DYN 10-Q Quarterly Report Sept. 30, 2010 | Alphaminr
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DYN 10-Q Quarter ended Sept. 30, 2010

Balance Sheet
Cash Flow
Income Statement
DYNEGY INC.
10-Q 1 form10q.htm DYNEGY 10-Q 9-30-2010 form10q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2010
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
DYNEGY INC.
DYNEGY HOLDINGS INC.
(Exact name of registrant as specified in its charter)
Entity
Commission
File Number
State of
Incorporation
I.R.S. Employer
Identification No.
Dynegy Inc.
001-33443
Delaware
20-5653152
Dynegy Holdings Inc.
000-29311
Delaware
94-3248415
1000 Louisiana, Suite 5800
Houston, Texas
77002
(Address of principal executive offices)
(Zip Code)
(713) 507-6400
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Dynegy Inc.
Yes x No o
Dynegy Holdings Inc.
Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Dynegy Inc.
Yes x No o
Dynegy Holdings Inc.
Yes o No 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer
Accelerated
filer
Non-accelerated filer
Smaller reporting
company
(Do not check if a smaller
reporting company)
Dynegy Inc.
x
o
o
o
Dynegy Holdings Inc.
o
o
x
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Dynegy Inc.
Yes o No x
Dynegy Holdings Inc.
Yes o No x
Indicate the number of shares outstanding of Dynegy Inc.’s class of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 120,894,257 shares outstanding as of November 1, 2010.  All of Dynegy Holdings Inc.’s outstanding common stock is owned by Dynegy Inc.
This combined Form 10-Q is separately filed by Dynegy Inc. and Dynegy Holdings Inc.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Each registrant makes no representation as to information relating to a registrant other than itself.
DYNEGY INC. and DYNEGY HOLDINGS INC.

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EXPLANATORY NOTE
This report includes the combined filing of Dynegy Inc. (“Dynegy”) and Dynegy Holdings Inc. (“DHI”).  DHI is the principal subsidiary of Dynegy, providing nearly 100 percent of Dynegy’s total consolidated revenue for the nine-month period ended September 30, 2010 and constituting nearly 100 percent of Dynegy’s total consolidated asset base as of September 30, 2010.  Unless the context indicates otherwise, throughout this report, the terms “the Company,” “we,” “us,” “our” and “ours” are used to refer to both Dynegy and DHI and their direct and indirect subsidiaries.  Discussions or areas of this report that apply only to Dynegy or DHI are clearly noted in such section.

DEFINITIONS
As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below.
ASU
Accounting Standard Update
BACT
Best available control technology
BART
Best available retrofit technology
BTA
Best technology available
CAISO
The California Independent System Operator
CAA
Clean Air Act
CCR
Coal combustion residuals
CO 2
Carbon Dioxide
DHI
Dynegy Holdings Inc.
DMSLP
Dynegy Midstream Services L.P.
DOJ
U.S. Department of Justice
EPA
Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
FTC
Federal Trade Commission
GAAP
Generally Accepted Accounting Principles of the United States of America
GEN
Our power generation business
GEN-MW
Our power generation business - Midwest segment
GEN-NE
Our power generation business - Northeast segment
GEN-WE
Our power generation business - West segment
GHG
Greenhouse Gas
ISO
Independent System Operator
MISO
Midwest Independent Transmission System Operator, Inc.
MMBtu
One million British thermal units
MW
Megawatts
MWh
Megawatt hour
NPDES
National Pollutant Discharge Elimination System
NRG
NRG Energy, Inc.
NYSDEC
New York State Department of Environmental Conservation
OAL
Office of Administrative Law
OTC
Over-the-counter
PJM
PJM Interconnection, LLC
PPEA
Plum Point Energy Associates, LLC
PSD
Prevention of significant deterioration
RACT
Reasonably available control technology
RCRA
Resource Conservation and Recovery Act
RMR
Reliability Must Run
SC Services
Sandy Creek Services LLC
SCH
Sandy Creek Holdings LLC
SEC
U.S. Securities and Exchange Commission
SPDES
State Pollutant Discharge Elimination System
VaR
Value at Risk
VIE
Variable Interest Entity
DYNEGY INC.
(unaudited) (in millions, except share data)
September 30,
2010
December 31,
2009
ASSETS
Current Assets
Cash and cash equivalents
$ 491 $ 471
Restricted cash and investments
119 78
Short-term investments
182 9
Accounts receivable, net of allowance for doubtful accounts of $33 and $22, respectively
202 212
Accounts receivable, affiliates
1 2
Inventory
121 141
Assets from risk-management activities
1,691 713
Deferred income taxes
25 6
Broker margin account
36 286
Prepayments and other current assets
110 120
Total Current Assets
2,978 2,038
Property, Plant and Equipment
8,653 9,071
Accumulated depreciation
(2,289 ) (1,954 )
Property, Plant and Equipment, Net
6,364 7,117
Other Assets
Restricted cash and investments
870 877
Assets from risk-management activities
344 163
Intangible assets
153 380
Other long-term assets
412 378
Total Assets
$ 11,121 $ 10,953
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable
$ 180 $ 181
Accounts payable, affiliates
12 —
Accrued interest
110 36
Accrued liabilities and other current liabilities
128 127
Liabilities from risk-management activities
1,548 696
Notes payable and current portion of long-term debt
146 807
Total Current Liabilities
2,124 1,847
Long-term debt
4,461 4,575
Long-term debt, affiliates
200 200
Long-Term Debt
4,661 4,775
Other Liabilities
Liabilities from risk-management activities
347 213
Deferred income taxes
757 780
Other long-term liabilities
342 359
Total Liabilities
$ 8,231 $ 7,974
Commitments and Contingencies (Note 14)
Stockholders’ Equity (Note 17)
Common Stock, $0.01 par value, 420,000,000 shares authorized at September 30, 2010 and December 31, 2009, and 121,444,560 and 120,715,515 shares issued and outstanding at September 30, 2010 and December 31, 2009, respectively
1 1
Additional paid-in capital
6,064 6,061
Subscriptions receivable
(2 ) (2 )
Accumulated other comprehensive loss, net of tax
(70 ) (150 )
Accumulated deficit
(3,032 ) (2,937 )
Treasury stock, at cost, 627,655 and 557,677 shares at September 30, 2010 and December 31, 2009, respectively
(71 ) (71 )
Total Dynegy Inc. Stockholders’ Equity
2,890 2,902
Noncontrolling interests
— 77
Total Stockholders’ Equity
2,890 2,979
Total Liabilities and Stockholders’ Equity
$ 11,121 $ 10,953

See the notes to condensed consolidated financial statements.
DYNEGY INC.
(unaudited) (in millions, except per share data)

Three Months Ended
September 30,
Nine Months Ended
September 30,
2010
2009
2010
2009
Revenues
$ 775 $ 673 $ 1,872 $ 2,027
Cost of sales
(334 ) (286 ) (873 ) (927 )
Operating and maintenance expense, exclusive of depreciation shown separately below
(110 ) (121 ) (341 ) (373 )
Depreciation and amortization expense
(96 ) (83 ) (261 ) (258 )
Goodwill impairments
— — — (433 )
Impairment and other charges, exclusive of goodwill impairments shown separately above
(134 ) (148 ) (135 ) (535 )
General and administrative expenses
(51 ) (42 ) (110 ) (125 )
Operating income (loss)
50 (7 ) 152 (624 )
Earnings (losses) from unconsolidated investments
— (8 ) (34 ) 13
Interest expense
(92 ) (115 ) (272 ) (311 )
Other income and expense, net
1 2 3 10
Loss from continuing operations before income taxes
(41 ) (128 ) (151 ) (912 )
Income tax benefit (Note 16)
17 34 80 147
Loss from continuing operations
(24 ) (94 ) (71 ) (765 )
Income (loss) from discontinued operations, net of tax benefit of zero, $84, zero and $91, respectively (Note 3)
— (129 ) 1 (141 )
Net loss
(24 ) (223 ) (70 ) (906 )
Less: Net loss attributable to the noncontrolling interests
— (11 ) — (14 )
Net loss attributable to Dynegy Inc.
$ (24 ) $ (212 ) $ (70 ) $ (892 )
Loss Per Share (Notes 13 and 17 ):
Basic loss per share attributable to Dynegy Inc. common stockholders:
Loss from continuing operations
$ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
Income (loss) from discontinued operations
— (0.77 ) 0.01 (0.84 )
Basic loss per share attributable to Dynegy Inc. common stockholders
$ (0.20 ) $ (1.26 ) $ (0.58 ) $ (5.31 )
Diluted loss per share attributable to Dynegy Inc. common stockholders:
Loss from continuing operations
$ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
Income (loss) from discontinued operations
— (0.77 ) 0.01 (0.84 )
Diluted loss per share attributable to Dynegy Inc. common stockholders
$ (0.20 ) $ (1.26 ) $ (0.58 ) $ (5.31 )
Basic shares outstanding
120 168 120 168
Diluted shares outstanding
121 169 121 169

See the notes to condensed consolidated financial statements.
DYNEGY INC.
(unaudited) (in millions)
Nine Months Ended
September 30,
2010
2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss
$ (70 ) $ (906 )
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization
273 279
Goodwill impairments
— 433
Impairment and other charges, exclusive of goodwill impairments shown separately above
135 793
(Earnings) losses from unconsolidated investments, net of cash distributions
34 (13 )
Risk-management activities
(123 ) 73
Gain on sale of assets
— (10 )
Deferred income taxes
(79 ) (246 )
Other
55 66
Changes in working capital:
Accounts receivable
11 (4 )
Inventory
15 (7 )
Broker margin account
353 (104 )
Prepayments and other assets
7 (30 )
Accounts payable and accrued liabilities
111 81
Changes in non-current assets
(51 ) (91 )
Changes in non-current liabilities
(1 ) (10 )
Net cash provided by operating activities
670 304
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(270 ) (429 )
Unconsolidated investments
(15 ) 1
Proceeds from asset sales, net
— 105
Maturities of short-term investments
152 14
Purchases of short-term investments
(428 ) —
Increase in restricted cash and restricted investments
(53 ) (35 )
Other investing
— 3
Net cash used in investing activities
(614 ) (341 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs
(5 ) 75
Repayments of borrowings
(31 ) (28 )
Net cash used in financing activities
(36 ) 47
Net increase in cash and cash equivalents
20 10
Cash and cash equivalents, beginning of period
471 693
Cash and cash equivalents, end of period
$ 491 $ 703
Other non-cash investing activity:
Non-cash capital expenditures
$ 10 $ 19

See the notes to condensed consolidated financial statements.

DYNEGY INC.
(unaudited) (in millions)

Three Months Ended
September 30,
2010
2009
Net loss
$ (24 ) $ (223 )
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net
— 45
Reclassification of mark-to-market losses to earnings, net
— 1
Deferred losses on cash flow hedges, net
— (2 )
Changes in cash flow hedging activities, net (net of tax expense of zero and $11, respectively)
— 44
Amortization of unrecognized prior service cost and actuarial gain (loss) (net of tax benefit of zero and $2)
1 (1 )
Unconsolidated investments other comprehensive loss, net (net of tax benefit of zero and $3)
— (3 )
Other comprehensive income, net of tax
1 40
Comprehensive loss
(23 ) (183 )
Less: Comprehensive income attributable to the noncontrolling interests
— 25
Comprehensive loss attributable to Dynegy Inc.
$ (23 ) $ (208 )
Nine Months Ended
September 30,
2010
2009
Net loss
$ (70 ) $ (906 )
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net
— 160
Reclassification of mark-to-market losses to earnings, net
— 1
Deferred losses on cash flow hedges, net
— (8 )
Changes in cash flow hedging activities, net (net of tax benefit (expense) of $1 and ($26), respectively)
— 153
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $1 and $3)
3 1
Unconsolidated investments other comprehensive income, net (net of tax expense of $1 and $2)
— 3
Other comprehensive income, net of tax
3 157
Comprehensive loss
(67 ) (749 )
Less: Comprehensive income attributable to the noncontrolling interests
— 107
Comprehensive loss attributable to Dynegy Inc.
$ (67 ) $ (856 )

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.
(unaudited) (in millions)
September 30,
2010
December 31,
2009
ASSETS
Current Assets
Cash and cash equivalents
$ 457 $ 419
Restricted cash and investments
119 78
Short-term investments
163 8
Accounts receivable, net of allowance for doubtful accounts of $14 and $20, respectively
201 214
Accounts receivable, affiliates
1 2
Inventory
121 141
Assets from risk-management activities
1,691 713
Deferred income taxes
23 7
Broker margin account
36 286
Prepayments and other current assets
110 120
Total Current Assets
2,922 1,988
Property, Plant and Equipment
8,653 9,071
Accumulated depreciation
(2,289 ) (1,954 )
Property, Plant and Equipment, Net
6,364 7,117
Other Assets
Restricted cash and investments
870 877
Assets from risk-management activities
344 163
Intangible assets
153 380
Other long-term assets
412 378
Total Assets
$ 11,065 $ 10,903
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable
$ 180 $ 181
Accounts payable, affiliates
12 —
Accrued interest
110 36
Accrued liabilities and other current liabilities
124 128
Liabilities from risk-management activities
1,548 696
Notes payable and current portion of long-term debt
146 807
Total Current Liabilities
2,120 1,848
Long-term debt
4,461 4,575
Long-term debt, affiliates
200 200
Long-Term Debt
4,661 4,775
Other Liabilities
Liabilities from risk-management activities
347 213
Deferred income taxes
686 704
Other long-term liabilities
342 360
Total Liabilities
8,156 7,900
Commitments and Contingencies (Note 14)
Stockholders’ Equity
Capital Stock, $1 par value, 1,000 shares authorized at September 30, 2010 and December 31, 2009
— —
Additional paid-in capital
5,135 5,135
Affiliate receivable
(774 ) (777 )
Accumulated other comprehensive loss, net of tax
(70 ) (150 )
Accumulated deficit
(1,382 ) (1,282 )
Total Dynegy Holdings Inc. Stockholder’s Equity
2,909 2,926
Noncontrolling interests
— 77
Total Stockholders’ Equity
2,909 3,003
Total Liabilities and Stockholders’ Equity
$ 11,065 $ 10,903

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.
(unaudited) (in millions)
Three Months Ended
September 30,
Nine Months Ended
September 30,
2010
2009
2010
2009
Revenues
$ 775 $ 673 $ 1,872 $ 2,027
Cost of sales
(334 ) (286 ) (873 ) (927 )
Operating and maintenance expense, exclusive of depreciation shown separately below
(110 ) (121 ) (341 ) (375 )
Depreciation and amortization expense
(96 ) (83 ) (261 ) (258 )
Goodwill impairments
— — — (433 )
Impairment and other charges, exclusive of goodwill impairments shown separately above
(134 ) (148 ) (135 ) (535 )
General and administrative expenses
(47 ) (42 ) (106 ) (125 )
Operating income (loss)
54 (7 ) 156 (626 )
Earnings (losses) from unconsolidated investments
— (8 ) (34 ) 12
Interest expense
(92 ) (115 ) (272 ) (311 )
Other income and expense, net
1 2 3 9
Loss from continuing operations before income taxes
(37 ) (128 ) (147 ) (916 )
Income tax benefit (Note 16)
15 35 71 152
Loss from continuing operations
(22 ) (93 ) (76 ) (764 )
Income (loss) from discontinued operations, net of tax benefit of zero, $74, zero and $91, respectively (Note 3)
— (139 ) 1 (141 )
Net loss
(22 ) (232 ) (75 ) (905 )
Less: Net loss attributable to the noncontrolling interests
— (11 ) — (14 )
Net loss attributable to Dynegy Holdings Inc.
$ (22 ) $ (221 ) $ (75 ) $ (891 )
See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.
(unaudited) (in millions)
Nine Months Ended
September 30,
2010
2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss
$ (75 ) $ (905 )
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization
273 279
Goodwill impairments
— 433
Impairment and other charges, exclusive of goodwill impairments shown separately above
135 793
(Earnings) losses from unconsolidated investments, net of cash distributions
34 (12 )
Risk-management activities
(123 ) 73
Gain on sale of assets, net
— (10 )
Deferred income taxes
(69 ) (248 )
Other
51 64
Changes in working capital:
Accounts receivable
14 (4 )
Inventory
15 (7 )
Broker margin account
353 (104 )
Prepayments and other assets
7 (30 )
Accounts payable and accrued liabilities
108 100
Changes in non-current assets
(51 ) (91 )
Changes in non-current liabilities
(2 ) (9 )
Net cash provided by operating activities
670 322
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(270 ) (429 )
Unconsolidated investments
(15 ) —
Proceeds from asset sales, net
— 105
Maturities of short-term investments
149 13
Purchases of short-term investments
(406 ) —
Increase in restricted cash and restricted investments
(53 ) (35 )
Affiliate transactions
(1 ) (2 )
Other investing
— 3
Net cash used in investing activities
(596 ) (345 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs
(5 ) 75
Repayments of borrowings
(31 ) (28 )
Dividend to affiliate
— (175 )
Net cash used in financing activities
(36 ) (128 )
Net increase (decrease) in cash and cash equivalents
38 (151 )
Cash and cash equivalents, beginning of period
419 670
Cash and cash equivalents, end of period
$ 457 $ 519
Other non-cash investing activity:
Non-cash capital expenditures
$ 10 $ 19

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.
(unaudited) (in millions)

Three Months Ended
September 30,
2010
2009
Net loss
$ (22 ) $ (232 )
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net
— 45
Reclassification of mark-to-market losses to earnings, net
— 1
Deferred losses on cash flow hedges, net
— (2 )
Changes in cash flow hedging activities, net (net of tax expense of zero and $11, respectively)
— 44
Amortization of unrecognized prior service cost and actuarial gain (loss) (net of tax expense of zero and $2)
1 (1 )
Unconsolidated investments other comprehensive loss, net (net of tax benefit of zero and $3)
— (3 )
Other comprehensive income, net of tax
1 40
Comprehensive loss
(21 ) (192 )
Less: Comprehensive income attributable to the noncontrolling interests
— 25
Comprehensive loss attributable to Dynegy Holdings Inc.
$ (21 ) $ (217 )
Nine Months Ended
September 30,
2010
2009
Net loss
$ (75 ) $ (905 )
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net
— 160
Reclassification of mark-to-market losses to earnings, net
— 1
Deferred losses on cash flow hedges, net
— (8 )
Changes in cash flow hedging activities, net (net of tax benefit (expense) of $1 and ($26), respectively)
— 153
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $2 and $3)
2 1
Unconsolidated investments other comprehensive income, net (net of tax expense of $1 and $2)
— 3
Other comprehensive income, net of tax
2 157
Comprehensive loss
(73 ) (748 )
Less: Comprehensive income attributable to the noncontrolling interests
— 107
Comprehensive loss attributable to Dynegy Holdings Inc.
$ (73 ) $ (855 )

See the notes to condensed consolidated financial statements.
DYNEGY INC. and DYNEGY HOLDINGS INC.
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Note 1—Accounting Policies
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC.  These interim financial statements do not include all disclosures required by accounting principles generally accepted in the United States of America.  These interim financial statements should be read together with the consolidated financial statements and notes thereto included in Dynegy’s and DHI’s Form 10-K for the year ended December 31, 2009 filed on February 25, 2010, which we refer to as each registrant’s “Form 10-K”.
The December 31, 2009 condensed consolidated balance sheet data was derived from audited consolidated financial statements, as adjusted for the 1-for-5 reverse stock split of Dynegy’s common stock that became effective on May 25, 2010.  Please read Note 17—Capital Stock for further discussion.
The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal and recurring nature that, in the opinion of management, are necessary for a fair statement of the results for the interim periods.  The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors.  The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations.  These estimates and judgments also impact the nature and extent of disclosure, if any, of our contingent liabilities based on currently available information.  We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments.  Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements.  Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications, (vi) estimating various factors used to value our pension assets and liabilities and (vii) determining the primary beneficiary of certain VIEs from a set of related parties.  Actual results could differ materially from any such estimates.  Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.
Short-Term Investments. Short-term investments consist of highly liquid investments, primarily U.S. Treasury, U.S. Agency and corporate debt securities, with original maturities over three months from the date of purchase.  Our investment policy restricts investments to high credit quality investments with limits on the length to maturity and the amount invested with any one issuer.  Debt securities which we have the ability and positive intent to hold to maturity are carried at amortized cost, net of unamortized premiums and unaccreted discounts, which approximates fair value.  At September 30, 2010, we did not hold any short-term investments that were classified as held-to-maturity.
Debt securities not held-to-maturity are classified as available for sale and are recorded at fair value.  Unrealized gains and losses, after applicable taxes, resulting from changes in fair value are recorded as a component of Other comprehensive loss.
Declines in the value of individual equity securities that are considered other than temporary result in write-downs to the individual securities to their fair value and the write-downs are included in the condensed consolidated statements of operations.  Declines in debt securities held-to-maturity and available for sale, that are considered other than temporary, result in write-downs when it is more likely than not that we will sell the securities before we recover our cost.  If we do not intend to sell an impaired debt security but do not expect to recover its cost, we determine whether a credit loss exists, and if so, the credit loss is recognized in the condensed consolidated statements of operations and any remaining impairment is recognized in Other comprehensive loss. The review for other-than-temporary declines considers the length of time and the extent to which the fair value has been less than cost, the financial condition and near-term prospects of the issuer, and our intent and ability to retain the investment for a period of time sufficient to allow for recovery.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
We consider all available for sale securities, including those with maturity dates beyond twelve months, as available to support current operational liquidity needs and therefore classify these securities as short-term investments within current assets on the consolidated balance sheets.  As of September 30, 2010, Dynegy and DHI held $286 million and $267 million, respectively, of available for sale securities with maturity dates within one year.  Of these amounts, $104 million is included in the Broker margin account on our unaudited condensed consolidated balance sheets.
Interest on securities, including the amortization of premiums and the accretion of discounts, is reported in Other income and expense, net using the interest method over the lives of the securities, adjusted for actual prepayments.  Gains and losses on the sale of securities are recorded on the trade date and recognized using the specific identification method and reported in Other income and expense, net.
Change in Accounting Estimate. In accordance with our policy, we review fixed assets for known facts that potentially would impact their estimated useful lives.  Based on events occurring in September 2010, we determined that it is not currently economical to continue to operate our Vermilion facility for the remainder of its estimated useful life.  As a result, effective September 1, 2010, we changed our estimate of the useful life of this facility to better reflect the estimated periods during which we expect the asset will remain in service.  The facility’s previously estimated remaining useful life of 15 years was decreased to 8 months.  The effect of this change in estimate was to increase depreciation expense by approximately $13 million ($8 million net of tax), or $0.07 per share (basic and diluted), for the three and nine months ended September 30, 2010.
Accounting Principle Adopted
Variable Interest Entities. On January 1, 2010, we adopted Accounting Standards Update (“ASU”) No. 2009-17—Consolidations (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (“ASU No. 2009-17”).  This guidance replaces the previous quantitative-based analysis for determining the primary beneficiary of a variable interest entity with a framework that is based on qualitative judgments.  The new guidance identifies the primary beneficiary of a variable interest entity as the party that both: (i) has the power to direct the activities of a variable interest entity that most significantly impact its economic performance and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the variable interest entity.  As a result of applying this guidance, we have determined that we are not the primary beneficiary of PPEA Holding Company, LLC (“PPEA Holding”) because we lack the power to direct the activities that most significantly impact PPEA Holding’s economic performance.  The activities that most significantly impact PPEA Holding’s economic performance are changes to the costs to construct and operate the facility, modifications to the off-take agreements, and/or changes in the financing structure.  As PPEA Holding’s LLC Agreement currently requires that those activities be approved by all members, the power to direct these activities is shared with the other owners of PPEA Holding and the participants in the 665 MW coal-fired power generation facility (the “Plum Point Project”).  We have historically consolidated PPEA Holding in our consolidated financial statements.  On September 14, 2010, we entered into an agreement to sell our interest in PPEA Holding.  Please read Note 10—Variable Interest Entities—PPEA Holding Company LLC for further discussion.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
The adoption of ASU No. 2009-17 resulted in a deconsolidation of our investment in PPEA Holding, which resulted in the cumulative effect of a change in accounting principle of approximately $41 million ($25 million after tax), which was recorded as an increase in Accumulated deficit on our unaudited condensed consolidated balance sheets as of January 1, 2010.  This pre-tax charge reflects the difference in the assets, liabilities and equity (including Other comprehensive loss) that we have historically included in our consolidated balance sheets and the carrying value of the equity investment and related accumulated other comprehensive loss that we would have recorded had we accounted for our investment in PPEA Holding as an equity method investment since April 2, 2007, the date we acquired an interest in PPEA Holding.  On January 1, 2010, we recorded an equity investment of approximately $19 million and accumulated other comprehensive loss of approximately $29 million ($17 million after tax).  The $19 million equity investment balance at January 1, 2010 reflects the fair value of our investment at that date, after an other than temporary pre-tax impairment charge of approximately $32 million that would have been recorded in 2009 had we accounted for our investment in PPEA Holding as an equity investment at that time.  Our assessment of the fair value of our investment in PPEA Holding at January 1, 2010 reflects the risk associated with PPEA Holding’s financing arrangement at that date.  Please read Note 7— Fair Value Measurements for further discussion about the assumptions used to determine the fair value of our investment as of January 1, 2010.  Please read Note 17—Debt—Plum Point (including PPEA Credit Agreement Facility and PPEA Tax Exempt Bonds) and Note 14—Variable Interest Entities—PPEA Holding Company, LLC in our Form 10-K for further discussion.  Summarized aggregate financial information for PPEA Holding, included in our December 31, 2009 consolidated balance sheets, is included below (in millions):

Current assets
$ 6
Property, plant and equipment, net
611
Intangible asset
190
Other non-current asset
20
Total assets
827
Current portion of long-term debt
744
Current liabilities
74
Noncontrolling interest
77
Accumulated other comprehensive loss
(157 )
The adoption of ASU No. 2009-17 had no impact on our investment in the Hydroelectric Generation Facilities, which we sold in the third quarter of 2010.  Please read Note 10—Variable Interest Entities—Hydroelectric Generation Facilities for further discussion.
Disclosures about Fair Value Measurements. On January 1, 2010, we adopted ASU No. 2010-06—Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.  Please read Note 7—Fair Value Measurements for further discussion.
Note 2—Proposed Blackstone Merger and NRG Sale
On August 13, 2010, Dynegy entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Denali Parent Inc., a Delaware corporation (“Parent”), and Denali Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of Parent (“Merger Sub”), providing for the merger of Merger Sub with and into Dynegy (the “Blackstone Merger”).  Both Parent and Merger Sub are affiliates of The Blackstone Group L.P. (“Blackstone”).  In the Blackstone Merger, each outstanding share of Dynegy common stock (except for shares owned by Parent, Merger Sub, Dynegy and their respective wholly owned subsidiaries and not held on behalf of third parties, and shares owned by stockholders who have properly demanded appraisal rights under applicable law) will be converted into the right to receive $4.50 in cash, without interest, less any applicable withholding taxes.  Dynegy will be the surviving corporation in the Blackstone Merger and will continue to do business following the Blackstone Merger.  As a result of the Blackstone Merger, Dynegy will cease to be a publicly traded company.
Concurrently with the execution of the Merger Agreement, Merger Sub entered into a Purchase and Sale Agreement (the “NRG PSA”) with NRG Energy, Inc., a Delaware corporation (“NRG”), pursuant to which NRG will, simultaneously with the closing of the Blackstone Merger, acquire the Casco Bay, Moss Landing, Morro Bay and Oakland power generation facilities and related assets currently owned by us for cash consideration of approximately $1.36 billion (the “NRG Sale”).  The completion of the Blackstone Merger between Dynegy and Merger Sub is contingent upon the concurrent closing of the NRG Sale.  The NRG Sale will not occur if the Blackstone Merger is not consummated.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
The respective obligations of Dynegy, Parent and Merger Sub to consummate the Blackstone Merger are subject to the satisfaction or waiver of certain customary conditions, including the adoption of the Merger Agreement by Dynegy’s stockholders, receipt of required regulatory approvals, the absence of any legal prohibitions, the accuracy of the representations and warranties of the parties and compliance by the parties with their respective obligations under the Merger Agreement.  Parent’s and Merger Sub’s obligations to consummate the Blackstone Merger are also subject to the satisfaction or waiver of the conditions to the obligations of NRG and Merger Sub to effect the NRG Sale under the NRG PSA (other than those conditions that by their nature are to be satisfied at the closing of the NRG Sale, and the condition relating to the consummation of the Blackstone Merger) and to NRG being ready, willing and able to complete the NRG Sale.
Under the Merger Agreement, between the date thereof and the effective time of the Blackstone Merger, Dynegy has agreed, subject to certain exceptions in the Merger Agreement and the disclosure schedules Dynegy delivered in connection with the Merger Agreement, to conduct the businesses of Dynegy and its subsidiaries, in the ordinary course and has also agreed to certain customary negative covenants, including but not limited to limitations on our ability to incur indebtedness, issue letters of credit, issue equity interests, make acquisitions or dispositions and sell or purchase derivative products or commodities.
Under specified circumstances, Dynegy, Parent or Merger Sub may have the right to terminate the Merger Agreement, or NRG or Merger Sub may have the right to terminate the NRG PSA.  In the event of a termination of the Merger Agreement and under specified circumstances, Dynegy may be required to pay to Parent a fee of up to $50 million in the aggregate (including any expenses of Parent, Merger Sub and their respective affiliates previously reimbursed by Dynegy) with respect to the termination of the Merger Agreement, or Dynegy may be required to reimburse Parent, Merger Sub and their affiliates for documented out-of-pocket expense up to $10 million, as applicable. Under other specified circumstances, Parent may be obligated to pay Dynegy a $100 million fee less the sum of certain expense reimbursement and indemnification amounts paid by Parent in connection with certain financial and third party investment activities and/or 50 percent of certain negotiated amounts Merger Sub or any of its affiliates receive from NRG in connection with a termination of the NRG PSA or a failure of the NRG Sale to be consummated.
NRG is an intended third party beneficiary of the Merger Agreement.  NRG has the right to enforce the rights and obligations of Parent, Merger Sub and Dynegy to the extent such rights and obligations directly relate to the assets it is acquiring, and the liabilities it is assuming, in the NRG Sale.  No party to the Merger Agreement may amend or waive any condition thereunder if such waiver or amendment would be adverse to NRG as a third party beneficiary in any material respect without NRG’s consent.
Dynegy is an intended third party beneficiary of the NRG PSA.  Dynegy has the right of enforcement in respect of Merger Sub’s and NRG’s obligations under the NRG PSA.  No party to the NRG PSA may amend, supplement or otherwise modify the NRG PSA in a manner adverse to Dynegy as a third party beneficiary in any material respect without Dynegy’s consent.
The DOJ and the FTC granted early termination of the waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, applicable to the Blackstone Merger and NRG Sale on September 7, 2010 and September 8, 2010, respectively. Further, on October 29, 2010, FERC approved the joint applications related to the Blackstone Merger and NRG Sale.  Assuming receipt of the remaining required regulatory approvals and timely satisfaction of other closing conditions, including the approval by Dynegy stockholders of the proposal to adopt the Merger Agreement for which a special meeting of stockholders is scheduled for November 17, 2010, we anticipate that the Blackstone Merger will be completed by the end of November 2010.  We cannot assure you that the conditions to the Blackstone Merger will be satisfied or that the Blackstone Merger will be consummated on the terms agreed, if at all.
At the signing of the Merger Agreement and NRG PSA, on August 13, 2010 there was an expectation that it is more likely than not the facilities subject to the NRG PSA will be disposed of before the end of their previously estimated useful lives, requiring us to perform an impairment analysis.  Based on the terms of the NRG PSA and the recent impairment analysis of the impact of such agreement on the recoverability of the carrying value of our long-lived assets, we recorded a pre-tax impairment charge of $134 million during the third quarter 2010 to reduce the carrying value of our Casco Bay facility and related assets to its fair value.  After giving effect to this impairment charge, the carrying value of the net assets to be sold will exceed the expected sales price by approximately $180 million.  However, if the Merger Agreement is completed, the carrying value of the assets to be sold to NRG will be adjusted to reflect their fair value in purchase accounting for the Merger Agreement, and we would not record additional losses or impairment charges related to the NRG Sale.  Actual losses and impairment charges recorded could differ materially from these estimates based on various factors, including failure to satisfy closing conditions, changes to working capital adjustments and additional costs incurred in connection with the NRG Sale.  Please read Note 8—Impairment Charges for further discussion of these impairments.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Upon closing of the Blackstone Merger, the change in ownership of Dynegy’s stock may impact our ability to fully utilize our federal net operating loss carry forwards (“NOLs”) and our alternative minimum tax credits (“AMT”) under Sections 382 and 383 of the Internal Revenue Code.  As a result, if the proposed Blackstone Merger closes, we may be required to record a valuation allowance with respect to certain of our deferred tax assets.  At September 30, 2010, our net operating loss deferred tax asset attributable to our previously incurred federal NOLs was approximately $98 million and $77 million, for Dynegy and DHI, respectively.
Note 3—Dispositions and Discontinued Operations
Dispositions
LS Power Transactions. We consummated our transactions (the “LS Power Transactions”) with LS Power Partners, L.P. and certain of its affiliates (“LS Power”) in two parts, with the issuance of $235 million of notes by DHI on December 1, 2009, and the remainder of the transactions closing on November 30, 2009.  Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations in our Form 10-K for further discussion of these transactions.
Discontinued Operations
Arlington Valley, Griffith and Bluegrass. On November 30, 2009, we completed the sale of our interests in the Arlington Valley and Griffith power generation assets (collectively, the “Arizona power generation facilities”) and Bluegrass power generation facility as part of the LS Power Transactions.
The Arizona power generation facilities, as well as our Bluegrass facility, met the criteria of held for sale during the third quarter 2009.  At that time, we discontinued depreciation and amortization of the Arizona power generation facilities’ and Bluegrass’ property, plant and equipment.  Depreciation and amortization expense related to the Arizona power generation facilities totaled approximately $4 million and $14 million in the three- and nine-month periods ended September 30, 2009, respectively.  Depreciation and amortization expense related to Bluegrass totaled approximately zero and $1 million in the three- and nine-month periods ended September 30, 2009, respectively.  We recorded an impairment charge of $235 million related to the Arizona power generation facilities during the third quarter 2009.  We previously recorded impairment charges of $5 million and $18 million related to the Bluegrass facility during the first and second quarters of 2009, respectively.  We are reporting the results of operations for the Arizona power generation facilities and the Bluegrass power generation facility in discontinued operations for all periods presented.
Heard County. On April 30, 2009, we completed the sale of our interest in the Heard County power generation facility for approximately $105 million.
Heard County was classified as held for sale during the first quarter 2009.  At that time, we discontinued depreciation and amortization of Heard County’s property, plant and equipment.  Depreciation and amortization expense related to Heard County totaled zero and $1 million in the three- and nine-month periods ended September 30, 2009, respectively.  We are reporting the results of Heard County’s operations in discontinued operations for all periods presented.

DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Summary. The following table summarizes information related to Dynegy’s discontinued operations:

GEN-MW
GEN-WE
Total
(in millions)
Three Months Ended September 30, 2009
Revenues
$ 1 $ 54 $ 55
Loss from operations before taxes (2)
— (213 ) (213 )
Loss from operations after taxes
— (129 ) (129 )
Nine Months Ended September 30, 2010
Revenues
$ — $ — $ —
Income from operations before taxes
— 1 1
Income from operations after taxes
— 1 1
Nine Months Ended September 30, 2009
Revenues
$ 4 $ 96 $ 100
Loss from operations before taxes (1) (2)
(23 ) (219 ) (242 )
Loss from operations after taxes
(14 ) (133 ) (147 )
Gain on sale before taxes
— 10 10
Gain on sale after taxes
— 6 6
(1)
Includes $23 million of impairment charges related to our Bluegrass power generation facility.
(2)
Includes $235 million of impairment charges related to our Arizona power generation facilities.
Summary. The following table summarizes information related to DHI’s discontinued operations:

GEN-MW
GEN-WE
Total
(in millions)
Three Months Ended September 30, 2009
Revenues
$ 1 $ 54 $ 55
Income (loss) from operations before taxes (2)
— (213 ) (213 )
Income (loss) from operations after taxes
— (139 ) (139 )
Nine Months Ended September 30, 2010
Revenues
$ — $ — $ —
Income from operations before taxes
— 1 1
Income from operations after taxes
— 1 1
Nine Months Ended September 30, 2009
Revenues
$ 4 $ 96 $ 100
Loss from operations before taxes (1) (2)
(23 ) (219 ) (242 )
Loss from operations after taxes
(14 ) (139 ) (153 )
Gain on sale before taxes
— 10 10
Gain on sale after taxes
— 12 12

(1)
Includes $23 million of impairment charges related to our Bluegrass power generation facility.
(2)
Includes $235 million of impairment charges related to our Arizona power generation facilities.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Note 4—Noncontrolling Interests
On January 1, 2009, we adopted authoritative guidance which requires: (i) ownership interests in subsidiaries held by parties other than the parent to be clearly identified, labeled, and presented in the consolidated statements of financial position within equity, but separate from the parent’s equity; (ii) the amount of consolidated net income (loss) attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statements of operations; (iii) changes in a parent’s ownership interests that do not result in deconsolidation to be accounted for as equity transactions; and (iv) that a parent recognize a gain or loss in net income upon deconsolidation of a subsidiary, with any retained noncontrolling equity investment in the former subsidiary initially measured at fair value.  The following table presents the net loss attributable to Dynegy’s and DHI’s stockholders:

Three Months Ended
September 30, 2009
Dynegy Inc.
Dynegy
Holdings Inc.
(in millions)
Loss from continuing operations
$ (83 ) $ (82 )
Loss from discontinued operations, net of tax benefit of $ 84 and $74, respectively
(129 ) (139 )
Net loss
$ (212 ) $ (221 )

Nine Months Ended
September 30, 2009
Dynegy Inc.
Dynegy
Holdings Inc.
(in millions)
Loss from continuing operations
$ (751 ) $ (750 )
Loss from discontinued operations, net of tax benefit of $91 and $91, respectively
(141 ) (141 )
Net loss
$ (892 ) $ (891 )
As a result of the deconsolidation of PPEA Holding, effective January 1, 2010, there are no longer any noncontrolling interests in any of our consolidated subsidiaries, and as a result, no reconciliation is needed for the nine months ended September 30, 2010.  The following table presents a reconciliation of the carrying amount of total equity, equity attributable to Dynegy and the equity attributable to the noncontrolling interests at the beginning and the end of the nine months ended September 30, 2009.

Controlling Interest
Noncontrolling Interests
Total
(in millions)
December 31, 2008
$ 4,515 $ (30 ) $ 4,485
Net loss
(892 ) (14 ) (906 )
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market gains arising during period
33 127 160
Reclassification of mark-to-market (gains) losses to earnings
(1 ) 2 1
Deferred losses on cash flow hedges
— (8 ) (8 )
Amortization of unrecognized prior service cost and actuarial gain
1 — 1
Unconsolidated investments other comprehensive income
3 — 3
Total other comprehensive income, net of tax
36 121 157
Other equity activity:
Options exercised
(1 ) — (1 )
Options and restricted stock granted
7 — 7
401(k) plan and profit sharing stock
5 — 5
Board of directors stock compensation
(2 ) — (2 )
September 30, 2009
$ 3,668 $ 77 $ 3,745
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
As a result of the deconsolidation of PPEA Holding, effective January 1, 2010, there are no longer any noncontrolling interests in any of our consolidated subsidiaries, and as a result, no reconciliation is needed for the nine months ended September 30, 2010.  The following table presents a reconciliation of the carrying amount of total equity, equity attributable to DHI and the equity attributable to the noncontrolling interests at the beginning and the end of the nine months ended September 30, 2009.

Controlling Interest
Noncontrolling Interests
Total
(in millions)
December 31, 2008
$ 4,613 $ (30 ) $ 4,583
Net loss
(891 ) (14 ) (905 )
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market gains arising during period
33 127 160
Reclassification of mark-to-market (gains) losses to earnings
(1 ) 2 1
Deferred losses on cash flow hedges
— (8 ) (8 )
Amortization of unrecognized prior service cost and actuarial gain
1 — 1
Unconsolidated investments other comprehensive income
3 — 3
Total other comprehensive income, net of tax
36 121 157
Other equity activity:
Dividend to Dynegy
(175 ) — (175 )
Contribution from Dynegy
36 — 36
Affiliate activity
4 — 4
September 30, 2009
$ 3,623 $ 77 $ 3,700

Note 5—Investments
The amortized cost basis, unrealized gains and losses and fair values of investments in available for sale investments as of September 30, 2010, is shown in the table below:

Cost Basis
Gross Unrealized Gains
Gross Unrealized Losses
Fair Value
(in millions)
Available for Sale investments:
Commercial Paper
$ 20 $ — $ — $ 20
Certificates of Deposit
16 — — 16
Corporate Securities
13 — — 13
U.S. Treasury and Government Securities (1)
218 — — 218
Total—DHI
$ 267 $ — $ — $ 267
Commercial Paper
2 — — 2
Certificates of Deposit
2 — — 2
Corporate Securities
5 — — 5
U.S. Treasury and Government Securities
10 — — 10
Total—Dynegy
$ 286 $ — $ — $ 286

(1)
Includes $104 million in Broker margin account on our consolidated balance sheets in support of transactions with our futures clearing manager .
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
During the three and nine months ended September 30, 2010, we received proceeds of $7 million and $53 million, respectively from the sale of available for sale securities.  We realized an immaterial amount of gains and losses on the sale of these available for sale securities in earnings for the three and nine months ended September 30, 2010.
Note 6—Risk Management Activities, Derivatives and Financial Instruments
The nature of our business necessarily involves market and financial risks.  Specifically, we are exposed to commodity price variability related to our power generation business.  Our commercial team seeks to manage these commodity price risks with financially settled and other types of contracts consistent with our commodity risk management policy.  Our commercial team also uses financial instruments in an attempt to capture the benefit of fluctuations in market prices in the geographic regions where our assets operate.  Our treasury team seeks to manage our financial risks and exposures associated with interest expense variability.
Our commodity risk management strategy gives us the flexibility to sell energy and capacity through a combination of spot market sales and near-term contractual arrangements (generally over a rolling 1 to 3 year time frame).  Our commodity risk management goal is to increase predictability of cash flows in the near-term while keeping the ability to capture value from rising commodity prices that are anticipated over the longer term.  Many of our contractual arrangements are derivative instruments and must be accounted for at fair value.  We also manage commodity price risk by entering into capacity forward sales arrangements, tolling arrangements, RMR contracts, fixed price coal purchases and other arrangements that do not receive fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase normal sales.”  As a result, the gains and losses with respect to these arrangements are not reflected in the unaudited condensed consolidated statements of operations until the settlement dates.
Quantitative Disclosures Related to Financial Instruments and Derivatives
The following disclosures and tables present information concerning the impact of derivative instruments on our unaudited condensed consolidated balance sheets and statements of operations. In the table below, commodity contracts primarily consist of derivative contracts related to our power generation business that we have not designated as accounting hedges, that are entered into for purposes of hedging future fuel requirements and sales commitments and securing commodity prices.  Interest rate contracts primarily consist of derivative contracts related to managing our interest rate risk.  As of September 30, 2010, our commodity derivatives were comprised of both long and short positions; a long position is a contract to purchase a commodity, while a short position is a contract to sell a commodity.  As of September 30, 2010, we had net long/ (short) commodity derivative contracts outstanding and notional interest rate swaps outstanding in the following quantities:
Contract Type
Hedge Designation
Quantity Unit of Measure
Net Fair Value
(in millions)
(in millions)
Commodity contracts:
Electric energy (1)
Not designated
(74 )
MW
$ 432
Natural gas (1)
Not designated
183
MMBtu
$ (273 )
Heat rate derivatives
Not designated
(7)/65
MW/MMBtu
$ (23 )
Other (2)
Not designated
1
Misc.
$ 4
Interest rate contracts:
Interest rate swaps
Fair value hedge
(25 )
Dollars
$ 1
Interest rate swaps
Not designated
231
Dollars
$ (11 )
Interest rate swaps
Not designated
(206 )
Dollars
$ 10
(1)
Mainly comprised of swaps, options and physical forwards.
(2)
Comprised of emissions, coal, crude oil, fuel oil options, swaps and physical forwards.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Derivatives on the Balance Sheet. We execute a significant volume of transactions through a futures clearing manager.  Our daily cash payments (receipts) to (from) our futures clearing manager consist of three parts: (i) fair value of open positions (exclusive of options) (“Daily Cash Settlements”); (ii) initial margin requirements related to open positions (exclusive of options) (“Initial Margin”); and (iii) fair value and margin requirements related to options (“Options”, and collectively with Initial Margin, “Collateral”).  We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we do not elect to offset the fair value amounts recognized for the Daily Cash Settlements paid or received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.
As a result, our consolidated balance sheets present derivative assets and liabilities, as well as related Daily Cash Settlements and Collateral, as applicable, on a gross basis.  As of September 30, 2010, the net value of our Daily Cash Settlements and Collateral with our futures clearing manager totaled $19 million, which is included in the Broker margin account on our unaudited condensed consolidated balance sheets.  The $19 million is comprised of approximately $87 million of Collateral offset by approximately $68 million of Daily Cash Settlements due to the broker.  As of September 30, 2010, the Broker margin account includes $104 million of short-term investments posted as collateral, which is partially offset by $68 million of Daily Cash Settlements due to the broker as discussed above.  In the second quarter 2010, we began using short-term investments to collateralize a portion of our collateral requirements.  The broker requires that we post approximately 103 percent of any collateral requirement collateralized with short-term investments.  Accordingly, our Broker margin account includes approximately $3 million related to this requirement.  As of December 31, 2009, of the approximately $286 million included in Broker margin account on our consolidated balance sheets, approximately $288 million represented Collateral, offset by approximately $2 million representing Daily Cash Settlements.
The following table presents the fair value and balance sheet classification of derivatives in the unaudited condensed consolidated balance sheet as of September 30, 2010, and December 31, 2009 segregated between designated, qualifying hedging instruments and those that are not, and by type of contract segregated by assets and liabilities.
Contract Type
Balance Sheet Location
September 30,
2010
December 31,
2009
(in millions)
Derivatives designated as hedging instruments:
Derivative Assets:
Interest rate contracts
Assets from risk management activities
$ 1 $ 2
Derivative Liabilities:
Interest rate contracts
Liabilities from risk management activities
— —
Total derivatives designated as hedging instruments
1 2
Derivatives not designated as hedging instruments:
Derivative Assets:
Commodity contracts
Assets from risk management activities
2,024 861
Interest rate contracts
Assets from risk management activities
10 13
Derivative Liabilities:
Commodity contracts
Liabilities from risk management activities
(1,884 ) (844 )
Interest rate contracts
Liabilities from risk management activities
(11 ) (65 )
Total derivatives not designated as hedging instruments
139 (35 )
Total derivatives, net
$ 140 $ (33 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Impact of Derivatives on the Consolidated Statements of Operations
The following discussion and tables present the disclosure of the location and amount of gains and losses on derivative instruments in our unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2010 and 2009 segregated between designated, qualifying hedging instruments and those that are not, by type of contract.
Cash Flow Hedges. We enter into financial derivative instruments that qualify, and that we may elect to designate, as cash flow hedges.  Interest rate swaps have been used to convert floating interest rate obligations to fixed interest rate obligations.
In 2007, a formerly consolidated variable interest entity, PPEA, entered into three interest rate swap agreements which were designated as cash flow hedges.  PPEA Holding was deconsolidated on January 1, 2010 upon adoption of ASU No. 2009-17, and therefore these instruments are not reflected in our consolidated risk management accounts at September 30, 2010.  Please read Note 1—Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.
During the three and nine months ended September 30, 2010 and 2009, we recorded no income or loss, related to ineffectiveness from changes in fair value of derivative positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in either of the periods.  During the three and nine months ended September 30, 2010 and 2009, no amounts were reclassified to earnings in connection with forecasted transactions that were considered probable of not occurring.
The balance in cash flow hedging activities within Accumulated other comprehensive loss, net, of $17 million at September 30, 2010, representing our share of the historical cash flow hedging activities of PPEA under the equity method, is expected to be reclassified to future earnings when the forecasted hedged transaction impacts earnings.  Currently we do not expect to make any reclassifications into earnings over the 12-month period ending September 30, 2011, unless we complete the sale of our investment in PPEA Holding during such period.  Upon completion of the sale, which is further described in Note 10—Variable Interest Entities—PPEA Holding Company LLC below, we would reclassify to earnings the $17 million currently deferred in Accumulated other comprehensive loss.  The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market prices, hedging strategies, the probability of forecasted transactions occurring and other factors.
The amount of gain recognized in Other comprehensive loss on the effective portion of interest rate derivatives for the three and nine months ended September 30, 2009 was $45 million and $160 million, respectively.  As of July 28, 2009, these derivatives no longer qualified for cash flow hedge accounting, and therefore, no additional gains or losses have been recognized in Other comprehensive loss since that date.  During the three months ended September 30, 2010 and 2009, zero and $1 million, respectively, of losses were reclassified from Accumulated other comprehensive loss into earnings.  During the nine months ended September 30, 2010 and 2009, zero and $3 million, respectively, of losses were reclassified from Accumulated other comprehensive loss into earnings.
Fair Value Hedges. We also enter into derivative instruments that qualify, and that we may elect to designate, as fair value hedges.  We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into floating-rate debt.  The maximum length of time for which we have hedged our exposure for fair value hedges is through 2011.  During the three and nine months ended September 30, 2010 and 2009, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness.  During the three and nine months ended September 30, 2010 and 2009, there were no gains or losses related to the recognition of firm commitments that no longer qualified as fair value hedges.
The impact of interest rate swap contracts designated as fair value hedges and the related hedged item on our unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2010 and 2009 was immaterial.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Financial Instruments Not Designated as Hedges. We elect not to designate derivatives related to our power generation business and certain interest rate instruments as cash flow or fair value hedges.  Thus, we account for changes in the fair value of these derivatives within the unaudited condensed consolidated statements of operations (herein referred to as “mark-to-market accounting treatment”).  As a result, these mark-to-market gains and losses are not reflected in the unaudited condensed consolidated statements of operations in the same period as the underlying activity for which the derivative instruments serve as economic hedges.
For the three months ended September 30, 2010, our revenues included approximately $132 million of mark-to-market gains related to this activity compared to $122 million of mark-to-market losses in the same period in the prior year.  For the nine months ended September 30, 2010, our revenues included approximately $127 million of mark-to-market gains related to this activity compared to $67 million of mark-to-market losses in the same period in the prior year.
The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the three months ended September 30, 2010 and 2009 is presented below.  Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments.  Therefore, this presentation is not indicative of the economic gross profit we expect to realize when the underlying physical transactions settle.
Derivatives Not Designated as Hedging
Location of Gain (Loss)
Recognized in Income on
Amount of Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended
September 30,
Instruments
Derivatives
2010
2009
(in millions)
Commodity contracts
Revenues
$ 106 $ 59
Interest rate contracts
Interest expense
— (14 )
The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the nine months ended September 30, 2010 and 2009 is presented below.  Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments.  Therefore, this presentation is not indicative of the economic gross profit we expect to realize when the underlying physical transactions settle.
Derivatives Not Designated as Hedging
Location of Gain (Loss)
Recognized in Income on
Amount of Gain (Loss) Recognized in Income on Derivatives for the Nine Months Ended September 30,
Instruments
Derivatives
2010
2009
(in millions)
Commodity contracts
Revenues
$ 246 $ 345
Interest rate contracts
Interest expense
(1 ) (14 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Note 7—Fair Value Measurements
Financial Assets and Liabilities. The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009.  These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Fair Value as of September 30, 2010
Level 1
Level 2
Level 3
Total
(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives
$ — $ 975 $ 84 $ 1,059
Natural gas derivatives
— 939 5 944
Heat rate derivatives
— — 1 1
Other derivatives
— 20 — 20
Total assets from commodity risk management activities
$ — $ 1,934 $ 90 $ 2,024
Assets from interest rate swaps
— 11 — 11
Short-term investments:
Commercial paper
— 20 — 20
Certificates of deposit
— 16 — 16
Corporate securities
— 13 — 13
Non U.S. government securities
— — — —
U.S. Treasury and government securities (1)
— 218 — 218
Total—DHI short-term investments
$ — $ 267 $ — $ 267
Total—DHI
— 2,212 90 2,302
Short-term investments:
Commercial paper
— 2 — 2
Certificates of deposit
— 2 — 2
Corporate securities
— 5 — 5
U.S. Treasury and government securities
— 10 — 10
Total—Dynegy
$ — $ 2,231 $ 90 $ 2,321
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives
$ — $ (591 ) $ (36 ) $ (627 )
Natural gas derivatives
— (1,217 ) — (1,217 )
Heat rate derivatives
— — (24 ) (24 )
Other derivatives
— (16 ) — (16 )
Total liabilities from commodity risk management activities
$ — $ (1,824 ) $ (60 ) $ (1,884 )
Liabilities from interest rate swaps
— (11 ) — (11 )
Total
$ — $ (1,835 ) $ (60 ) $ (1,895 )
(1)
Includes $104 million in Broker margin account on our consolidated balance sheets in support of transactions with our futures clearing manager.

DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Fair Value as of December 31, 2009
Level 1
Level 2
Level 3
Total
(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives
$ — $ 442 $ 57 $ 499
Natural gas derivatives
— 302 5 307
Heat rate derivatives
— — 19 19
Other derivatives
— 36 — 36
Total assets from commodity risk management activities
— 780 81 861
Assets from interest rate swaps
— 15 — 15
Other—DHI (1)
— 8 — 8
Total—DHI
— 803 81 884
Other—Dynegy (1)
— 1 — 1
Total—Dynegy
$ — $ 804 $ 81 $ 885
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives
$ — $ (361 ) $ (51 ) $ (412 )
Natural gas derivatives
— (401 ) — (401 )
Heat rate derivatives
— — (2 ) (2 )
Other derivatives
— (29 ) — (29 )
Total liabilities from commodity risk management activities
— (791 ) (53 ) (844 )
Liabilities from interest rate swaps
— (15 ) (50 ) (65 )
Total
$ — $ (806 ) $ (103 ) $ (909 )
(1)
Other represents short-term investments and long-term investments.
We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  For example, assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts.  Some exchange-traded derivatives are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets.  In such cases, these exchange-traded derivatives are classified within Level 2.  OTC derivative trading instruments include swaps, forwards, options and complex structures that are valued at fair value.  In certain instances, these instruments may utilize models to measure fair value.  Generally, we use a similar model to value similar instruments.  Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs.  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  Certain OTC derivatives trade in less active markets with a lower availability of pricing information.  In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.  We have consistently used this valuation technique for all periods presented.  Please read Note 2—Summary of Significant Accounting Policies—Fair Value Measurements in our Form 10-K for further discussion.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:

Three Months Ended September 30, 2010
Electricity Derivatives
Natural Gas Derivatives
Heat Rate Derivatives
Interest Rate Swaps
Total
(in millions)
Balance at June 30, 2010
$ 23 $ 5 $ (23 ) $ — $ 5
Realized and unrealized gains, net
27 — 4 — 31
Purchases, issuances and settlements, net
(2 ) — (4 ) — (6 )
Balance at September 30, 2010
$ 48 $ 5 $ (23 ) $ — $ 30
Unrealized gains relating to instruments still held as of September 30, 2010
$ 28 $ — $ 2 $ — $ 30

Nine Months Ended September 30, 2010
Electricity Derivatives
Natural Gas Derivatives
Heat Rate Derivatives
Interest Rate Swaps
Total
(in millions)
Balance at December 31, 2009
$ 6 $ 5 $ 17 $ (50 ) $ (22 )
Deconsolidation of Plum Point
— — — 50 50
Realized and unrealized gains (losses), net
58 — (5 ) — 53
Purchases, issuances and settlements, net
(16 ) — (35 ) — (51 )
Balance at September 30, 2010
$ 48 $ 5 $ (23 ) $ — $ 30
Unrealized gains (losses) relating to instruments still held as of September 30, 2010
$ 49 $ — $ (23 ) $ — $ 26

Three Months Ended September 30, 2009
Electricity Derivatives
Natural Gas Derivatives
Heat Rate Derivatives
Interest Rate Swaps
Total
(in millions)
Balance at June 30, 2009
$ 3 $ 5 $ 35 $ — $ 43
Realized and unrealized gains (losses), net
9 — 5 (11 ) 3
Purchases, issuances and settlements, net
(16 ) — (12 ) 2 (26 )
Transfer into Level 3
— — — (50 ) (50 )
Balance at September 30, 2009
$ (4 ) $ 5 $ 28 $ (59 ) $ (30 )
Unrealized gains (losses) relating to instruments still held as of September 30, 2009
$ 5 $ — $ 2 $ (11 ) $ (4 )

Nine Months Ended September 30, 2009
Electricity Derivatives
Natural Gas Derivatives
Heat Rate Derivatives
Interest Rate Swaps
Total
(in millions)
Balance at December 31, 2008
$ 7 $ 7 $ 46 $ — $ 60
Realized and unrealized gains (losses), net
14 (2 ) 25 (11 ) 26
Purchases, issuances and settlements, net
(25 ) — (43 ) 2 (66 )
Transfer into Level 3
— — — (50 ) (50 )
Balance at September 30, 2009
$ (4 ) $ 5 $ 28 $ (59 ) $ (30 )
Unrealized gains (losses) relating to instruments still held as of September 30, 2009
$ (6 ) $ (2 ) $ 10 $ (11 ) $ (9 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Gains and losses (realized and unrealized) for Level 3 recurring items are included in Revenues on the unaudited condensed consolidated statements of operations.  We believe an analysis of instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio.
Transfers in and/or out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.  As of September 30, 2009, PPEA held interest rate swaps with a contractual net liability of approximately $135 million.  The fair value of these liabilities is estimated to be approximately $59 million reflecting a valuation adjustment for the recent deterioration of PPEA’s credit worthiness pursuant to fair value accounting standards.  As a result of the significance of the credit valuation adjustment, these interest rate swaps are now reflected in Level 3.
Nonfinancial Assets and Liabilities. The following table sets forth by level within the fair value hierarchy our fair value measurements with respect to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis.  These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Fair Value Measurements as of September 30, 2010
Level 1
Level 2
Level 3
Total
Total Losses
(in millions)
Assets held and used
$ — $ — $ 275 $ 275 $ (135 )
Equity method investment
— — — — (37 )
Total
$ — $ — $ 275 $ 275 $ (172 )
During the nine months ended September 30, 2010, long-lived assets held and used were written down to their fair value of $275 million, resulting in pre-tax impairment charges of $135 million, which is included in Impairment and other charges on our unaudited condensed consolidated statements of operations.  Please read Note 8—Impairment Charges for further discussion.
As discussed in Note 1—Accounting Policies—Accounting Policies Adopted—Variable Interest Entities, on January 1, 2010, we recorded an impairment of our investment in PPEA Holding as part of our cumulative effect of a change in accounting principle.  We determined the fair value of our investment using assumptions that reflect our best estimate of third party market participants’ considerations based on the facts and circumstances related to our investment at that time.  The fair value of our investment on January 1, 2010 is considered a Level 3 measurement as the fair value was determined based on probability weighted cash flows resulting from various alternative scenarios including no change in the financing structure, a restructuring of the project debt and insolvency.  These scenarios and the related probability weighting are consistent with the scenarios used at December 31, 2009 in our long-lived asset impairment analysis.  Please read Note 8—Impairment Charges—2009—Impairment Charges—Other in our Form 10-K.  At March 31, 2010, we fully impaired our investment in PPEA Holding due to the uncertainty and risk surrounding PPEA’s financing structure.  During the period from April 1, 2010 through September 30,  2010, we did not recognize our share of losses from our investment in PPEA Holding.  Please read Note 10—Variable Interest Entities—PPEA Holding Company, LLC for further discussion.

DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Fair Value Measurements as of September 30, 2009
Level 1
Level 2
Level 3
Total
Total Losses
(in millions)
Assets/Liabilities:
Goodwill
$ — $ — $ — $ — $ (433 )
Assets held for sale and liabilities associated with assets held for sale
— — 1,258 1,258 (584 )
Assets held and used
— — — — (209 )
Total
$ — $ — $ 1,258 $ 1,258 $ (1,226 )
During the first quarter 2009, goodwill with a carrying amount of $433 million was written down to its implied fair value of zero.  In order to determine the fair value of our reporting units for purposes of calculating the implied fair value of goodwill, we placed equal weight on a market-based approach and an income approach valuation.  Our market-based approach compared our forecasted earnings and Dynegy’s market capitalization to those of similarly situated public companies by considering multiples of earnings.  Our income approach was based on a discounted cash flows model.  This approach used forward-looking projections of our estimated future operating results based on discrete financial forecasts developed by management for planning purposes.  Cash flows beyond the discrete forecasts were estimated using a terminal value calculation, which incorporated historical and forecasted financial trends and considered long-term earnings growth rates based on growth rates observed in the power sector.  As a result of this analysis, we recorded an impairment charge of $433 million, which is included in Goodwill impairments on our unaudited condensed consolidated statements of operations.
During the nine months ended September 30, 2009, long-lived assets held and used were written down to their fair value of zero, resulting in an impairment charge of $209 million, which is included in Impairment and other charges on our unaudited condensed consolidated statements of operations.  In addition, during the nine months ended September 30, 2009, net assets/liabilities held for sale were written down to their fair value of $1,258 million, less costs to sell of $25 million, resulting in an impairment charge of $584 million.  Of this amount, $326 million is included in Impairment and other charges and $258 million is included in Income (loss) on discontinued operations on our unaudited condensed consolidated statements of operations.  Please read Note 8—Impairment Charges for further discussion.
Fair Value of Financial Instruments. We have determined the estimated fair-value amounts using available market information and selected valuation methodologies.  Considerable judgment is required in interpreting market data to develop the estimates of fair value.  The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair-value amounts.

DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
The carrying values of financial assets and liabilities, not presented in the table below, approximate fair values due to the short-term maturities of these instruments.  The fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes for the periods ending September 30, 2010 and December 31, 2009, respectively.
September 30, 2010
December 31, 2009
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
(in millions)
Interest rate derivatives designated as fair value accounting hedges (1)
$ 1 $ 1 $ 2 $ 2
Interest rate derivatives not designated as accounting hedges (1)
(1 ) (1 ) (52 ) (52 )
Commodity-based derivative contracts not designated as accounting hedges (1)
140 140 17 17
Term Loan B, due 2013
(68 ) (67 ) (68 ) (66 )
Term Facility, floating rate due 2013
(850 ) (840 ) (850 ) (814 )
Senior Notes and Debentures:
6.875 percent due 2011
(80 ) (79 ) (81 ) (82 )
8.75 percent due 2012
(89 ) (88 ) (89 ) (92 )
7.5 percent due 2015 (2)
(767 ) (612 ) (764 ) (737 )
8.375 percent due 2016 (3)
(1,043 ) (809 ) (1,043 ) (998 )
7.125 percent due 2018
(172 ) (112 ) (172 ) (140 )
7.75 percent due 2019
(1,100 ) (740 ) (1,100 ) (950 )
7.625 percent due 2026
(171 ) (102 ) (171 ) (119 )
Subordinated Debentures payable to affiliates, 8.316 percent, due 2027
(200 ) (93 ) (200 ) (107 )
PPEA Credit Agreement Facility, floating rate, due 2010 (4)
— — (644 ) (334 )
PPEA Tax Exempt Bonds, floating rate, due 2036 (4)
— — (100 ) (100 )
Sithe Senior Notes, 9.0 percent due 2013 (5)
(266 ) (265 ) (300 ) (294 )
Other—DHI (6)
267 267 8 8
Other—Dynegy (7)
19 19 1 1
(1)
Included in both current and non-current assets and liabilities on the unaudited condensed consolidated balance sheets.
(2)
Includes unamortized discounts of $ 18 million and $21 million at September 30, 2010 and December 31, 2009, respectively.
(3)
Includes unamortized discounts of $ 4 million and $4 million at September 30, 2010 and December 31, 2009, respectively.
(4)
As discussed in Note 1—Accounting Policies—Accounting Policies Adopted—Variable Interest Entities, effective January 1, 2010, we deconsolidated our investment in PPEA Holding, and as a result, PPEA’s debt is no longer included in our unaudited condensed consolidated balance sheets.
(5)
Includes unamortized premiums of $ 9 million and $13 million at September 30, 2010 and December 31, 2009, respectively.
(6)
Other represents short-term investments, including $104 million of short-term investments included in the Broker margin account at September 30, 2010.
(7)
Other represents short-term investments at September 30, 2010.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Note 8—Impairment Charges
In August 2010, in connection with the Merger Agreement with Blackstone and the NRG PSA discussed further in Note 2—Proposed Blackstone Merger and NRG Sale, we determined it was more likely than not that the facilities subject to the NRG PSA will be disposed of before the end of their previously estimated useful lives.  Based on the terms of the NRG PSA and our impairment analysis of the impact of such agreement on the recoverability of the carrying value of our long-lived assets, we recorded a pre-tax impairment charge of $134 million ($81 million after-tax) during the three months ended September 30, 2010 to reduce the carrying value of our Casco Bay facility and related assets to its fair value.  This charge is included in Impairment and other charges in our unaudited condensed consolidated statements of operations.
In performing the impairment analysis, we concluded that the assets included in the NRG PSA do not meet the criteria of “held for sale”, as the NRG PSA is a contractual arrangement between Blackstone and NRG, and Dynegy management has not committed to any plan to dispose of these assets prior to the end of their previously estimated useful lives.  Whether the sale of these assets to NRG is ultimately completed is dependent on a number of factors, including the completion of the proposed Blackstone Merger.  As such, we assessed the recoverability of the carrying value of these assets using expected cash flows from the proceeds from the potential sale of these assets to NRG, probability weighted with the expected cash flow from continuing to hold and use the assets.  We performed this analysis considering a range of likelihoods that management considered reasonable regarding whether the sale to NRG will be completed.  In any of the scenarios within this range of the probabilities we consider reasonable, the expected undiscounted cash flows from the Moss Landing, Morro Bay and Oakland facilities were sufficient to recover their carrying values, while the expected undiscounted cash flows from the Casco Bay facility were not.  Therefore, we recorded an impairment charge to reduce the carrying value of the Casco Bay facility and related assets to its estimated fair value.  We determined the fair value of the facility based on assumptions that reflect our best estimate of third party market participants’ considerations, and corroborated these assumptions based upon the terms of the NRG PSA.
After giving effect to the Casco Bay facility impairment charge, the carrying value of the net assets to be sold will exceed the expected sales price by approximately $180 million.  However, if the Blackstone Merger is completed, the carrying value of the assets to be sold to NRG will be adjusted to reflect their fair value in purchase accounting for the Blackstone Merger, and we would not record additional losses or impairment charges related to the NRG Sale.  Actual losses and impairment charges recorded in future periods will be based on various factors, including failure to satisfy closing conditions, or changes to working capital adjustments and additional costs incurred in connection with the NRG Sale.
Our impairment analysis of our generating assets is based on forward-looking projections of our estimated future cash flows based on discrete financial forecasts developed by management for planning purposes.  These projections incorporate certain assumptions including forward power and capacity prices, forward fuel costs and costs of complying with environmental regulations.  As additional information becomes available regarding the significant assumptions used in our analysis, we may conclude that it is necessary to update estimated useful lives and our impairment analyses in future periods to assess the recoverability of our assets and additional impairment charges could be required.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
2009 Impairment Charges
The following summarizes pre-tax impairment charges recorded during 2009 which are included in Impairment and other charges in our consolidated statements of operations:
GEN-MW
GEN-WE
GEN-NE
Total
(in millions)
Three months ended June 30, 2009:
Assets included in the LS Power Transactions
$ — $ — $ (179 ) $ (179 )
Roseton and Danskammer
— — (208 ) (208 )
Total 2nd Quarter Impairment Charges
— — (387 ) (387 )
Three months ended September 30, 2009:
Assets included in the LS Power Transactions (1)
(147 ) — — (147 )
Roseton and Danskammer
— — (1 ) (1 )
Total 3rd Quarter Impairment Charges
(147 ) — (1 ) (148 )
Impairment Charges for the Nine Months Ended September 30, 2009
$ (147 ) $ — $ (388 ) $ (535 )
(1)
Upon classification of these assets as held for sale at August 9, 2009, we recognized impairment charges of $196 million and $19 million in our GEN-MW and GEN-NE segments, respectively.  At September 30, 2009, based on an increase in the fair value of the consideration to be received, we recovered $49 million and $19 million of the impairment charges in our GEN-MW and GEN-NE segments, respectively.
The following summarizes pre-tax impairment charges recorded during 2009 which are included in Income (loss) from discontinued operations in our consolidated statements of operations:
GEN-MW
GEN-WE
GEN-NE
Total
(in millions)
Three months ended March 31, 2009:
Bluegrass (included in the LS Power Transactions)
$ (5 ) $ — $ — $ (5 )
Total 1st Quarter Impairment Charges
(5 ) — — (5 )
Three months ended June 30, 2009:
Assets included in the LS Power Transactions
(18 ) — — (18 )
Total 2nd Quarter Impairment Charges
(18 ) — — (18 )
Three months ended September 30, 2009:
Assets included in the LS Power Transactions (1)
— (235 ) — (235 )
Total 3rd Quarter Impairment Charges
— (235 ) — (235 )
Impairment Charges for the Nine Months Ended September 30, 2009
$ (23 ) $ (235 ) $ — $ (258 )
(1)
Upon classification of these assets as held for sale at August 9, 2009, we recognized an impairment charge of $292 million and $4 million in our GEN-WE and GEN-MW segments, respectively.  At September 30, 2009, based on an increase in the fair value of the consideration to be received, we recovered $57 million and $4 million of the impairment charges in our GEN-WE and GEN-MW segments, respectively.
Bluegrass Impairment. During the first quarter 2009, we performed a goodwill impairment test due to changes in market conditions that would more likely than not reduce the fair values of our GEN-MW, GEN-WE and GEN-NE reporting units below their carrying amounts.  This decline in value also triggered testing of the recoverability of our long-lived assets.  We performed an impairment analysis and recorded a pre-tax impairment charge of $5 million ($3 million after tax).  This charge, which related to the Bluegrass power generation facility, is included in Income (loss) on discontinued operations in our consolidated statements of operations.  We determined the fair value of the Bluegrass facility using assumptions that reflected our best estimate of third party market participants’ considerations.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Assets Included in the LS Power Transactions. At June 30, 2009, in connection with discussions leading to the agreement with LS Power discussed further in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations in our Form 10-K, we determined it was more likely than not that certain assets would be sold prior to the end of their previously estimated useful lives.  Therefore, we updated our March 31, 2009 long-lived asset impairment analysis for each of the asset groups that we were considering for sale as part of the proposed transaction as of June 30, 2009.  As a result, we recorded a pre-tax impairment charge of $197 million ($120 million after-tax).  Of this charge, $179 million related to the Bridgeport power generation facility and related assets and is included in Impairment and other charges in our consolidated statements of operations in the GEN-NE segment.  The remaining $18 million ($11 million after-tax) related to the Bluegrass power generation facility and related assets and is included in Income (loss) from discontinued operations in our consolidated statements of operations in the GEN-MW segment.  This additional impairment charge for the Bluegrass power generation facility reflected updated assumptions regarding the terms of a potential sale as well as continued weakening of forward capacity prices in the second quarter 2009.  We determined the fair value of these generation facilities and related assets using assumptions that reflect our best estimate of third party market participants’ considerations and corroborated these estimates indirectly based on our assumptions regarding the terms of and the overall value inherent in the LS Power Transactions.
In performing the June 30, 2009 impairment analysis, we used an 80 percent likelihood at June 30, 2009 of reaching an agreement for sale of the assets, and certain assumptions about the terms of such a sale.  Upon reaching the agreement with LS Power discussed further in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations in our Form 10-K, the assets qualified as held for sale, and additional impairment charges were recorded, as discussed below.
On August 9, 2009, we entered into the purchase and sale agreement with LS Power.  At that time, the operating assets included in that agreement met the criteria of held for sale.  Accordingly, we updated our impairment analysis reflecting the estimated fair value for the consideration to be received from LS Power inclusive of costs to sell.  As a result, we recognized pre–tax impairment charges of $147 million and $235 million in our GEN-MW and GEN-WE segments, respectively, for the three month period ended September 30, 2009.  The $147 million charge is included in Impairment and other charges in our consolidated statements of operations.  The $235 million charge is included in Income (loss) on discontinued operations in our consolidated statements of operations.
At September 30, 2009, the fair value of the consideration was based partially upon the closing stock price of  Dynegy’s Class A common stock of $12.75 per share, as adjusted for the 1-for-5 reverse stock split of Dynegy's common stock that became effective on May 25,2010.  We recorded additional losses on the sale of these assets upon close of the transaction in the fourth quarter 2009, based on changes subsequent to September 30, 2009 in the fair value of the shares to be received as part of the consideration for this transaction, changes in the fair value of debt to be issued, and changes in working capital items not reimbursed by the purchaser.  In addition, we recorded a loss of $84 million on the sale of our Sandy Creek project investment included in this transaction.  Please refer to Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations in our Form 10-K for further discussion.
Roseton and Danskammer. In updating our impairment analysis for assets that were being considered for sale as discussed above, we noted that the aggregate carrying value of the assets included in the proposed transaction exceeded the aggregate fair value of the consideration to be received.  In addition, we noted a continued weakening in forward capacity and forward power prices in certain of the markets in which we operate.  This indicated a possible decline in the value of power generation assets in all three of our reportable segments.  Therefore, at June 30, 2009, we updated our March 31, 2009 impairment analysis for our remaining power generation facilities not currently under consideration for sale.  As a result of changes in market conditions in the second quarter 2009 within the Northeast region, we recorded a pre-tax impairment charge of $208 million ($129 million after-tax) related to the Roseton and Danskammer power generation facilities.  This charge is included in Impairment and other charges in our consolidated statements of operations.  We determined the fair value of these facilities using assumptions that reflect our best estimate of third party market participants’ considerations.  This involved using the present value technique, incorporating our best estimate of third party market participants’ assumptions about the best use of assets, future power and fuel costs and the costs of complying with environmental regulations.  Based on a continuation of expected cash flow losses for these assets in 2009, we recorded additional pre-tax impairment charges of $1 million ($1 million after-tax) for the three months ended September 30, 2009.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Note 9—Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss, net of tax, is included in Dynegy’s and DHI’s stockholders’ equity on our unaudited condensed consolidated balance sheets as follows:
September 30,
2010
December 31, 2009
(in millions)
Cash flow hedging activities, net
$ 3 $ (24 )
Unrecognized prior service cost and actuarial loss, net
(56 ) (59 )
Accumulated other comprehensive loss—unconsolidated investments, net (1)
(17 ) —
Accumulated other comprehensive loss, net of tax
(70 ) (83 )
Less: Accumulated other comprehensive income attributable to the noncontrolling interests (1)
— 67
Accumulated other comprehensive loss attributable to Dynegy and DHI, net of tax
$ (70 ) $ (150 )
(1)
As discussed in Note 1—Accounting Policies—Accounting Policies Adopted—Variable Interest Entities, effective January 1, 2010, we deconsolidated our investment in PPEA Holding, and as a result, there are no longer any noncontrolling interests in any of our consolidated subsidiaries.
Note 10—Variable Interest Entities
Hydroelectric Generation Facilities. In 2005, Dynegy acquired, as part of a larger purchase, four hydroelectric generation facilities in Pennsylvania.  The entities owning these facilities meet the definition of VIEs.  In accordance with the purchase agreement, Exelon Corporation (“Exelon”) had the sole and exclusive right to direct our efforts to decommission, sell, or otherwise dispose of the hydroelectric facilities owned through the VIEs.  Exelon is obligated to reimburse us for all costs, liabilities, and obligations of the entities owning these facilities, and to indemnify us with respect to the assets and operations of the entities.  As a result, we are not the primary beneficiary of the entities and have not consolidated them.  During December 2009, we sold two of these facilities and we sold the remaining two units during the third quarter 2010 to a third party as directed by Exelon. Please see Note 14—Variable Interest Entities—Hydroelectric Generation Facilities in our Form 10-K for discussion of these entities.
PPEA Holding Company LLC. We own an approximate 37 percent interest in PPEA Holding, which through PPEA, its wholly-owned subsidiary, owns an approximate 57 percent undivided interest in the Plum Point Project.    On September 1, 2010, the Plum Point Power Station commenced commercial operation.  PPEA financed its share of construction costs through debt financing.  Our obligation to PPEA Holding was limited to our funding commitment of approximately $15 million, which was paid in May 2010.  We have no future funding obligations related to PPEA Holding.  On September 14, 2010, we entered into an agreement to sell our interest in PPEA Holding to one of the other investors in PPEA Holding.  This transaction is expected to close in the fourth quarter 2010, subject to receipt of required regulatory approvals and satisfaction of closing conditions.  Upon closing, we will reclassify approximately $17 million of losses into earnings from Accumulated other comprehensive loss.
PPEA previously had a waiver for certain covenants required by its credit agreement.  This waiver expired on March 12, 2010.  Please read Note 17—Debt—Plum Point of our Form 10-K for further discussion.  In addition, Ambac, the guarantor of PPEA’s interest rate swaps, filed for rehabilitation on March 24, 2010.  Please read Note 7—Risk Management Activities, Derivatives and Financial Instruments of our Form 10-K for further discussion.  On March 30, 2010, the lenders requested that PPEA post collateral of approximately $101 million.  PPEA did not have the liquidity to provide this collateral and did not comply with the request.  The lenders have not funded any borrowing requests since April 2010.  PPEA has continued funding its portion of the construction costs with cash received from its sponsors, which includes the $15 million funded by us in May 2010, as well as existing cash related to PPEA tax exempt bonds and cash flow from commercial operations.  There can be no assurance that the lenders will fund future borrowing requests or as to the potential impact of any such refusal to fund on the Plum Point Project.  PPEA is currently evaluating its financing structure.  Subsequent to the achievement of commercial operations, PPEA and its lender have been disputing the existence of continuing defaults under its credit agreement.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
The carrying amount and classification of the amounts related to our investment in PPEA Holding included in our unaudited condensed consolidated balance sheet as of September 30, 2010 are included in the table below:
September 30,
2010
(in millions)
Unconsolidated investments
$ —
Accumulated other comprehensive loss, net of tax
17
Due to the uncertainty and risk surrounding PPEA’s financing structure as a result of events that occurred in 2010, we concluded that there was an other-than-temporary impairment of our investment in PPEA Holding and fully impaired our equity investment at March 31, 2010.  As a result, we recorded an impairment charge of approximately $37 million, which is included in Losses from unconsolidated investments in our unaudited condensed consolidated statements of operations.  Although our investment has been fully impaired, our maximum exposure to an accounting loss as a result of our investment in PPEA Holding is approximately $17 million, the amount currently deferred in Accumulated other comprehensive loss.  We have now satisfied our obligation to provide support to PPEA discussed previously.  The impairment is a Level 3 non-recurring fair value measurement and reflects our best estimate of third party market participants’ considerations including probabilities related to restructuring of the project debt and potential insolvency.  Please read Note 7—Fair Value Measurements for further discussion.
Please also read Note 1—Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.  There are no cross-default provisions related to the PPEA credit facility and the Fifth Amended and Restated Credit Facility and our other long-term debt.
Summarized aggregate financial information for our unconsolidated equity investment in PPEA Holding and our equity share thereof was:
Three Months Ended September 30, 2010
Total
Equity Share
(in millions)
Revenues
$ 13 $ —
Operating income
3 —
Net loss
(20 ) —
Nine Months Ended September 30, 2010
Total
Equity Share
(in millions)
Revenues
$ 13 $ —
Operating income
1 —
Net income (loss)
(53 ) 3
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
During the second and third quarters, we did not recognize our share of losses from our investment in PPEA Holding as our investment in PPEA Holding was valued at zero at September 30, 2010, and we do not have an obligation to provide further financial support.
Losses from unconsolidated investments for the nine months ended September 30, 2010 were $34 million, which includes an impairment loss of $37 million, discussed above.  This impairment was partially offset by equity earnings of $3 million, comprised primarily of mark-to-market gains related to PPEA’s interest rate swaps, partly offset by financing expenses.
DLS Power Holdings and DLS Power Development. In December 2008, Dynegy executed an agreement with LS Associates to dissolve DLS Power Holdings and DLS Power Development effective January 1, 2009.  Under the terms of the dissolution, Dynegy acquired exclusive rights, ownership and developmental control of substantially all repowering or expansion opportunities related to its existing portfolio of operating assets.  In the first quarter 2009, Dynegy subsequently contributed these assets to DHI.  LS Associates received approximately $19 million in cash from Dynegy on January 2, 2009, and acquired full ownership and developmental rights associated with various “greenfield” power generation and transmission development projects not related to Dynegy’s then existing operating portfolio of assets.
Note 11—Debt
Contingent LC Facility. On May 21, 2010, DHI executed a new $150 million unsecured bilateral contingent letter of credit facility (“Contingent LC Facility”) with Morgan Stanley Capital Group Inc. to provide DHI access to liquidity to support collateral posting requirements.  Availability under the Contingent LC Facility is tied to increases in 2012 forward spark spreads and power prices.  A facility fee will accrue on the unutilized portion of the facility at an annual rate of 0.60 percent and letter of credit availability fees will accrue at an annual rate of 7.25 percent.  The facility will mature on December 31, 2012.  No amounts were available under this facility at September 30, 2010.
Senior Notes. On December 1, 2009, as part of the transactions with LS Power, DHI issued to Adio Bond, LLC (“Adio Bond”), an affiliate of LS Power, $235 million aggregate principal amount of its 7.5 percent Senior Unsecured Notes due 2015 (the “Notes”) for $214 million in proceeds.  In connection with the closing of the transactions with LS Power, DHI entered into a registration rights agreement with Adio Bond pursuant to which DHI agreed to offer to exchange the Notes for a new issue of substantially identical notes registered under the Securities Act of 1933.  On October 6, 2010, pursuant to the registration rights agreement, DHI initiated the exchange offer, which expired on November 5, 2010, and is expected to close on or about November 8, 2010.  The Blackstone Merger, if consummated, will have no effect on the exchanged notes and thus they will remain outstanding at closing.
Note 12—Related Party Transactions
We previously held two investments in joint ventures in which LS Power or its affiliates were also investors.  DHI had 50 percent ownership interests in SCH and SC Services, and subsidiaries of LS Power held the remaining 50 percent interests.  On November 30, 2009, we sold our interests in SCH and SC Services to LS Power.  Please see Note 14—Variable Interest Entities—Sandy Creek Project in our Form 10-K for further discussion.
We also previously held two other investments in joint ventures in which LS Power or its affiliates were also investors.  Dynegy had 50 percent ownership interests in DLS Power Holdings and DLS Power Development.  Effective January 1, 2009, Dynegy and LS Power Associates, L.P. agreed to dissolve the two companies’ development joint venture.
Under the terms of the dissolution, Dynegy acquired exclusive rights, ownership and developmental control of substantially all repowering or expansion opportunities related to its existing portfolio of operating assets, and subsequently contributed approximately $15 million of these assets and approximately $21 million of deferred tax assets associated with these assets to DHI.  Please read Note 14—Variable Interest Entities—DLS Power Holdings and DLS Power Development in our Form 10-K for further discussion.  As a result of the LS Power Transaction, as discussed in Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—LS Power Transactions in our Form 10-K, effective November 30, 2009, LS Power is no longer considered a related party.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Other. On January 8, 2009, DHI paid a dividend of $175 million to Dynegy.
Note 13—Dynegy’s Loss Per Share
Basic loss per share represents the amount of losses for the period available to each share of Dynegy’s common stock outstanding during the period.  Diluted loss per share represents the amount of losses for the period available to each share of Dynegy’s common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period.  Basic and diluted shares outstanding have been calculated to reflect the 1-for-5 reverse stock split for all periods presented.  Please read Note 17—Capital Stock for further discussion.
The reconciliation of basic loss per share from continuing operations to diluted loss per share from continuing operations is shown in the following table:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2010
2009
2010
2009
(in millions, except per share amounts)
Loss from continuing operations
$ (24 ) $ (94 ) $ (71 ) $ (765 )
Less:  Net loss attributable to the noncontrolling interests
— (11 ) — (14 )
Loss from continuing operations attributable to Dynegy Inc. for basic and diluted loss per share
$ (24 ) $ (83 ) $ (71 ) $ (751 )
Basic weighted-average shares
120 168 120 168
Effect of dilutive securities:
Stock options and restricted stock
1 1 1 1
Diluted weighted-average shares
121 169 121 169
Loss per share from continuing operations attributable to Dynegy Inc.:
Basic
$ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
Diluted (1)
$ (0.20 ) $ (0.49 ) $ (0.59 ) $ (4.47 )
(1)
Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per-share amounts.  Accordingly, Dynegy Inc. has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2010 and 2009.
Note 14—Commitments and Contingencies
Legal Proceedings
Set forth below is a summary of our material ongoing legal proceedings.  We record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable.  In addition, we disclose matters for which management believes a material loss is at least reasonably possible.  In all instances, management has assessed the matters below based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success.  Management’s judgment may prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Gas Index Pricing Litigation. We, several of our affiliates, our former joint venture affiliate and other energy companies were named as defendants in numerous lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications in the 2000-2002 timeframe.  Many of the cases have been resolved and those which remain are pending in Nevada federal district court.  Recent developments include:
●
In February 2007, the Tennessee state court dismissed a class action on defendants’ motion.  Plaintiffs appealed and, in October 2008, the appellate court reversed the dismissal.  Thereafter, defendants appealed to the Tennessee Supreme Court which, in April 2010, reversed the appellate court ruling and dismissed all of plaintiffs’ claims.  Plaintiffs’ deadline to appeal to the United States Supreme Court has expired.
●
In February 2008, the United States District Court in Las Vegas, Nevada granted defendants’ motion for summary judgment in a Colorado class action and, ultimately, dismissed the case and all of plaintiffs’ claims.  The decision is subject to appeal once the remaining defendants’ claims are adjudicated.
●
The remaining five cases, three of which seek class certification, are also pending in Nevada federal court.  All of the cases contain similar claims that individually, and in conjunction with other energy companies, we engaged in an illegal scheme to inflate natural gas prices in four states by providing false information to natural gas index publications.  In November 2009, following defendants’ motion for reconsideration, the court invited defendants to renew their motions for summary judgment on preemption of plaintiffs' state law claims, which were filed shortly thereafter.  Plaintiffs concurrently moved to amend their complaints to add federal claims.  In October 2010, the court denied plaintiffs' motion to amend.  We await an order on defendants' motions for summary judgement or further instruction from the court.  In the interim, discovery and plaintiffs’ class certification motion are stayed.
We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining individual matters.  Due to the uncertainty of litigation, we cannot predict whether we will incur any liability in connection with these lawsuits.  However, given the nature of the claims, an adverse result in these proceedings could have a material effect on our financial condition, results of operations and cash flows.
Cooling Water Intake Permits. The cooling water intake structures at several of our power generation facilities are regulated under section 316(b) of the Clean Water Act.  This provision generally provides that standards set for power generation facilities require that the location, design, construction and capacity of cooling water intake structures reflect the BTA for minimizing adverse environmental impact.  These standards are developed and implemented for power generating facilities through the NPDES permits or individual SPDES permits on a case by case basis.
The environmental groups that participate in our NPDES and SPDES permit proceedings generally argue that only closed cycle cooling meets the BTA requirement.  The issuance and renewal of NPDES or SPDES permits for three of our power generation facilities have been challenged on this basis, with two still pending.
●
Roseton SPDES Permit — In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton plant.  The permit is opposed by environmental groups challenging the BTA determination.  The hearing will be scheduled after the Commissioner rules on appeals of procedural matters.  We believe that the petitioners’ claims lack merit and we plan to oppose those claims vigorously.
●
Moss Landing NPDES Permit — The California Regional Water Quality Control Board (“Water Board”) issued an NPDES permit for the Moss Landing power generating facility in 2000 that did not require closed cycle cooling.  A local environmental group challenged the BTA determination of the permit.  The Water Board’s decision was affirmed by the Superior Court in 2004 and by the Court of Appeals in 2007.  The Supreme Court of California granted review in March 2008.  The petitioner’s brief was filed in December 2009.  We filed a motion to dismiss and our responsive brief in March 2010.  The petitioner’s reply brief was filed in May 2010.  Our motion to dismiss was denied in June 2010.  In July 2010, the California Energy Commission filed an application for leave to file a brief in support of our argument challenging the jurisdiction of the Superior Court.  In September 2010, four air quality control districts filed an application for leave to file a brief in support of jurisdiction of the Superior Court.  We believe that petitioner’s claims lack merit and we plan to continue to oppose those claims vigorously.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Due to the nature of these claims, an adverse result in either of these proceedings could have a material effect on our financial condition, results of operations and cash flows.
Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska initiated an action in federal court in the Northern District of California against DHI and 23 other companies in the energy industry.  Plaintiffs claim that defendants’ emissions of GHG including CO 2 contribute to climate change and have caused significant damage to a native Alaskan Eskimo village through increased vulnerability to waves, storm surges and erosion.  In September 2009, the court dismissed all of the plaintiffs’ claims based on lack of subject matter jurisdiction and because plaintiffs lacked standing to bring the suit.  Shortly thereafter, plaintiffs appealed to the Ninth Circuit.  The appeal is fully briefed and we await further instruction from the Court.  We believe the plaintiffs’ suit lacks merit and we will continue to oppose their claims vigorously.
Shareholder Litigation Relating to the Proposed Blackstone Merger. In connection with the Merger Agreement, between August 13, 2010 and August 24, 2010, nineteen stockholder lawsuits were filed (one of which was subsequently voluntarily dismissed) in the District Courts of Harris County, Texas against Dynegy, its directors and Blackstone. Parent, Merger Sub, the guarantor, NRG and/or certain of Dynegy’s executive officers have also been named as defendants in certain of these lawsuits.  The remaining eighteen Texas state actions were consolidated on September 9, 2010 (the “Texas Actions”).  The First Amended Verified, Consolidated Class Action Petition and Request for a Temporary and Permanent Injunction was filed on September 21, 2010.

One stockholder derivative lawsuit was filed in a District Court in Harris County, Texas on September 16, 2010 (the “Derivative Action”).

Three stockholder lawsuits were filed against Dynegy, its directors, certain of its executive officers, Blackstone, Parent, Merger Sub and/or NRG in the United States District Court in the Southern District of Texas; the first was filed on August 31, 2010, the second was filed on September 16, 2010, and the third was filed on October 7, 2010 (collectively, the “Federal Actions”).

Six additional stockholder actions against Dynegy, its directors, Blackstone, Parent, Merger Sub, the guarantor and/or certain of our executive officers were filed in the Court of Chancery of the State of Delaware (the “Delaware Actions”) between August 17, 2010 and August 23, 2010, and were consolidated on August 24, 2010.  One of these lawsuits was voluntarily dismissed on August 23, 2010.  A Verified Amended Class Action Complaint was filed on September 23, 2010.

Each of the Texas and Delaware complaints generally alleges, among other things, that Dynegy’s board of directors and in certain cases, certain of Dynegy’s executive officers have violated various fiduciary duties.  The federal actions additionally allege violations of Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, as amended, and the Texas state court actions allege failure to disclose material information.  Further, certain of the complaints allege that Dynegy, Blackstone and/or NRG aided and abetted such alleged breaches of fiduciary duties.  The plaintiffs seek various remedies, including an injunction against the Blackstone Merger and/or the stockholder vote, corrective disclosure, declaratory relief with respect to the alleged breaches of fiduciary duty, and monetary damages including attorneys’ fees and expenses.

On November 7, 2010, we entered into a memorandum of understanding (the “MOU”) with plaintiffs in the Texas Actions and Delaware Actions regarding the settlement of the consolidated stockholder lawsuits filed in Texas state court and the consolidated stockholder lawsuits filed in the Delaware Court of Chancery.  The Company believes that no further supplemental disclosure is required under applicable laws; however, to avoid the risk of the litigation covered by the MOU delaying or adversely affecting the Merger and to minimize the expense of defending such actions, the Company has agreed, pursuant to the terms of the proposed settlement, to make certain supplemental disclosures related to the proposed Merger, all of which are set forth in the Supplement to Definitive Proxy Statement filed on November 8, 2010.  The settlement, including the payment of attorneys’ fees, is conditioned upon, among other things, execution of final settlement documents, court approval, and consummation of the Merger.  Expected costs associated with this proposed settlement have been accrued as of September 30, 2010.

The MOU does not resolve the Derivative Action or the Federal Actions.  All defendants deny any wrongdoing in connection with the Merger Agreement and plan to vigorously defend against these remaining pending claims.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Ordinary Course Litigation. In addition to the matters discussed above, we are party to numerous legal proceedings arising in the ordinary course of business or related to discontinued business operations.  In management’s judgment, which may prove to be materially inaccurate as indicated above, the disposition of these matters will not materially affect our financial condition, results of operations or cash flows.
Guarantees and Indemnifications
In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees.  Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales and procurement and construction contracts.  Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party.  Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false.  While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote.  Related to the indemnifications discussed below, we have accrued an aggregate of approximately $2 million as of September 30, 2010.
LS Power Indemnities. In connection with the LS Power Transactions we agreed in the purchase and sale agreement to indemnify LS Power against claims regarding any breaches in our representations and warranties and certain other potential liabilities.  Claims for indemnification shall survive until twelve months subsequent to closing with exceptions for tax claims, which shall survive for the applicable statute of limitations plus 30 days, and certain other representations and potential liabilities, which shall survive indefinitely.  The indemnifications provided to LS Power are limited to $1.3 billion in total; however, several categories of indemnifications are not available to LS Power until the liabilities incurred in the aggregate are equal to or exceed $15 million and are capped at a maximum of $100 million.  Further, the purchase and sale agreement provides in part that we may not reduce or avoid liability for a valid claim based on a claim of contribution.  In addition to the above indemnities related to the LS Power Transactions, we have agreed to indemnify LS Power against claims related to the Riverside/Foothills Project for certain aspects of the project.  Namely, LS Power has been indemnified for any disputes that arise as to ownership, transfer of bonds related to the project, and any failure by us to obtain approval for the transfer of the payment in-lieu of taxes program already in place.  The indemnities related solely to the Riverside/Foothills Project are capped at a maximum of $180 million and extend until the earlier of the expiration of the tax agreement or December 26, 2026.  At this time, we have incurred no significant expenses under these indemnities.
West Coast Power Indemnities. In connection with the sale of our 50 percent interest in West Coast Power to NRG on March 31, 2006, an agreement was executed to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation.  The indemnification agreement in relevant part provides that NRG assumes responsibility for all defense costs and any risk of loss, subject to certain conditions and limitations, arising from a February 2002 complaint filed at FERC by the California Public Utilities Commission alleging that several parties, including West Cost Power subsidiaries, overcharged the State of California for wholesale power.  FERC found the rates charged by wholesale suppliers to be just and reasonable.  However, this matter was appealed to the U.S. Supreme Court, which remanded the case to FERC for further review.
Targa Indemnities. During 2005, as part of our sale of our midstream business (“DMSLP”), we agreed to indemnify Targa Resources, Inc. (“Targa”) against losses it may incur under indemnifications DMSLP provided to purchasers of certain assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP.  We have incurred no material expense under these prior indemnities.  We have recorded an accrual in association with the remediation of groundwater contamination at the Breckenridge Gas Processing Plant.  The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million.  We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP.  We have recorded a tax reserve associated with this indemnification.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Illinois Power Indemnities. Dynegy has indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased natural gas and investments in specified items.  Although there is no absolute limitation on Dynegy’s liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses.  Dynegy has made certain payments in respect of these indemnities following regulatory action by the ICC, and has established reserves for further potential indemnity claims.  Further events, which fall within the scope of the indemnity, may still occur.  However, Dynegy is not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible.  Dynegy intends to contest any proposed regulatory actions.
Black Mountain Guarantee. Through one of our subsidiaries, we hold a 50 percent ownership interest in Black Mountain (Nevada Cogeneration) (“Black Mountain”), in which our partner is a Chevron subsidiary.  Black Mountain owns the Black Mountain power generation facility and has a power purchase agreement with a third party that extends through April 2023.  In connection with the power purchase agreement, pursuant to which Black Mountain receives payments which decrease in amount over time, we agreed to guarantee 50 percent of certain payments that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement.  At September 30, 2010, if an event of default due to early termination had occurred under the terms of the mortgage on the facility entered into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $55 million under the guarantee.
Other Indemnities. We entered into indemnifications regarding environmental, tax, employee and other representations when completing asset sales such as, but not limited, to the Rolling Hills, Calcasieu, CoGen Lyondell and Heard County power generating facilities.  As of September 30, 2010, no claims have been made against these indemnities.  There is no limitation on our liability under certain of these indemnities.  However, management is unaware of any existing claims.
Note 15—Employee Compensation, Savings and Pension Plans
We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate.  These plans are more fully described in Note 23—Employee Compensation, Savings and Pension Plans in our Form 10-K.
Components of Net Periodic Benefit Cost. The components of net periodic benefit cost were:
Pension Benefits Other Benefits
Three Months Ended September 30,
2010 2009 2010 2009
(in millions)
Service cost benefits earned during period
$ 2 $ 3 $ 1 $ 1
Interest cost on projected benefit obligation
4 3 1 1
Expected return on plan assets
(4 ) (3 ) — —
Recognized net actuarial loss
2 1 — —
Net periodic benefit cost
$ 4 $ 4 $ 2 $ 2
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Pension Benefits Other Benefits
Nine Months Ended September 30,
2010 2009 2010 2009
(in millions)
Service cost benefits earned during period
$ 8 $ 9 $ 2 $ 2
Interest cost on projected benefit obligation
11 9 3 3
Expected return on plan assets
(12 ) (10 ) — —
Recognized net actuarial loss
4 3 — —
Net periodic benefit cost
$ 11 $ 11 $ 5 $ 5
Contributions. During the nine months ended September 30, 2010, we made $18 million in contributions to our pension plans and other postretirement benefit plans.  We made $24 million in contributions to our pension plans and other postretirement benefit plans during the nine months ended September 30, 2009.  We expect to make total contributions of approximately $19 million to our pension plans and $2 million to other postretirement benefit plans during 2010.
Employee Compensation Plans. We have various employee compensation plans in which our current employees participate.  The stock awards granted under these plans will vest and be paid in cash if the Blackstone Merger is consummated.  Please read Note 2—Proposed Blackstone Merger and NRG Sale for additional information.  We expect to recognize expense related to these plans of approximately $22 million if the Blackstone Merger is consummated.  The expected expense related to these plans includes restricted stock awards, phantom stock awards and performance unit awards.
Note 16—Income Taxes
Effective Tax Rate . We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions.  Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs.  Dynegy’s income taxes included in continuing operations were as follows:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2010 2009 2010 2009
(in millions, except rates)
Income tax benefit
$ 17 $ 34 $ 80 $ 147
Effective tax rate
42 % 27 % 53 % 16 %
For the nine months ended September 30, 2010, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to a benefit of $18 million related to the release of reserves for uncertain tax positions, partly offset by the impact of state taxes.  For the nine months ended September 30, 2009, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to nondeductible goodwill.  Additionally, a change in state income tax law resulted in additional income tax expense of approximately $19 million.  As a result of the LS Power Transactions, we revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore we recorded valuation allowances resulting in additional state tax expense of $10 million for the nine months ended September 30, 2009.

DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
DHI’s income taxes included in continuing operations were as follows:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2010 2009 2010 2009
(in millions, except rates)
Income tax benefit
$ 15 $ 35 $ 71 $ 152
Effective tax rate
41 % 27 % 48 % 17 %
For the nine months ended September 30, 2010, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to a benefit of $12 million related to the release of reserves for uncertain tax positions, partly offset by the impact of state taxes.  For the nine months ended September 30, 2009, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to nondeductible goodwill.  Additionally, a change in state income tax law resulted in additional income tax expense of approximately $14 million.  As a result of the LS Power Transactions, we revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore we recorded valuation allowances resulting in additional state tax expense of $7 million for the nine months ended September 30, 2009.
Note 17—Capital Stock
At September 30, 2010, Dynegy had authorized capital stock consisting of 420,000,000 shares of common stock, $0.01 par value per share, and 20,000,000 of preferred stock, $0.01 per value per share.  As of September 30, 2010, there were no shares of preferred stock issued or outstanding.
Common Stock. On May 25, 2010, Dynegy effected a reverse stock split of its outstanding common stock at a ratio of 1-for-5 and proportionately decreased the number of authorized shares of its capital stock.  As a result, Dynegy’s authorized capital decreased from 2,100,000,000 shares of common stock to 420,000,000 shares of common stock and its issued and outstanding shares of common stock decreased on May 25, 2010 from 605,192,308 shares of common stock to 121,032,255 shares of common stock.
In addition, the December 31, 2009 condensed consolidated balance sheet was adjusted in this report to reflect the impact of the reverse stock split so that the basis of presentation is consistent.  As a result, Dynegy’s authorized capital was adjusted from 2,100,000,000 shares of common stock to 420,000,000 shares of common stock and its issued and outstanding shares of common stock as of December 31, 2009 was adjusted from 603,577,577 shares of common stock to 120,715,515 shares of common stock.
If the proposal to adopt the Merger Agreement is approved by Dynegy’s stockholders and the other closing conditions under the Merger Agreement have been satisfied or waived, each outstanding share of Dynegy common stock (except for shares owned by Parent, Merger Sub, Dynegy and their respective wholly owned subsidiaries and not held on behalf of third parties, and shares owned by stockholders who have properly demanded appraisal rights under applicable law) will be converted into the right to receive $4.50 in cash, without interest, less any applicable withholding taxes.  Dynegy will be the surviving corporation in the Blackstone Merger and will continue to do business following the Blackstone Merger.  As a result of the Blackstone Merger, Dynegy will cease to be a publicly traded company.  Both Parent and Merger Sub are affiliates of Blackstone.  Please read Note 2—Proposed Blackstone Merger and NRG Sale for further discussion.
Treasury Stock . As a result of the reverse stock split, the number of common stock shares of Dynegy held as treasury stock at May 25, 2010 decreased from 3,137,959 shares to 627,591 shares.  The condensed consolidated balance sheet was adjusted for all periods presented for the 1-for-5 reverse stock split.
In addition, the December 31, 2009 condensed consolidated balance sheet was adjusted in this report to reflect the impact of the reverse stock split so that the basis of presentation is consistent.  As a result, Dynegy’s shares of treasury stock as of December 31, 2009 was adjusted from 2,788,383 shares to 557,677 shares.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Note 18—Segment Information
We report results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE.  Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.
Reportable segment information for Dynegy, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2010 and 2009 is presented below:
Dynegy’s Segment Data as of and for the Three Months Ended September 30, 2010
(in millions)
Power Generation
GEN-MW GEN-WE GEN-NE Other Total
Unaffiliated revenues:
Domestic
$ 404 $ 140 $ 231 $ — $ 775
Total revenues
$ 404 $ 140 $ 231 $ — $ 775
Depreciation and amortization
$ (71 ) $ (17 ) $ (7 ) $ (1 ) $ (96 )
Impairment and other charges
— — (134 ) — (134 )
Operating income (loss)
$ 135 $ 61 $ (90 ) $ (56 ) $ 50
Other items, net
— — — 1 1
Interest expense
(92 )
Loss from continuing operations before income taxes
(41 )
Income tax benefit
17
Net loss
$ (24 )
Identifiable assets:
Domestic
$ 5,394 $ 2,318 $ 1,791 $ 1,618 $ 11,121
Total
$ 5,394 $ 2,318 $ 1,791 $ 1,618 $ 11,121
Capital expenditures
$ (59 ) $ (7 ) $ (1 ) $ (2 ) $ (69 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Dynegy’s Segment Data as of and for the Three Months Ended September 30, 2009
(in millions)
Power Generation
GEN-MW GEN-WE GEN-NE Other Total
Unaffiliated revenues:
Domestic
$ 391 $ 110 $ 174 $ (2 ) $ 673
Total revenues
$ 391 $ 110 $ 174 $ (2 ) $ 673
Depreciation and amortization
$ (57 ) $ (15 ) $ (8 ) $ (3 ) $ (83 )
Impairment and other charges
(147 ) — (1 ) — (148 )
Operating income (loss)
$ 5 $ 34 $ 1 $ (47 ) $ (7 )
Losses from unconsolidated investments
— (8 ) — — (8 )
Other items, net
— 1 — 1 2
Interest expense
( 115 )
Loss from continuing operations before income taxes
(128 )
Income tax benefit
34
Loss from continuing operations
(94 )
Loss from discontinued operations, net of taxes
(129 )
Net loss
(223 )
Less: Net loss attributable to the noncontrolling interests
( 11 )
Net loss attributable to Dynegy Inc.
$ (212 )
Identifiable assets:
Domestic
$ 6,703 $ 2,636 $ 2,027 $ 1,663 $ 13,029
Other
— — — (5 ) (5 )
Total
$ 6,703 $ 2,636 $ 2,027 $ 1,658 $ 13,024
Capital expenditures
$ (120 ) $ ( 2 ) $ (2 ) $ (2 ) $ (126 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Dynegy’s Segment Data as of and for the Nine Months Ended September 30, 2010
(in millions)
Power Generation
GEN-MW GEN-WE GEN-NE Other Total
Unaffiliated revenues:
Domestic
$ 953 $ 354 $ 565 $ — $ 1,872
Total revenues
$ 953 $ 354 $ 565 $ — $ 1,872
Depreciation and amortization
$ (184 ) $ (50 ) $ (23 ) $ (4 ) $ (261 )
Impairment and other charges
— — (135 ) — (135 )
Operating income (loss)
$ 230 $ 97 $ (56 ) $ (119 ) $ 152
Losses from unconsolidated investments
(34 ) — — — (34 )
Other items, net
— — 1 2 3
Interest expense
(272 )
Loss from continuing operations before income taxes
(151 )
Income tax benefit
80
Loss from continuing operations
(71 )
Income from discontinued operations, net of taxes
1
Net loss
$ (70 )
Identifiable assets:
Domestic
$ 5,394 $ 2,318 $ 1,791 $ 1,618 $ 11,121
Total
$ 5,394 $ 2,318 $ 1,791 $ 1,618 $ 11,121
Capital expenditures and investments in unconsolidated affiliates
$ (256 ) $ (17 ) $ (6 ) $ (6 ) $ (285 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Dynegy’s Segment Data as of and for the Nine Months Ended September 30, 2009
(in millions)

Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
Unaffiliated revenues:
Domestic
$ 1,085 $ 293 $ 652 $ (3 ) $ 2,027
Total revenues
$ 1,085 $ 293 $ 652 $ (3 ) $ 2,027
Depreciation and amortization
$ (165 ) $ (45 ) $ (39 ) $ (9 ) $ (258 )
Goodwill impairments
(76 ) (260 ) (97 ) — (433 )
Impairments and other charges , exclusive of goodwill impairments shown separately above
(147 ) — ( 388 ) — (535 )
Operating income (loss)
$ 143 $ (209 ) $ ( 424 ) $ (134 ) $ (624 )
Earnings from unconsolidated investments
— 12 — 1 13
Other items, net
2 3 — 5 10
Interest expense
(311 )
Loss from continuing operations before income taxes
(912 )
Income tax benefit
147
Loss from continuing operations
(765 )
Loss from discontinued operations, net of taxes
(141 )
Net loss
(906 )
Less: Net loss attributable to the noncontrolling interests
(14 )
Net loss attributable to Dynegy Inc.
$ (892 )
Identifiable assets:
Domestic
$ 6,703 $ 2,636 $ 2,027 $ 1,663 $ 13,029
Other
— — — (5 ) (5 )
Total
$ 6,703 $ 2,636 $ 2,027 $ 1,658 $ 13,024
Capital expenditures
$ ( 394 ) $ (10 ) $ (20 ) $ (5 ) $ (429 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2010 and 2009 is presented below:
DHI’s Segment Data as of and for the Three Months Ended September 30, 2010
(in millions)
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
Unaffiliated revenues:
Domestic
$ 404 $ 140 $ 231 $ — $ 775
Total revenues
$ 404 $ 140 $ 231 $ — $ 775
Depreciation and amortization
$ (71 ) $ (17 ) $ (7 ) $ (1 ) $ (96 )
Impairment and other charges
— — (134 ) — (134 )
Operating income (loss)
$ 135 $ 61 $ (90 ) $ (52 ) $ 54
Other items, net
— — — 1 1
Interest expense
(92 )
Loss from continuing operations before income taxes
(37 )
Income tax benefit
15
Net loss
$ (22 )
Identifiable assets:
Domestic
$ 5,394 $ 2,318 $ 1,791 $ 1,562 $ 11,065
Total
$ 5,394 $ 2,318 $ 1,791 $ 1,562 $ 11,065
Capital expenditures
$ (59 ) $ (7 ) $ (1 ) $ (2 ) $ (69 )

DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
DHI’s Segment Data as of and for the Three Months Ended September 30, 2009
(in millions)
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
Unaffiliated revenues:
Domestic
$ 391 $ 110 $ 174 $ (2 ) $ 673
Total revenues
$ 391 $ 110 $ 174 $ (2 ) $ 673
Depreciation and amortization
$ (57 ) $ (15 ) $ (8 ) $ (3 ) $ (83 )
Impairment and other charges
(147 ) — (1 ) — (148 )
Operating income (loss)
$ 5 $ 34 $ 1 $ (47 ) $ (7 )
Losses from unconsolidated investments
— (8 ) — — (8 )
Other items, net
— 1 — 1 2
Interest expense
( 115 )
Loss from continuing operations before income taxes
(128 )
Income tax benefit
35
Loss from continuing operations
(93 )
Loss from discontinued operations, net of taxes
(139 )
Net loss
(232 )
Less: Net loss attributable to the noncontrolling interests
( 11 )
Net loss attributable to Dynegy Holdings Inc.
$ (221 )
Identifiable assets:
Domestic
$ 6,703 $ 2,636 $ 2,027 $ 1,481 $ 12,847
Other
— — — (5 ) (5 )
Total
$ 6,703 $ 2,636 $ 2,027 $ 1,476 $ 12,842
Capital expenditures
$ (120 ) $ ( 2 ) $ (2 ) $ (2 ) $ (126 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009

DHI’s Segment Data as of and for the Nine Months Ended September 30, 2010
(in millions)
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
Unaffiliated revenues:
Domestic
$ 953 $ 354 $ 565 $ — $ 1,872
Total revenues
$ 953 $ 354 $ 565 $ — $ 1,872
Depreciation and amortization
$ (184 ) $ (50 ) $ (23 ) $ (4 ) $ (261 )
Impairment and other charges
— — (135 ) — (135 )
Operating income (loss)
$ 230 $ 97 $ (56 ) $ (115 ) $ 156
Losses from unconsolidated investments
(34 ) — — — (34 )
Other items, net
— — 1 2 3
Interest expense
(272 )
Loss from continuing operations before income taxes
(147 )
Income tax benefit
71
Loss from continuing operations
(76 )
Income from discontinued operations, net of taxes
1
Net loss
$ (75 )
Identifiable assets:
Domestic
$ 5,394 $ 2,318 $ 1,791 $ 1,562 $ 11,065
Total
$ 5,394 $ 2,318 $ 1,791 $ 1,562 $ 11,065
Capital expenditures and investments in unconsolidated affiliates
$ (256 ) $ (17 ) $ (6 ) $ (6 ) $ (285 )
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For the Interim Periods Ended September 30, 2010 and 2009
DHI’s Segment Data as of and for the Nine Months Ended September 30, 2009
(in millions)
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
Unaffiliated revenues:
Domestic
$ 1,085 $ 293 $ 652 $ (3 ) $ 2,027
Total revenues
$ 1,085 $ 293 $ 652 $ (3 ) $ 2,027
Depreciation and amortization
$ (165 ) $ (45 ) $ (39 ) $ (9 ) $ (258 )
Goodwill impairments
(76 ) (260 ) (97 ) — (433 )
Impairments and other charges , exclusive of goodwill impairments shown separately above
(147 ) — ( 388 ) — (535 )
Operating income (loss)
$ 143 $ (209 ) $ ( 424 ) $ (136 ) $ (626 )
Earnings from unconsolidated investments
— 12 — — 12
Other items, net
2 3 — 4 9
Interest expense
(311 )
Loss from continuing operations before income taxes
(916 )
Income tax benefit
152
Loss from continuing operations
(764 )
Loss from discontinued operations, net of taxes
(141 )
Net loss
(905 )
Less: Net loss attributable to the noncontrolling interests
(14 )
Net loss attributable to Dynegy Holdings Inc.
$ (891 )
Identifiable assets:
Domestic
$ 6,703 $ 2,636 $ 2,027 $ 1,481 $ 12,847
Other
— — — (5 ) (5 )
Total
$ 6,703 $ 2,636 $ 2,027 $ 1,476 $ 12,842
Capital expenditures
$ ( 394 ) $ (10 ) $ (20 ) $ (5 ) $ (429 )


DYNEGY INC. and DYNEGY HOLDINGS INC.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
For the Interim Periods Ended September 30, 2010 and 2009
The following discussion should be read together with the unaudited condensed consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Form 10-K.
We are holding companies and conduct substantially all of our business operations through our subsidiaries.  Our current business operations are focused primarily on the power generation sector of the energy industry.  We report the results of our power generation business as three separate segments in our consolidated financial statements: (i) the Midwest segment (“GEN-MW”); (ii) the West segment (“GEN-WE”); and (iii) the Northeast segment (“GEN-NE”).  Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.
Recent Developments
Proposed Blackstone Merger and NRG Sale. On August 13, 2010, Dynegy entered into the Merger Agreement with Parent and Merger Sub, providing for the Blackstone Merger, pursuant to which Dynegy will survive the Blackstone Merger as a wholly owned subsidiary of Parent. Parent and Merger Sub are affiliates of Blackstone.
Concurrently with the execution of the Merger Agreement, Merger Sub entered into the NRG PSA, pursuant to which NRG has agreed to, simultaneously with the closing of the Blackstone Merger, purchase and assume, and Merger Sub has agreed to sell and assign, or cause to be sold and assigned, to NRG, four natural gas-fired facilities and related assets currently owned by us – the Casco Bay facility in Maine and the Moss Landing, Morro Bay and Oakland facilities in California.
The DOJ and the FTC granted early termination of the waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 applicable to the Blackstone Merger and NRG Sale on September 7, 2010 and September 8, 2010, respectively.  Further, on October 29, 2010, FERC approved the joint applications related to the Blackstone Merger and NRG Sale.  Assuming timely receipt of the remaining required regulatory approvals and satisfaction of other closing conditions, including approval by Dynegy’s stockholders of the proposal to adopt the Merger Agreement for which a special meeting of stockholders is scheduled on November 17, 2010, we anticipate that the Blackstone Merger will be completed by the end of November 2010.  We cannot assure you that the conditions to the Blackstone Merger will be satisfied or that the Blackstone Merger will be consummated on the terms agreed, if at all.  Please read Note 2—Proposed Blackstone Merger and NRG Sale, for further discussion of the Blackstone Merger.
The consummation of the Blackstone Merger will result in amounts coming due under the Fifth Amended and Restated Credit Facility (the “Credit Facility”).  As a result, we expect to (i) repay or refinance indebtedness outstanding under the Credit Facility that will come due as a result of the Blackstone Merger (which we anticipate, based upon indebtedness outstanding as of September 30, 2010, will be approximately $918 million, consisting of an $850 million term letter of credit facility (“Term LC Facility”) and a $68 million senior secured term loan facility) and (ii) replace or refinance the letters of credit issued under the Term LC Facility (as of September 30, 2010, letters of credit issued under the Term LC Facility were approximately $453 million).  We anticipate the necessary funds will collectively be funded from cash on hand, restricted cash associated with the Term LC Facility and proceeds the surviving corporation of the Blackstone Merger receives in the NRG Sale of approximately $1.36 billion and funds otherwise provided by Parent (as of September 30, 2010, (i) Dynegy and DHI’s cash on hand was approximately $491 million and $457 million, respectively, and (ii) restricted cash associated with the Term LC Facility was approximately $850 million).
LIQUIDITY AND CAPITAL RESOURCES
Overview
In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources.  Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs.  Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll.
Our primary sources of internal liquidity are cash flows from operations, cash on hand, and available capacity under our Credit Facility, of which the revolver capacity of $1,080 million is scheduled to mature in April 2012 and the term letter of credit capacity of $850 million is scheduled to mature in April 2013.  However, using the latest available forward commodity price curves and considering our current hedging contracts, we project potential non-compliance with certain financial covenants contained in our Credit Facility based on forecast earnings as of June 30, 2011.  To avoid such non-compliance, if the Blackstone Merger is not consummated, we expect to proactively amend, extend or refinance the Credit Facility over the next six months.  Please read Revolver Capacity and Financial Covenants below for further discussion.  Secondarily, we expect to continue utilizing both lien-secured commodity hedging arrangements, which reduce collateral requirements, and spark spread-contingent liquidity facilities, which increase potential liquidity availability.  These internal liquidity sources, as they may be supplemented from time to time (including through the efforts regarding the Credit Facility described in more detail below under Revolver Capacity and Financial Covenants), are expected to be sufficient to fund the operation of our business, and potential requirements to post additional collateral, as well as our planned capital expenditure program, including expenditures in connection with the Midwest Consent Decree, and debt service requirements over the next twelve months.  Please read the discussion below regarding our Revolver Capacity, as well as Note 17—Debt—Credit Facility in our Form 10-K, for a further discussion of the financial covenants contained in the Credit Facility.
Our primary sources of external liquidity are asset sales proceeds and proceeds from capital market transactions to the extent we engage in these transactions.  If the Blackstone Merger is not consummated, capital-structuring transactions, additional capital markets transactions and/or asset sales will be considered.  Please read Capital Structuring Transactions and Asset Dispositions below for more detail.
Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at November 1, 2010, September 30, 2010 and December 31, 2009:
November 1,
2010
September 30,
2010
December 31,
2009
(in millions)
Revolver capacity (1) (2)
$ 1, 027 $ 1,027 $ 1,080
Borrowings against revolver capacity
— — —
Term letter of credit capacity, net of required reserves
825 825 825
Plum Point letter of credit capacity (3)
— — 102
Available contingent letter of credit facility capacity (4)
— — —
Outstanding letters of credit (3)
( 484
) (453 ) (536 )
Unused capacity
1,368 1,399 1,471
Cash—DHI
468
457 419
Short-term investments—DHI (5)
120
163 —
Total available liquidity—DHI
1,956 2,019 1,890
Cash—Dynegy
43
34 52
Short-term investments—Dynegy (5)
13
19 —
Total available liquidity—Dynegy
$ 2,012 $ 2,072 $ 1,942
(1)
We currently have a syndicate of lenders participating in the revolving portion of our Credit Facility with commitments ranging from $30 million to $165 million.
(2)
As of September 30, 2010, DHI’s available liquidity under the Credit Facility was reduced by $53 million as a result of borrowing limitations under the covenant regarding the ratio of secured debt to Adjusted EBITDA.  Although our available liquidity is reduced, we have adequate liquidity to meet expected needs for the remainder of this quarter.  Further reduction in capacity may occur based on our ratio of secured debt to Adjusted EBITDA at December 31, 2010.
(3)
Reflects the reduction of $102 million of capacity and corresponding outstanding letters of credit as of January 1, 2010 due to the deconsolidation of PPEA Holding.  Please read Note 1—Accounting Policies —Accounting Policies Adopted—Variable Interest Entities for further discussion.
(4)
Under the terms of the Contingent LC Facility, up to $150 million of capacity can become available, contingent on changes in forward spark spreads and power prices for 2012.
(5)
We invest our available cash balances in certain investments permitted by our internal policies and external financing agreements.  Please read Note 1—Accounting Policies—Short-Term Investments and Note 5—Investments for further discussion.
Cash on Hand. At November 1, 2010 and September 30, 2010, Dynegy had cash on hand of $511 million and $491 million, respectively, as compared to $471 million at December 31, 2009.  At November 1, 2010 and September 30, 2010, DHI had cash on hand of $468 million and $457 million respectively, as compared to $419 million at December 31, 2009.  The increase in cash on hand through November 1, 2010 and September 30, 2010 as compared to the end of 2009 is primarily attributable to cash provided by operating activities and the return of cash that was held in our Broker margin account, partially offset by net purchases of short term investments and capital expenditures.
Revolver Capacity. DHI’s available liquidity under the Credit Facility was reduced by $53 million as of September 30, 2010 as a result of borrowing limitations under the covenant regarding the ratio of secured debt to Adjusted EBITDA (as defined therein).  The effect of reduced availability under the Credit Facility is less available liquidity to DHI.  Further reduction in capacity may occur at December 31, 2010.  Using the latest available forward commodity price curves and considering our current hedging contracts, we project potential covenant non-compliance specifically relating to our Adjusted EBITDA to Interest Expense covenant based on forecast earnings as of June 30, 2011.  In such event, the Credit Facility may be terminated by the lenders and outstanding amounts thereunder accelerated.  Please read Financial Covenants for more information.  If the Blackstone Merger is not consumated, we will seek to proactively amend, extend or refinance the Credit Facility within the next six months.  We expect the capacity of any amended or new credit facility to be less than the current capacity of $1.9 billion and to be at a higher cost.  The timing of any amendment, extension, or refinancing of the Credit Facility would be accelerated by the closing of the Blackstone Merger, upon which amounts come due and payable under our Credit Facility.  Please read Recent Developments—Proposed Blackstone Merger and NRG Sale and Note 17—Debt—Credit Facility in our Form 10-K for further discussion.
Capital Structuring Transactions. The Merger Agreement limits our ability to participate in certain capital structuring transactions and, if completed, the Blackstone Merger would limit Dynegy’s ability to publicly issue equity as a capital-raising option.  Please read Recent Developments—Proposed Blackstone Merger and NRG Sale for additional information.  However, if the Blackstone Merger is not consummated, we expect to pursue in the near-term additional sources of external liquidity, including asset sales, public or private issuances of debt, equity, debt for equity swaps, equity-linked securities, or a combination of these, to supplement our liquidity position and/or better position our operating portfolio relative to the declining forward commodity curves.  Matters to be considered include depressed or dilutive prices for assets, cash interest expense, covenant flexibility and compliance and maturity profile, all to be balanced with an attempt to maintain adequate liquidity.  The receptiveness of the traditional capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our non-investment grade credit ratings, significant debt maturities, business prospects and other factors beyond our control, including current and projected market conditions.  Any issuance of equity by Dynegy likely would have other effects as well, including stockholder dilution, and our ability to issue debt securities may be limited by our financing agreements, including our Credit Facility.
Operating Activities
Historical Operating Cash Flows. Dynegy’s and DHI’s cash flow provided by operations totaled $670 million for the nine months ended September 30, 2010.  During the period, our power generation business provided positive cash flow from operations of $992 million from the operation of our power generation facilities, primarily reflecting positive earnings for the period and approximately $353 million of cash received from our futures clearing manager.  The receipt of this cash is partly due to lower commodity prices and a reduction of margin requirements; the remaining cash was returned as a result of the posting of short-term investments and a letter of credit in substitute of cash.  Corporate and other operations included a use of approximately $322 million in cash by both Dynegy and DHI, primarily due to interest payments to service debt and general and administrative expenses.
Dynegy’s cash flow provided by operations totaled $304 million for the nine months ended September 30, 2009.  DHI’s cash flow provided by operations totaled $322 million for the nine months ended September 30, 2009.  During the period, our power generation business provided positive cash flow from operations of $683 million from the operation of our power generation facilities.  Cash provided by the operations of our power generation facilities was partly offset by a $160 million increase in collateral postings, excluding the effect of cash inflows and outflows arising from the daily settlements of our exchange-traded or brokered commodity futures positions held with our futures clearing manager.  Corporate and other operations included a use of approximately $379 million and $361 million in cash by Dynegy and DHI, respectively, primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income.  Dynegy’s operating cash flow also reflected the payment of $19 million to LS Associates in conjunction with the dissolution of DLS Power Holdings and DLS Power Development.
Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the price of natural gas and its correlation to power prices, the cost of coal and fuel oil, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, our ability to achieve the cost savings contemplated in our 2010-2013 cost reduction program and the level of our ability to capture value associated with commodity price volatility.  If the NRG Sale is consummated, our future operating cash flows will be reduced by the loss of cash flows from the assets sold to NRG.  Using current forward commodity price curves, our future operating cash flows are likely to decline materially.
Collateral Postings. We use a significant portion of our capital resources, in the form of cash, short-term investments and letters of credit, to satisfy counterparty collateral demands.  These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.  The following table summarizes our consolidated collateral postings to third parties by business at November 1, 2010, September 30, 2010 and December 31, 2009:
November 1,
2010
September 30,
2010
December 31,
2009
(in millions)
By Business :
Generation
$
482
$ 469 $ 637
Other (1)
88
88 190
Total
$
570
$ 557 $ 827
By Type :
Cash and short-term investments (2)
$
86
$ 104 $ 291
Letters of credit (1)
484
453 536
Total
$
570
$ 557 $ 827
(1)
November 1, 2010 and September 30, 2010 reflect the reduction of $102 million of capacity and corresponding outstanding letters of credit due to the deconsolidation of PPEA Holding.  Please read Note 1—Accounting Policies —Accounting Policies Adopted—Variable Interest Entities for further discussion.
(2)
Includes Collateral included in Broker margin account on our consolidated balance sheets at November 1, 2010 , September 30, 2010 and December 31, 2009, respectively, as well as other collateral postings included in Prepayments and other current assets.
The change in letters of credit postings from December 31, 2009 to September 30, 2010 and to November 1, 2010 is related to a $102 million decrease due to the removal of the PPEA letter of credit as a result of the deconsolidation of PPEA Holding and lower commodity prices offset by an increase resulting from a $75 million letter of credit posted with our broker in substitute of cash.  Collateral postings of cash and short-term investments also decreased due to the letters of credit posted with our broker noted above, lower commodity prices and a reduction of margin requirements.
In addition to cash and letters of credit posted as collateral, we have granted additional permitted first priority liens on the assets currently subject to first priority liens under our Credit Facility as collateral under certain of our commodity derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements.  The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under the Credit Facility.  The fair value of our commodity derivatives collateralized by first priority liens, netted by counterparty, included liabilities of $17 million, $33 million and $31 million at November 1, 2010 , September 30, 2010 and December 31, 2009, respectively.
Going forward, we expect counterparties’ collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness.  We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for the foreseeable future.
Investing Activities
Capital Expenditures. We continue to tightly manage our operating costs and capital expenditures.  We had approximately $270 million and $429 million in capital expenditures during the nine months ended September 30, 2010 and 2009.  Our capital spending by reportable segment was as follows:
For the Nine Months Ended
September 30,
2010
2009
(in millions)
GEN-MW
$ 241 $ 394
GEN-WE
17 10
GEN-NE
6 20
Other
6 5
Total
$ 270 $ 429
Capital spending in our GEN-MW segment primarily consisted of environmental and maintenance capital projects, as well as approximately $66 million spent on development capital related to the Plum Point Project during the nine months ended September 30, 2009.  Capital spending in our GEN-WE and GEN-NE segments primarily consisted of maintenance projects.
Asset Dispositions. Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure, market recovery expectations, regulatory or legislative risks and cash flows.  We consider divestitures of assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the benefits that can be captured through a divestiture outweigh the benefits of continuing to own and operate such assets.  We have previously indicated that we consider our investment in PPEA Holding a non-core asset and have entered an agreement to sell our interest in such project, which sale is expected to close in the fourth quarter 2010, subject to receipt of required regulatory approvals and satisfaction of closing conditions.  The financial impact of the sale of our investment in PPEA Holding is expected to be immaterial.  If the Blackstone Merger is not consummated, additional asset divestures will be considered to supplement our liquidity position.
On August 13, 2010, Dynegy entered into the Merger Agreement which provides that Merger Sub will merge with and into Dynegy. Dynegy will be the surviving corporation and will continue to do business following the Blackstone Merger.  Concurrently with the execution of the Merger Agreement, Merger Sub and NRG entered into the NRG PSA pursuant to which NRG will purchase four of our natural gas-fired assets. Please read Recent Developments—Proposed Blackstone Merger and NRG Sale for further discussion.
On April 30, 2009, we completed our sale of the Heard County power generation facility to Oglethorpe for approximately $105 million, net of transaction costs.
Other Investing Activities. Cash outflow related to purchases of short-term investments during the nine months ended September 30, 2010 totaled $428 million and $406 million for Dynegy and DHI, respectively.  Cash inflow related to distributions from short-term investments for the nine months ended September 30, 2010 totaled $152 million and $149 million for Dynegy and DHI, respectively.  There was a $53 million cash outflow related to restricted cash balances during the nine months ended September 30, 2010, primarily due to an increase in the Independence restricted cash balance.  There was a $15 million cash outflow related to our funding commitment obligation under the PPEA Sponsor Support Agreement.
Cash inflow related to short-term investments during the nine months ended September 30, 2009 totaled $14 million and $13 million for Dynegy and DHI, respectively, reflecting a distribution from our short-term investments.  There was a $35 million cash outflow during the nine months ended September 30, 2009 for both Dynegy and DHI, related to changes in restricted cash balances.  Other included $3 million of insurance proceeds.
Financing Activities
Historical Cash Flow from Financing Activities. Dynegy’s and DHI’s net cash used in financing activities during the nine months ended September 30, 2010 totaled $36 million due to $31 million of repayments of borrowings on our Sithe senior debt and $5 million of financing fees.
Dynegy’s net cash provided by financing activities during the nine months ended September 30, 2009 totaled $47 million, primarily related to $91 million of proceeds from long-term borrowings under the Plum Point Credit Agreement Facility, partly offset by a $28 million principal payment on our 9.00 percent secured bonds due 2013 and $14 million of financing fees related to the Credit Facility Amendment No. 4.  DHI’s net cash used in financing activities during the nine months ended September 30, 2009 totaled $128 million.  This included a one-time dividend payment from DHI to Dynegy of $175 million, a $28 million principal payment on our 9.00 percent secured bonds due 2013 and $14 million of financing fees related to the Credit Facility Amendment No. 4 offset by $91 million of proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.
Future Financing Activities. The revolver capacity under our Credit Facility is scheduled to mature in April 2012, and the term loan capacity is scheduled to mature in April 2013.  In order to prudently provide for adequate long-term liquidity to support our business, and to avoid any potential covenant non-compliance under such facilities, within the next six months, we expect to seek to proactively amend, extend or refinance these facilities in advance of their scheduled maturities.  We expect the capacity of any amended or new credit facility to be less than the current capacity of $1.9 billion and to be at a higher cost.  The timing of any amendment, extension, or refinancing of these facilities would be accelerated by the closing of the Blackstone Merger, upon which amounts come due and payable under our Credit Facility.  Please read Recent Developments—Proposed Blackstone Merger and NRG Sale for additional information.  Absent the closing of the Blackstone Merger, we expect to pursue the aforementioned refinancing in the near-term, with the exact timing and the likelihood of success of any amendment, extension or refinancing of these facilities depends on a variety of factors, including general market receptiveness, commodity prices and any changes in our forecasts regarding our continued compliance with the existing Credit Facility financial covenants.  There can be no assurance that such activity will result in amended, extended or refinanced facilities or as to our ability to continue to satisfy the covenants contained in such facilities in the absence of such amendment, extension or refinancing thereof.
Financing Trigger Events. Our debt instruments and other financial obligations include provisions which, if not met, could require early payment, additional collateral support or similar actions.  These trigger events include the potential violation of financial covenants, including the Interest Coverage Ratio discussed below, insolvency events, defaults on scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions.  The Blackstone Merger, if consummated, will result in amounts coming due under the Credit Facility.  We do not have any trigger events tied to specified Dynegy or DHI credit ratings or Dynegy’s stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.
Financial Covenants. Our Credit Facility contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter) that requires DHI and certain of its subsidiaries to maintain a ratio of secured debt to Adjusted EBITDA (each as defined therein) for DHI and its relevant subsidiaries of no greater than a specified amount; and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of Adjusted EBITDA to Interest Expense (each as defined therein) for DHI and its relevant subsidiaries as of the last day of the measurement periods as specified below of no less than a specified amount.  We are in compliance with these covenants as of September 30, 2010.  Please read “Revolver Capacity” above for further discussion.
As of September 30, 2010, DHI’s available liquidity under the Credit Facility was reduced by $53 million as a result of borrowing limitations under the covenant regarding the ratio of secured debt to Adjusted EBITDA.  Further reduction in capacity may occur at December 31, 2010.
Depressed power prices and commodity price volatility will make covenant compliance more difficult to meet absent an improving trend in demand for power and/or commodity market pricing and consequent financial performance, particularly as the Adjusted EBITDA to Interest Expense covenant ratio requirements increase over the course of 2011 and into 2012.  Using the latest available forward commodity price curves and considering our current hedging contracts, we project potential covenant non-compliance based on forecast earnings as of June 30, 2011.  A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements could result in reduced borrowing capacity or even a default, causing our debt obligations under such financing agreements (and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable.  If we are unable to cure any such default, obtain a waiver or a replacement financing, and those lenders accelerate the payment of such indebtedness, in the case that we are unable to repay those amounts, the holders of the indebtedness under our secured debt obligations would be entitled to foreclose on, and acquire control of substantially all of our assets, which would have a material adverse impact on our financial condition, results of operations and cash flows.  However, as discussed in “Future Financing Activities” above, within the next six months we expect to seek to proactively amend, extend or refinance the Credit Facility, including any prudent potential modifications to existing financial covenants, to the extent we deem it advisable or necessary.  We expect the capacity of any amended or new credit facility to be less than the current capacity of $1.9 billion and to be at a higher cost.  The timing of any amendment, extension, or refinancing of these facilities would be accelerated by the closing of the Blackstone Merger, upon which amounts come due and payable under our Credit Facility.  There can be no assurance that such activity will result in amended, extended or refinanced facilities or as to our ability to continue to satisfy the covenants contained in such facilities in the absence of such amendments, extension or refinancing thereof.
Subject to certain exceptions, DHI and its relevant subsidiaries are subject to restrictions on asset sales, incurring additional indebtedness, limitations on investments and certain limitations on dividends and other payments with respect to capital stock.  Please read Note 17—Debt—Credit Facility in our Form 10-K for further discussion of our Credit Facility.
Dividends and Dynegy Common Stock. Dividend payments on Dynegy’s common stock are at the discretion of its Board of Directors and subject to limits contained in our Credit Facility and applicable law.  Dynegy did not declare or pay a dividend on its common stock during the third quarter 2010, and does not expect to pay a dividend on its common stock in the foreseeable future.  Upon consummation of the Blackstone Merger, Dynegy will cease to be a publicly traded company.
Credit Ratings
Our credit rating status is currently “non-investment grade”; our senior unsecured debt is rated “B-” by Standard & Poor’s, “Caa2” by Moody’s, and “B” by Fitch.  On April 12, 2010, Standard & Poor’s downgraded our corporate family ratings to “B-” from “B” based on projected lower commodity prices affecting credit metrics.  The agency also reduced our senior secured bank facilities rating to “B+” from “BB-”, and senior unsecured debt rating to “B-” from “B”.  On October 1, 2010, Moody’s issued a rating action to conclude their prior review.  The corporate family rating was downgraded to “Caa1”; the senior secured rating downgraded to “B1”; and the senior unsecured rating was confirmed at “Caa2.”  The downgrades did not trigger any obligations under our financing arrangements or other obligations and otherwise have not tangibly impacted our operations or liquidity.  The Moody’s rating outlook for Dynegy and DHI is negative.
Disclosure of Contractual Obligations and Contingent Financial Commitments
We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.  Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees.
PPEA Holding was deconsolidated on January 1, 2010 upon adoption of ASU No. 2009-17, which resulted in the deconsolidation of $744 million of debt obligations.  Please read Note 1—Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.  As of September 30, 2010, there were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2009.
Please read “Uncertainty of Forward-Looking Statements and Information” for additional factors that could impact our future operating results and financial condition.

RESULTS OF OPERATIONS—DYNEGY INC. and DYNEGY HOLDINGS INC.
Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three- and nine- month periods ended September 30, 2010 and 2009.  At the end of this section, we have included our outlook for each segment.
We report the results of our power generation business as three separate geographical segments in our unaudited condensed consolidated financial statements.  Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.
Three Months Ended September 30, 2010 and 2009
Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the three month periods ended September 30, 2010 and 2009, respectively:
Dynegy’s Results of Operations for the Three Months Ended September 30, 2010
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 404 $ 140 $ 231 $ — $ 775
Cost of sales
(149 ) (42 ) (143 ) — (334 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(49 ) (20 ) (37 ) (4 ) (110 )
Depreciation and amortization expense
(71 ) (17 ) (7 ) (1 ) (96 )
Impairment and other charges
— — (134 ) — (134 )
General and administrative expense
— — — (51 ) (51 )
Operating income (loss)
$ 135 $ 61 $ (90 ) $ (56 ) $ 50
Other items, net
— — — 1 1
Interest expense
(92 )
Loss from continuing operations before income taxes
(41 )
Income tax benefit
17
Net loss
$ (24 )
Dynegy’s Results of Operations for the Three Months Ended September 30, 2009
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 391 $ 110 $ 174 $ (2 ) $ 673
Cost of sales
(129 ) (36 ) (121 ) — (286 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(53 ) (25 ) (43 ) — (121 )
Depreciation and amortization expense
(57 ) (15 ) (8 ) (3 ) (83 )
Impairment and other charges
(147 ) — (1 ) — (148 )
General and administrative expense
— — — (42 ) (42 )
Operating income (loss)
$ 5 $ 34 $ 1 $ (47 ) $ (7 )
Losses from unconsolidated investments
— (8 ) — — (8 )
Other items, net
— 1 — 1 2
Interest expense
(115 )
Loss from continuing operations before income taxes
(128 )
Income tax benefit
34
Loss from continuing operations
(94 )
Loss from discontinued operations, net of taxes
(129 )
Net loss
(223 )
Less: Net loss attributable to the noncontrolling interests
(11 )
Net loss attributable to Dynegy Inc.
$ (212 )
The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the three month periods ended September 30, 2010 and 2009, respectively:
DHI’s Results of Operations for the Three Months Ended September 30, 2010
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 404 $ 140 $ 231 $ — $ 775
Cost of sales
(149 ) (42 ) (143 ) — (334 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(49 ) (20 ) (37 ) (4 ) (110 )
Depreciation and amortization expense
(71 ) (17 ) (7 ) (1 ) (96 )
Impairment and other charges
— — (134 ) — (134 )
General and administrative expense
— — — (47 ) (47 )
Operating income (loss)
$ 135 $ 61 $ (90 ) $ (52 ) $ 54
Other items, net
— — — 1 1
Interest expense
(92 )
Loss from continuing operations before income taxes
(37 )
Income tax benefit
15
Net loss
$ (22 )
DHI’s Results of Operations for the Three Months Ended September 30, 2009
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 391 $ 110 $ 174 $ (2 ) $ 673
Cost of sales
(129 ) (36 ) (121 ) — (286 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(53 ) (25 ) (43 ) — (121 )
Depreciation and amortization expense
(57 ) (15 ) (8 ) (3 ) (83 )
Impairment and other charges
(147 ) — (1 ) — (148 )
General and administrative expense
— — — (42 ) (42 )
Operating income (loss)
$ 5 $ 34 $ 1 $ (47 ) $ (7 )
Losses from unconsolidated investments
— (8 ) — — (8 )
Other items, net
— 1 — 1 2
Interest expense
(115 )
Loss from continuing operations before income taxes
(128 )
Income tax benefit
35
Loss from continuing operations
(93 )
Loss from discontinued operations, net of taxes
(139 )
Net loss
(232 )
Less: Net loss attributable to the noncontrolling interests
(11 )
Net loss attributable to Dynegy Holdings Inc.
$ (221 )
The following table provides summary segmented operating statistics for the three months ended September 30, 2010 and 2009, respectively:
Three Months Ended
September 30,
2010
2009
GEN-MW
Million Megawatt Hours Generated (1) (2)
7.4 6.6
In Market Availability for Coal Fired Facilities (3)
91 % 92 %
Average Capacity Factor for Combined Cycle Facilities (4)
41 % 38 %
Average Quoted On-Peak Market Power Prices ($/MWh) (5):
Cinergy (CIN Hub)
$ 48 $ 31
Commonwealth Edison (NI Hub)
$ 49 $ 31
PJM West
$ 65 $ 40
Average Market Spark Spreads ($/MWh) (6):
PJM West
$ 33 $ 16
GEN-WE
Million Megawatt Hours Generated (7) (8)
1.1 2.4
Average Capacity Factor for Combined Cycle Facilities (4)
32 % 56 %
Average Quoted On-Peak Market Power Prices ($/MWh) (5):
North Path 15 (NP 15)
$ 39 $ 38
Average Market Spark Spreads ($/MWh) (6):
North Path 15 (NP 15)
$ 8 $ 12
GEN-NE
Million Megawatt Hours Generated
3.0 2.6
In Market Availability for Coal Fired Facilities (3)
96 % 95 %
Average Capacity Factor for Combined Cycle Facilities (4)
65 % 44 %
Average Quoted On-Peak Market Power Prices ($/MWh) (5):
New York—Zone G
$ 70 $ 44
New York—Zone A
$ 53 $ 29
Mass Hub
$ 66 $ 37
Average Market Spark Spreads ($/MWh) (6):
New York—Zone A
$ 19 $ 4
Mass Hub
$ 34 $ 13
Fuel Oil
$ (59 ) $ (72 )
Average natural gas price—Henry Hub ($/MMBtu) (9)
$ 4.28 $ 3.15
(1)
Excludes less than 0.1 million MWh generated by our former Bluegrass power generation facility, which we sold on November 30, 2009 and is reported in discontinued operations for the three months ended September 30, 2009.
(2)
Includes 0.1 MWh related to our ownership percentage in the MWh generated by our GEN-MW investment in the Plum Point power generation facility for the three months ended September 30, 2010.
(3)
Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.
(4)
Reflects actual production as a percentage of available capacity.  Excludes the Arizona power generation facilities which are reported as discontinued operations with respect to the GEN-WE segment, for all periods presented.  For the 2009  period presented, includes the Tilton, Rocky Road, Riverside and Renaissance power generation facilities with respect to the GEN-MW segment and the Bridgeport power generation facility with respect to the GEN-NE segment.
(5)
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realize.
(6)
Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.
(7)
Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the three months ended September 30, 2010 and 2009, respectively.
(8)
Excludes less than 1.6 million MWh generated by our Arizona power generation facilities, which we sold on November 30, 2009, and are reported in discontinued operations for the three months ended September 30, 2009.
(9)
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
The following tables summarize significant items on a pre-tax basis, with the exception of the tax items, affecting net loss for the period presented:
Three Months Ended September 30, 2010
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Merger Agreement transaction costs
$ — $ — $ — $ (10 ) $ (10 )
Impairment
— — (134 ) — (134 )
Total
$ — $ — $ (134 ) $ (10 ) $ (144 )

Three Months Ended September 30, 2009
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Impairments (1)
$ (147 ) $ (235 ) $ (1 ) $ — $ (383 )
Total
$ (147 ) $ (235 ) $ (1 ) $ — $ (383 )
(1)
Includes $235 million of impairment charges related to our Arizona power generation facilities which are included in discontinued operations.
Operating Income (Loss)
Dynegy’s and DHI’s operating income was $50 million and $54 million, respectively, for the three months ended September 30, 2010, compared to an operating loss of $7 million for each of the three months ended September 30, 2009.
Our operating income for the three months ended September 30, 2010 includes a pre-tax asset impairment of $134 million related to our Casco Bay power generation facility and related assets.  Our operating loss for the three months ended September 30, 2009 includes $148 million of asset impairments.  Please read Note 8—Impairment Charges for further discussion.
Mark-to-market gains on forward sales of power and other derivatives associated with our generating assets are included in Revenues in the unaudited consolidated statements of operations.  Such gains totaled $132 million for the three months ended September 30, 2010, compared to $122 million of mark-to-market losses for the three months ended September 30, 2009.  The gains in 2010 reflect an increase in the value of positions due to decreasing forward market prices during the period compared to the immediately preceding period.  The losses in 2009 reflect a loss from the settlement of risk management positions that matured during the period, partially offset by an increase in the value of positions due to decreasing forward market prices during the period compared to the immediately preceding period.
Power Generation—Midwest Segment. Operating income for GEN-MW was $135 million for the three months ended September 30, 2010, compared to income of $5 million for the three months ended September 30, 2009.  The amounts for the three months ended September 30, 2009 do not include results from the Bluegrass power generating facility, which is included in discontinued operations.  Operating income for the three months ended September 30, 2009 included a pre-tax charge of approximately $147 million for the impairment of the Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities and related assets, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations.
Revenues for the three months ended September 30, 2010 increased by $13 million compared to the three months ended September 30, 2009, cost of sales increased by $20 million and operating and maintenance expense decreased by $4 million, resulting in a net decrease of $3 million.  The decrease was primarily driven by the following:
●
Energy sales – GEN-MW’s results from energy sales, including both physical and financial transactions, decreased from $238 million for the three months ended September 30, 2009 to $130 million for the three months ended September 30, 2010.  The contribution from physical transactions was higher primarily as a result of higher power prices at our coal-fired facilities and improved spark spreads at our combined cycle facilities.  These increases were more than offset by reduced contribution from financial transactions,  as well as the impact of a $50 million payment received in the three months ended September 30, 2009 to assign our rights under a power sales agreement to a third party; and
●
Decreased tolling/capacity revenues of $34 million – Tolling/capacity revenues decreased $15 million as a result of the sale of assets in the fourth quarter 2009 and $19 million primarily due to lower prices for MISO capacity and the early termination of our Kendall tolling contract.  These decreases were partially offset by increases from higher prices for PJM capacity.
These items were partly offset by the following:
●
Mark-to-market gains – GEN-MW’s results for the three months ended September 30, 2010 included mark-to-market gains of $90 million related to forward sales and other derivative contracts, compared to $44 million of mark-to-market losses for the three months ended September 30, 2009.  Of the $90 million in 2010 mark-to-market gains, $15 million related to positions that settled or will settle in 2010, and the remaining $75 million related to positions that will settle in 2011 and beyond; and
●
Decreased operating and maintenance expenses – operating and maintenance expenses decreased from $53 million for the three months ended September 30, 2009 to $49 million for the three months ended September 30, 2010, primarily as a result of the sale of certain Midwest assets to LS Power in the fourth quarter 2009.
Depreciation expense increased from $57 million for the third quarter 2009 to $71 million for the third quarter 2010 primarily as a result of accelerating the depreciation of our Vermilion facility, as we do not currently expect the facility to continue to operate beyond the second quarter 2011.  The impact of additional depreciation related to capital projects associated with the Midwest Consent Decree was largely offset by the impact of reduced depreciation resulting from the sale of assets in 2009.
Power Generation—West Segment. Operating income for GEN-WE was $61 million for three months ended September 30, 2010, compared to $34 million for the three months ended September 30, 2009.  The amounts for the three months ended September 30, 2009 do not include results from the Arizona and Heard County power generating facilities, which are included in discontinued operations.
Revenues for the three months ended September 30, 2010 increased by $30 million compared to the three months ended September 30, 2009, cost of sales increased by $6 million and operating and maintenance expense decreased by $5  million, resulting in a net increase of $29 million.  The increase was primarily driven by the following:
●
Mark-to-market gains – GEN-WE’s results for the three months ended September 30, 2010 included mark-to-market gains of $22 million related to forward sales and other derivative contracts, compared to $33 million of mark-to-market losses for the three months ended September 30, 2009.  The $22 million in 2010 mark-to-market gains relates to positions that will settle in 2011 and beyond; and
●
Decreased operating and maintenance expenses – operating and maintenance expenses decreased from $25 million for the three months ended September 30, 2009 to $20 million for the three months ended September 30, 2010, primarily as a result of the retirement of two units at our South Bay facility and lower outage expenses.
These items were partly offset by the following:
●
Energy sales – GEN-WE’s results from energy sales, including both physical and financial transactions, decreased from $32 million for the three months ended September 30, 2009 to $14 million for the three months ended September 30, 2010.  The contribution from physical transactions was lower primarily as a result of reduced spark spreads and a forced outage.  The contribution from financial transactions also decreased; and
●
Decreased tolling/RMR revenues of $13 million – Tolling/RMR revenues decreased primarily as a result of the timing of payments under our 2009 South Bay facility tolling contract compared to the rateable RMR payment received for South Bay in 2010 and lower variable revenues at Moss Landing.
Depreciation expense increased from $15 million for the third quarter 2009 to $17 million for the third quarter 2010 as a result of capital projects placed into service.
Power Generation—Northeast Segment. Operating loss for GEN-NE was $90 million for the three months ended September 30, 2010, compared to operating income of $1 million for the three months ended September 30, 2009.  Operating loss for the three months ended September 30, 2010 includes a pre-tax charge of approximately $134 million for the impairment of our Casco Bay facility and related assets, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations.  Please read Note 8—Impairment Charges for further discussion.
Revenues for the three months ended September 30, 2010 increased by $57 million compared to the three months ended September 30, 2009, cost of sales increased by $22 million and operating and maintenance expense decreased by $6 million, resulting in a net increase of $41 million.  The increase was primarily driven by the following:
●
Mark-to-market gains – GEN-NE’s results for the three months ended September 30, 2010 included mark-to-market gains of $20 million related to forward sales and other derivative contracts, compared to losses of $45 million for the three months ended September 30, 2009.  Of the $20 million in 2010 mark-to-market gains, $3 million related to positions that settled or will settle in 2010, and the remaining $17 million related to positions that will settle in 2011 and beyond; and
●
Decreased operating and maintenance expenses – Operating and maintenance expenses decreased from $43 million for the three months ended September 30, 2009 to $37 million for the three months ended September 30, 2010 as a result of the sale of the Bridgeport facility in the fourth quarter 2009 and lower maintenance expenses.
These items were partly offset by the following:
●
Energy sales – GEN-NE’s results from energy sales, including both physical and financial transactions, decreased from $49 million for the three months ended September 30, 2009 to $23 million for the three months ended September 30, 2010.  The contribution from physical transactions increased primarily as a result of improved spark spreads and higher prices resulting from warmer weather; however, these increases were more than offset by the sale of the Bridgeport facility in the fourth quarter 2009, and reduced contribution from financial transactions; and
●
Decreased capacity revenues of $6 million – Capacity revenues decreased primarily as a result of the sale of the Bridgeport facility in the fourth quarter 2009.
Depreciation expense decreased from $8 million for the third quarter 2009 to $7 million for the third quarter 2010, primarily due to the sale of the Bridgeport power generating facility.
Other . Dynegy’s other operating loss for the three months ended September 30, 2010 was $56 million, compared to an operating loss of $47 million for the three months ended September 30, 2009.  DHI’s other operating loss for the three months ended September 30, 2010 was $52 million compared to an operating loss of $47 million for the three months ended September 30, 2009.  Operating losses in both periods were comprised primarily of general and administrative expenses.
Dynegy’s consolidated general and administrative expenses were $51 million and $42 million for the three months ended September 30, 2010 and 2009, respectively.  DHI’s consolidated general and administrative expenses were $47 million and $42 million for the three months ended September 30, 2010 and 2009, respectively.  General and administrative expenses for the three months ending September 30, 2010 are higher when compared to the three months ended September 30, 2009 due to $10 million of Merger Agreement transaction costs and legal expenses, partly offset by cost reduction program savings.
Losses from Unconsolidated Investments
Dynegy’s and DHI’s losses from unconsolidated investments were $8 million for the three months ended September 30, 2009, related to the GEN-WE investment in Sandy Creek, which was sold in the fourth quarter 2009.  The $8 million consisted of $5 million of mark-to-market losses primarily related to interest rate swap contracts and $3 million of financing costs.
Other Items, Net
Dynegy’s and DHI’s other items, net, totaled $1 million of income for the three months ended September 30, 2010, compared to $2 million of income for the three months ended September 30, 2009.
Interest Expense
Dynegy’s and DHI’s interest expense totaled $92 million for the three months ended September 30, 2010, compared to $115 million for the three months ended September 30, 2009.  The decrease was primarily attributable to lower outstanding debt due to the December 2009 repurchase of $833 million in aggregate principal amount of our senior unsecured notes, as well as the deconsolidation of PPEA Holding.  These decreases were partly offset by the December 2009 issuance of $235 million of senior unsecured notes in connection with the LS Power Transactions, and higher applicable margin on our variable-rate debt resulting from an amendment in August 2009 to the Credit Facility.
Income Tax Benefit
Dynegy reported an income tax benefit from continuing operations of $17 million for the three months ended September 30, 2010, compared to an income tax benefit from continuing operations of $34 million for the three months ended September 30, 2009.  The 2010 effective tax rate was 42 percent, compared to 27 percent in 2009.
DHI reported an income tax benefit from continuing operations of $15 million for the three months ended September 30, 2010, compared to an income tax benefit of $35 million from continuing operations for the three months ended September 30, 2009.  The 2010 effective tax rate was 41 percent, compared to 27 percent in 2009.
For the three month period ended September 30, 2010, the difference between the effective rate of 42 percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted primarily from the impact of state taxes.  For the three month period ended September 30, 2009, the difference between the effective rate of 27 percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted primarily from the impact of disallowed losses as a result of the LS Power Transactions.
Discontinued Operations
Loss From Discontinued Operations Before Taxes
For the three months ended September 30, 2009, our pre-tax loss from discontinued operations was $213 million, including a pre-tax impairment charge of $235 million related to the Arizona and Bluegrass power generation facilities.
Income Tax Benefit From Discontinued Operations
Dynegy and DHI recorded an income tax benefit from discontinued operations of $84 million and $74 million, respectively, during the three months ended September 30, 2009.  These amounts reflect effective rates of 39 percent and 35 percent, respectively.  The detailed methodology of allocating income taxes between continuing and discontinued operations often results in an effective rate for discontinued operations significantly different from the statutory rate of 35 percent.
Nine Months Ended September 30, 2010 and 2009
Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the nine months ended September 30, 2010 and 2009, respectively:
Dynegy’s Results of Operations for the Nine Months Ended September 30, 2010
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 953 $ 354 $ 565 $ — $ 1,872
Cost of sales
(386 ) (138 ) (349 ) — (873 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(153 ) (69 ) (114 ) (5 ) (341 )
Depreciation and amortization expense
(184 ) (50 ) (23 ) (4 ) (261 )
Impairment and other charges
— — (135 ) — (135 )
General and administrative expense
— — — (110 ) (110 )
Operating income (loss)
$ 230 $ 97 $ (56 ) $ (119 ) $ 152
Losses from unconsolidated investments
(34 ) — — — (34 )
Other items, net
— — 1 2 3
Interest expense
(272 )
Loss from continuing operations before income taxes
(151 )
Income tax benefit
80
Loss from continuing operations
(71 )
Income from discontinued operations, net of taxes
1
Net loss
$ (70 )
Dynegy’s Results of Operations for the Nine Months Ended September 30, 2009

Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 1,085 $ 293 $ 652 $ (3 ) $ 2,027
Cost of sales
(389 ) (121 ) (417 ) — (927 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(165 ) (76 ) (135 ) 3 (373 )
Depreciation and amortization expense
(165 ) (45 ) (39 ) (9 ) (258 )
Goodwill impairments
(76 ) (260 ) (97 ) — (433 )
Impairment and other charges, exclusive of goodwill impairments shown separately above
(147 ) — (388 ) — (535 )
General and administrative expense
— — — (125 ) (125 )
Operating income (loss)
$ 143 $ (209 ) $ (424 ) $ (134 ) $ (624 )
Earnings from unconsolidated investments
— 12 — 1 13
Other items, net
2 3 — 5 10
Interest expense
(311 )
Loss from continuing operations before income taxes
(912 )
Income tax benefit
147
Loss from continuing operations
(765 )
Loss from discontinued operations, net of taxes
(141 )
Net loss
(906 )
Less: Net loss attributable to the noncontrolling interests
(14 )
Net loss attributable to Dynegy Inc.
$ (892 )
The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the nine month periods ended September 30, 2010 and 2009, respectively:
DHI’s Results of Operations for the Nine Months Ended September 30, 2010
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 953 $ 354 $ 565 $ — $ 1,872
Cost of sales
(386 ) (138 ) (349 ) — (873 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(153 ) (69 ) (114 ) (5 ) (341 )
Depreciation and amortization expense
(184 ) (50 ) (23 ) (4 ) (261 )
Impairment and other charges
— — (135 ) — (135 )
General and administrative expense
— — — (106 ) (106 )
Operating income (loss)
$ 230 $ 97 $ (56 ) $ (115 ) $ 156
Losses from unconsolidated investments
(34 ) — — — (34 )
Other items, net
— — 1 2 3
Interest expense
(272 )
Loss from continuing operations before income taxes
(147 )
Income tax benefit
71
Loss from continuing operations
(76 )
Income from discontinued operations, net of taxes
1
Net loss
$ (75 )

DHI’s Results of Operations for the Nine Months Ended September 30, 2009
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Revenues
$ 1,085 $ 293 $ 652 $ (3 ) $ 2,027
Cost of sales
(389 ) (121 ) (417 ) — (927 )
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below
(165 ) (76 ) (135 ) 1 (375 )
Depreciation and amortization expense
(165 ) (45 ) (39 ) (9 ) (258 )
Goodwill impairments
(76 ) (260 ) (97 ) — (433 )
Impairment and other charges, exclusive of goodwill impairments shown separately above
(147 ) — (388 ) — (535 )
General and administrative expense
— — — (125 ) (125 )
Operating income (loss)
$ 143 $ (209 ) $ (424 ) $ (136 ) $ (626 )
Earnings from unconsolidated investments
— 12 — — 12
Other items, net
2 3 — 4 9
Interest expense
(311 )
Loss from continuing operations before income taxes
(916 )
Income tax benefit
152
Loss from continuing operations
(764 )
Loss from discontinued operations, net of taxes
(141 )
Net loss
(905 )
Less: Net loss attributable to the noncontrolling interests
(14 )
Net loss attributable to Dynegy Holdings Inc.
$ (891 )
The following table provides summary segmented operating statistics for the nine months ended September 30, 2010 and 2009, respectively:
Nine Months Ended
September 30,
2010
2009
GEN-MW
Million Megawatt Hours Generated (1) (2)
19.4 19.1
In Market Availability for Coal Fired Facilities (3)
90 % 89 %
Average Capacity Factor for Combined Cycle Facilities (4)
27 % 32 %
Average Quoted On-Peak Market Power Prices ($/MWh) (5)
Cinergy (CIN Hub)
$ 44 $ 35
Commonwealth Edison (NI Hub)
$ 43 $ 34
PJM West
$ 56 $ 45
Average Market Spark Spreads ($/MWh) (6)
PJM West
$ 20 $ 13
GEN-WE
Million Megawatt Hours Generated (7) (8)
3.0 4.7
Average Capacity Factor for Combined Cycle Facilities (4)
36 % 44 %
Average Quoted On-Peak Market Power Prices ($/MWh) (5)
North Path 15 (NP 15)
$ 41 $ 36
Average Market Spark Spreads ($/MWh) (6)
North Path 15 (NP 15)
$ 6 $ 8
GEN-NE
Million Megawatt Hours Generated
6.0 7.8
In Market Availability for Coal Fired Facilities (3)
94 % 94 %
Average Capacity Factor for Combined Cycle Facilities (4)
43 % 44 %
Average Quoted On-Peak Market Power Prices ($/MWh) (5)
New York—Zone G
$ 60 $ 50
New York—Zone A
$ 45 $ 36
Mass Hub
$ 57 $ 45
Average Market Spark Spreads ($/MWh) (6)
New York—Zone A
$ 9 $ 5
Mass Hub
$ 20 $ 11
Fuel Oil
$ (69 ) $ (45 )
Average natural gas price—Henry Hub ($/MMBtu) (9)
$ 4.58 $ 3.80
(1)
Excludes approximately less than 0.1 million MWh generated by our Bluegrass power generation facility, which we sold on November 30, 2009 and is reported in discontinued operations for the nine months ended 2009.
(2)
Includes 0.1 MWh related to our ownership percentage in the MWh generated by our GEN-MW investment in the Plum Point power generation facility for the nine months ended September 30, 2010.
(3)
Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.
(4)
Reflects actual production as a percentage of available capacity.  Excludes Arizona power generation facilities which are reported as discontinued operations with respect to the GEN-WE segment.  For the 2009 period presented, includes the Tilton, Rocky Road, Riverside and Renaissance power generation facilities with respect to the GEN-MW segment and the Bridgeport power generation facility with respect to the GEN-NE segment.
(5)
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
(6)
Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.
(7)
Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the nine months ended September 30, 2010 and 2009, respectively.
(8)
Excludes less than 0.1 million MWh generated by the Heard County power generation facility, which we sold in April 2009 and is reported in discontinued operations, for the nine months ended September, 30, 2009.  Excludes  approximately 2.1 million MWh generated by our Arizona power generation facilities, which we sold on November 30, 2009 and are reported in discontinued operations, for the nine months ended September 30, 2009.
(9)
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
The following tables summarize significant items on a pre-tax basis, with the exception of the tax items, affecting net loss for the period presented:
Nine Months Ended September 30, 2010
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Impairments (1)
$ (37 ) $ — $ (135 ) $ — $ (172 )
Merger Agreement transaction costs
— — — (10 ) (10 )
Taxes
— — — 11 11
Total—DHI
(37 ) — (135 ) 1 (171 )
Taxes
— — — 5 5
Total—Dynegy
$ (37 ) $ — $ (135 ) $ 6 $ (166 )
(1)
Includes $37 million of impairment charges related to our equity investment in PPEA Holding, which is included in Earnings (losses) from unconsolidated investments.  Also includes $134 million and $1 million of impairment charges related to our Casco Bay and Roseton/Danskammer power generation facilities, respectively.
Nine Months Ended September 30, 2009
Power Generation
GEN-MW
GEN-WE
GEN-NE
Other
Total
(in millions)
Impairments (1)
$ (246 ) $ (495 ) $ (485 ) $ — $ (1,226 )
Sandy Creek mark-to-market gains (2)
— 20 — — 20
Gain on Sale of Heard County (3)
— 10 — — 10
Taxes (4)
— — — (22 ) (22 )
Total—DHI
(246 ) (465 ) (485 ) (22 ) (1,218 )
Taxes
— — — (9 ) (9 )
Total—Dynegy
$ (246 ) $ (465 ) $ (485 ) $ (31 ) $ (1,227 )
(1)
Includes $258 million of impairment charges related to our Arizona and Bluegrass power generation facilities which are included in discontinued operations.
(2)
These mark-to-market gains represent our 50 percent share and are included in Earnings (losses) from unconsolidated investments.
(3)
Presented in discontinued operations.
(4)
Includes charges of $21 million for Dynegy and $15 million for DHI related to a change in a California state tax law.  Also includes $10 million for Dynegy and $7 million for DHI due to revised assumptions around the ability to utilize certain state deferred tax assets.
Operating Income (Loss)
Operating income for Dynegy was $152 million for the nine months ended September 30, 2010, compared to an operating loss of $624 million for the nine months ended September 30, 2009.  Operating income for DHI was $156 million for the nine months ended September 30, 2010, compared to an operating loss of $626 million for the nine months ended September 30, 2009.
Our operating income for the nine months ended September 30, 2010 includes a pre-tax asset impairment of $134 million related to our Casco Bay power generating facility and related assets.  Our operating loss for the nine months ended September 30, 2009 included a $433 million impairment of goodwill and $535 million of asset impairments.
Mark-to-market gains on forward sales of power associated with our generating assets are included in Revenues in the unaudited condensed consolidated statements of operations.  Such gains totaled $127 million for the nine months ended September 30, 2010 compared to $64 million of mark-to-market losses for the nine months ended September 30, 2009.  The gains in 2010 reflect an increase in the value of positions due to decreasing forward market prices, partially offset by the impact of the settlement of risk management positions that matured during the period.  The losses in 2009 reflect a loss from the impact of the settlement of risk management positions that matured during the period, partially offset by an increase in the value of positions due to decreasing forward market prices during the period.
Power Generation—Midwest Segment. Operating income for GEN-MW was $230 million for the nine months ended September 30, 2010, compared to $143 million for the nine months ended September 30, 2009.  The amounts for the nine months ended September 30, 2009 do not include results from the Bluegrass power generating facility, which is included in discontinued operations.  Operating income for the nine months ended September 30, 2009 included a pre-tax charge of approximately $76 million for the impairment of goodwill, reflected in Goodwill impairments in our unaudited condensed statement of operations, and also included a pre-tax charge of approximately $147 million for the impairment of the Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities and related assets, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations.
Revenues for the nine months ended September 30, 2010 decreased by $132 million compared to the nine months ended September 30, 2009, cost of sales decreased by $3 million and operating and maintenance expense decreased by $12 million, resulting in a net decrease of $117 million.  The decrease was primarily driven by the following:
●
Energy sales – GEN-MW’s results from energy sales, including both physical and financial transactions, decreased from $572 million for the nine months ended September 30, 2009 to $371 million for the nine months ended September 30, 2010.  The contribution from physical transactions increased primarily as a result of higher power prices at our coal fired facilities and improved spark spreads at our combined cycle facilities, partially offset by more unplanned outages as well as the impact of a $50 million payment received in the nine months ended September 30, 2009 to assign our rights to a third party pursuant to a power sales agreement.  These increases were more than offset by reduced contribution from financial transactions; and
●
Decreased tolling/capacity revenues of $17 million – Tolling/capacity revenues decreased $54 million as a result of the sale of assets in the fourth quarter 2009 and lower prices for MISO capacity.  These decreases were partially offset by $37 million of increases attributable to higher prices for PJM capacity and a payment in the first quarter 2010 associated with the early termination of our Kendall tolling contract.
These items were partly offset by the following:
●
Mark-to-market gains – GEN-MW’s results for the nine months ended September 30, 2010 included mark-to-market gains of $86 million related to forward sales and other derivative contracts, compared to $4 million of mark-to-market losses for the nine months ended September 30, 2009.  The $86 million in 2010 mark-to-market gains reflects $20 million of losses related to positions that settled or will settle in 2010, and $106 million of gains related to positions that will settle in 2011 and beyond; and
●
Decreased operating and maintenance expenses – operating and maintenance expenses decreased from $165 million for the nine months ended September 30, 2009 to $153 million for the nine months ended September 30, 2010, primarily as a result of the sale of certain Midwest assets to LS Power in the fourth quarter 2009 as well as lower planned outage expenses.
Depreciation expense increased from $165 million for the nine months ended September 30, 2009 to $184 million for the nine months ended September 30, 2010 primarily as a result of accelerating the depreciation of our Vermilion facility, as we do not currently expect the facility to continue to operate beyond the second quarter 2011.  The impact of additional capital projects associated with the Midwest Consent Decree and early retirement of Wood River units 1-3 and Havana units 1-5 was partially offset by the impact of reduced depreciation resulting from the sale of assets in 2009.
Power Generation—West Segment. Operating income for GEN-WE was $97 million for the nine months ended September 30, 2010, compared to operating loss of $209 million for the nine months ended September 30, 2009.  The amounts for the nine months ended September 30, 2009 do not include results from the Arizona and Heard County power generating facilities, which are included in discontinued operations.  Operating loss for the nine months ended September 20, 2009 included a pre-tax charge of approximately $260 million for the impairment of goodwill, reflected in Goodwill impairments in our unaudited condensed consolidated statements of operations.
Revenues for the nine months ended September 30, 2010 increased by $61 million compared to the nine months ended September 30, 2009, cost of sales increased by $17 million and operating and maintenance expense decreased by $7 million, resulting in a net increase of $51 million.  The increase was primarily driven by the following:
●
Mark-to-market gains – GEN-WE’s results for the nine months ended September 30, 2010 included mark-to-market gains of $18 million related to forward sales and other derivative contracts, compared to $52 million of mark-to-market losses for the nine months ended September 30, 2009.  Of the $18 million in 2010 mark-to-market gains, $9 million related to positions that settled or will settle in 2010, and the remaining $9 million related to positions that will settle in 2011 and beyond; and
●
Decreased operating and maintenance expenses – operating and maintenance expenses decreased from $76 million for the nine months ended September 30, 2009 to $69 million for the nine months ended September 30, 2010, primarily as a result of the retirement of two units at our South Bay facility and lower maintenance expenses.
These items were partly offset by the following:
●
Energy sales – GEN-WE’s results from energy sales, including both physical and financial transactions, decreased from $76 million for the nine months ended September 30, 2009 to $66 million for the nine months ended September 30, 2010.  The contribution from physical transactions decreased primarily as a result of reduced spark spreads and forced outages.  The contribution from financial transactions also decreased; and
●
Decreased tolling/RMR revenues of $16 million – Tolling/RMR revenues decreased primarily as a result of the timing of payments under our 2009 South Bay facility tolling contract compared to the rateable RMR payment received for South Bay in 2010, lower variable revenues at Moss Landing and unplanned outages.
Depreciation expense increased from $45 million for the nine months ended September 30, 2009 to $50 million for the nine months ended September 30, 2010 as a result of capital projects placed into service.
Power Generation—Northeast Segment. Operating loss for GEN-NE was $56 million for the nine months ended September 30, 2010, compared to operating loss of $424 million for the nine months ended September 30, 2009.  Operating loss for the nine months ended September 30, 2010 includes a pre-tax charge of approximately $134 million for the impairment of the Casco Bay facility and related assets.  Operating loss for the nine months ended September 30, 2009 included a pre-tax charge of approximately $97 million for the impairment of goodwill, reflected in Goodwill impairment in our unaudited condensed consolidated statements of operations, and included a pre-tax charge of approximately $179 million for the impairment of our Bridgeport power generating facility and related assets as well as a pre-tax charge of approximately $209 million for the impairment of our Roseton and Danskammer power generation facilities and related assets.  All of these impairments are reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations for their respective years.  Please read Note 8—Impairment Charges for further discussion.
Revenues for the nine months ended September 30, 2010 decreased by $87 million compared to the nine months ended September 30, 2009, cost of sales decreased by $68 million and operating and maintenance expense decreased by $21 million, resulting in a net increase of $2 million.  The increase was primarily driven by the following:
●
Mark-to-market gains – GEN-NE’s results for the nine months ended September 30, 2010 included mark-to-market gains of $23 million related to forward sales and other derivative contracts, compared to losses of $8 million for the nine months ended September 30, 2009.  Of the $23 million in 2010 mark-to-market gains, $9 million related to positions that settled or will settle in 2010, and the remaining $14 million related to positions that will settle in 2011 and beyond;
●
Decreased operating and maintenance expenses – Operating and maintenance expenses decreased from $135 million for the nine months ended September 30, 2009 to $114 million for the nine months ended September 30, 2010, primarily as a result of the sale of the Bridgeport facility in the fourth quarter 2009 and lower maintenance expenses; and
●
Coal inventory write-down of approximately $11 million recorded during the nine months ended September 20, 2009.
These items were partly offset by:
●
Energy sales – GEN-NE’s results from energy sales, including both physical and financial transactions, decreased from $101 million for the nine months ended September 30, 2009 to $64 million for the nine months ended September 30, 2010.  The contribution from physical transactions increased primarily as a result of improved spark spreads and higher prices resulting from warmer weather in the second and third quarter, partially offset by weaker winter spark spreads and the sale of the Bridgeport facility in the fourth quarter 2009; however, this net increase was more than offset by reduced contribution from financial transactions;
●
Decreased capacity revenues of $13 million – Capacity revenues decreased primarily due to a $17 million reduction in capacity revenue from the Bridgeport facility that was sold to LS Power in the fourth quarter 2009.  This decrease was partially offset by increased capacity revenues at our other facilities due to slightly higher prices; and
●
Emissions sales – sales of emissions decreased by $10 million due to lower sale volumes and market prices of emissions credits in 2010.
Depreciation expense decreased from $39 million for the nine months ended September 30, 2009 to $23 million for the nine months ended September 30, 2010, primarily due to the sale of the Bridgeport power generating facility and the impairments of our Roseton and Danskammer power generation facilities in the second quarter 2009.
Other. Dynegy’s other operating loss for the nine months ended September 30, 2010 was $119 million, compared to an other operating loss of $134 million for the nine months ended September 30, 2009.  DHI’s other operating loss for the nine months ended September 30, 2010 was $115 million, compared to an other operating loss of $136 million for the nine months ended September 30, 2009.  Operating losses in both periods were comprised primarily of general and administrative expenses.
Dynegy’s consolidated general and administrative expenses decreased from $125 million from the nine months ended September 30, 2009 to $110 million for the nine months ended September 30, 2010.  DHI’s consolidated general and administrative expenses decreased from $125 million from the nine months ended September 30, 2009 to $106 million for the nine months ended September 30, 2010.  General and administrative expenses for the nine months ending September 30, 2010 are lower when compared to the nine months ended September 30, 2009 due to cost reduction program savings, lower stock-based compensation expense resulting from decreases in fair value of the underlying stock, and lower professional and legal expenses.  These decreases are partly offset by $10 million of transaction costs associated with the Merger Agreement.
Earnings (Losses) from Unconsolidated Investments
Losses from unconsolidated investments were $34 million for the nine months ended September 30, 2010 related to the GEN-MW investment in PPEA Holding.  The losses consisted of an impairment charge of approximately $37 million partially offset by $3 million in equity earnings primarily related to mark-to-market gains on interest rate swaps offset by financing expenses.  Due to the uncertainty regarding PPEA’s financing structure, our investment in PPEA Holding was fully impaired at March 31, 2010.  Please see Note 10—Variable Interest Entities—PPEA Holding Company LLC for further discussion.
Earnings from unconsolidated investments were $13 million and $12 million for Dynegy and DHI, respectively, for the nine months ended September 30, 2009.  Earnings of $12 million related to the GEN-WE investment in Sandy Creek.  The $12 million consisted of $20 million in mark-to-market gains primarily related to interest rate swap contracts offset by $8 million of financing costs.  Dynegy’s earnings also included $1 million of earnings related to Dynegy’s former investment in DLS Power Development, included in Other.
Other Items, Net
Dynegy’s and DHI’s other items, net, totaled $3 million of income for the nine months ended September 30, 2010, compared to $10 million and $9 million, respectively, of income for the nine months ended September 30, 2009.  The decrease is primarily associated with insurance proceeds received in the nine months ended September 30, 2009, and with lower interest income due to lower cash and restricted cash balances in 2010.
Interest Expense
Dynegy’s and DHI’s interest expense totaled $272 million for the nine months ended September 30, 2010, compared to $311 million for the nine months ended September 30, 2009.  The decrease was primarily attributable to lower outstanding debt due to the December 2009 repurchase of $833 million in aggregate principal amount of our senior unsecured notes, as well as the deconsolidation of PPEA Holding.  These decreases were partly offset by the December 2009 issuance of $235 million of senior unsecured notes in connection with the LS Power Transactions, and higher applicable margin on our variable-rate debt resulting from an amendment in August 2009 to the Credit Facility.
Income Tax Benefit
Dynegy reported an income tax benefit from continuing operations of $80 million for the nine months ended September 30, 2010, compared to an income tax benefit from continuing operations of $147 million for the nine months ended September 30, 2009.  The 2010 effective tax rate was 53 percent, compared to 16 percent in 2009.
DHI reported an income tax benefit from continuing operations of $71 million for the nine months ended September 30, 2010, compared to an income tax benefit of $152 million from continuing operations for the nine months ended September30, 2009.  The 2010 effective tax rate was 48 percent, compared to 17 percent in 2009.
The primary difference between the effective rates of 53 and 48 percent for Dynegy and DHI, respectively, for the nine months ended September 30, 2010 and the statutory rate of 35 percent resulted primarily from the benefit of $18 million and $12 million for Dynegy and DHI, respectively related to the release of reserves for uncertain tax positions, partly offset by the impact of state taxes.  For the period ended September 30, 2009, the difference resulted from the effect of the nondeductible goodwill impairment charge.  Additionally, for the nine months ended September 30, 2009, Dynegy and DHI recorded $19 million and $14 million, respectively, of income tax expense related to a change in California state tax law.  As a result of the LS Power Transactions, we revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore Dynegy and DHI recorded valuation allowances resulting in additional state tax expense of $10 million and $7 million, respectively for the nine months ended September 30, 2009.
Discontinued Operations
Loss From Discontinued Operations Before Taxes
For the nine months ended September 30, 2010, our pre-tax income from discontinued operations was $1 million.  For the nine months ended September 30, 2009, Dynegy and DHI’s pre-tax loss from discontinued operations was $232 million, related to the operation of the Arlington Valley, Griffith, Bluegrass and Heard County facilities.  We recorded impairment charges of $235 million related to the Arlington Valley and Griffith Facilities, as these facilities collectively met the criteria for classification as held for sale at August 9, 2009.  Additionally, we recorded impairment charges of $23 million related to the Bluegrass facility.
Income Tax Benefit From Discontinued Operations
We recorded income tax benefit from discontinued operations of $91 million during the nine months ended September 30, 2009.  This amount reflects an effective rate of 39 percent.  The detailed methodology of allocating income taxes between continuing and discontinued operations often results in an effective rate for discontinued operations significantly different from the statutory rate of 35 percent.
Outlook
The following summarizes our general business outlook, and unique business issues impacting the outlook of each of our three regions, for the next 12 months.
Our power generation portfolio currently consists of approximately 12,200 MW of generating capacity that is diversified by fuel source (i.e., coal, natural gas and fuel oil) and dispatch type (i.e., baseload, intermediate and peaking facilities).
We expect that our future financial results will continue to be sensitive to fuel and commodity prices, especially gas prices and the impact on such prices of shale gas proliferation.  Other factors to which our future financial results will remain sensitive to include market structure and prices for electric energy, capacity and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions and IMA.  Further, as described in our Form 10-K, there is a trend toward greater environmental regulation of all aspects of our business.  As this trend continues, it is likely that we will experience additional costs and limitations.  Please read Item 1. Business—Environmental Matters in our Form 10-K as well as environmental matters discussed below.
We have volumetrically hedged nearly 100 percent of our expected generation volumes for 2010 and 2011.  Based on specific market conditions, at any point in time we may enter into transactions that will increase or decrease the portion of our expected output that has been contracted.  Even though we have largely contracted our expected output through 2011, our future operating cash flows during this period may vary based on a number of other factors, including the value of capacity and ancillary services, the operational performance of our generating facilities, the price differential between the locations where we deliver generated power and the liquid market hub, legal, environmental, and regulatory requirements, and other factors.
If the NRG Sale is completed, NRG will acquire four natural gas-fired facilities and related assets currently owned by us—the Casco Bay facility in Maine and the Moss Landing, Morro Bay and Oakland facilities in California.  In such event, our portfolio of generation assets will become less diversified in terms of dispatch profile, fuel type and geography.  Changes in our dispatch profile may reduce our ability to capitalize on market opportunities as power demand and pricing increase in the future.  Increased dependence on our coal-fired generation facilities means our profitability will also become more dependent on our ability to procure coal at reasonable prices.  We may also have greater exposure to certain business risks as weather patterns, regulatory regimes and commodity prices often differ by region and state.  If we are less geographically diversified, individual risks in any one region may negatively impact our financial performance in a more pronounced way.  Furthermore, our total net generating capacity will be reduced by approximately 3,884 MW, or 31.8%.  These factors, individually and in the aggregate, could have a material negative effect on the level and consistency of our earnings and operating cash flows.
If the Blackstone Merger is not consummated, it is expected that within the next six months we will proactively seek to amend, extend or refinance our Credit Facility in an attempt to provide for adequate liquidity to support our business and to avoid any potential covenant non-compliance under such facilities.  Please read the discussion above regarding our Revolver Capacity, as well as Note 17—Debt—Credit Facility in our Form 10-K, for a discussion of the financial covenants contained in the Credit Facility.  Additionally, we may also seek external sources of liquidity to supplement our liquidity position, which may include asset sales and issuing public and/or private debt or equity securities.  Please read Item 2.—Liquidity and Capital Resources for further discussion.
GEN-MW. Our Midwest Consent Decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest.  We have achieved all emission reductions scheduled to date under the Midwest Consent Decree and are in the process of installing additional emission control equipment to meet future Midwest Consent Decree emission limits.  We expect our costs associated with the remaining Midwest Consent Decree projects, which we have planned to incur through 2013, to be approximately $272 million.  This estimate includes a number of assumptions about uncertainties beyond our control, such as costs associated with labor and materials.  If the costs of these capital expenditures become great enough to render the operation of the affected power generation facility or facilities uneconomical, we could, at our option, cease to operate the power generation facility or facilities and forego these capital expenditures without incurring any further obligations under the Midwest Consent Decree.
Our Midwest coal requirements are approximately 100 percent contracted for the remainder of 2010, 92 percent contracted in 2011 and 96 percent contracted in 2012.  All forecast coal requirements are priced through 2010, 100 percent are priced through 2011 and 65 percent are priced through 2012.  Committed volumes that are currently unpriced are subject to a price collar structure.  Our Midwest coal transportation requirements are 100 percent contracted and priced through 2013, except for coal transportation for our Vermilion power generation facility, which is priced through 2010.  We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies.  Our Midwest expected generation volumes are 95 percent hedged through 2011 and approximately 15 percent hedged for 2012.
Recent moves by certain MISO market participants expressing their intentions to exit the MISO could mitigate earlier membership increases and impact system reserve margins favorably in the future.  The impacts to MISO capacity market-clearing practices and the resulting prices are unclear at this time as the ISO continues to consult with market stakeholders regarding optimal capacity auction mechanics and product offerings.  In addition, competing initiatives of increased market participation by demand response resources offset by potential retirement of marginal MISO coal capacity due to expected environmental mandates could also affect MISO capacity and energy markets in the future.
GEN-WE. Approximately 70 percent of our power plant capacity in the West is contracted through 2011 under tolling agreements with load-serving entities and RMR agreements with the CAISO.  A significant portion of the remaining capacity is sold as a resource adequacy product in the California market, and much of the expected production associated with our plants without tolls or RMR agreements has been financially hedged.
Our South Bay and Oakland power generation facilities are operating under RMR agreements with the CAISO which expire on December 31, 2010.  The Oakland power plant facility has been designated as an RMR unit for 2011.   We have been notified by the CAISO that South Bay’s RMR designation will not be renewed for 2011.  As a result, the South Bay power generation facility will permanently cease operation on December 31, 2010 as per the terms of the lease with the Port of San Diego.
Upon retirement of the South Bay power generation facility, we have a contractual obligation to demolish the plant and remediate specific parcels of the property.  The collection of a negotiated settlement for a portion of the expected demolition and remediation costs via RMR rates will be substantially complete by the expiration of the 2010 RMR agreement.
GEN-NE. Our physical coal supply and delivery requirements for our Danskammer coal-fired facility are fully contracted and priced through 2010.  A substantial portion of our physical supply and delivery requirements for 2011 are also fully contracted and priced with the balance financially hedged.  While we continue to source the majority of our coal supply from South America, having access to both marine and rail unloading facilities at the site affords us opportunities to explore alternative supply and delivery options for Danskammer.  Lower natural gas prices are expected to continue to compress dark spreads and likely to alter the dispatch stack favoring natural gas-fired assets over coal-fired assets during shoulder months in much of the Northeast for the near term.  While capacity prices have trended lower in New York due to surplus capacity and lower demand, we have contracted approximately 25 percent of our capacity in the NYISO at favorable pricing through 2014.  We have attempted to maximize revenue opportunities for the balance of our portfolio through active participation in the NYISO capacity auctions and through bilateral transactions.
The ISO-NE restructured its capacity market and has transitioned to a forward capacity market structure in 2010.  The delivery of capacity under the forward capacity market became fully effective on June 1, 2010.  Four forward capacity auctions have been held to date with capacity prices ranging from a high of $4.50 kW-month for the 2010-2011 market period to a low of $2.95 kW-month for the 2012-2013 market period.  These capacity clearing prices represent the floor price, and the actual rate paid to Casco Bay (and other facilities) has been reduced due to oversupply conditions and pro-rationing.  Efforts to implement prospective improvements in the forward capacity market design are currently underway in active proceedings at FERC and in discussions by the ISO and its stakeholders.
Environmental and Regulatory Matters
Federal Regulation of Greenhouse Gases. Please read Item 1 Business – Environmental Matters—Climate Change—Federal Regulation of Greenhouse Gases in our Form 10-K.
The EPA is “phasing in” new GHG emissions applicability thresholds for its PSD permit program and for the operating permit program under Title V of the CAA.  PSD permits for new major sources of GHG, and for GHG sources that undergo major modification on or after January 2, 2011, will be required to implement BACT for the control of GHG emissions.
New York Regional Haze Rule. In July 1999, the EPA published its final Regional Haze Rule which requires states to submit regional haze implementation plans to the EPA detailing their plans to reduce emissions of visibility–impairing pollutants (NO x , SO 2 and particulates) that affect visibility in downwind Federal Class I Areas (i.e. parks and wilderness) with a goal to restore natural visibility conditions in these areas by 2064.  The State of New York has been identified as having certain BART eligible facilities that contribute to regional haze in Class I Areas in other states, including our Roseton power generating facility and Unit 4 at our Danskammer power generating facility.  On May 1, 2010, the New York State BART Rule became effective.  In compliance with the rule, our Danskammer and Roseton power generation facilities performed a comprehensive, unit specific modeling analysis for their BART eligible units to determine their impact on visibility.  In October 2010, we submitted this analysis to NYSDEC along with a proposal, effective January 1, 2014, reduce NO x and SO 2 emission limits to address impacts on visibility in order to meet federal standards.  Compliance at our Roseton facility would be achieved by reducing the sulfur content of our fuel oil and optimization of existing NO x emission controls.  Compliance at Danskammer Unit 4 would be achieved through optimization of existing NO x emission controls, co-firing with natural gas, use of alternative coal, and/or installation of additional emission controls.  We are continuing to review our compliance options at Danskammer.
New York NO x RACT Rule. In June 2010, New York State issued a final rule establishing revised RACT limits for emissions of NO x from stationary combustion sources.   Compliance with the revised NO x RACT limits is required by July 1, 2014, and compliance plans must be submitted to NYSDEC by January 1, 2012.  Compliance options include meeting presumptive RACT limits, case-by-case RACT determinations, fuel switching during the ozone season (May 1 through September 30), and participation in a system averaging plan.  We are continuing to review the potential impact of the revised NO x RACT rule on our subject power generation facilities.
California Water Intake Policy. The California State Water Board adopted its Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (the “Policy”) at its meeting on May 4, 2010, introducing and adopting several amendments making it more stringent than the proposed draft Policy.  The approved Policy requires that existing power plants: (i) reduce their water intake flow rate to a level commensurate with that which can be achieved by a closed cycle cooling system; or (ii) if it is not feasible to reduce the water intake flow rate to this level, reduce impingement mortality and entrainment to a level comparable to that achieved by such a reduced water intake flow rate using operational or structural controls, or both.  Compliance with the Policy is required at our Morro Bay power generation facility by December 31, 2015 and at our Moss Landing power generation facility by December 31, 2017.  The Policy was approved by the OAL on September 27, 2010 with minor changes not applicable to our facilities and became effective October 1, 2010.  On October 27, 2010, Dynegy Morro Bay, LLC and Dynegy Moss Landing, LLC joined with other California power plant owners in filing a lawsuit in the Sacramento County Superior Court challenging the Policy.
On September 29, 2010, the State Water Board proposed to amend the Policy to allow an owner or operator of a power plant with previously installed combined-cycle power generating units to continue to use once-through cooling at combined-cycle units until the unit reaches the end of its useful life under certain circumstances.  A hearing to receive comment and to take action on the proposed amendment is scheduled for December 14, 2010.  We are continuing to review the potential impact of the proposed amendment on our affected power generation facilities.
It may not be possible to meet the requirements of the Policy in its final form without installing closed cycle cooling systems.  Given the numerous variables and factors involved in calculating the potential costs of closed-cycle cooling systems, any decision to install such a system would be made on a case-by-case basis considering all relevant factors at the time.  If capital expenditure requirements related to cooling water systems become great enough to render the continued operation of a particular plant uneconomical, we could, at our option, and subject to any applicable financing agreements and other obligations, reduce operations or cease to operate the plant and forego such capital expenditures.
New York Water Intake Policy. On March 4, 2010, the NYSDEC issued a draft policy (“the NYSDEC Policy”) on “BTA for Cooling Water Intake Structures.”  The NYSDEC Policy, which was subject to comment until July 8, 2010, would establish closed cycle cooling or its equivalent as the minimum performance goal for existing power plants.  If NYSDEC determines that closed cycle cooling is not available for a facility, the NYSDEC Policy would establish a performance goal of 90 percent or greater reduction in impingement mortality and entrainment from that which could be achieved by closed cycle cooling.  The NYSDEC Policy would exempt certain power generation facilities that operate at very low capacity.  We are continuing to review the potential impact of the NYSDEC Policy, if adopted, on our subject power generation facilities.
Coal Combustion Residuals .  On May 4, 2010, the EPA released two alternative proposals for federal regulation of the management and disposal of CCR from electric utilities and independent power producers.  The agency proposed two alternative approaches for regulating these materials under the RCRA.  One proposal would regulate CCR as a special waste under subtitle C rules when those wastes are destined for disposal in a landfill or surface impoundment.  The subtitle C proposal would subject persons who generate, transport, treat, store or dispose of such CCR to many of the existing RCRA regulations applicable to hazardous waste.  Certain types of beneficial use of CCR would be exempt from regulation under the subtitle C proposal.  Regulation under subtitle C would effectively phase out the use of ash ponds for disposal of CCR.
The second alternative proposal would regulate CCR disposed in landfills or surface impoundments as a solid waste under subtitle D of RCRA.  The subtitle D proposal would establish national criteria for disposal of CCR in landfills and surface impoundments, requiring new units to install composite liners.  The subtitle D proposal might also require existing surface impoundments without liners to close or be retrofitted with composite liners within five years.
Comments on the proposals are now due on or before November 19, 2010.  The timing and ultimate requirements of a final rule governing CCR, as well as options available for compliance, cannot be predicted with confidence at this time.  Such a rule could have a material adverse effect on our financial condition, results of operations and cash flows.  Please read Item 1. Business—Other Environmental Matters—Coal Combustion Byproducts in our Form 10-K for further discussion.
Interstate Transport Rule. On July 6, 2010, the EPA released its proposed Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (the “proposed Transport Rule”).  The proposed Transport Rule would be implemented through federal implementation plans that would be effective in each affected state as soon as the final rule is issued.  The proposed rules are intended to reduce emissions of SO 2 and NO X from large electric generating units in 31 eastern states and the District of Columbia.  The rules would impose cap and trade programs within each state that would cap emissions of SO 2 and NO X at levels predicted to eliminate that state’s contribution to nonattainment in, or interference with maintenance of attainment status by, down-wind areas to the east with respect to the National Ambient Air Quality Standards for particulate matter (PM 2.5 ) and ozone.  Our generating facilities in Illinois, New York and Pennsylvania would be subject to the rules.
The rules applicable to annual and ozone season NO X emissions would require compliance by January 1, 2012.  The rules applicable to SO 2 emissions from electric generating units in Illinois, New York and Pennsylvania would be implemented in two stages with compliance dates of January 1, 2012 and January 1, 2014.  EPA would initially allocate NO X and SO 2 emission allowances to existing electric generating units based on the lower of 2009 annual emissions or projected 2012 emissions necessary to meet EPA’s emission budget for the state.  The SO 2 emission budgets in Illinois, New York and Pennsylvania would be reduced in 2014, and existing electric generating units in these states would be allocated fewer SO 2 emission allowances beginning in 2014.  Electric generating units would be required to hold one emission allowance for every ton of SO 2 and/or NO X emitted during the applicable compliance period.  Electric generating units can comply with the required emission reductions by any combination of (i) installing emission control technologies, (ii) operating existing emission controls more often, (iii) switching fuels, or (iv) curtailing or ceasing operation.
Allowance trading would be allowed under the proposed Transport Rule among sources within the same state, with limited interstate allowance trading.  Illinois, New York and Pennsylvania would be subject to three new cap and trade programs under the proposed Transport Rule capping emissions of NO X from May 1 st through September 30 th and capping emissions of SO 2 and NO X respectively, on an annual basis.
In the preamble to the proposed Transport Rule, the EPA solicited comments on alternatives and variations to a number of provisions of the proposal including the state emissions budgets, the emission allowance allocation approach, auction of allowances rather than allocation by the EPA, and direct control of emissions through emission rate limits.  We submitted comments on the proposed rule on October 1, 2010 and will continue to monitor the rulemaking process surrounding the proposed Transport Rule and to evaluate any potential impacts it might have on our operations.
Financial Reform Legislation. On July 21, 2010, Financial Reform Legislation was signed into law.  The legislation primarily provides broad impacts to the financial services industry.  However, among its provisions are requirements for OTC derivatives transactions.  We use a variety of these transactions in connection with the purchase and sale of electricity and fuel, as well as to support our risk management practices.  The legislation provides an end-user exemption that may excuse asset-based energy companies from independent exchange clearing and collateralization requirements that otherwise apply to OTC derivative transactions.  Regardless of how end-user exemptions are ultimately determined, we use a collateral clearing agent, with the majority of our transactions collateralized with cash, short-term investments, or availability under our term letter of credit facility.  We will continue to monitor for potential impacts as regulatory entities develop regulations necessary for implementing the legislation.
RISK-MANAGEMENT DISCLOSURES
The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance sheets:
As of and
for the
Nine Months Ended September 30, 2010
(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at December 31, 2009
$ (33 )
Risk-management gains recognized through the income statement in the period, net
236
Cash received related to risk-management contracts settled in the period, net
(113 )
Changes in fair value as a result of a change in valuation technique (1)
—
Non-cash adjustments and other (2)
50
Fair value of portfolio at September 30, 2010
$ 140
(1)
Our modeling methodology has been consistently applied.
(2)
Includes the reduction of $50 million of risk management activity as of January 1, 2010 due to the deconsolidation of PPEA Holding.  Please read Note 1—Accounting Policies —Accounting Policies Adopted—Variable Interest Entities for further discussion.
The net risk management asset of $140 million is the aggregate of the following line items on our unaudited condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.
Risk-Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of September 30, 2010, based on our valuation methodology:
Net Fair Value of Risk-Management Portfolio
Total
2010
2011
2012
2013
2014
Thereafter
(in millions)
Market quotations (1)
$ 110 $ 47 $ 88 $ (25 ) $ — $ — $ —
Prices based on models(2)(3)
30 15 23 (11 ) — 1 2
Total
$ 140 $ 62 $ 111 $ (36 ) $ — $ 1 $ 2
(1)
Prices obtained from actively traded, liquid markets for commodities.
(2)
The market quotations and prices based on models categorization differs from the fair value accounting standards’ categories of Level 1, Level 2 and Level 3 due to the application of the different methodologies.  Please see Note 7—Fair Value Measurements for further discussion.
(3)
The majority of the $15 million in 2010 and the $23 million in 2011 is for instances where industry-standard models are used but the pricing inputs combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the location under the contract.  Therefore, the value is included in the prices based on models category.
UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements”.  All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements.  These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements.  You can identify these statements by the fact that they do not relate strictly to historical or current facts.  They use words such as “anticipate”, “estimate”, “project”, “forecast”, “plan”, “may”, “will”, “should”, “expect” and other words of similar meaning.  In particular, these include, but are not limited to, statements relating to the following:
●
the timing and anticipated benefits to be achieved through our 2010-2013 company-wide cost reduction program;
●
beliefs and assumptions relating to liquidity, available borrowing capacity and capital resources generally;
●
expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations to which we are, or could become, subject;
●
beliefs, assumptions and projections regarding the overall economy, demand for power, generation volumes and commodity pricing, including gas prices and the impact on such prices from shale gas proliferation;
●
anticipated liquidity in the regional power and fuel markets in which we transact, including the extent to which such liquidity could be affected by poor economic and financial market conditions or new regulations and any resulting impacts on financial institutions and other current and potential counterparties;
●
sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof;
●
beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale power generation market, including the anticipation of higher market pricing over the longer term;
●
the possibility of further consolidation of the power generation industry and the impact of any such activity on Dynegy;
●
the beliefs and assumptions regarding our ability to enhance long-term value for stockholders;
●
the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;
●
beliefs and assumptions about weather and general economic conditions;
●
projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;
●
expectations regarding our revolver capacity, credit facility compliance, financial covenants, collateral demands, capital expenditures, interest expense and other payments;
●
beliefs or expectations regarding the potential amendment, extension or refinancing of our Credit Facility, or the timing thereof;
●
our focus on safety and our ability to efficiently operate our assets so as to maximize our revenue generating opportunities and operating margins;
●
beliefs about the outcome of legal, regulatory, administrative and legislative matters;
●
expectations and estimates regarding capital and maintenance expenditures, including the Midwest Consent Decree and its associated costs; and
●
the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement including a termination of the Merger Agreement under circumstances that could require Dynegy to pay a termination fee to parent or to reimburse Parent, Merger Sub and their affiliates for documented out-of-pocket expenses;
●
the occurrence of any event, change or other circumstances that could give rise to the termination of the NRG PSA between Merger Sub and NRG;
●
Parent’s failure to obtain the necessary equity financing set forth in the equity commitment letter received in connection with the Merger Agreement or the failure of that financing to be sufficient to complete the Merger and the other transactions contemplated by the Merger Agreement;
●
the inability to complete the Blackstone Merger due to the failure to obtain stockholder approval or the failure to satisfy other conditions to completion of the Merger, including receipt of required regulatory approvals and the satisfaction or waiver of the conditions to the obligations of NRG and Merger Sub to effect the NRG Sale (other than those that by their nature are to be satisfied at the closing of those transactions, and the condition relating to the consummation of the Merger) and NRG standing ready, willing and able to consummate the NRG Sale upon the consummation of the Blackstone Merger;
●
the failure of the Blackstone Merger to close for any other reason;
●
risks that the proposed transaction disrupts current plans and operations and the potential difficulties in retention of executive management and other key employees as a result of the Merger Agreement or the NRG PSA;
●
the outcome of any legal proceedings that have been or may be instituted against Dynegy and/or others relating to the Merger Agreement and/or the NRG PSA;
●
diversion of management’s attention from ongoing business concerns;
●
limitations placed on our ability to operate the business by the Merger Agreement;
●
limitations on our ability to utilize the Company’s previously incurred federal net operating losses or alternative minimum tax credits;
●
the effect of the announcement of the Merger Agreement or the transaction contemplated by the NRG PSA on our business relationships, standing with regulators, operating results and business generally; and
●
the amount of the costs, fees, expenses, impairments, and other charges related to the Blackstone Merger and the NRG Sale.
Any or all of our forward-looking statements may turn out to be wrong.  They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth under Part II–Other Information, Item 1A-Risk Factors and Item 1A-Risk Factors of our Form 10-K.
RECENT ACCOUNTING PRONOUNCEMENTS
See Note 1—Accounting Policies to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us.
CRITICAL ACCOUNTING POLICIES
Estimated Useful Lives. The estimated useful lives of our long−lived assets are used to compute depreciation expense, future AROs and are used in impairment testing.  Estimated useful lives are based, among other things, on the assumption that we provide an appropriate level of capital expenditures while the assets are still in operation. Estimated lives could be impacted by such factors as future energy prices, environmental regulations, various legal factors and competition. If the useful lives of these assets were found to be shorter than originally estimated, depreciation expense may increase, liabilities for future AROs may be insufficient and impairments in carrying values of tangible and intangible assets may result.
Please read “Critical Accounting Policies” in our Form 10-K for a complete description of our critical accounting policies, with respect to which there have been no material changes since the filing of such Form 10-K.
Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our Form 10-K for a discussion of our exposure to commodity price variability and other market risks related to our net non-trading derivative assets and liabilities, including foreign currency exchange rate risk.  Following is a discussion of the more material of these risks and our relative exposures as of September 30, 2010.
Value at Risk (“VaR”). The following table sets forth the aggregate daily VaR of the mark-to-market portion of our risk-management portfolio primarily associated with the GEN segments and the remaining legacy customer risk management business.  The VaR calculation does not include market risks associated with the accrual portion of the risk-management portfolio that is designated as a cash flow hedge or a “normal purchase normal sale”, nor does it include expected future production from our generating assets.  Please read “Value at Risk” in our Form 10-K for a complete description of our valuation methodology.
Daily and Average VaR for Risk-Management Portfolios
September 30,
2010
December 31,
2009
(in millions)
One day VaR—95 percent confidence level (1)
$ 9 $ 41
One day VaR—99 percent confidence level (1)
$ 13 $ 57
Average VaR for the year-to-date period—95 percent confidence level (1)
$ 25 $ 34
(1)
The decrease in the September 30, 2010 VaR was primarily due to lower commodity price and historical volatility levels as compared to December 31, 2009.
Credit Risk. The following table represents our credit exposure at September 30, 2010 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.
Credit Exposure Summary
Investment
Grade Quality
Non-Investment Grade Quality
Total
(in millions)
Type of Business:
Financial institutions
$ 32 $ — $ 32
Utility and power generators
11 — 11
Commercial, industrial and end users
— — —
Oil and gas producers
2 — 2
Total
$ 45 $ — $ 45
Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations.  As of September 30, 2010, our fixed rate debt instruments, as a percentage of total debt instruments, were approximately 80 percent.  The net notional fixed rate debt as a percentage of total debt was approximately 80 percent.  Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of September 30, 2010, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended September 30, 2010 would either decrease or increase interest expense by approximately $9 million.  This exposure would be partially offset by an approximate $9 million increase or decrease in interest income related to the restricted cash balance of $850 million posted as collateral to support the term letter of credit facility.  Over time, we may seek to reduce or increase the percentage of fixed rate financial obligations in our debt portfolio through the use of swaps or other financial instruments.
The notional financial contract amounts associated with our interest rate contracts were as follows at September 30, 2010 and December 31, 2009, respectively:
September 30,
2010
December 31,
2009
Fair value hedge interest rate swaps (in millions of U.S. dollars)
$ 25 $ 25
Fixed interest rate received on swaps (percent)
5.70 5.70
Interest rate risk-management contract (in millions of U.S. dollars) (1)
$ 231 $ 784
Fixed interest rate paid on swaps (percent)
5.35 5.33
Interest rate risk-management contract (in millions of U.S. dollars)
$ 206 $ 206
Fixed interest rate received on swaps (percent)
5.28 5.28
(1)
Reflects the reduction of $553 million of notional financial contract amounts due to the deconsolidation of PPEA Holding.  Please read Note 1—Accounting Policies —Accounting Policies Adopted—Variable Interest Entities for further discussion.
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of Dynegy’s and DHI’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended).  This evaluation included consideration of the various processes carried out under the direction of Dynegy’s disclosure committee.  This evaluation also considered the work completed relating to Dynegy’s and DHI’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002.  Based on this evaluation, Dynegy’s and DHI’s CEO and CFO concluded that Dynegy’s and DHI’s disclosure controls and procedures were effective as of September 30, 2010.
Changes in Internal Controls Over Financial Reporting
There were no changes in Dynegy’s and DHI’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect Dynegy’s and DHI’s internal control over financial reporting during the quarter ended September 30, 2010.
DYNEGY INC. and DYNEGY HOLDINGS INC.
See Note 14—Commitments and Contingencies—Legal Proceedings to the accompanying unaudited condensed consolidated financial statements for a discussion of the legal proceedings that we believe could be material to us.
There can be no assurance that the Blackstone Merger or NRG Sale will be consummated, which could have a material adverse effect on Dynegy’s financial condition, results of operations and cash flows.
The consummation of the Blackstone Merger is subject to the approval of Dynegy’s stockholders holding a majority of the outstanding shares of its common stock and is subject to the satisfaction or waiver of other conditions, including receipt of required regulatory approvals, the absence of any legal prohibitions, the accuracy of the representations and warranties of Dynegy, Parent and Merger Sub in the Merger Agreement, the satisfaction or waiver of the conditions to the obligations of NRG and Merger Sub to effect the transactions contemplated by the NRG PSA (other than those that by their nature are to be satisfied at the closing of those transactions, and the condition relating to the consummation of the Merger), and NRG standing ready, willing and able to consummate the NRG Sale upon the consummation of the Blackstone Merger.  We cannot assure you that these conditions will be satisfied or waived in a timely manner, or at all and, as a result, we cannot assure you that the Blackstone Merger or NRG Sale will be consummated in a timely manner, or at all.  Moreover, a substantial delay in obtaining any required approvals, consents and clearances or the imposition of unfavorable terms or conditions in connection with obtaining such approvals, consents and clearances could have a material adverse effect on our business, financial condition and results of operations and/or may cause us, Blackstone, and/or NRG to terminate the Merger Agreement or NRG PSA, respectively.
Failure to complete the Blackstone Merger could have a material adverse effect on our financial condition, results of operations and cash flows.
If the Merger Agreement is terminated and/or the Blackstone Merger is not consummated, we will have incurred substantial expenses, including legal, accounting and financial advisory fees, without realizing the expected benefits of the Blackstone Merger.  In addition, we may also be subject to additional risks including, without limitation:
●
Depending on the reasons for termination of the Merger Agreement, the requirement that we pay out-of-pocket expenses incurred by Blackstone affiliates of up to $10,000,000 and/or a termination fee of up to $50,000,000 (inclusive of expenses paid);
●
Potential disruption to our current plans, operations and businesses, relationships with counterparties, and distraction of our workforce and management team;
●
Potential difficulties in employee retention as a result of termination of the Merger Agreement and/or the failure of the Blackstone Merger to be consummated;
●
Potential need to access external sources of liquidity in the near-term to supplement our liquidity position, which may include asset sales at inopportune prices, issuance of equity that would be dilutive to current stockholders, issuance of new debt and restructuring of existing debt; and
●
The need, in the near term, to amend, extend or refinance our existing credit facilities, which we may not be able to accomplish in a timely fashion or upon terms that allow us to continue to support our business operations
Any such events could have a material adverse effect on our financial condition, results of operations and cash flows.
Failure to complete the Blackstone Merger could adversely affect our stock price .
If the Blackstone Merger is not completed for any reason, the market price of shares of Dynegy’s common stock may decline significantly to the extent the current market price of those shares reflects a market assumption that the proposed Blackstone Merger will be completed.  If the Merger Agreement and/or NRG PSA is terminated and Dynegy’s Board of Directors seeks another merger, asset sale or business combination, we cannot offer any assurance that we will be able to execute on such a transaction or find an acquirer willing to pay an equivalent or better price than the price contemplated to be paid under the Merger Agreement.
Several lawsuits have been filed against Dynegy, its directors and Blackstone challenging the Merger Agreement, and an adverse judgment in such lawsuits may prevent the Blackstone Merger from becoming effective or from becoming effective within the expected timeframe.
Dynegy, its directors and Blackstone have been named, and in some instances Parent, Merger Sub, Blackstone Capital Partners V L.P., NRG and/or certain of Dynegy’s executive officers have also been named, as defendants in purported class action lawsuits brought by certain of our stockholders challenging the proposed Blackstone Merger and seeking, among other things, to enjoin the defendants from consummating the Blackstone Merger on the agreed-upon terms.  If the plaintiffs are successful in obtaining an injunction prohibiting the parties from completing the Blackstone Merger on the terms contemplated by the Merger Agreement, the injunction may prevent the completion of the Blackstone Merger in the expected timeframe or altogether.
We are exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies because some of our facilities do not have long-term coal, natural gas or fuel oil supply agreements.
We purchase the fuel requirements for many of our power generation facilities, primarily those that are natural gas-fired, under short-term contracts or on the spot market.  As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match those required for energy sales, due in part to our need to pre-purchase fuel inventories for reliability and dispatch requirements.
Moreover, profitable operation of many of our coal-fired generation facilities is highly dependent on our ability to procure coal at prices we consider reasonable.  Power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. In the Midwest, our Midwest coal requirements are 100 percent contracted and priced through 2010.  For 2011 and 2012, approximately 35 percent of our coal forecast requirements are contracted, and the price for these volumes will be determined in 2010 under the terms of the coal purchase contract that governs these purchases.  Additionally, our Midwest coal transportation agreement expires in 2013 except for coal transportation for our Vermilion power generation facility, which is hedged through 2010.  We expect any revision or extension to result in higher coal transportation costs.  We have entered into term contracts for South American coal, which we use for our GEN-NE coal facility, and for PRB, which we use for our GEN-MW coal facilities.  We cannot assure you that we will be able to renew our coal procurement and transportation contracts when they terminate on terms that are favorable to us or at all.  Further, our and our suppliers’ ability to procure South American coal is subject to local political and other factors that could have a negative impact on our coal deliveries regardless of our contract situation.  Permit limitations that restrict the sulfur content of coal used at our coal facilities limit our options for coal fuel supply, creating risk for us in terms of our ability to procure coal for periods and at prices we believe are firm and favorable.
If the NRG Sale is completed, the percentage of our generation facilities which are coal-fired will increase, which means that our profitability will become more dependent on our ability to procure coal at prices that allow economic dispatch of our facilities at prevailing market prices.  As a result, our fuel cost and fuel supply risks discussed above may increase, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Further, any changes in the costs of coal, fuel oil, natural gas or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results.  If we are unable to procure fuel for physical delivery at prices we consider favorable, our financial condition, results of operations and cash flows could be materially adversely affected.
If the NRG Sale is completed, the resulting regional concentration of our business in the Midwest may increase the effects of adverse trends or events in that market.
If the NRG Sale is completed, a greater portion of our productive assets would be located in the Midwest region of the United States.  Changes in economic conditions in this market, including changing demographics, or oversupply of or reduced demand for power, could have a material adverse effect on our financial condition, results of operations and cash flows.  A substantial portion of our net income is currently derived from the Midwest region, specifically our Baldwin facility, and if the NRG Sale is completed the region would constitute a significantly larger portion.  Any disruption of production or additional expenses associated with environmental costs as a result of regulatory or legislative actions, weather, and political conditions could have a material adverse effect on our financial condition, results of operations and cash flows.
Currently, our results in the Midwest are exposed to volatility in market prices which could cause us to realize losses in a weak power price environment.
If Dynegy issues or acquires a material amount of its common stock in the future, certain of its stockholders sell a material amount of Dynegy’s common stock or if the Blackstone Merger is consummated, Dynegy’s ability to use its federal net operating losses or alternative minimum tax credits to offset its future taxable income may be limited under Section 382 of the Internal Revenue Code.
Dynegy’s ability to utilize previously incurred federal NOLs and alternative minimum tax (AMT) credits to offset future taxable income would be limited if it were to undergo an “ownership change” within the meaning of Section 382 of the Internal Revenue Code (the “Code”).  In general, an ownership change occurs whenever the percentage of the stock of a corporation owned by “5-percent shareholders” (within the meaning of Section 382 of the Code) increases by more than 50 percentage points over the lowest percentage of the stock of such corporation owned by such “5-percent shareholders” at any time over the preceding three years.
More specifically, depending on prevailing interest rates and our market value at the time of such future ownership change, an ownership change under Section 382 of the Code would establish an annual limitation which might prevent full utilization of the deferred tax assets attributable to our previously incurred federal NOLs and AMT credits against the total future taxable income of a given year. If the Blackstone Merger is consummated our previously incurred federal NOLs will become subject to the limitations set forth in Section 382 of the Code.
The magnitude of such limitations and their effect on us are difficult to assess and depend in part on our value at the time of any such ownership change and prevailing interest rates.  For accounting purposes, at September 30, 2010, Dynegy’s and DHI’s  net operating loss deferred tax asset attributable to our previously incurred federal NOLs was approximately $98 million and $77 million, respectively.
See Also Item 1A—Risk Factors, of our Form 10-K for additional factors, risks and uncertainties that may affect future results.
Upon vesting of restricted stock awarded by Dynegy to employees, shares are withheld to cover the employees’ withholding taxes.  Information on Dynegy’s deemed purchases of equity securities for that purpose during the quarter follows:
Period
(a)
Total Number
of Shares
Purchased
(b)
Average
Price Paid
per Share
(c)
Total Number of Shares Purchased
as Part of
Publicly Announced Plans
or Programs
(d)
Maximum
Number of
Shares that
May Yet Be
Purchased
Under the
Plans or
Programs
July 1-31
— $ — — N/A
August 1-31
— $ — — N/A
September 1-30
48 $ 4.76 — N/A
Total
48 $ 4.76 — N/A
These were the only purchases of equity securities made by us during the three months ended September 30, 2010.  Dynegy does not have a stock repurchase program.
The following documents are included as exhibits to this Form 10-Q
Exhibit Number
Description
2.1
—Agreement and Plan of Merger, dated as of August 13, 2010, among Dynegy Inc., Denali Parent Inc. and Denali Merger Sub Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings Inc. filed on August 13, 2010, File No. 000-29311).
10.1
—Second Amendment to the Dynegy Inc. Restoration Pension Plan, executed on July 2, 2010 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Dynegy Inc. and Dynegy Holdings Inc. filed on August 6, 2010, File No. 000-29311).
*10.2 First Amendment to the Dynegy Inc. Executive Change In Control Severance Pay Plan, dated as of September 22, 2010.
*10.3 Second Amendment to the Dynegy Inc. Restoration Pension Plan, dated as of July 2, 2010.
*10.4 Second Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of September 20, 2010.
**101.INS
XBRL Instance Document
**101.SCH
XBRL Taxonomy Extension Schema Document
Exhibit Number
Description
**101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB
XBRL Taxonomy Extension Label Linkbase Document
**101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
*
Filed herewith.
†
Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.
**
XBRL information is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 193, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.
90
DYNEGY INC. and DYNEGY HOLDINGS INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DYNEGY INC.
Date: November 8, 2010
By:
/s/ Holli C. Nichols
Holli C. Nichols
Executive Vice President and Chief Financial Officer
(Duly Authorized Officer and Principal Financial Officer)
DYNEGY HOLDINGS INC.
Date: November 8, 2010
By:
/s/ Holli C. Nichols
Holli C. Nichols
Executive Vice President and Chief Financial Officer
(Duly Authorized Officer and Principal Financial Officer)
91
TABLE OF CONTENTS
Part I. Financial InformationItem 1 Financial Statements Dynegy Inc. and Dynegy Holdings IncNote 1 Accounting PoliciesNote 2 Proposed Blackstone Merger and Nrg SaleNote 3 Dispositions and Discontinued OperationsNote 4 Noncontrolling InterestsNote 5 InvestmentsNote 6 Risk Management Activities, Derivatives and Financial InstrumentsNote 7 Fair Value MeasurementsNote 8 Impairment ChargesNote 9 Accumulated Other Comprehensive LossNote 10 Variable Interest EntitiesNote 11 DebtNote 12 Related Party TransactionsNote 13 Dynegy S Loss Per ShareNote 14 Commitments and ContingenciesNote 15 Employee Compensation, Savings and Pension PlansNote 16 Income TaxesNote 17 Capital StockNote 18 Segment InformationItem 2 Management S Discussion and Analysis Of Financial Condition and Results Of Operations Dynegy Inc. and Dynegy Holdings IncItem 3 Quantitative and Qualitative Disclosures About Market Risk Dynegy Inc. and Dynegy Holdings IncItem 4 Controls and Procedures Dynegy Inc. and Dynegy Holdings IncPart II. Other InformationItem 1 Legal Proceedings Dynegy Inc. and Dynegy Holdings IncItem 1A Risk Factors Dynegy Inc. and Dynegy Holdings IncItem 2 Unregistered Sales Of Equity Securities and Use Of Proceeds Dynegy IncItem 2 Unregistered Sales Of Equity Securities and Use Of ProceedsItem 6 Exhibits Dynegy Inc. and Dynegy Holdings IncItem 6 Exhibits

Exhibits

*10.2 First Amendment to the Dynegy Inc. Executive Change In Control Severance Pay Plan, dated as of September 22, 2010. *10.3 Second Amendment to the Dynegy Inc. Restoration Pension Plan, dated as of July 2, 2010. *10.4 Second Amendment to the Dynegy Inc. Executive SeverancePay Plan, dated as of September 20, 2010. *31.1 Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *31.1(a) Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *31.2 Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *31.2(a) Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.1(a) Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2(a) Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.