMA A & NEMA B puts, and the related reference prices and calculation periods were segregated into three distinct periods per day, and

	•	Established a specific daily put expiration, or exercise deadline, of 9:40AM of the on-peak day prior to any upcoming calculation period.

F-124

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

ii) Amendment 2 — NEMA A Put & Swap — Executed August 19, 2007:


	•	The underlying power reference price was changed from 4008: NEMASSBOST to 4000: H.INTERNAL for the period January 1, 2009 through December 31, 2010, and

	•	The monthly fixed premium payment was increased from $1,942 to $2,592

iii) Amendment 3 — NEMA A Put & Swap — Executed October 1, 2007:


	•	The underlying power reference price was changed from 4008: NEMASSBOST to 4000: H.INTERNAL for the period January 1, 2008 through December 31, 2008, and

	•	The monthly fixed premium payment was increased from $1,942 to $2,428


*(c)*	*Natural Gas Supply Contract — (Distrigas Agreement)*

The Company executed (i) a settlement and release agreement entered into as of April 18, 2008 to settle all the claims, (ii) an Amended and Restated Firm Gas Sales and Purchase Agreement (ARGA) effective April 11, 2008 and (iii) a Non-Firm Gas Sales and Purchase Agreement.


	i)	*Settlement and Release Agreement*

As of December 31, 2007, the Company was in litigation with Distrigas in Suffolk County, Massachusetts, Superior Court with respect to two 20-year fuel agreements. Under the original agreements, the Company was required to purchase at least 1,400,000 MMBtu of gas per week from Distrigas. Distrigas alleged that the Company was liable for approximately $40,100 in liquidated damages, unpaid gas invoices and late payment fees as of December 31, 2007. The Company has agreed to pay $18,175 plus accrued interest of $91 in full satisfaction of the amounts past due for liquidated damages and disputed gas invoices. The Company had $37,458, and $29,900 accrued for this purpose as of May 31, 2007 and December 31, 2006, respectively. On June 1, 2007, the Company recorded an adjustment to reduce the accrual to the agreed upon settlement and reflected the adjustment as an increase to goodwill as of June 1, 2007, the date of the Combination.

ii) Amended and Restated Firm Gas Sales and Purchase Agreement (ARGA)

The ARGA amends and replaces the existing Firm Gas and Purchase Agreement. The terms of the new agreement are as follows:


	•	Term is extended to December 3, 2027.

	•	Allows the Company to purchase firm weekly quantities (FWQ’s) at a price determined by the TETCO M3 pricing point, with additional gas volumes priced at the Algonquin City Gate for the first five years of the agreement. The price reverts to the Algonquin City Gate less $0.20 per MMBtu for the remaining term of the contract. FWQs are adjusted on a monthly basis to reflect seasonal operations and are subject to certain provisions that allow the Company to reduce FWQ’s up to 350,000 MMBtu per week with proper notification.

	•	The Company also has a weekly balancing tolerance of up to plus or minus 10,000 MMBtu without incurring liquidated damages.

	•	The Company provided a letter of credit in the amount of $50,000 subject to an adjustment five months after the execution of the ARGA based on the Company’s credit rating, and terms of the existing loan documents in any case the amount of the letter of credit is not to exceed $75,000 and not to be less than $35,000.

F-125

EBG HOLDINGS LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

(Dollars in thousands, except as otherwise indicated)

iii) Non-Firm Gas Sales and Purchase Agreement

The net intangible value of the agreement as of December 31, 2007 is $74,312. The Company recorded the impact of the new agreement as of June 1, 2007, the date of the combination.


*(d)*	*Boston Capacity Market Event*

On December 1, 2006, ISO-NE implemented changes in the capacity market whereby companies could sell capacity as part of the FERC-approved FCM structure. The structure has two main components, a settlement period and forward capacity auctions. During the settlement period, power generators supplying capacity will receive fixed transition payments of $3.05/kW-month from June 1, 2007 through May 31, 2008, $3.75/kW-month from June 1, 2008 through May 31, 2009, and $4.10 /kW-month from June 1, 2009 to May 31, 2010.

The first FCM auction covering the period June 1, 2010 through May 31, 2011 was held on February 2008. The market cleared at the floor price of $4.50/ kW-month with an excess of 2047 MWs. The revenue will be prorated among all of MW’s. All of the Company’s available capacity was sold along with and an additional 31.3 MW of winter only capacity.

With the initial FCM Auction clearing at the floor price of $4.50/kW-month, the Company believes that future revenues derived from the sale of its Boston capacity will likely fall short of amounts previously projected. As such, the Company has determined that the initial FCM Auction represents a trigger event, as defined under SFAS 142, Goodwill and Other Intangible Assets, requiring an interim assessment of goodwill impairment. As such, the Company evaluated (i) the impact of the FCM Auction results on its capacity revenue projections through May 31, 2011, (ii) the potential impact of subsequent FCM Auctions on its capacity revenues beyond May 31, 2011, and (iii) the resultant impact on its estimate of the Company’s enterprise value. The Company calculated a goodwill impairment of $250,067 which was recognized during the three months ended March 31, 2008.

F-126

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

The following table sets forth all costs and expenses, other than the underwriting discounts and commissions payable by US Power Generating Company, in connection with the offer and sale of the securities being registered. All amounts shown are estimates except for the Securities and Exchange Commission registration fee and the FINRA filing fee.


Securities and Exchange Commission registration fee	$	19,650
FINRA filing fee	$	50,500
NYSE listing fee		*
Printing expenses		*
Legal fees and expenses		*
Accounting fees and expenses		*
Miscellaneous expenses		*

Total expenses	$	*


*		To be provided by amendment.


Item 14.	*Indemnification of Directors and Officers.*

Section 102(b)(7) of the General Corporation Law of the State of Delaware, as amended (the “DGCL”) allows a corporation to provide in its certificate of incorporation that a director of the corporation will not be personally liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except where the director breached the duty of loyalty, failed to act in good faith, engaged in intentional misconduct or knowingly violated a law, authorized the payment of a dividend or approved a stock repurchase in violation of Delaware corporate law or obtained an improper personal benefit. Our certificate of incorporation will provide for this limitation of liability.

Section 145 (“Section 145”) of the DGCL provides that a Delaware corporation may indemnify any person who was, is or is threatened to be made, party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such corporation), by reason of the fact that such person is or was an officer, director, employee or agent of such corporation or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such person acted in good faith and in a manner he reasonably believed to be in or not opposed to the corporation’s best interests and, with respect to any criminal action or proceeding, had no reasonable cause to believe that his or her conduct was illegal. A Delaware corporation may indemnify any persons who are, were or are threatened to be made, a party to any threatened, pending or completed action or suit by or in the right of the corporation by reasons of the fact that such person is or was a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys’ fees) actually and reasonably incurred by such person in connection with the defense or settlement of such action or suit, provided such person acted in good faith and in a manner he reasonably believed to be in or not opposed to the corporation’s best interests, provided that no indemnification is permitted without judicial approval if the officer, director, employee or agent is adjudged to be liable to the corporation. Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses which such officer or director has actually and reasonably incurred.

II-1

Section 145 further authorizes a corporation to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or enterprise, against any liability asserted against him and incurred by him in any such capacity, or arising out of his or her status as such, whether or not the corporation would otherwise have the power to indemnify him under Section 145.

Our certificate of incorporation will provide that we must indemnify our directors and officers to the fullest extent authorized by the DGCL and must also pay expenses incurred in defending any such proceeding in advance of its final disposition upon delivery of an undertaking, by or on behalf of an indemnified person, to repay all amounts so advanced if it should be determined ultimately that such person is not entitled to be indemnified under this section or otherwise.

The indemnification rights set forth above shall not be exclusive of any other right which an indemnified person may have or hereafter acquire under any statute, provision of our certificate of incorporation, our by-laws, agreement, vote of stockholders or disinterested directors or otherwise.

We expect to maintain standard policies of insurance that provide coverage (1) to our directors and officers against loss rising from claims made by reason of breach of duty or other wrongful act and (2) to us with respect to indemnification payments that we may make to such directors and officers.

The proposed form of Underwriting Agreement to be filed as Exhibit 1.1 to this Registration Statement provides for indemnification to our directors and officers by the underwriters against certain liabilities.


Item 15.	*Recent Sales of Unregistered Securities.*

The Registrant was incorporated in February 2007. Since the date of its incorporation, its has issued the following securities without registration under the Securities Act:

On February 28, 2007, the Registrant entered into an Agreement and Plan of Merger, dated as of February 28, 2007 (the “Merger Agreement”), among EBG Holdings, LLC, Astoria Generating Company Holdings, L.L.C. (“Astoria”), EBG Merger LLC (“EBG MergerCo”) and Astoria Merger LLC (“Astoria MergerCo”). The Merger Agreement provided for (i) the merger of EBG MergerCo with and into EBG (the “EBG Merger”), and (ii) the merger of Astoria MergerCo with and into Astoria (the “Astoria Merger” and together with the EBG Merger, the “Mergers”). On June 1, 2007, the Mergers were completed and in connection therewith, the Registrant issued (i) an aggregate of 41,069,600 shares of Class A Common Stock on account of the EBG Merger to the former holders of limited liability company interests of EBG and (ii) an aggregate of 35,539,000 shares of Class A Common Stock on account of the Astoria Merger to the former owner of limited liability company interests of Astoria. The issuance of the shares in the Mergers was exempt from registration under the Section 4(2) of the Securities Act. In that regard, the Registrant received a representation in the Merger Agreement from Astoria that all of the members of its newly formed parent company, New Astoria Generating Company Holdings, L.L.C., would be “accredited investors” (as defined in Rule 501 of Regulation D) and EBG had received from each of its existing equity holders a representation that each was an “accredited investor.”


Item 16.	*Exhibits and Financial Statement Schedules*

(a) Exhibits

The exhibit index attached hereto is incorporated herein by reference.

(b) Financial Statement Schedules

No financial statement schedules are provided because the information called for is not applicable or is shown in the financial statements or notes thereto.

II-2


Item 17.	*Undertakings*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions referenced in Item 14 of this registration statement or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered hereunder, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in the form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective; and

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

(3) For the purpose of determining liability under the Securities Act of 1933 to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(4) For the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(a) any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(b) any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(c) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(d) any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

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SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of New York, on August 12, 2008.

US POWER GENERATING COMPANY


	By:	/s/ Jacob J. Worenklein

Name: Jacob J. Worenklein


	Title:	Chairman, Chief Executive Officer and Director

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each officer and director of US Power Generating Company whose signature appears below constitutes and appoints Jacob J. Worenklein and Jeff D. Hunter, and each of them, his or her true and lawful attorney-in-fact and agent, with full power of substitution and revocation, for him or her and in his or her name, place and stead, in any and all capacities, to execute any or all amendments including any post-effective amendments and supplements to this Registration Statement, and any additional Registration Statement filed pursuant to Rule 462(b), and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

* * * *

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities indicated on August 12, 2008:


Signature	Title	Date


/s/ Jacob J. Worenklein Jacob J. Worenklein	Chairman, Chief Executive Officer and Director (principal executive officer)	August 12, 2008

/s/ Jeff D. Hunter Jeff D. Hunter	Executive Vice President and Chief Financial Officer (principal financial officer)	August 12, 2008

/s/ James Calandra James Calandra	Chief Accounting Officer (principal accounting officer)	August 12, 2008

/s/ Zaid F. Alsikafi Zaid F. Alsikafi	Director	August 12, 2008

/s/ Patrick C. Eilers Patrick C. Eilers	Director	August 12, 2008

/s/ Kip Horton Kip Horton	Director	August 12, 2008

II-4

EXHIBIT INDEX


Exhibit
Number			Description

	1	.1*	Form of Underwriting Agreement.
	3	.1	Certificate of Incorporation of the Registrant.
	3	.2*	Form of Amended and Restated Certificate of Incorporation of the Registrant.
	3	.3	Amended and Restated By-laws of the Registrant.
	4	.1*	Specimen Common Stock Certificate.
	4	.2	Investor Rights Agreement, dated as of June 1, 2007, by and among US Power Generating Company, New Astoria Generating Company Holdings, LLC, each of the New Astoria Members party thereto, the EBG Investors party thereto and the other Stockholders party thereto.
	5	.1*	Form of Opinion of Kirkland & Ellis LLP.
	10	.1	First Lien Credit and Guaranty Agreement, dated as of December 21, 2006, among Boston Generating, LLC, the guarantors named therein, the initial lenders, synthetic issuing banks and fronting bank named therein, Credit Suisse, Cayman Islands Branch, Credit Suisse Securities (USA) LLC and Goldman Sachs Credit Partners L.P.
	10	.2	Second Lien Credit and Guaranty Agreement, dated as of December 21, 2006, among Boston Generating, LLC, the guarantors named therein, the initial lenders named therein, Credit Suisse, Cayman Islands Branch, Credit Suisse Securities (USA) LLC and Goldman Sachs Credit Partners L.P.
	10	.3	Credit Agreement, dated as of December 21, 2006, among EBG Holdings LLC, the initial lenders named therein, Credit Suisse, Cayman Islands Branch, Credit Suisse Securities (USA) LLC and Goldman Sachs Credit Partners L.P.
	10	.4	First Lien Credit Agreement, dated as of February 23, 2006, among Astoria Generating Company Holdings, L.L.C., Astoria Generating Company Holdings, L.L.C., the guarantors named therein, initial lenders, initial revolving issuing bank and initial term issuing bank named therein, The Bank of New York, Morgan Stanley Senior Funding, Inc., Goldman Sachs Credit Partners L.P., Merrill Lynch, Pierce, Fenner & Smith Incorporated, BNS Paribas and Morgan Stanley & Co. Incorporated.
	10	.5	Letter Agreement amending First Lien Credit Agreement, dated as of November 22, 2006, among Astoria Generating Company Acquisitions, L.L.C., Astoria Generating Company Holdings, L.L.C., Astoria Generating Company GP, L.L.C., Astoria Generating Company, L.P., Astoria Operating Services, Inc., Morgan Stanley Senior Funding, Inc. and Morgan Stanley Bank.
	10	.6	Consent and Amendment No. 2 to the First Lien Credit Agreement, dated as of May 18, 2007 among Astoria Generating Company Holdings, L.L.C., Astoria Generating Company Holdings, L.L.C., the guarantors named therein, the lenders named therein and Morgan Stanley Senior Funding, Inc.
	10	.7	Second Lien Credit Agreement, dated as of February 23, 2006, among Astoria Generating Company Holdings, L.L.C., Astoria Generating Company Holdings, L.L.C., the guarantors named therein, the initial lenders named therein, The Bank of New York, Morgan Stanley Senior Funding, Inc., Goldman Sachs Credit Partners L.P., Merrill Lynch, Pierce, Fenner & Smith Incorporated, BNS Paribas and Morgan Stanley & Co. Incorporated.
	10	.8	Letter Agreement amending Second Lien Credit Agreement, dated as of November 22, 2006, among the banks, financial institutions and other institutional lenders and parties to the Credit Agreement named therein and Morgan Stanley Senior Fundings, Inc.
	10	.9	Consent and Amendment No. 2 to the Second Lien Credit Agreement, dated as of May 18, 2007 among Astoria Generating Company Holdings, L.L.C., Astoria Generating Company Holdings, L.L.C., the guarantors named therein, the lenders named therein and Morgan Stanley Senior Funding, Inc.
	10	.10	Astoria Purchase Agreement.
	10	.11	Agreement and Plan of Merger, dated as of February 28, 2007, among US Power Generating Company, EBG Holdings LLC, EBG Merger LLC, Astoria Generating Company Holdings, L.L.C. and Astoria Merger LLC.
	10	.12	Letter Agreement amending Agreement and Plan of Merger, dated as of May 31, 2007, among US Power Generating Company, EBG Holdings LLC, EBG Merger LLC, Astoria Generating Company Holdings, L.L.C. and Astoria Merger LLC.


Exhibit
Number			Description

	10	.13	Investor Rights Agreement, dated as of June 1, 2007, among US Power Generating Company, New Astoria Generating Company Holdings, LLC, the persons identified as New Astoria Members named therein, the persons identified as EBG Investors named therein and each other person who becomes a party after the date of the agreement pursuant to Section 12(e) or 12(f) of the agreement.
	10	.14	Consulting Agreement, dated as of June 1, 2007, among US Power Generating Company and K Road BG Management, LLC.
	10	.15	Third Amended and Restated Limited Liability Company Operating Agreement of Astoria Generating Company Holdings, L.L.C., dated as of June 1, 2007, by the member, US Power Generating Company.
	10	.16	Securities Purchase Agreement, dated as of February 23, 2006, among Astoria Generating Company Holdings, L.L.C. and each of the individuals and entities listed on Schedule of Investors attached thereto.
	10	.17	2007 Annual Incentive Plan.
	10	.18*	2007 Employee Stock Purchase Plan.
	10	.19	2007 Stock Incentive Plan.
	10	.20.1	Form of Restricted Stock Units Agreement for Non-Union Employees with Employment Agreements under the 2007 Stock Incentive Plan.
	10	.20.2	Form of Restricted Stock Units Agreement for Non-Union Employees without Employment Agreements under the 2007 Stock Incentive Plan.
	10	.20.3	Form of Restricted Stock Units Agreement for Union Employees under the 2007 Stock Incentive Plan.
	10	.21.1	Form of Stock-Settled Stock Appreciation Rights Agreement for Executives with Employment Agreements under the 2007 Stock Incentive Plan.
	10	.21.2	Form of Stock-Settled Stock Appreciation Rights Agreement for Employees without Employment Agreements under the 2007 Stock Incentive Plan.
	10	.23	General Release and Waiver Agreement, dated as of November 30, 2007, between US Power Generating Company and Donna Brandin.
	10	.24*+	Amended and Restated Firm Gas Sales and Purchase Agreement, dated as of December 3, 2007, between Distrigas of Massachusetts LLC and Mystic Development, LLC.
	10	.25*+	Non-Firm Gas Sales and Purchase Agreement, dated as of April 11, 2008, between Distrigas of Massachusetts LLC and Mystic I, LLC.
	21	.1	List of subsidiaries of the Registrant.
	23	.1.1	Consent of KPMG, independent registered public accounting firm, with respect to US Power Generating Company report.
	23	.1.2	Consent of KPMG, independent registered public accounting firm, with respect to EBG Holdings LLC report.
	23	.2*	Consent of Kirkland & Ellis LLP (included in Exhibit 5.1).
	24	.1	Powers of Attorney (included on signature page).


*		To be filed by amendment.

+		Certain confidential portions will be omitted pursuant to a confidential treatment request to be filed separately with the Securities and Exchange Commission.


Prospectus Summary			1
Risk Factors			13
Forward-Looking Statements			34
Use of Proceeds			36
Dividend Policy			36
Capitalization			37
Dilution			38
Institutional Trading and Holders of our Common Stock			40
Unaudited Pro Forma Consolidated Financial Statements			41
Selected Historical Financial Data			44
Management’s Discussion and Analysis of Financial Condition and Results of Operations			46
Business			99
Management			128
Executive Compensation			134
Principal and Selling Stockholders			158
Certain Relationships and Related Party Transactions			161
Description of Capital Stock			164
Description of Principal Indebtedness			167
Shares Eligible for Future Sale			172
Certain Material United States Federal Income Tax Consequences			174
Underwriting			178
Notice to Canadian Residents			183
Legal Matters			185
Experts			185
Where You Can Find More Information			185
Index to Financial Statements			F-1
EX-3.1: CERTIFICATE OF INCORPORATION
EX-3.3: AMENDED AND RESTATED BYLAWS
EX-4.2: INVESTOR RIGHTS AGREEMENT
EX-10.1: FIRST LIEN CREDIT AND GUARANTY AGREEMENT
EX-10.2: SECOND LIEN CREDIT AND GUARANTY AGREEMENT
EX-10.3: CREDIT AGREEMENT
EX-10.4: FIRST LIEN CREDIT AGREEMENT
EX-10.5: LETTER AGREEMENT AMENDING FIRST LIEN CREDIT AGREEMENT
EX-10.6: CONSENT AND AMENDMENT NO. 2 TO THE FIRST LIEN CREDIT AGREEMENT
EX-10.7: SECOND LIEN CREDIT AGREEMENT
EX-10.8: LETTER AGREEMENT AMENDING SECOND LIEN CREDIT AGREEMENT
EX-10.9: CONSENT AND AMENDMENT NO.2 TO THE SECOND LIEN CREDIT AGREEMENT
EX-10.10: ASTORIA PURCHASE AGREEMENT
EX-10.11: AGREEMENT AND PLAN OF MERGER
EX-10.12: LETTER AGREEMENT AMENDING AGREEMENT AND PLAN OF MERGER
EX-10.13: INVESTOR RIGHTS AGREEMENT
EX-10.14: CONSULTING AGREEMENT
EX-10.15: THIRD AMENDED AND RESTATED LIMITED LIABILITY COMPANY OPERATING AGREEMENT
EX-10.16: SECURITIES PURCHASE AGREEMENT
EX-10.17: 2007 ANNUAL INCENTIVE PLAN
EX-10.19: 2007 STOCK INCENTIVE PLAN
EX-10.20.1: FORM OF RESTRICTED STOCK UNITS AGREEMENT
EX-10.20.2: FORM OF RESTRICTED STOCK UNITS AGREEMENT
EX-10.20.3: FORM OF RESTRICTED STOCK UNITS AGREEMENT
EX-10.21.1: FORM OF STOCK-SETTLED STOCK APPRECIATION RIGHTS AGREEMENT
EX-10.21.2: FORM OF STOCK-SETTLED STOCK APPRECIATION RIGHTS AGREEMENT
EX-10.23: GENERAL RELEASE AND WAIVER AGREEMENT
EX-21.1: SUBSIDIARIES
EX-23.1.1: CONSENT OF KPMG
EX-23.1.2: CONSENT OF KPMG


Fiscal Year	Expense (Income)

Year ended December 31, 2003	$	497
Year ended December 31, 2004		(20,837	)
Year ended December 31, 2005		21,292

Total	$	952