Attached files
file | filename |
---|---|
EX-31.2 - EXHIBIT 31.2 - DYNEGY HOLDINGS, LLC | ex31_2.htm |
EX-31.1 - EXHIBIT 31.1 - DYNEGY HOLDINGS, LLC | ex31_1.htm |
EX-32.2 - EXHIBIT 32.2 - DYNEGY HOLDINGS, LLC | ex32_2.htm |
EX-32.1 - EXHIBIT 32.1 - DYNEGY HOLDINGS, LLC | ex32_1.htm |
EX-31.1A - EXHIBIT 31.1(A) - DYNEGY HOLDINGS, LLC | ex31_1a.htm |
EX-31.2A - EXHIBIT 31.2(A) - DYNEGY HOLDINGS, LLC | ex31_2a.htm |
EX-32.2A - EXHIBIT 32.2(A) - DYNEGY HOLDINGS, LLC | ex32_2a.htm |
EX-32.1A - EXHIBIT 32,1(A) - DYNEGY HOLDINGS, LLC | ex32_1a.htm |
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
__________________
FORM
10-Q
T
|
QUARTERLY REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the quarterly period ended September 30, 2009
£
|
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
T No
£
|
Dynegy
Holdings Inc.
|
Yes
T No
£
|
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
£ No
£
|
Dynegy
Holdings Inc.
|
Yes
£ No
£
|
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.
|
T
|
£
|
£
|
£
|
||||
Dynegy
Holdings Inc.
|
£
|
£
|
T
|
£
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Dynegy
Inc.
|
Yes
£ No
T
|
Dynegy
Holdings Inc.
|
Yes
£ No
T
|
Indicate
the number of shares outstanding of Dynegy Inc.’s classes of common stock, as of
the latest practicable date: Class A common stock, $0.01 par value per share,
505,561,433
shares outstanding as of October 29, 2009; Class B common stock, $0.01 par value
per share, 340,000,000
shares outstanding as of October 29, 2009. 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.
TABLE
OF CONTENTS
Page
|
||
PART
I. FINANCIAL INFORMATION
|
||
Item
1.
|
FINANCIAL
STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.:
|
|
|
||
4 | ||
|
||
5 | ||
|
||
6 | ||
|
||
7 | ||
|
||
8 | ||
|
||
9 | ||
|
||
10 | ||
11
|
||
12
|
||
Item
2.
|
54
|
|
Item
3.
|
87
|
|
Item
4.
|
89
|
|
PART
II. OTHER INFORMATION
|
||
Item
1.
|
90
|
|
Item
1A.
|
90
|
|
Item
2.
|
90
|
|
Item
6.
|
90
|
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, 2009 and constituting nearly 100 percent
of Dynegy’s total consolidated asset base as of September 30,
2009. 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.
|
ACES
|
The
American Clean Energy and Security Act of
2009
|
|
APB
|
Accounting
Principles Board
|
|
BTA
|
Best
technology available
|
|
Cal
ISO
|
The
California Independent System
Operator
|
|
CARB
|
California
Air Resources Board
|
|
CAA
|
Clean
Air Act
|
|
CCA
|
Coal
combustion ash
|
|
CDWR
|
California
Department of Water Resources
|
|
CEC
|
California
Energy Commission
|
|
CFTC
|
Commodity
Futures Trading Commission
|
|
CO2
|
Carbon
Dioxide
|
|
CRM
|
Our
former customer risk management business
segment
|
|
CUSA
|
Chevron
U.S.A. Inc., a wholly owned subsidiary of Chevron
Corporation
|
|
DHI
|
Dynegy
Holdings Inc., Dynegy’s primary financing
subsidiary
|
|
DMG
|
Dynegy
Midwest Generation, Inc.
|
|
DMSLP
|
Dynegy
Midstream Services L.P.
|
|
EPA
|
Environmental
Protection Agency
|
|
FASB
|
Financial
Accounting Standards Board
|
|
FERC
|
Federal
Energy Regulatory 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
|
|
ICC
|
Illinois
Commerce Commission
|
|
IMA
|
In-market
asset availability
|
|
ISO
|
Independent
System Operator
|
|
LNG
|
Liquefied
natural gas
|
|
MISO
|
Midwest
Independent Transmission 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
|
|
PJM
|
PJM
Interconnection, LLC
|
|
PPEA
|
Plum
Point Energy Associates, LLC
|
|
PSD
|
Prevention
of significant deterioration
|
|
PUHCA
|
Public
Utility Holding Company Act of 1935, as
amended
|
|
RGGI
|
Regional
Greenhouse Gas Initiative
|
|
RMR
|
Reliability
Must Run
|
|
RSG
|
Revenue
Sufficiency Guarantee
|
|
SCEA
|
Sandy
Creek Energy Associates, LP
|
|
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
|
PART
I. FINANCIAL INFORMATION
Item
1—FINANCIAL STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.
DYNEGY INC.
CONDENSED
CONSOLIDATED BALANCE SHEETS
(unaudited)
(in millions, except share data)
September 30,
2009
|
December 31,
2008
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and cash equivalents
|
$ | 703 | $ | 693 | ||||
Restricted
cash and investments
|
115 | 87 | ||||||
Short-term
investments
|
2 | 25 | ||||||
Accounts
receivable, net of allowance for doubtful accounts of $22 and $22,
respectively
|
253 | 340 | ||||||
Accounts
receivable, affiliates
|
1 | 1 | ||||||
Inventory
|
157 | 184 | ||||||
Assets
from risk-management activities
|
927 | 1,263 | ||||||
Deferred
income taxes
|
4 | 6 | ||||||
Prepayments
and other current assets
|
339 | 204 | ||||||
Assets
held for sale
|
1,273 | — | ||||||
Total
Current Assets
|
3,774 | 2,803 | ||||||
Property,
Plant and Equipment
|
8,895 | 10,869 | ||||||
Accumulated
depreciation
|
(1,880 | ) | (1,935 | ) | ||||
Property,
Plant and Equipment, Net
|
7,015 | 8,934 | ||||||
Other
Assets
|
||||||||
Unconsolidated
investments
|
— | 15 | ||||||
Restricted
cash and investments
|
1,164 | 1,158 | ||||||
Assets
from risk-management activities
|
295 | 114 | ||||||
Goodwill
|
— | 433 | ||||||
Intangible
assets
|
399 | 437 | ||||||
Accounts
receivable, affiliates
|
8 | 4 | ||||||
Other
long-term assets
|
369 | 315 | ||||||
Total
Assets
|
$ | 13,024 | $ | 14,213 | ||||
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
payable
|
$ | 231 | $ | 303 | ||||
Accrued
interest
|
124 | 56 | ||||||
Accrued
liabilities and other current liabilities
|
149 | 160 | ||||||
Liabilities
from risk-management activities
|
834 | 1,119 | ||||||
Notes
payable and current portion of long-term debt
|
65 | 64 | ||||||
Deferred
income taxes
|
8 | — | ||||||
Liabilities
associated with assets held for sale
|
31 | — | ||||||
Total
Current Liabilities
|
1,442 | 1,702 | ||||||
Long-term
debt
|
5,928 | 5,872 | ||||||
Long-term
debt, affiliates
|
200 | 200 | ||||||
Long-Term
Debt
|
6,128 | 6,072 | ||||||
Other
Liabilities
|
||||||||
Liabilities
from risk-management activities
|
313 | 288 | ||||||
Deferred
income taxes
|
945 | 1,166 | ||||||
Other
long-term liabilities
|
451 | 500 | ||||||
Total
Liabilities
|
$ | 9,279 | $ | 9,728 | ||||
Commitments
and Contingencies (Note 13)
|
||||||||
Stockholders’
Equity
|
||||||||
Class
A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at
September 30, 2009 and December 31, 2008; 508,175,228 and 505,821,277
shares issued and outstanding at September 30, 2009 and December 31, 2008,
respectively
|
5 | 5 | ||||||
Class
B Common Stock, $0.01 par value, 850,000,000 shares authorized at
September 30,
2009 and December 31, 2008; 340,000,000 shares issued and outstanding at
September 30, 2009 and December 31, 2008
|
3 | 3 | ||||||
Additional
paid-in capital
|
6,494 | 6,485 | ||||||
Subscriptions
receivable
|
(2 | ) | (2 | ) | ||||
Accumulated
other comprehensive loss, net of tax
|
(179 | ) | (215 | ) | ||||
Accumulated
deficit
|
(2,582 | ) | (1,690 | ) | ||||
Treasury
stock, at cost,
2,777,376 and 2,568,286 shares at September 30, 2009 and December
31, 2008, respectively
|
(71 | ) | (71 | ) | ||||
Total
Dynegy Inc. Stockholders’ Equity
|
3,668 | 4,515 | ||||||
Noncontrolling
interests
|
77 | (30 | ) | |||||
Total
Stockholders’ Equity
|
3,745 | 4,485 | ||||||
Total
Liabilities and Stockholders’ Equity
|
$ | 13,024 | $ | 14,213 |
See the
notes to condensed consolidated financial statements.
DYNEGY INC.
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
(in millions, except per share data)
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenues
|
$ | 673 | $ | 1,759 | $ | 2,027 | $ | 2,550 | ||||||||
Cost
of sales
|
(286 | ) | (498 | ) | (927 | ) | (1,326 | ) | ||||||||
Operating
and maintenance expense, exclusive of depreciation shown separately
below
|
(121 | ) | (122 | ) | (373 | ) | (344 | ) | ||||||||
Depreciation
and amortization expense
|
(83 | ) | (85 | ) | (258 | ) | (258 | ) | ||||||||
Gain
on sale of assets
|
— | 57 | — | 83 | ||||||||||||
Goodwill
impairments
|
— | — | (433 | ) | — | |||||||||||
Impairment
and other charges, exclusive of goodwill impairments shown separately
above
|
(148 | ) | — | (535 | ) | — | ||||||||||
General
and administrative expenses
|
(42 | ) | (48 | ) | (125 | ) | (126 | ) | ||||||||
Operating
income (loss)
|
(7 | ) | 1,063 | (624 | ) | 579 | ||||||||||
Earnings
(losses) from unconsolidated investments
|
(8 | ) | (5 | ) | 13 | (17 | ) | |||||||||
Interest
expense
|
(115 | ) | (105 | ) | (311 | ) | (322 | ) | ||||||||
Other
income and expense, net
|
2 | 11 | 10 | 46 | ||||||||||||
Income
(loss) from continuing operations before income taxes
|
(128 | ) | 964 | (912 | ) | 286 | ||||||||||
Income
tax benefit (expense) (Note 15)
|
34 | (392 | ) | 147 | (121 | ) | ||||||||||
Income
(loss) from continuing operations
|
(94 | ) | 572 | (765 | ) | 165 | ||||||||||
Income
(loss) from discontinued operations, net of tax (expense) benefit of $84,
$(22), $91 and $(10), respectively (Note 2)
|
(129 | ) | 32 | (141 | ) | 13 | ||||||||||
Net
income (loss)
|
(223 | ) | 604 | (906 | ) | 178 | ||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(11 | ) | (1 | ) | (14 | ) | (3 | ) | ||||||||
Net
income (loss) attributable to Dynegy Inc.
|
$ | (212 | ) | $ | 605 | $ | (892 | ) | $ | 181 | ||||||
Earnings
(Loss) Per Share (Note 12):
|
||||||||||||||||
Basic
earnings (loss) per share attributable to Dynegy Inc. common
stockholders:
|
||||||||||||||||
Earnings
(loss) from continuing operations
|
$ | (0.10 | ) | $ | 0.68 | $ | (0.89 | ) | $ | 0.20 | ||||||
Income
(loss) from discontinued operations
|
(0.15 | ) | 0.04 | (0.17 | ) | 0.02 | ||||||||||
Basic
earnings (loss) per share attributable to Dynegy Inc. common
stockholders
|
$ | (0.25 | ) | $ | 0.72 | $ | (1.06 | ) | $ | 0.22 | ||||||
Diluted
earnings (loss) per share attributable to Dynegy Inc. common
stockholders:
|
||||||||||||||||
Earnings
(loss) from continuing operations
|
$ | (0.10 | ) | $ | 0.68 | $ | (0.89 | ) | $ | 0.20 | ||||||
Income
(loss) from discontinued operations.
|
(0.15 | ) | 0.04 | (0.17 | ) | 0.02 | ||||||||||
Diluted
earnings (loss) per share attributable to Dynegy Inc. common
stockholders
|
$ | (0.25 | ) | $ | 0.72 | $ | (1.06 | ) | $ | 0.22 | ||||||
Basic
shares outstanding
|
843 | 840 | 842 | 840 | ||||||||||||
Diluted
shares outstanding
|
846 | 842 | 845 | 842 |
See the
notes to condensed consolidated financial statements.
DYNEGY INC.
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(in millions)
Nine Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||
Net
income (loss)
|
$ | (906 | ) | $ | 178 | |||
Adjustments
to reconcile net loss to net cash flows from operating
activities:
|
||||||||
Depreciation
and amortization
|
279 | 281 | ||||||
Goodwill
impairments
|
433 | — | ||||||
Impairment
and other charges, exclusive of goodwill impairments shown separately
above
|
793 | — | ||||||
(Earnings)
losses from unconsolidated investments, net of cash
distributions
|
(13 | ) | 17 | |||||
Risk-management
activities
|
73 | (127 | ) | |||||
Gain
on sale of assets
|
(10 | ) | (83 | ) | ||||
Deferred
income taxes
|
(246 | ) | 116 | |||||
Legal
and settlement charges
|
— | 7 | ||||||
Other
|
66 | 37 | ||||||
Changes
in working capital:
|
||||||||
Accounts
receivable
|
(4 | ) | 43 | |||||
Inventory
|
(7 | ) | 27 | |||||
Prepayments
and other assets
|
(134 | ) | (75 | ) | ||||
Accounts
payable and accrued liabilities
|
81 | 75 | ||||||
Changes
in non-current assets
|
(91 | ) | (84 | ) | ||||
Changes
in non-current liabilities
|
(10 | ) | (15 | ) | ||||
Net
cash provided by operating activities
|
304 | 397 | ||||||
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||
Capital
expenditures
|
(429 | ) | (460 | ) | ||||
Unconsolidated
investments
|
1 | (1 | ) | |||||
Proceeds
from asset sales, net
|
105 | 452 | ||||||
Decrease
(increase) in short-term investments
|
14 | (127 | ) | |||||
(Increase)
decrease in restricted cash and restricted investments
|
(35 | ) | 17 | |||||
Other
investing
|
3 | 11 | ||||||
Net
cash used in investing activities
|
(341 | ) | (108 | ) | ||||
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||
Proceeds
from long-term borrowings, net
|
75 | 153 | ||||||
Repayments
of long-term borrowings, net
|
(28 | ) | (21 | ) | ||||
Proceeds
from issuance of capital stock
|
— | 2 | ||||||
Other
financing, net
|
— | (1 | ) | |||||
Net
cash provided by financing activities
|
47 | 133 | ||||||
Net
increase in cash and cash equivalents
|
10 | 422 | ||||||
Cash
and cash equivalents, beginning of period
|
693 | 328 | ||||||
Cash
and cash equivalents, end of period
|
$ | 703 | $ | 750 | ||||
Other
non-cash investing activity:
|
||||||||
Non-cash
capital expenditures
|
$ | 19 | $ | 3 |
See the
notes to condensed consolidated financial statements.
DYNEGY INC.
CONDENSED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited)
(in millions)
Three Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
Net
income (loss)
|
$ | (223 | ) | $ | 604 | |||
Cash
flow hedging activities, net:
|
||||||||
Unrealized
mark-to-market gains (losses) arising during period, net
|
45 | (21 | ) | |||||
Reclassification
of mark-to-market losses to earnings, net
|
1 | 3 | ||||||
Deferred
gains (losses) on cash flow hedges, net
|
(2 | ) | 2 | |||||
Changes
in cash flow hedging activities, net (net of tax (expense) benefit of
$(11) and $4, respectively)
|
44 | (16 | ) | |||||
Amortization
of unrecognized prior service cost and actuarial loss (net of tax benefit
of $2 and zero)
|
(1 | ) | — | |||||
Unconsolidated
investments other comprehensive loss, net (net of tax benefit of $3 and
$3)
|
(3 | ) | (4 | ) | ||||
Other
comprehensive income (loss), net of tax
|
40 | (20 | ) | |||||
Comprehensive income
(loss)
|
(183 | ) | 584 | |||||
Less:
Comprehensive income (loss) attributable to the noncontrolling
interests
|
25 | (11 | ) | |||||
Comprehensive income (loss)
attributable to Dynegy Inc.
|
$ | (208 | ) | $ | 595 |
Nine Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
Net
income (loss)
|
$ | (906 | ) | $ | 178 | |||
Cash
flow hedging activities, net:
|
||||||||
Unrealized
mark-to-market gains (losses) arising during period, net
|
160 | (27 | ) | |||||
Reclassification
of mark-to-market losses to earnings, net
|
1 | 10 | ||||||
Deferred
losses on cash flow hedges, net
|
(8 | ) | — | |||||
Changes
in cash flow hedging activities, net (net of tax (expense) benefit of
$(26) and 4,
respectively)
|
153 | (17 | ) | |||||
Amortization
of unrecognized prior service cost and actuarial gain (net of tax expense
of $3 and zero)
|
1 | 1 | ||||||
Net
unrealized losses, (net of tax benefit of zero and $8,
respectively)
|
— | (12 | ) | |||||
Unconsolidated
investments other comprehensive income (loss), net (net of tax (expense)
benefit of $(2) and $7)
|
3 | (11 | ) | |||||
Other
comprehensive income (loss), net of tax
|
157 | (39 | ) | |||||
Comprehensive
income (loss)
|
(749 | ) | 139 | |||||
Less:
Comprehensive income (loss) attributable to the noncontrolling
interests
|
107 | (15 | ) | |||||
Comprehensive income (loss)
attributable to Dynegy Inc.
|
$ | (856 | ) | $ | 154 |
See the
notes to condensed consolidated financial statements.
DYNEGY HOLDINGS INC.
CONDENSED
CONSOLIDATED BALANCE SHEET
(unaudited)
(in millions)
September 30,
2009
|
December 31,
2008
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and cash equivalents
|
$ | 519 | $ | 670 | ||||
Restricted
cash and investments
|
115 | 87 | ||||||
Short-term
investments
|
2 | 24 | ||||||
Accounts
receivable, net of allowance for doubtful accounts of $20 and $20,
respectively
|
255 | 343 | ||||||
Accounts
receivable, affiliates
|
1 | 1 | ||||||
Inventory
|
157 | 184 | ||||||
Assets
from risk-management activities
|
927 | 1,263 | ||||||
Deferred
income taxes
|
4 | 4 | ||||||
Prepayments
and other current assets
|
340 | 204 | ||||||
Assets
held for sale
|
1,273 | — | ||||||
Total
Current Assets
|
3,593 | 2,780 | ||||||
Property,
Plant and Equipment
|
8,895 | 10,869 | ||||||
Accumulated
depreciation
|
(1,880 | ) | (1,935 | ) | ||||
Property,
Plant and Equipment, Net
|
7,015 | 8,934 | ||||||
Other
Assets
|
||||||||
Restricted
cash and investments
|
1,164 | 1,158 | ||||||
Assets
from risk-management activities
|
295 | 114 | ||||||
Goodwill
|
— | 433 | ||||||
Intangible
assets
|
399 | 437 | ||||||
Accounts
receivable, affiliates
|
8 | 4 | ||||||
Other
long-term assets
|
368 | 314 | ||||||
Total
Assets
|
$ | 12,842 | $ | 14,174 | ||||
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
payable
|
$ | 231 | $ | 284 | ||||
Accrued
interest
|
124 | 56 | ||||||
Accrued
liabilities and other current liabilities
|
147 | 157 | ||||||
Liabilities
from risk-management activities
|
834 | 1,119 | ||||||
Notes
payable and current portion of long-term debt
|
65 | 64 | ||||||
Deferred
income taxes
|
10 | 1 | ||||||
Liabilities
associated with assets held for sale
|
31 | — | ||||||
Total
Current Liabilities
|
1,442 | 1,681 | ||||||
Long-term
debt
|
5,928 | 5,872 | ||||||
Long-term
debt, affiliates
|
200 | 200 | ||||||
Long-Term
Debt
|
6,128 | 6,072 | ||||||
Other
Liabilities
|
||||||||
Liabilities
from risk-management activities
|
313 | 288 | ||||||
Deferred
income taxes
|
808 | 1,052 | ||||||
Other
long-term liabilities
|
451 | 498 | ||||||
Total
Liabilities
|
9,142 | 9,591 | ||||||
Commitments
and Contingencies (Note 13)
|
||||||||
Stockholders’
Equity
|
||||||||
Capital
Stock, $1 par value, 1,000 shares authorized at September 30, 2009 and
December 31, 2008
|
— | — | ||||||
Additional
paid-in capital
|
5,545 | 5,684 | ||||||
Affiliate
receivable
|
(823 | ) | (827 | ) | ||||
Accumulated
other comprehensive loss, net of tax
|
(179 | ) | (215 | ) | ||||
Accumulated
deficit
|
(920 | ) | (29 | ) | ||||
Total
Dynegy Holdings Inc. Stockholder’s Equity
|
3,623 | 4,613 | ||||||
Noncontrolling
interests
|
77 | (30 | ) | |||||
Total
Stockholders’ Equity
|
3,700 | 4,583 | ||||||
Total
Liabilities and Stockholders’ Equity
|
$ | 12,842 | $ | 14,174 |
See the
notes to condensed consolidated financial statements.
DYNEGY HOLDINGS INC.
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
(in millions)
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenues
|
$ | 673 | $ | 1,759 | $ | 2,027 | $ | 2,550 | ||||||||
Cost
of sales
|
(286 | ) | (498 | ) | (927 | ) | (1,326 | ) | ||||||||
Operating
and maintenance expense, exclusive of depreciation shown separately
below
|
(121 | ) | (122 | ) | (375 | ) | (344 | ) | ||||||||
Depreciation
and amortization expense
|
(83 | ) | (85 | ) | (258 | ) | (258 | ) | ||||||||
Gain
on sale of assets
|
— | 57 | — | 83 | ||||||||||||
Goodwill
impairments
|
— | — | (433 | ) | — | |||||||||||
Impairment
and other charges, exclusive of goodwill impairments shown separately
above
|
(148 | ) | — | (535 | ) | — | ||||||||||
General
and administrative expenses
|
(42 | ) | (48 | ) | (125 | ) | (126 | ) | ||||||||
Operating
income (loss)
|
(7 | ) | 1,063 | (626 | ) | 579 | ||||||||||
Earnings
(losses) from unconsolidated investments
|
(8 | ) | (5 | ) | 12 | (7 | ) | |||||||||
Interest
expense
|
(115 | ) | (105 | ) | (311 | ) | (322 | ) | ||||||||
Other
income and expense, net
|
2 | 11 | 9 | 45 | ||||||||||||
Income
(loss) from continuing operations before income taxes
|
(128 | ) | 964 | (916 | ) | 295 | ||||||||||
Income
tax benefit (expense) (Note 15)
|
35 | (391 | ) | 152 | (127 | ) | ||||||||||
Income
(loss) from continuing operations
|
(93 | ) | 573 | (764 | ) | 168 | ||||||||||
Income
(loss) from discontinued operations, net of tax (expense) benefit of $74,
$(22), $91 and $(10), respectively (Note 2)
|
(139 | ) | 32 | (141 | ) | 13 | ||||||||||
Net
income (loss)
|
(232 | ) | 605 | (905 | ) | 181 | ||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(11 | ) | (1 | ) | (14 | ) | (3 | ) | ||||||||
Net
income (loss) attributable to Dynegy Holdings Inc.
|
$ | (221 | ) | $ | 606 | $ | (891 | ) | $ | 184 |
See the
notes to condensed consolidated financial statements.
DYNEGY HOLDINGS INC.
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(in millions)
Nine Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
||||||||
Net
income (loss)
|
$ | (905 | ) | $ | 181 | |||
Adjustments
to reconcile net loss to net cash flows from operating
activities:
|
||||||||
Depreciation
and amortization
|
279 | 281 | ||||||
Goodwill
impairments
|
433 | — | ||||||
Impairment
and other charges, exclusive of goodwill impairments shown separately
above
|
793 | — | ||||||
(Earnings)
losses from unconsolidated investments, net of cash
distributions
|
(12 | ) | 7 | |||||
Risk-management
activities
|
73 | (127 | ) | |||||
Gain
on sale of assets, net
|
(10 | ) | (83 | ) | ||||
Deferred
income taxes
|
(248 | ) | 123 | |||||
Legal
and settlement charges
|
— | 7 | ||||||
Other
|
64 | 33 | ||||||
Changes
in working capital:
|
||||||||
Accounts
receivable
|
(4 | ) | 43 | |||||
Inventory
|
(7 | ) | 27 | |||||
Prepayments
and other assets
|
(134 | ) | (75 | ) | ||||
Accounts
payable and accrued liabilities
|
100 | 76 | ||||||
Changes
in non-current assets
|
(91 | ) | (84 | ) | ||||
Changes
in non-current liabilities
|
(9 | ) | (16 | ) | ||||
Net
cash provided by operating activities
|
322 | 393 | ||||||
CASH
FLOWS FROM INVESTING ACTIVITIES:
|
||||||||
Capital
expenditures
|
(429 | ) | (460 | ) | ||||
Unconsolidated
investments
|
— | 10 | ||||||
Proceeds
from asset sales, net
|
105 | 452 | ||||||
Decrease
(increase) in short-term investments
|
13 | (120 | ) | |||||
(Increase)
decrease in restricted cash and restricted investments
|
(35 | ) | 17 | |||||
Affiliate
transactions
|
(2 | ) | 2 | |||||
Other
investing
|
3 | 7 | ||||||
Net
cash used in investing activities
|
(345 | ) | (92 | ) | ||||
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
||||||||
Proceeds
from long-term borrowings, net
|
75 | 153 | ||||||
Repayments
to long-term borrowings
|
(28 | ) | (21 | ) | ||||
Dividend
to affiliate
|
(175 | ) | — | |||||
Other
financing, net
|
— | (1 | ) | |||||
Net
cash provided by (used in) financing activities
|
(128 | ) | 131 | |||||
Net
increase (decrease) in cash and cash equivalents
|
(151 | ) | 432 | |||||
Cash
and cash equivalents, beginning of period
|
670 | 292 | ||||||
Cash
and cash equivalents, end of period
|
$ | 519 | $ | 724 | ||||
Other
non-cash investing activity:
|
||||||||
Non-cash
capital expenditures
|
$ | 19 | $ | 3 |
See the
notes to condensed consolidated financial statements.
DYNEGY HOLDINGS INC.
CONDENSED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited)
(in millions)
Three Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
Net
income (loss)
|
$ | (232 | ) | $ | 605 | |||
Cash
flow hedging activities, net:
|
||||||||
Unrealized
mark-to-market gains (losses) arising during period, net
|
45 | (21 | ) | |||||
Reclassification
of mark-to-market losses to earnings, net
|
1 | 3 | ||||||
Deferred
gains (losses) on cash flow hedges, net
|
(2 | ) | 2 | |||||
Changes
in cash flow hedging activities, net (net of tax (expense) benefit of
$(11) and $4, respectively)
|
44 | (16 | ) | |||||
Amortization
of unrecognized prior service cost and actuarial loss (net of tax expense
of $2 and
zero)
|
(1 | ) | — | |||||
Unconsolidated
investments other comprehensive loss, net (net of tax benefit of $3 and
$3)
|
(3 | ) | (4 | ) | ||||
Other
comprehensive income (loss), net of tax
|
40 | (20 | ) | |||||
Comprehensive
income (loss)
|
(192 | ) | 585 | |||||
Less:
Comprehensive income (loss) attributable to the noncontrolling
interests
|
25 | (11 | ) | |||||
|
||||||||
Comprehensive
income (loss) attributable to Dynegy Holdings Inc.
|
$ | (217 | ) | $ | 596 |
Nine Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
Net
income (loss)
|
$ | (905 | ) | $ | 181 | |||
Cash
flow hedging activities, net:
|
||||||||
Unrealized
mark-to-market gains (losses) arising during period, net
|
160 | (27 | ) | |||||
Reclassification
of mark-to-market losses to earnings, net
|
1 | 10 | ||||||
Deferred
losses on cash flow hedges, net
|
(8 | ) | — | |||||
Changes
in cash flow hedging activities, net (net of tax (expense) benefit of
$(26) and $4, respectively)
|
153 | (17 | ) | |||||
Amortization
of unrecognized prior service cost and actuarial gain (net of tax expense
of $3 and
zero)
|
1 | 1 | ||||||
Net
unrealized loss on securities, net (net of tax benefit of zero and $8,
respectively)
|
— | (12 | ) | |||||
Unconsolidated
investments other comprehensive income (loss), net (net of tax (expense)
benefit of $(2) and $7)
|
3 | (11 | ) | |||||
Other
comprehensive income (loss), net of tax
|
157 | (39 | ) | |||||
Comprehensive
income (loss)
|
(748 | ) | 142 | |||||
Less:
Comprehensive income (loss) attributable to the noncontrolling
interests
|
107 | (15 | ) | |||||
Comprehensive
income (loss) attributable to Dynegy Holdings Inc.
|
$ | (855 | ) | $ | 157 |
See the
notes to condensed consolidated financial statements.
DYNEGY INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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. The year-end condensed consolidated balance
sheet data was derived from audited financial statements, as adjusted for the
adoption of authoritative guidance for noncontrolling interests as discussed
below. 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, 2008 filed on
February 26, 2009, as supplemented by our Current Report on Form 8-K dated
September 28, 2009, which we refer to as each registrant’s “Form
10-K”.
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.
Accounting
Principles Adopted
Business
Combinations. On January 1, 2009, we adopted authoritative
guidance issued by the Financial Accounting Standards Board (“FASB”) on business
combinations. The guidance requires the acquiring entity in a
business combination to recognize the assets acquired and liabilities assumed in
the transaction; establishes the acquisition-date fair value as the measurement
objective for all assets acquired and liabilities assumed; and requires the
acquirer to disclose to investors and other users of the financial statements
all the information they need to evaluate and understand the nature and
financial effect of the business combination. The adoption of this
statement had no impact on our financial statements.
Fair Value
Measurements. On January 1, 2009, we adopted authoritative
guidance issued by the for nonfinancial assets and liabilities measured at fair
value on a nonrecurring basis, except for items that are recognized or disclosed
at fair value in the financial statements on a recurring basis (at least
annually). Please read Note 5—Fair Value Measurements for further
discussion.
Noncontrolling
Interests. On January 1, 2009, we adopted authoritative
guidance issued by the FASB for noncontrolling interests. Please read
Note 3—Noncontrolling Interests for further discussion.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Disclosures about
Derivative Instruments and Hedging Activities. On January 1,
2009, we adopted authoritative guidance issued by the FASB for the disclosure of
derivative instruments and hedging activities. Please read Note
4—Risk Management Activities, Derivatives and Financial Instruments for further
discussion.
Subsequent
Events. On June 30, 2009, we adopted authoritative guidance
issued by the FASB which provides guidance on management’s assessment of
subsequent events. We have evaluated subsequent events
through November 5, 2009, the date our financial statements were issued and up
to the time of the filing of our financial statements with the SEC.
Accounting
Standards Codification. Effective July 1, 2009, we adopted
authoritative guidance issued by the FASB which superseded all then-existing
non-SEC accounting and reporting standards. All other
non-grandfathered non-SEC accounting literature not included in the Codification
is no longer considered authoritative. The adoption of this adopted
authoritative had no impact on our financial condition, results of operations or
cash flows.
Third Party
Credit Enhancement. On January 1, 2009, we adopted
authoritative guidance issued by the FASB which applies to liabilities issued
with an inseparable third-party credit enhancement when they are measured or
disclosed at fair value on a recurring basis. Please read Note 5—Fair
Value Measurements for further discussion.
Fair Value of
Financial Instruments. On June 30, 2009, we adopted
authoritative guidance issued by the FASB which requires the disclosure of the
estimated fair value of financial instruments. Please read Note
5—Fair Value Measurements for further discussion.
Determining Fair
Value When the Volume and Level of Activity for the Asset or Liability Have
Significantly Decreased and Identifying Transactions That Are Not
Orderly. On June 30, 2009, we adopted authoritative guidance
issued by the FASB which provides guidance on (i) estimating the fair value of
an asset or liability when the volume and level of activity for the asset or
liability have significantly decreased and (ii) identifying transactions that
are not orderly. The adoption of this authoritative guidance had no
impact on our financial statements. Please read Note 5—Fair Value
Measurements for further discussion.
Accounting
Principles Not Yet Adopted
Employers’
Disclosures about Pensions and Other Postretirement
Benefits. On January 1, 2009, the FASB issued authoritative
guidance to provide guidance on an employer’s disclosures about plan assets of a
defined benefit pension or other postretirement plan. The objectives
of the disclosures about plan assets in an employer’s defined benefit pension or
other postretirement plan are to provide users of financial statements with an
understanding of: (i) how investment allocation decisions are made, including
the factors that are pertinent to an understanding of investment policies and
strategies; (ii) the major categories of plan assets; (iii) the inputs and
valuation techniques used to measure the fair value of plan assets; (iv) the
effect of fair value measurements using significant unobservable inputs (Level
3) on changes in plan assets for the period and (v) significant concentrations
of risk within plan assets. The disclosures about plan assets
required by this authoritative guidance are to be provided for fiscal years
ending after December 15, 2009. We are currently evaluating the
disclosure implications of this standard; however, this authoritative guidance
will have no impact on our financial condition, results of operations or cash
flows.
Variable Interest
Entities. On June 12, 2009, the FASB issued authoritative
guidance which amends the consolidation guidance that applies to variable
interest entities. The FASB’s objective in issuing this authoritative
guidance is to improve financial reporting by enterprises involved with variable
interest entities. This authoritative guidance is effective for
fiscal years beginning after November 15, 2009. We are currently
evaluating the impact of this standard on our consolidated financial
statements.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
2—Dispositions and Discontinued Operations
Dispositions
LS Power
Transaction. On August 9, 2009, we entered into a purchase and
sale agreement with LS Power Partners, L.P. and certain of its
affiliates (collectively, “LS Power”) pursuant to which we agreed to (i) sell to
LS Power our interests in: Dynegy Arlington Valley, LLC; Griffith Energy LLC;
Bridgeport Energy LLC; Rocky Road Power, LLC; Tilton Energy LLC; Riverside
Generating Company, L.L.C.; Bluegrass Generation Company, L.L.C.; Renaissance
Power, L.L.C.; Sandy Creek Services, LLC; and Dynegy Sandy Creek Holdings, LLC,
and (ii) issue to Adio Bond, LLC, an affiliate of LS Power, $235 million
aggregate principal amount of DHI 7.50 percent senior unsecured notes due
2015. In exchange for the ownership interests and notes, we will
receive at closing (i) approximately $1.025 billion in cash (consisting, in
part, of the release of $175 million of restricted cash on our unaudited
condensed consolidated balance sheets that was used to support our funding
commitment to Sandy Creek and approximately $200 million for the unsecured
notes), subject to working capital adjustments, and (ii) 245 million shares of
Dynegy’s Class B common stock (currently held by LS Power), with the remaining
95 million shares of Dynegy’s Class B common stock held by LS Power converted at
closing to the same number of shares of Dynegy’s Class A common
stock. Concurrent with the execution of the purchase and sale
agreement, LS Power and Dynegy entered into a new shareholder agreement, which
upon the closing of the transaction will eliminate special approval rights,
board representation and certain other rights associated with the former Class B
common shares and limit the acquisition and transfer of Dynegy’s Class A common
stock to be held by LS Power. This shareholder agreement provides
that following closing we cannot issue Dynegy’s equity securities for our own
purposes until the earlier of (i) 121 days following the closing of the
transaction with LS Power or (ii) the first date following closing of the
transaction in which LS Power owns, in aggregate, less than 10 percent of
Dynegy’s then outstanding Class A common stock. The sale is expected
to close in the fourth quarter 2009 assuming all necessary closing conditions
are satisfied or waived.
In
connection with the signing of the purchase and sale agreement with LS Power on
August 9, 2009, our Arizona power generation assets, as defined below, and our
Bluegrass power generation facility met the requirements for classification as
discontinued operations. Accordingly, the results of operations for
these facilities have been reclassified as discontinued operations for all
periods presented (see Discontinued Operations discussed below). The
Renaissance, Tilton, Riverside/Foothills, Rocky Road and Bridgeport power
generation facilities did not meet the requirements for classification as
discontinued operations, based on our continuing presence in the markets where
these assets are located; however, these assets are reported as held for
sale. The major classes of current and long-term assets and
liabilities at September 30, 2009 classified as assets held for sale or
liabilities associated with assets held for sale and included in the LS Power
transaction are as follows (in millions):
Current
Assets:
|
||||
Accounts
receivable
|
$ | 39 | ||
Inventory
|
18 | |||
Assets
from risk management activities
|
5 | |||
Prepayments
and other current assets
|
11 | |||
Total
Current Assets
|
$ | 73 | ||
Long-Term
Assets:
|
||||
Property,
plant and equipment
|
$ | 1,163 | ||
Assets
from risk management activities
|
4 | |||
Other
|
33 | |||
Total
Long-Term Assets
|
$ | 1,200 | ||
Current
Liabilities:
|
||||
Accounts
payable
|
$ | 17 | ||
Current
liabilities and accrued liabilities
|
8 | |||
Total
Current Liabilities
|
$ | 25 | ||
Long-Term
Liabilities:
|
||||
Other
|
$ | 6 | ||
Total
Long-Term Liabilities
|
$ | 6 |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
We
recorded pre-tax impairment charges of $147 million and $326 million, inclusive
of costs to sell, related to the assets included in the LS Power transaction
that did not meet the criteria for classification as discontinued operations in
the three and nine month periods ended September 30, 2009, respectively, which
is included in Impairment and other charges in our unaudited condensed
consolidated statements of operations. Please read Note 6—Impairment
Charges for further discussion of these impairments.
We
discontinued depreciation and amortization of property, plant and equipment
included in the LS Power transaction that did not meet the criteria for
classification as discontinued operations during the third quarter
2009. Depreciation and amortization expense related to these assets
totaled $3 million and $24 million in the three and nine month periods ended
September 30, 2009, respectively, compared to $8 million and $23 million in the
three and nine months ended September 30, 2008, respectively.
Rolling
Hills. On July 31, 2008, we completed the sale of the Rolling
Hills power generation facility (“Rolling Hills”) to an affiliate of Tenaska
Capital Management, LLC for approximately $368 million, net of transaction
costs. We recorded a $57 million gain in the third quarter 2008
related to the sale, which is included in Gain on sale of assets in our
unaudited condensed consolidated statements of operations. The gain
includes the impact of allocating approximately $5 million of goodwill
associated with the GEN-MW reporting unit to Rolling Hills. The
amount of goodwill allocated to Rolling Hills was based on the relative fair
values of Rolling Hills and the portion of the GEN-MW reporting unit being
retained.
The sale
of Rolling Hills represented the sale of a significant portion of a reporting
unit. As such, we assessed the goodwill of the GEN-MW reporting unit
for impairment during the third quarter 2008. No impairment was
indicated as a result of this assessment.
We
discontinued depreciation and amortization of Rolling Hills’ property, plant and
equipment during the second quarter 2008. Depreciation and
amortization expense related to Rolling Hills totaled zero and approximately $3
million in the three and nine month periods ended September 30, 2008,
respectively.
NYMEX
Securities. In November 2006, the New York Mercantile Exchange
(“NYMEX”) completed its initial public offering. At the time, we had
two membership seats on the NYMEX, and therefore, we received 90,000 NYMEX
shares for each membership seat. During August 2007, we sold 30,000
shares for approximately $4 million, and we recognized a gain of $4
million. During the second quarter 2008, we sold our remaining
150,000 shares and both of our membership seats for approximately $16 million,
and we recognized a gain of $15 million, which is included in Gain on sale of
assets in our unaudited condensed consolidated statements of operations
partially offset by a reduction of $8 million, net of tax of $5 million, in our
unaudited condensed consolidated statements of other comprehensive
loss.
Oyster
Creek. In May 2008, we sold the beneficial interest in Oyster
Creek Limited for approximately $11 million, which is included in Gain on sale
of assets in our unaudited condensed consolidated statements of
operations.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Discontinued
Operations
Arlington Valley,
Griffith and Bluegrass. On August 9, 2009, we entered into a
purchase and sale agreement to sell our interests in, among others, the
Arlington Valley, Griffith and Bluegrass power generation facilities as part of
the LS Power transaction, as discussed above.
The
Arlington Valley and Griffith facilities (collectively, the “Arizona
power generation facilities”), as well as our Bluegrass facility, met the
criteria of held for sale during the third quarter 2009 and are classified as
such on our unaudited condensed consolidated balance sheet. At that
time, we discontinued depreciation and amortization of Arlington Valley’s,
Griffith’s and Bluegrass’ property, plant and equipment. Depreciation
and amortization expense related to the Arizona power generation facilities
totaled approximately $4 and $14 million in the three and nine months ended
September 30, 2009, respectively, compared to approximately $5 million and $15
million in the three and nine months ended September 30, 2008,
respectively. Depreciation and amortization expense related to
Bluegrass totaled approximately zero and $1 million in the three and nine months
ended September 30, 2009, respectively, compared to approximately zero and $1
million in the three and nine months ended September 30, 2008,
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. Please read Note 6—Impairment Charges for
further discussion. 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. We recorded a $10 million pre-tax gain during the second
quarter 2009 related to the sale, which is included in Income from discontinued
operations on our unaudited condensed consolidated statements of
operations.
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 approximately zero and $1
million in the three and nine months ended September 30, 2009, respectively,
compared to approximately $1 million and $3 million in the three and nine months
ended September 30, 2008, respectively. We are reporting the results
of Heard County’s operations in discontinued operations for all periods
presented.
Calcasieu. On
March 31, 2008, we completed the sale of the Calcasieu power generation facility
for approximately $56 million, net of transaction costs.
Calcasieu
was classified as held for sale during the first quarter 2007. At
that time, we discontinued depreciation and amortization of Calcasieu’s
property, plant and equipment. Depreciation and amortization expense
related to Calcasieu totaled zero in the three and nine months ended September
30, 2008. We are reporting the results of Calcasieu’s operations in
discontinued operations for the three months ended March 31,
2008.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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
|
— | (213 | )(2) | (213 | ) | |||||||
Loss
from operations after taxes
|
— | (129 | ) | (129 | ) | |||||||
Three
Months Ended September 30, 2008
|
||||||||||||
Revenues
|
$ | 1 | $ | 126 | $ | 127 | ||||||
Income
from operations before taxes
|
— | 53 | 53 | |||||||||
Income
from operations after taxes
|
— | 32 | 32 | |||||||||
Gain
on sale before taxes
|
— | 1 | 1 | |||||||||
Gain
on sale after taxes
|
— | — | — | |||||||||
Nine
Months Ended September 30, 2009
|
||||||||||||
Revenues
|
$ | 4 | $ | 96 | $ | 100 | ||||||
Loss
from operations before taxes
|
(23 | )(1) | (219 | )(2) | (242 | ) | ||||||
Loss
from operations after taxes
|
(14 | ) | (133 | ) | (147 | ) | ||||||
Gain
on sale before taxes
|
— | 10 | 10 | |||||||||
Gain
on sale after taxes
|
— | 6 | 6 | |||||||||
Nine
Months Ended September 30, 2008
|
||||||||||||
Revenues
|
$ | 2 | $ | 202 | $ | 204 | ||||||
Income
(loss) from operations before taxes
|
(1 | ) | 24 | 23 | ||||||||
Income
(loss) from operations after taxes
|
(1 | ) | 14 | 13 |
____________________________
|
(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, 2009 and 2008
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 | ||||||
Loss
from operations before taxes
|
— | (213 | )(2) | (213 | ) | |||||||
Loss
from operations after taxes
|
— | (139 | ) | (139 | ) | |||||||
Three
Months Ended September 30, 2008
|
||||||||||||
Revenues
|
$ | 1 | $ | 126 | $ | 127 | ||||||
Income
from operations before taxes
|
— | 53 | 53 | |||||||||
Income
from operations after taxes
|
— | 32 | 32 | |||||||||
Gain
on sale before taxes
|
— | 1 | 1 | |||||||||
Gain
on sale after taxes
|
— | — | — | |||||||||
Nine
Months Ended September 30, 2009
|
||||||||||||
Revenues
|
$ | 4 | $ | 96 | $ | 100 | ||||||
Loss
from operations before taxes
|
(23 | )(1) | (219 | )(2) | (242 | ) | ||||||
Loss
from operations after taxes
|
(14 | ) | (139 | ) | (153 | ) | ||||||
Gain
on sale before taxes
|
— | 10 | 10 | |||||||||
Gain
on sale after taxes
|
— | 12 | 12 | |||||||||
Nine
Months Ended September 30, 2008
|
||||||||||||
Revenues
|
$ | 2 | $ | 202 | $ | 204 | ||||||
Income
(loss) from operations before taxes
|
(1 | ) | 24 | 23 | ||||||||
Income
(loss) from operations after taxes
|
(1 | ) | 14 | 13 |
____________________________
|
(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.
|
Note
3—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 income (loss)
attributable to Dynegy’s and DHI’s stockholders:
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Dynegy Inc.
|
Dynegy Holdings Inc.
|
|||||||||||||||
Three Months Ended
September 30,
|
Three Months Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Income
(loss) from continuing operations
|
$ | (83 | ) | $ | 573 | $ | (82 | ) | $ | 574 | ||||||
Income
(loss) from discontinued operations, net of tax benefit (expense) of $84,
($22), $74 and ($22), respectively
|
(129 | ) | 32 | (139 | ) | 32 | ||||||||||
Net
income (loss)
|
$ | (212 | ) | $ | 605 | $ | (221 | ) | $ | 606 |
Dynegy Inc.
|
Dynegy Holdings Inc.
|
|||||||||||||||
Nine Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Income
(loss) from continuing operations
|
$ | (751 | ) | $ | 168 | $ | (750 | ) | $ | 171 | ||||||
Income
(loss) from discontinued operations, net of tax benefit (expense) of $91,
($10), $91 and ($10), respectively
|
(141 | ) | 13 | (141 | ) | 13 | ||||||||||
Net
income (loss)
|
$ | (892 | ) | $ | 181 | $ | (891 | ) | $ | 184 |
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, 2009 and 2008
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, 2008:
Controlling Interest
|
Noncontrolling Interests
|
Total
|
||||||||||
(in
millions)
|
||||||||||||
December
31, 2007
|
$ | 4,506 | $ | 23 | $ | 4,529 | ||||||
Net
income (loss)
|
181 | (3 | ) | 178 | ||||||||
Other
comprehensive income (loss), net of tax:
|
||||||||||||
Unrealized
mark-to-market losses arising during period
|
(18 | ) | (9 | ) | (27 | ) | ||||||
Reclassification
of mark-to-market (gains) losses to earnings
|
11 | (1 | ) | 10 | ||||||||
Deferred
gains (losses) on cash flow hedges
|
2 | (2 | ) | — | ||||||||
Amortization
of unrecognized prior service cost and actuarial gain
|
1 | — | 1 | |||||||||
Unconsolidated
investments other comprehensive loss
|
(11 | ) | — | (11 | ) | |||||||
Net
unrealized loss on securities
|
(12 | ) | — | (12 | ) | |||||||
Total
other comprehensive loss, net of tax
|
(27 | ) | (12 | ) | (39 | ) | ||||||
Other
equity activity:
|
||||||||||||
Subscriptions
receivable
|
2 | — | 2 | |||||||||
Options
exercised
|
1 | — | 1 | |||||||||
401(k)
plan and profit sharing stock
|
4 | — | 4 | |||||||||
Options
and restricted stock granted
|
12 | — | 12 | |||||||||
September
30, 2008
|
$ | 4,679 | $ | 8 | $ | 4,687 |
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 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 |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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 of the nine months
ended September 30, 2008:
Controlling Interest
|
Noncontrolling Interests
|
Total
|
||||||||||
(in
millions)
|
||||||||||||
December
31, 2007
|
$ | 4,597 | $ | 23 | $ | 4,620 | ||||||
Net
income (loss)
|
184 | (3 | ) | 181 | ||||||||
Other
comprehensive income (loss), net of tax:
|
||||||||||||
Unrealized
mark-to-market losses arising during period
|
(18 | ) | (9 | ) | (27 | ) | ||||||
Reclassification
of mark-to-market (gains) losses to earnings
|
11 | (1 | ) | 10 | ||||||||
Deferred
gains (losses) on cash flow hedges
|
2 | (2 | ) | — | ||||||||
Amortization
of unrecognized prior service cost and actuarial gain
|
1 | — | 1 | |||||||||
Unconsolidated
investments other comprehensive loss
|
(11 | ) | — | (11 | ) | |||||||
Net
unrealized loss on securities
|
(12 | ) | — | (12 | ) | |||||||
Total
other comprehensive loss, net of tax
|
(27 | ) | (12 | ) | (39 | ) | ||||||
Other
equity activity:
|
||||||||||||
Affiliate
activity
|
14 | — | 14 | |||||||||
September
30, 2008
|
$ | 4,768 | $ | 8 | $ | 4,776 |
Note
4—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 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 12 to 36 month 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 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
On
January 1, 2009, we adopted authoritative guidance which requires disclosure of
the fair values of derivative instruments and their gains and losses in a
tabular format. It also provides more information about an entity’s
liquidity by requiring disclosure of derivative features that are credit
risk-related and it requires cross-referencing within footnotes to enable
financial statement users to locate important information about derivative
instruments.
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 economically 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, 2009, 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, 2009, we had net
long/(short) commodity derivative contracts outstanding and notional interest
rate swaps outstanding in the following quantities:
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Contract Type
|
Hedge Designation
|
Quantity
|
Unit of Measure
|
Net Fair Value
|
|||||||
(in
millions)
|
(in
millions)
|
||||||||||
Commodity
derivative contracts:
|
|||||||||||
Electric
energy (1)(3)
|
Not
designated
|
(93 | ) |
MW
|
$ | 135 | |||||
Natural
gas (1)
|
Not
designated
|
99 |
MMBtu
|
$ | (22 | ) | |||||
Electricity/natural
gas spread options (3)
|
Not
designated
|
(9)/46 |
MW/MMBtu
|
$ | 28 | ||||||
Other
(2)
|
Not
designated
|
2 |
Misc.
|
$ | 2 | ||||||
Interest
rate contracts:
|
|||||||||||
Interest
rate swaps
|
Fair
value hedge
|
(25 | ) |
Dollars
|
$ | 2 | |||||
Interest
rate swaps
|
Not
designated
|
532 |
Dollars
|
$ | (59 | ) | |||||
Interest
rate swaps
|
Not
designated
|
231 |
Dollars
|
$ | (20 | ) | |||||
Interest
rate swaps
|
Not
designated
|
(206 | ) |
Dollars
|
$ | 18 |
____________________________
|
(1)
|
Mainly
comprised of swaps, options and physical
forwards.
|
|
(2)
|
Comprised
of emissions, coal, crude oil, fuel oil options, swaps and physical
forwards.
|
|
(3)
|
Includes
$9 million of net commodity derivative contracts classified as held for
sale as of September 30, 2009, comprised of electric energy of (0.22) MW
and electricity/natural gas spread options of (1.0) MW/11 MMBtu,
respectively, with a net fair value of $2 million and $7 million,
respectively.
|
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Derivatives
on the Balance Sheet. The following
table presents the fair value and balance sheet classification of derivatives in the
unaudited condensed consolidated balance sheet as of September 30, 2009,
segregated between designated, qualifying hedging instruments and those that are
not, and by type of contract segregated by assets and liabilities. We
do not offset fair value amounts recognized for derivative instruments executed
with the same counterparty under a master netting agreement and we did not elect
to adopt the netting provisions that allow an entity to offset the fair value
amounts recognized for cash collateral paid or cash collateral received against
the fair value amounts recognized for derivative instruments executed with the
same counterparty under a master netting agreement. As a result, our
unaudited condensed consolidated balance sheets present derivative assets and
liabilities, as well as cash collateral paid or received, on a gross
basis.
Contract Type
|
Balance Sheet Location
|
September 30,
2009
|
December 31,
2008
|
|||||||
(in
millions)
|
||||||||||
Derivatives
designated as hedging instruments:
|
||||||||||
Derivative
Assets:
|
||||||||||
Interest
rate contracts
|
Assets
from risk management activities
|
$ | 2 | $ | 3 | |||||
Derivative
Liabilities:
|
||||||||||
Interest
rate contracts
|
Liabilities
from risk management activities
|
— | (238 | ) | ||||||
Total
derivatives designated as hedging instruments, net
|
2 | (235 | ) | |||||||
Derivatives
not designated as hedging instruments:
|
||||||||||
Derivative
Assets:
|
||||||||||
Commodity
contracts (1)
|
Assets
from risk management activities
|
1,211 | 1,355 | |||||||
Interest
rate contracts
|
Assets
from risk management activities
|
18 | 19 | |||||||
Derivative
Liabilities:
|
||||||||||
Commodity
contracts
|
Liabilities
from risk management activities
|
(1,068 | ) | (1,147 | ) | |||||
Interest
rate contracts
|
Liabilities
from risk management activities
|
(79 | ) | (22 | ) | |||||
Total
derivatives not designated as hedging instruments, net
|
82 | 205 | ||||||||
Total
derivatives, net
|
$ | 84 | $ | (30 | ) |
_____________
(1)
|
Includes
$9 million of risk management assets classified as held for sale as of
September 30, 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, 2009 and 2008 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 the
second quarter 2007, one of our consolidated subsidiaries, PPEA, entered into
three interest rate swap agreements with an initial aggregate notional amount of
approximately $184 million. These interest rate swap agreements
convert certain of PPEA’s floating rate debt exposure to a fixed interest rate
of approximately 5.3 percent. The aggregate notional amount of the
swaps at September 30, 2009 was approximately $532 million. These
interest rate swap agreements expire in June 2040. Effective July 1,
2007, we designated these agreements as cash flow hedges. Therefore,
the effective portion of the changes in value after that date (and prior to July
28, 2009, as further discussed below) are reflected in other comprehensive
income (loss), and subsequently reclassified to interest expense
contemporaneously with the related accruals of interest expense, or depreciation
expense in the event the interest was capitalized.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
The PPEA
interest rate swap agreements are unconditionally and irrevocably guaranteed by
Ambac Assurance Corporation (“Ambac”). On July 28, 2009, Ambac’s
credit rating was downgraded. As a result of the Ambac downgrade, on
October 16, 2009, PPEA’s credit rating was also downgraded. Based on
PPEA’s downgrade, the interest rate swap agreements can now be terminated at
Ambac’s discretion, which would result in an obligation by PPEA to pay the
termination value. Ambac has the ability to control the termination
of these swaps at its sole discretion under the applicable agreements;
therefore, the associated risk management liability has been classified as
current at September 30, 2009. However, Ambac has given no indication
that it intends to cause the swaps to be terminated. In fact, if it
were to do so, it would trigger its own obligation as insurer to pay the
termination value to the swap counterparties, as PPEA does not have the
resources to do so. In addition, Ambac can also consent to a request
by any of the counterparties to terminate the interest rate swaps, which would
result in a payment obligation by PPEA for the termination
value. However, should PPEA fail to pay the termination value, Ambac
would only be required to pay the scheduled quarterly
settlements. Failure to pay the termination value could result in the
potential acceleration of PPEA’s debt. Please read Note 6—Impairment
Charges—Other for further discussion of our obligations to PPEA.
Based on
the events described above, as of July 28, 2009, we believe the interest rate
swap agreements no longer qualify for cash flow hedge accounting because the
hedged forecasted transaction (that is, the future interest payments arising
from the Plum Point Credit Agreement Facility) is no longer probable of
occurring. We performed a final effectiveness test as of July 28,
2009 and no ineffectiveness was recorded. The amounts previously
deferred in Accumulated other comprehensive income (loss) were not reclassified
into earnings because, although the likelihood of the forecasted transaction is
not high enough to be considered probable of occurring at September 30, 2009, it
is also not low enough that we would consider it probable that the future
interest payments associated with the underlying debt will not
occur. The change in value of the interest rate swap agreements from
July 28, 2009 through September 30, 2009 was a loss of approximately $9 million,
and is included in Interest expense on our unaudited condensed consolidated
statement of operations. As a result of discontinuing hedge
accounting for the interest rate swaps, all prospective changes in the fair
value and associated settlements of these interest rate swaps will impact
earnings. Please read Note 10—Debt—Plum Point Credit Agreement
Facility for further discussion.
For the
three and nine months ended September 30, 2008, we recorded $1 million and
$3 million,
respectively, 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 any of the
periods. During the three and nine months ended September 30, 2008,
no amounts were
reclassified to earnings in connection with forecasted transactions that were no
longer considered probable of occurring.
The
balance in cash flow hedging activities within Accumulated other comprehensive
income (loss), net at September 30, 2009 is expected to be reclassified to
future earnings when the forecasted hedged transaction impacts
earnings. Because a significant majority of the interest expense
incurred by PPEA is capitalized, a significant portion of the derivative
settlements prior to the dedesignation discussed above are deferred in
Accumulated other comprehensive income (loss) and will be reclassified to
depreciation expense over the expected life of the plant once the Plum Point
Project (as defined below) commences operations. Because not all of
the interest expense is capitalized, of this amount, after-tax losses of
approximately $1 million are currently estimated to be reclassified into
earnings over the 12-month period ending June 30, 2010. 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 the
probability of the forecasted transactions not occurring. For
example, if there were an event of default under the PPEA Credit Agreement
Facility, it would be probable that the forecasted transactions (that is, the
underlying interest payments) would not occur and the balance in Accumulated
other comprehensive income (loss) would be immediately reclassified to
earnings.
The PPEA
interest rate swap agreements contain provisions that require PPEA’s debt to
maintain an investment grade credit rating from a major credit rating
agency. As PPEA’s debt has fallen below investment grade, the
counterparties to two of the three interest rate swap agreements could request
immediate payment or demand collateralization on instruments in net liability
positions if Ambac, as guarantor, were to declare
bankruptcy. However, absent an Ambac bankruptcy, PPEA is under no
obligation to post collateral or terminate the swaps. A default on
PPEA’s obligations pursuant to the interest rate swap agreements would cause
PPEA to also be in default of the terms of its project debt. Our
obligations related to our investment in PPEA are limited to our $15 million
letter of credit issued under our Credit Facility to support our contingent
equity contribution to the Plum Point Project. Please read Note 10—
Debt—Plum Point Credit Agreement Facility for further
discussion.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
The
impact of interest rate swap contracts designated as cash flow hedges and the
related hedged item on our unaudited condensed consolidated statements of
operations for the three months ended September 30, 2009 and 2008 is presented
below:
Derivatives
in Cash Flow Hedging
|
Amount of Gain (Loss) Recognized in OCI on
Derivatives (Effective Portion) For the Three Months
Ended
September 30,
|
Location
of Loss Reclassified from Accumulated OCI into Income
|
Amount of Loss Reclassified from Accumulated OCI
into Income (Effective Portion) For the Three Months
Ended
September 30,
|
||||||||||||||
Relationships
|
2009
|
2008
|
(Effective Portion)
|
2009
|
2008
|
||||||||||||
(in
millions)
|
(in
millions)
|
||||||||||||||||
Interest
rate contracts
|
$ | 45 | $ | (21 | ) |
Interest
expense
|
$ | (1 | ) | $ | — | ||||||
Commodity
contracts (1)
|
— | — |
Revenues
|
— | (10 | ) | |||||||||||
Total
|
$ | 45 | $ | (21 | ) | $ | (1 | ) | $ | (10 | ) |
________________________
|
(1)
|
Beginning
April 2, 2007, we chose to cease designating derivatives related to our
power generation business as hedges. These amounts represent
reclassifications into earnings of amounts that were previously frozen in
Accumulated other comprehensive loss upon de-designation in April
2007.
|
The
impact of interest rate swap contracts designated as cash flow hedges and the
related hedged item on our unaudited condensed consolidated statements of
operations for the nine months ended September 30, 2009 and 2008 is presented
below:
Derivatives
in Cash Flow Hedging
|
Amount of Gain (Loss) Recognized in OCI on
Derivatives (Effective Portion) For the Nine Months
Ended
September 30,
|
Location
of Loss Reclassified from Accumulated OCI into Income
|
Amount of Loss Reclassified from Accumulated OCI
into Income (Effective Portion) For the Nine Months
Ended
September 30,
|
||||||||||||||
Relationships
|
2009
|
2008
|
(Effective Portion)
|
2009
|
2008
|
||||||||||||
(in
millions)
|
(in
millions)
|
||||||||||||||||
Interest
rate contracts
|
$ | 160 | $ | (27 | ) |
Interest
expense
|
$ | — | $ | — | |||||||
Commodity
contracts (1)
|
— | — |
Revenues
|
— | (22 | ) | |||||||||||
Total
|
$ | 160 | $ | (27 | ) | $ | — | $ | (22 | ) |
________________________
|
(1)
|
Beginning
April 2, 2007, we chose to cease designating derivatives related to our
power generation business as hedges. These amounts represent
reclassifications into earnings of amounts that were previously frozen in
Accumulated other comprehensive loss upon de-designation in April
2007.
|
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
2012. During the three and nine months ended September 30, 2009 and
2008, 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 three and nine months ended September 30, 2009
and 2008, there were no gains or losses related to the recognition of firm
commitments that no longer qualified as fair value
hedges.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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, 2009 and 2008 was
immaterial.
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, 2009, our revenues included approximately $123
million of mark-to-market losses related to this activity compared to $863
million of mark-to-market gains in the same period in the prior
year. For the nine months ended September 30, 2009, our revenues
included approximately $67 million of mark-to-market losses related to this activity
compared to $125 million of mark-to-market gains 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, 2009 and 2008 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 All Gain (Loss) Recognized in Income on
Derivatives for the
Three Months Ended
September 30,
|
||||||||
Instruments
|
Derivatives
|
2009
|
2008
|
|||||||
(in
millions)
|
||||||||||
Commodity
contracts
|
Revenues
|
$ | 59 | $ | 811 | |||||
Interest
rate contracts
|
Interest
expense
|
(14 | ) | (1 | ) |
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, 2009 and 2008 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 All Gain (Loss) Recognized in Income on
Derivatives for the
Nine Months Ended
September 30,
|
||||||||
Instruments
|
Derivatives
|
2009
|
2008
|
|||||||
(in
millions)
|
||||||||||
Commodity
contracts
|
Revenues
|
$ | 345 | $ | 49 | |||||
Interest
rate contracts
|
Interest
expense
|
(14 | ) | (1 | ) |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
5—Fair Value Measurements
The
following table sets 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, 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,
2009
|
||||||||||||||||
Level 1
|
Level 2
|
Level 3
|
Total
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Assets:
|
||||||||||||||||
Assets
from commodity risk management activities (1)
|
$ | — | $ | 1,126 | $ | 85 | $ | 1,211 | ||||||||
Assets
from interest rate swaps
|
— | 20 | — | 20 | ||||||||||||
Other (2)
|
— | 11 | — | 11 | ||||||||||||
Total
|
$ | — | $ | 1,157 | $ | 85 | $ | 1,242 | ||||||||
Liabilities:
|
||||||||||||||||
Liabilities
from commodity risk management activities
|
$ | — | $ | (1,012 | ) | $ | (56 | ) | $ | (1,068 | ) | |||||
Liabilities
from interest rate swaps
|
— | (20 | ) | (59 | ) | (79 | ) | |||||||||
Total
|
$ | — | $ | (1,032 | ) | $ | (115 | ) | $ | (1,147 | ) |
______________
|
(1)
|
Includes
$2 million and $7 million in Levels 2 and 3, respectively, that is
classified as Assets held for sale on our unaudited condensed consolidated
balance sheet as of September 30,
2009.
|
|
(2)
|
Other
represents short-term investments and long-term
investments.
|
The
following table sets 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,
2009
|
||||
(in
millions)
|
||||
Balance
at June 30, 2009
|
$ | 43 | ||
Realized
and unrealized gains, net
|
3 | |||
Purchases,
issuances and settlements
|
(26 | ) | ||
Transfer
to Level 3
|
(50 | ) | ||
Balance
at September 30, 2009
|
$ | (30 | ) | |
Unrealized
gains relating to instruments still held as of September 30,
2009
|
$ | (4 | ) |
Nine Months Ended
September 30, 2009
|
||||
(in
millions)
|
||||
Balance
at December 31, 2008
|
$ | 59 | ||
Realized
and unrealized gains, net
|
26 | |||
Purchases,
issuances and settlements
|
(65 | ) | ||
Transfer
to Level 3
|
(50 | ) | ||
Balance
at September 30, 2009
|
$ | (30 | ) | |
Unrealized
gains relating to instruments still held as of September 30,
2009
|
$ | (9 | ) |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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 as it reflects 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
On
January 1, 2009, we adopted authoritative guidance, which applies to liabilities
issued with an inseparable third-party credit enhancement when they are measured
or disclosed at fair value on a recurring basis. The underlying
principle is that a third-party credit enhancement does not relieve the issuer
of its ultimate obligation under the liability. We had approximately $190
million of cash collateral postings as of September 30, 2009 included in
Prepayments and other current assets on our unaudited condensed consolidated
balance sheets, which represents the effect of net cash outflows arising from
the daily settlements of our exchange-traded or brokered commodity futures
positions held with our futures clearing manager. In addition, we had
approximately
$886 million of letters of credit issued as of September 30,
2009. Substantially all of our derivative positions with our
derivative counterparties are supported by letters of credit issued pursuant to
our Fifth Amended and Restated Credit Facility (the “Credit Facility”) or by
cash collateral postings. As a result, we no longer can consider the
letters of credit as credit enhancements in our valuation of our derivative
liabilities beginning in 2009. Based on our net risk management asset
position as of January 1, 2009 and September 30, 2009, our adoption of this
authoritative guidance did not result in a material effect on our unaudited
condensed consolidated financial statements for the three or nine months ended
September 30, 2009.
On
January 1, 2009, we adopted authoritative guidance for nonfinancial assets and
liabilities measured at fair value on a nonrecurring basis, which had been
deferred under existing authoritative guidance. 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 as of September 30, 2009. 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,
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, resulting in an impairment
charge of $433 million, which is included in Goodwill impairment on our
unaudited condensed consolidated statements of operations. Please
read Note 9—Goodwill for further discussion and disclosures addressing the
description of the inputs and information used to develop the inputs as well as
the valuation techniques used to measure the goodwill
impairment.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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
6—Impairment Charges for further discussion.
On June
30, 2009, we adopted authoritative guidance which provides guidance on (i)
estimating the fair value of an asset or liability when the volume and level of
activity for the asset or liability have significantly decreased and (ii)
identifying transactions that are not orderly. The adoption of this
authoritative guidance had no impact on our financial statements.
Fair Value of
Financial Instruments. On June 30, 2009, we adopted
authoritative guidance, which requires the disclosure of the estimated 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.
The
carrying values of financial assets and liabilities approximate fair values due
to the short-term maturities of these instruments. The carrying
amounts and fair values of debt are included in Note 10—Debt.
September 30, 2009
|
December 31, 2008
|
|||||||||||||||
Carrying Amount
|
Fair
Value
|
Carrying Amount
|
Fair
Value
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Interest
rate derivatives designated as cash flow accounting hedges
(1)
|
$ | — | $ | — | $ | (238 | ) | $ | (238 | ) | ||||||
Interest
rate derivatives designated as fair value accounting hedges
(1)
|
2 | 2 | 3 | 3 | ||||||||||||
Interest
rate derivatives not designated as accounting hedges (1)
|
(61 | ) | (61 | ) | (2 | ) | (2 | ) | ||||||||
Commodity-based
derivative contracts not designated as accounting hedges
(1)(3)
|
143 | 143 | 207 | 207 | ||||||||||||
Other
(2)
|
11 | 11 | 25 | 25 | ||||||||||||
Total
|
$ | 95 | $ | 95 | $ | (5 | ) | $ | (5 | ) |
____________
|
(1)
|
Included
in both current and non-current assets and liabilities on the unaudited
condensed consolidated balance
sheets.
|
|
(2)
|
Other
represents short-term and long-term
investments.
|
|
(3)
|
Includes
$9 million of net commodity derivative contracts not designated as
accounting hedges classified as held for sale as of September 30,
2009.
|
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
6—Impairment Charges
The
following summarizes pre-tax impairment charges recorded during 2009 which are
included in Impairment and other charges in our unaudited condensed consolidated
statements of operations:
GEN-MW
|
GEN-WE
|
GEN-NE
|
Total
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Three
months ended June 30, 2009:
|
||||||||||||||||
Assets
included in proposed sale to LS Power
|
$ | — | $ | — | $ | (179 | ) | $ | (179 | ) | ||||||
Roseton
and Danskammer
|
— | — | (208 | ) | (208 | ) | ||||||||||
Total
2nd Quarter Impairment Charges
|
— | — | (387 | ) | (387 | ) | ||||||||||
Three
months ended September 30, 2009:
|
||||||||||||||||
Assets
included in proposed sale to LS Power (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 unaudited
condensed consolidated statements of operations:
GEN-MW
|
GEN-WE
|
GEN-NE
|
Total
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Three
months ended March 31, 2009:
|
||||||||||||||||
Bluegrass
(included in the proposed sale to LS Power)
|
$ | (5 | ) | $ | — | $ | — | $ | (5 | ) | ||||||
Total
1st Quarter Impairment Charges
|
(5 | ) | — | — | (5 | ) | ||||||||||
Three
months ended June 30, 2009:
|
||||||||||||||||
Assets
included in proposed sale to LS Power
|
(18 | ) | — | — | (18 | ) | ||||||||||
Total
2nd Quarter Impairment Charges
|
(18 | ) | — | — | (18 | ) | ||||||||||
Three
months ended September 30, 2009:
|
||||||||||||||||
Assets
included in proposed sale to LS Power (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.
|
Goodwill
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. Please read Note
9—Goodwill for further discussion. 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 relates to the
Bluegrass power generation facility, is included in Income (loss) on
discontinued operations in our unaudited condensed 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. Please read Note 2—Dispositions and
Discontinued Operations—Discontinued Operations—Arlington Valley, Griffith and
Bluegrass for further discussion.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Assets Included
in Sale to LS Power. At June 30, 2009, in connection with
discussions leading to the agreement with LS Power discussed further in Note
2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction, 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 relates to the Bridgeport power generation facility and
related assets and is included in Impairment and other charges in our unaudited
condensed consolidated statements of operations in the GEN-NE
segment. The remaining $18 million ($11 million after-tax) relates to
the Bluegrass power generation facility and related assets and is included in
Income (loss) from discontinued operations in our unaudited condensed
consolidated statements of operations in the GEN-MW segment. This
additional impairment charge for the Bluegrass power generation facility
reflects 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 transaction with LS Power.
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 2—Dispositions and
Discontinued Operations—Dispositions—LS Power Transaction, the assets qualified
as held for sale, and additional impairment charges were recorded, as discussed
below.
On August
9, 2009, we entered into a 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 unaudited condensed consolidated statements of
operations. The $235 million charge is included in Income (loss) on
discontinued operations in our unaudited condensed 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 $2.55 per
share. We expect to record additional gains or losses on the sale of
these assets upon close of the transaction anticipated to occur 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, or changes in
working capital items not reimbursed by the purchaser. In addition,
we expect to record a loss of approximately $85 million on the sale of our Sandy
Creek investment included in this transaction, based on the value of our
investment in Sandy Creek at September 30, 2009. This estimate could
change materially based on changes in the value of our investment between
September 30, 2009 and the close of the transaction.
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 unaudited condensed 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
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, 2009 and 2008
Other. At
September 30, 2009, we assessed the carrying amount of our Plum Point assets for
impairment because we believed it was more likely than not that we would sell
our interest in PPEA before the end of its useful life. In performing
this analysis, we used a 50 percent likelihood of a sales transaction occurring
in the fourth quarter 2009, and a 50 percent likelihood on our continuing to own
the asset while seeking a buyer, and we concluded that an impairment is not
indicated. We have no further obligation to provide any financial or
other support to PPEA beyond the $15 million letter of credit we have
posted to support our contingent equity contribution (as distinct from financial
or other support provided by the holders of the remaining interests in PPEA
Holding). As a result, we would not be obligated to either (i) sell
the assets at a price below an amount that would settle the liabilities
associated with Plum Point after considering the equity commitments of PPEA’s
owners, or (ii) own and operate it at a loss that would require us to contribute
more than $15 million. However, if we do complete a sale of our
interest in PPEA during the fourth quarter, we would expect to recognize a loss
on the sale, as we would recognize through the statement of operations losses
associated with PPEA’s interest rate swaps that were previously recorded in
Accumulated other comprehensive loss.
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 and anticipated timing of the sale of certain assets to LS
Power. As additional information becomes available regarding the
significant assumptions used in our analysis, we may conclude that it is
necessary to update our impairment analyses in future periods to assess the recoverability of our
assets and additional impairment charges could be required.
Note
7—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,
2009
|
December 31,
2008
|
|||||||
(in
millions)
|
||||||||
Cash
flow hedging activities, net
|
$ | (93 | ) | $ | (125 | ) | ||
Unrecognized
prior service cost and actuarial loss
|
(65 | ) | (66 | ) | ||||
Accumulated
other comprehensive loss—unconsolidated investments
|
(21 | ) | (24 | ) | ||||
Accumulated
other comprehensive loss, net of tax
|
$ | (179 | ) | $ | (215 | ) |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
8—Variable Interest Entities
Hydroelectric
Generation Facilities. On January 31, 2005, Dynegy completed
the acquisition of ExRes, the parent company of Sithe Energies, Inc. and
Independence. ExRes also owns through its subsidiaries 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”) has 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 ExRes for all costs, liabilities, and obligations of the
entities owning these facilities, and to indemnify ExRes with respect to the
past and present assets and operations of the entities. As a result,
we are not the primary beneficiary of the entities and have not consolidated
them. There was no material change during the three and nine months
ended September 30, 2009. During October 2009, we entered into an
agreement to sell two of these facilities to a third party. As we do
not consolidate these entities, we will not record a gain or loss upon
completion of the transaction. We expect to close the transaction
during the fourth quarter 2009, pending the receipt of required regulatory
approvals. Please see Note 12—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 Company LLC (“PPEA Holding”) which, through its wholly-owned subsidiary,
Plum Point Energy Associates, LLC (“PPEA”) owns an approximate 57 percent
undivided interest in a 665 MW coal-fired power generation facility (the “Plum
Point Project”), which is under construction in Mississippi County,
Arkansas. Our net investment in PPEA Holding at September 30, 2009
(which amount does not include investments by the holders of the remaining
interests in PPEA Holding) was a liability of approximately $64
million. Our unaudited condensed consolidated balance sheet included
$570 million of plant construction in progress at September 30, 2009 that is
collateral for the Plum Point Project debt, which is nonrecourse to
us. As of September 30, 2009, we have posted a $15 million letter of
credit issued under our Credit Facility to support our contingent equity
contribution to the Plum Point Project. Please see Note 15—Debt—Plum
Point Credit Agreement Facility in our Form 10-K for discussion of Plum Point’s
borrowings. PPEA Holding meets the definition of a VIE, and we have
determined we are the primary beneficiary of this entity; therefore, we have
consolidated it. Please see Note 12—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 unaudited
condensed consolidated financial statements, is included below:
September 30,
2009
|
December 31,
2008
|
|||||||
(in
millions)
|
||||||||
As
of:
|
||||||||
Current
assets
|
$ | 2 | $ | 1 | ||||
Property,
plant and equipment, net
|
573 | 507 | ||||||
Intangible
asset
|
193 | 193 | ||||||
Other
non-current asset
|
31 | 29 | ||||||
Total
assets
|
799 | 730 | ||||||
Current
liabilities
|
80 | 19 | ||||||
Long-term
debt
|
705 | 615 | ||||||
Non-current
liabilities
|
6 | 244 | ||||||
Noncontrolling
interest
|
77 | (30 | ) | |||||
Accumulated
other comprehensive loss
|
(157 | ) | (215 | ) | ||||
For
the period ending:
|
||||||||
Operating
loss
|
— | (1 | ) | |||||
Net
loss
|
(7 | ) | (3 | ) |
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 existing operating portfolio of assets.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Sandy
Creek. Dynegy Sandy Creek Holdings, LLC (the “Dynegy Member”),
an indirectly wholly owned subsidiary of Dynegy and DHI, and LSP Sandy Creek
Member, LLC (the “LSP Member”) each own a 50 percent interest in Sandy Creek
Holdings LLC (“SCH”), which owns all of Sandy Creek Energy
Associates, LP (“SCEA”). SCEA owns an approximate 64 percent
undivided interest in the Sandy Creek Energy Station (“the Sandy Creek
Project”), which is an 898 MW facility under construction in McLennan County,
Texas. In addition, Sandy Creek Services, LLC (“SC Services”) was
formed to provide services to SCH. Dynegy Power Services and LSP
Sandy Creek Services LLC each own a 50 percent interest in SC
Services.
SCH and
SC Services both meet the definition of a VIE, as they will require additional
subordinated financial support to conduct their normal ongoing
operations. However, we are not the primary beneficiary of the
entities, and therefore, do not consolidate them. We account for our
investments in SCH and SC Services as equity method investments. At
September 30, 2009, we had $8 million included in non-current Accounts
receivable, affiliate and $63 million included in Other long-term liabilities on
our unaudited condensed consolidated balance sheets. We believe that
our maximum exposure to economic loss from these VIEs is limited to $283
million.
On August
9, 2009, we entered into an agreement to sell our interests in SCH and SC
Services to LS Power. At the closing of the transaction we expect to
record a loss of approximately $85 million based on the fair value of these
investments, compared to the book value of our investment at September 30,
2009. This estimate could change materially based on changes in the
value of our investment prior to close of the transaction. Please
read Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power
Transaction for further discussion.
Note
9—Goodwill
Assets
and liabilities of companies acquired in purchase transactions are recorded at
fair value at the date of acquisition. Goodwill represents the excess
purchase price over the fair value of net assets acquired, plus any identifiable
intangibles. We review goodwill for potential impairment as of
November 1st of each year or more frequently if events or circumstances occur
that would more likely than not reduce the fair value of a reporting unit below
its carrying amount. During the first quarter 2009, there were
several events and circumstances which, when considered in the aggregate,
indicated such a reduction in the fair value of our GEN-MW, GEN-WE and GEN-NE
reporting units:
|
·
|
The
first quarter 2009 was characterized by a steep decline in forward
commodity prices. Forward market prices for natural gas
decreased by 27 percent and 17 percent, respectively, for the calendar
years 2009 and 2010, significantly impacting the current market and
corresponding forward market prices for
power;
|
|
·
|
During
the first quarter 2009, acquisition activity related to power generation
facilities was very low, indicating a lack of demand for such
transactions;
|
|
·
|
Dynegy’s
market capitalization continued to decline through the first quarter 2009,
with Dynegy’s stock price falling from an average of $2.51 per share in
the fourth quarter 2008 to an average of $1.73 per share in the first
quarter 2009 and a closing price of $1.41 at March 31, 2009;
and
|
|
·
|
General
economic indicators, such as economic growth forecasts and unemployment
forecasts, deteriorated further during the first quarter
2009.
|
Considered
individually, none of the foregoing events and circumstances would necessarily
indicate a significant reduction in the fair value of our reporting
units. Dynegy’s stock price is likely to remain volatile throughout
2009, and may change significantly from the closing price on March 31,
2009. However, in light of the significant drop in forward power
prices during the first quarter 2009 and the further deterioration in general
economic indicators, it was deemed unlikely that Dynegy’s market capitalization
would exceed its book equity in the near future. As a result, we
concluded that an impairment test of our goodwill on our GEN-MW, GEN-WE and
GEN-NE reporting units was required as of March 31, 2009.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
The
impairment test is performed in two steps at the reporting unit
level. The first step compares the fair value of the reporting unit
with its carrying amount, including goodwill. If the fair value of
the reporting unit is higher than its carrying amount, no impairment of goodwill
is indicated and no further testing is required. However, if the fair
value of the reporting unit is below its carrying amount, a second step must be
performed to determine the goodwill impairment required, if any.
Consistent
with historical practice, on November 1, 2008, we determined the fair value of
our reporting units using the income approach 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. In performing our impairment test at November 1, 2008, the
results of our fair value assessment using the income approach were corroborated
using market information about recent sales transactions for comparable assets
within the regions in which we operate.
Due to
further declines in our market capitalization through December 31, 2008, we
determined that assumptions utilized in the November 1, 2008 analysis required
updating. We evaluated key assumptions including forward natural gas
and power pricing, power demand growth, and cost of capital. While
some of the assumptions had changed subsequent to the November 1, 2008 analysis,
we determined that the impact of updating those assumptions would not have
caused the fair value of the individual reporting units to be below their
respective carrying values at December 31, 2008.
As a
result of the events and circumstances discussed above, as of March 31, 2009, we
updated our fair value assessment using the income approach, taking into account
the significant drop in forward prices we observed over the three months ended
March 31, 2009. As our long-term outlook on power demand remained
unchanged, we did not change our expectations regarding commodity prices beyond
2011 for purposes of this analysis. Additionally, we updated the
weighted average cost of capital assumptions used in our income approach to
reflect current market data as of March 31, 2009.
Based on
the decline in acquisition activity during the first quarter 2009 and the length
of time from the most recent asset sales transactions we used to corroborate the
results of our income approach valuation in November 2008, we were not able to
rely fully on recent sales transactions to corroborate the results of our fair
value assessment using the income approach in March 2009. Therefore,
for our first quarter 2009 analysis, we also used a market-based approach,
comparing our forecasted earnings and Dynegy’s market capitalization to those of
similarly situated public companies by considering multiples of
earnings.
For each
of the reporting units included in our analysis, fair value assessed using the
income approach exceeded the fair value assessed using this market-based
approach. However, given that Dynegy’s market capitalization had
continued to remain below its book equity for more than nine months and given
the absence of recent asset sales transaction activity to reasonably corroborate
the results of our income approach valuation, we had determined that there has
been a shift in the manner in which market participants were valuing our
business, and believed that the market-based approach has become more relevant
for estimating the fair value of our reporting units as of March 31,
2009. We therefore concluded that it was appropriate to place equal
weight on the market-based approach (rather than relying primarily on the income
approach) for the purpose of determining fair value in step one of the
impairment analysis. Based on the results of our analysis discussed
above, our GEN-MW, GEN-WE and GEN-NE reporting units did not pass the first step
as of March 31, 2009.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Having
determined that the carrying values of the GEN-MW, GEN-WE and GEN-NE reporting
units exceeded their fair values, we performed the second step of the
analysis. This second step compares the implied fair value of each
reporting unit’s goodwill with the carrying amount of such
goodwill. We performed a hypothetical allocation of the fair value of
the reporting units determined in step one to all of the assets and liabilities
of the unit, including any unrecognized intangible assets. After
making these hypothetical allocations, we determined no residual value remained
that could be allocated to goodwill within each of our GEN-MW, GEN-WE or GEN-NE
segments. We recorded first quarter 2009 impairment charges on all
three of these reporting units, as follows:
GEN-MW
|
GEN-WE
|
GEN-NE
|
Total
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Goodwill
at December 31, 2008
|
$ | 76 | $ | 260 | $ | 97 | $ | 433 | ||||||||
Impairment
of Goodwill
|
(76 | ) | (260 | ) | (97 | ) | (433 | ) | ||||||||
Goodwill
at September 30, 2009
|
$ | — | $ | — | $ | — | $ | — |
Note
10—Debt
September 30, 2009
|
December 31,
2008
|
|||||||||||||||
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Term
Loan B, due 2013
|
$ | 69 | $ | 66 | $ | 69 | $ | 52 | ||||||||
Term
Facility, floating rate due 2013
|
850 | 814 | 850 | 639 | ||||||||||||
Senior
Notes and Debentures:
|
||||||||||||||||
6.875
percent due 2011
|
502 | 506 | 502 | 427 | ||||||||||||
8.75
percent due 2012
|
501 | 509 | 501 | 426 | ||||||||||||
7.5
percent due 2015
|
550 | 505 | 550 | 388 | ||||||||||||
8.375
percent due 2016
|
1,047 | 964 | 1,047 | 742 | ||||||||||||
7.125
percent due 2018
|
172 | 132 | 173 | 110 | ||||||||||||
7.75
percent due 2019
|
1,100 | 936 | 1,100 | 762 | ||||||||||||
7.625
percent due 2026
|
171 | 116 | 172 | 93 | ||||||||||||
Subordinated
Debentures payable to affiliates, 8.316 percent, due 2027
|
200 | 110 | 200 | 83 | ||||||||||||
Sithe
Senior Notes, 9.0 percent due 2013
|
316 | 318 | 344 | 328 | ||||||||||||
Plum
Point Credit Agreement Facility, floating rate due 2010
(1)
|
605 | 277 | 515 | 365 | ||||||||||||
Plum
Point Tax Exempt Bonds, floating rate due 2036
|
100 | 100 | 100 | 100 | ||||||||||||
6,183 | 6,123 | |||||||||||||||
Unamortized
premium on debt, net
|
10 | 13 | ||||||||||||||
6,193 | 6,136 | |||||||||||||||
Less:
Amounts due within one year, including non-cash amortization of basis
adjustments
|
65 | 64 | ||||||||||||||
Total
Long-Term Debt
|
$ | 6,128 | $ | 6,072 |
_______
|
(1)
|
Upon
completion of the construction of the Plum Point Project, the $700 million
construction loan will terminate and the debt will be replaced by a $700
million term loan commitment. The term loan commitment matures
on the thirtieth anniversary of the later of the date on which substantial
completion of the facility has occurred or the first date of commercial
operation under any of the power purchase agreements then in
effect. The expected commercial operations date is August
2010. Please read Note 15—Debt—Plum Point Credit Agreement
Facility in our Form 10-K for further
discussion.
|
From July
1, 2009 through September 30, 2009, DHI’s ability to draw upon its available
capacity under the Credit Facility was reduced temporarily as a result of
borrowing limitations under the covenant regarding the ratio of secured debt to
EBITDA. As of October 1, 2009, the capacity was
restored.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Credit Facility
Amendment. On August 5, 2009, we entered into Amendment No. 4
(“Amendment No. 4”) to DHI’s Credit Facility, which includes, among other items,
the following material amendments:
Ratio of Secured
Debt to EBITDA. To allow for more flexibility, the financial
covenants were amended to provide that the ratio of Secured Debt to EBITDA (as
defined in the Credit Facility) (measured as of the last day of the specified
measurement period) shall be no greater than: 3.00:1 (measurement periods ending
September 30, 2009 and December 31, 2009); 3.25:1 (measurement periods ending
March 31, 2010 and June 30, 2010); 3.50:1 (measurement periods ending September
30, 2010, December 31, 2010, March 31, 2011 and June 30, 2011); 3.25:1
(measurement period ending September 30, 2011); 3.00:1 (measurement period
ending December 31, 2011); and 2.50:1 (measurement periods ending
thereafter).
Ratio of EBITDA
to Consolidated Interest Expense. To allow for more
flexibility, the financial covenants were amended to provide that the ratio of
EBITDA to Consolidated Interest Expense (as defined in the Credit Facility)
(measured as of the last day of the specified measurement period) shall be no
less than: 1.75:1 (measurement periods ending September 30, 2009 and December
31, 2009); 1.70:1 (measurement period ending March 31, 2010); 1.60:1
(measurement period ending June 30, 2010); 1.30:1 (measurement periods ending
September 30, 2010 and December 31, 2010); 1.35:1 (measurement period ending
March 31, 2011); 1.40:1 (measurement period ending June 30, 2011); 1.60:1
(measurement periods ending September 30, 2011 and December 31, 2011); and
1.75:1 (measurement periods ending thereafter).
Ratio of Total
Indebtedness to EBITDA. Prior to
incurring certain DHI indebtedness, adding revolver commitments,
making certain investments or certain sales of assets or engaging in certain
other permitted activities, we must satisfy certain conditions precedent,
including satisfaction, on a pro forma basis, of a separate ratio test of Total
Indebtedness to EBITDA (as defined in the Credit Facility). To allow
for more flexibility, Amendment No. 4 amended this ratio test (measured as of
the last day of the specified measurement period) to no greater than: 6.00:1
(for measurement periods ending at any time from July 1, 2009 through December
31, 2009); 6.50:1 (for measurement periods ending at any time from January 1,
2010 through June 30, 2011); 6.25:1 (for measurement periods ending at any time
from July 1, 2011 through September 30, 2011;6.00:1 (for measurement periods
ending at any time from October 1, 2011 through December 31, 2011); and 5.00:1
(for measurement periods ending thereafter).
Post-Amendment
Asset Sales. We may designate
up to $500 million of net proceeds from the sale of assets after August 5, 2009,
as excluded from the asset sale, reinvestment and prepayment provisions of the
Credit Facility.
Prepayment
Covenants. The debt prepayment covenants were amended to
provide that, in the event the maturity date of any of the 6.875 percent Senior
Notes due 2011 or the 8.75 percent Senior Notes due 2012 issued by DHI is
extended to a date, or refinanced with debt maturing, after the April 2, 2013
Term L/C Facility maturity date, DHI may prepay other longer-dated indebtedness
in the amount of any such notes so extended or refinanced.
Margin for
Borrowings. The margin for borrowings was amended to provide
that the applicable margin would be increased to either 2.375 percent or 2.75
percent per annum for Revolving Facility base rate loans and either 3.375
percent or 3.75 percent per annum for Eurodollar loans, with the lower
applicable margin being payable if the ratings for the Credit Facility by
S&P or Moody’s are BB+ or Ba1 or higher, respectively, and the higher
applicable margin being payable if such ratings are both less than BB+ and
Ba1. The margin for Term Loan borrowing was amended to provide that
the applicable margin would be increased to either 2.75 percent per annum for
base rate loans or 3.75 percent per annum for Eurodollar loans.
Unused Commitment
Fee. The
unused commitment fee was amended to increase the fee to either 0.625 percent or
0.75 percent payable on the unused portion of the Revolving Facility, with the
lower commitment fee being payable if the ratings for the Revolving Facility by
S&P or Moody’s are BB+ or Ba1 or higher, respectively, and the higher
commitment fee being payable if such ratings are both less than BB+ and
Ba1.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
We are
currently in compliance with our covenants.
PPEA Credit
Agreement Facility. On October 16, 2009, Standard & Poor’s
downgraded PPEA’s credit rating from “BBB-” to “CC”. If Ambac, as the
insurer of PPEA’s interest rate swaps, enters bankruptcy, the counterparties to
these swaps could demand collateralization or immediate termination payments on
the swaps, which are in contractual net liability positions of $135 million as
of September 30, 2009. The fair value of these derivative liabilities
as reflected in our unaudited condensed consolidated balance sheets is $59
million as it reflects a valuation adjustment for the deterioration of PPEA’s
creditworthiness pursuant to the fair value accounting
standards. PPEA does not have the liquidity to collateralize the
swaps or pay the estimated interest rate swap termination
obligations. Failure to pay the interest rate swap obligations would
likely result in an Event of Default under the Credit Agreement Facility and a
potential acceleration of debt. The PPEA Credit Agreement Facility is
a non-recourse facility and our liability (as distinct from the obligations of
the holders of the remaining interests in PPEA Holding) would be limited to our
$15 million letter of credit supporting our equity commitment. Please
read Note 4—Risk Management Activities, Derivatives and Financial
Instruments—Cash Flow Hedges for further discussion.
Note
11—Related Party Transactions
LS
Power. On August 9, 2009, we entered into an agreement to sell
certain assets to LS Power, including our interests in SCH and SC
Services. Please read Note 2—Dispositions and Discontinued
Operations—Dispositions—LS Power Transaction for further
discussion.
Subsequent
to the dissolution of DLS Power Holdings and DLS Power Development, 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 $19 million of deferred tax assets associated
with these assets to DHI. Upon completion of the agreement with LS
Power discussed above, assets related to repowering or expansion opportunities
at the Bridgeport, Arlington Valley, and Griffith facilities will be transferred
to LS Power in connection with the sale of those facilities. Please
read Note 8—Variable Interest Entities—DLS Power Holdings and DLS Power
Development for
further information.
Other. On
January 8, 2009, DHI paid a dividend of $175 million to Dynegy.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
12—Dynegy’s Earnings (loss) Per Share
Basic
earnings (loss) per share represents the amount of earnings (losses) for the
period available to each share of Dynegy’s common stock outstanding during the
period. Diluted earnings (loss) per share represents the amount of
earnings (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.
The
reconciliation of basic earnings (loss) per share from continuing operations to
diluted earnings (loss) per share from continuing operations is shown in the
following table:
Three Months Ended
September 30,
|
Nine months Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions, except per share amounts)
|
||||||||||||||||
Income
(loss) from continuing operations
|
$ | (94 | ) | $ | 572 | $ | (765 | ) | $ | 165 | ||||||
Less: Net
loss attributable to the noncontrolling interests
|
(11 | ) | (1 | ) | (14 | ) | (3 | ) | ||||||||
Income
(loss) from continuing operations attributable to Dynegy Inc. for basic
and diluted income (loss) per share
|
$ | (83 | ) | $ | 573 | $ | (751 | ) | $ | 168 | ||||||
Basic
weighted-average shares
|
843 | 840 | 842 | 840 | ||||||||||||
Effect
of dilutive securities:
|
||||||||||||||||
Stock
options and restricted stock
|
3 | 2 | 3 | 2 | ||||||||||||
Diluted
weighted-average shares
|
846 | 842 | 845 | 842 | ||||||||||||
Earnings
(loss) per share from continuing operations attributable to Dynegy
Inc.:
|
||||||||||||||||
Basic
|
$ | (0.10 | ) | $ | 0.68 | $ | (0.89 | ) | $ | 0.20 | ||||||
Diluted
(1)
|
$ | (0.10 | ) | $ | 0.68 | $ | (0.89 | ) | $ | 0.20 |
____________________________
|
(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,
2009.
|
Note
13—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.
Cooling Water
Intake Permits. The cooling water intake structures at several
of our facilities are regulated under section 316(b) of the Clean Water
Act. This provision generally requires that standards set for
facilities require that the location, design, construction, and capacity of
cooling water intake structures reflect the best technology available (“BTA”)
for minimizing adverse environmental impact. These standards are
developed and implemented for power generating facilities through National
Pollutant Discharge Elimination System (“NPDES”) permits or individual State
Pollutant Discharge Elimination System (“SPDES”)
permits. Historically, standards for minimizing adverse environmental
impacts of cooling water intakes have been made by permitting agencies on a
case-by-case basis considering the best professional judgment of the permitting
agency.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
The
environmental groups that participate in 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 facilities have been challenged on this basis.
|
·
|
Danskammer
SPDES Permit — In January 2005, the New York State Department of
Environmental Conservation (“NYSDEC”) issued a Draft SPDES Permit renewal
for the Danskammer power generation facility. Three
environmental groups sought to impose a permit requirement that the
Danskammer facility install a closed cycle cooling
system. Following a formal evidentiary hearing, the revised
Danskammer SPDES Permit was issued on June 1, 2006 without requiring
installation of a closed cycle cooling system. The permit was
upheld on appeal by the Appellate Division and petitions for leave to
appeal to the New York Court of Appeals were
denied.
|
|
·
|
Roseton
SPDES Permit — In April 2005, the NYSDEC issued a Draft SPDES Permit
renewal for the Roseton power generation facility. The Draft
Roseton SPDES Permit would require the facility to actively manage its
water intake to substantially reduce mortality of aquatic
organisms. In July 2005, a public hearing was held to receive
comments on the Draft Roseton SPDES Permit. Three environmental
organizations filed petitions for party status in the permit renewal
proceeding. The petitioners are seeking to impose a permit
requirement that the Roseton facility install a closed cycle cooling
system. In September 2006, the administrative law judge issued
a ruling admitting the petitioners to party status and setting forth the
issues to be adjudicated in the permit renewal hearing. Various
holdings in the ruling have been appealed to the Commissioner of NYSDEC by
the petitioners, NYSDEC staff and us. The adjudicatory hearing
on the Draft Roseton SPDES Permit will be scheduled after the Commissioner
decides the appeal. 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
generation facility in 2000 in connection with modernization of the
facility. A local environmental group sought review of the
permit contending that the once through seawater-cooling system at the
Moss Landing power generation facility should be replaced with a closed
cycle cooling system to meet the BTA requirements. Following an
initial remand from the courts, the Water Board affirmed its BTA
finding. The Water Board’s decision was affirmed by the
Superior Court in 2004 and by the Court of Appeals in 2007. The
petitioners filed a petition for review by the California Supreme Court,
which was granted in March 2008. The California Supreme Court
deferred further action pending final disposition of the U.S. Supreme
Court challenge regarding the Cooling Water Intake Structures Phase II
regulations (“Phase II Rules”). As further described below, the
U.S. Supreme Court issued its decision on April 1, 2009. On
September 9, 2009, the California Supreme Court directed the parties to
brief all issues raised by the pleadings. The petitioner’s
brief is due on December 8, 2009 and our response is due on January 7,
2010. We believe that petitioner’s claims lack merit and we
plan to continue opposing those claims
vigorously.
|
Due to
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.
In 2004,
the U.S. EPA issued the Phase II Rules, which set forth standards to implement
the BTA requirements for cooling water intakes at existing
facilities. The rules were challenged by several environmental groups
and in 2007 were struck down by the U.S. Court of Appeals for the Second Circuit
in Riverkeeper, Inc. v.
EPA. The Court’s decision remanded several provisions of the
rules to the U.S. EPA for further rulemaking. Several parties sought
review of the decision before the U.S. Supreme Court. On April 1,
2009, the U.S. Supreme Court ruled that the U.S. EPA permissibly relied on
cost-benefit analysis in setting the national BTA performance standard and in
providing for cost-benefit variances from those standards as part of the Phase
II Rules. We believe the U.S. Supreme Court’s decision supports our
position in the actions described above.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
On June
30, 2009, the California State Water Resources Control Board issued its draft
Statewide Water Quality Control Policy on the Use of Coastal and Estuarine
Waters for Power Plant Cooling (the “policy”). If the policy becomes
final in its present form, it will require that existing power plants either:
(i) reduce water intake flow rate to a level commensurate with that which can be
achieved by a closed cycle wet cooling system; or (ii) 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. The policy may allow less stringent requirements under limited
circumstances for very efficient generating units such as Moss Landing’s units 1
and 2. Compliance with the policy would be required at our South Bay
power generation facility by December 31, 2012, at our Morro Bay power
generation facility by December 31, 2015 and at our Moss Landing power
generation facility by December 17, 2017. A public hearing was held
on the policy on September 15, 2009 and public comments were taken through
September 30, 2009. We filed substantial comments on the draft policy
on September 29, 2009.
Given the
numerous variables and factors involved in calculating the potential costs
associated with closed cycle cooling, any decision to install such a system at
any of our plants, should one be required, would be made on a case-by-case basis
considering all relevant factors at such time. If capital
expenditures related to cooling water systems become great enough to render the
operation of the plant uneconomical, we could, at our option, and subject to any
applicable financing agreements or other obligations, reduce operations or cease
to operate that facility and forego the capital expenditures.
Gas Index Pricing
Litigation. We, several of our affiliates and other energy
companies are 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 certain index publications in the 2000-2002
timeframe (the “Gas Index Pricing Litigation”). The cases are pending
in Nevada federal district court and Tennessee state appellate
court. Recent developments include:
|
·
|
In
February 2007, the Tennessee state court dismissed a putative class action
on defendants’ motion. Plaintiffs appealed and in October 2008,
the appellate court reversed the dismissal and remanded the case for
further proceedings. In December 2008, the defendants appealed
the decision to the Tennessee Supreme Court. Oral argument is
scheduled in November 2009.
|
|
·
|
In
February 2008, the U.S. District Court in Las Vegas, Nevada granted
defendants’ motion for summary judgment in a putative class action in
Colorado, which was transferred to Nevada through the multi-district
litigation management process, thereby dismissing the case and all of
plaintiffs’ claims against certain defendants (including
Dynegy). Plaintiffs moved for reconsideration and the court
ordered additional briefing on plaintiffs’ declaratory judgment claims
against certain defendants (including Dynegy). In January 2009,
the court dismissed plaintiffs’ remaining declaratory judgment
claims. The decision is subject to appeal, but only upon final
resolution of all pending claims against all other
defendants.
|
|
·
|
In
June 2009, we and the plaintiff in an action pending in Nevada federal
court entered into a confidential settlement agreement to resolve the
litigation. The settlement was without admission of wrongdoing
and we continue to deny plaintiff’s
allegations.
|
|
·
|
The
remaining five cases, three of which seek class certification, are also
pending in Nevada federal court. All of the cases were
transferred through the multi-district litigation management process from
other states, including Kansas, Wisconsin, Missouri and
Illinois. The cases allege that individually and in conjunction
with other energy companies, we engaged in an illegal scheme to inflate
natural gas prices by providing false information to natural gas index
publications. The complaints rely heavily on prior FERC and
CFTC investigations into and reports concerning index manipulation in the
energy industry. The lawsuits seek actual and punitive damages,
restitution and/or expenses, and are currently in the discovery
phase. In December 2008, plaintiffs in the class actions filed
motions for class certification. The motion is expected to be
fully briefed in the fourth quarter
2009.
|
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
We
continue to analyze the Gas Index Pricing Litigation and are vigorously
defending the remaining 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.
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 greenhouse
gases, including CO2,
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 June 2008, defendants filed multiple motions to
dismiss based on the court’s lack of subject matter jurisdiction over
plaintiffs’ federal claim for common law nuisance. In particular,
defendants argued that under the political question doctrine, the court lacks
jurisdiction to consider the merits of plaintiffs’ nuisance claim because its
resolution would require the court to make policy determinations which are
inherently political. In October 2009, the court granted defendants’
motions and dismissed all of plaintiffs’ claims. The decision is
subject to appeal.
Information
Request under Section 114 of the Clean Air Act. On March 9,
2009, we received an information request from the U.S. EPA regarding
maintenance, repair and replacement projects undertaken
between January 1, 2000 and the present at the Danskammer power
generation facility. We submitted responses to the information
request on April 7 and July 17, 2009 and are continuing to cooperate with the
U.S. EPA to provide additional information as requested. The
information request is related to a nationwide enforcement initiative by the
U.S. EPA targeting electric utilities. The U.S. EPA’s inquiry may
lead to claims of CAA violations that could result in an enforcement action, the
scope of which cannot be predicted with confidence at this time, but which could
have a material effect on our financial condition, results of operations and
cash flows.
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 approximately $2 million
as of September 30, 2009.
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 agreement
provides that we will manage the Gas Index Pricing Litigation for which NRG
could suffer a loss subsequent to the closing and that we would indemnify NRG
for all costs or losses resulting from such litigation, as well as from other
proceedings based on similar acts or omissions. West Coast Power is
no longer a party to any active Gas Index Pricing Litigation
matters. The indemnification agreement further 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.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Targa
Indemnities. During 2005, as part of our sale of 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 significant expense under these prior
indemnities and deem their value to be insignificant. 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.
Illinois Power
Indemnities. As a condition of Dynegy’s 2004 sale of Illinois
Power and its interest in Electric Energy Inc.’s plant in Joppa, Illinois,
Dynegy provided indemnifications to third parties regarding environmental, tax,
employee and other representations. These indemnifications are
limited to a maximum recourse of $400 million. Additionally, 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 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.
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,
2009, no claims have been made against these indemnities. There is no
limitation on our liability under these indemnities. However,
management is unaware of any existing claims.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
14—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, which are more fully described in
Note 21—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,
|
||||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Service
cost benefits earned during period
|
$ | 3 | $ | 3 | $ | 1 | $ | 1 | ||||||||
Interest
cost on projected benefit obligation
|
3 | 3 | 1 | 1 | ||||||||||||
Expected
return on plan assets
|
(3 | ) | (3 | ) | — | — | ||||||||||
Recognized
net actuarial loss
|
1 | — | — | — | ||||||||||||
Net
periodic benefit cost
|
$ | 4 | $ | 3 | $ | 2 | $ | 2 |
Pension Benefits
|
Other Benefits
|
|||||||||||||||
Nine Months Ended September
30,
|
||||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions)
|
||||||||||||||||
Service
cost benefits earned during period
|
$ | 9 | $ | 8 | $ | 2 | $ | 2 | ||||||||
Interest
cost on projected benefit obligation
|
9 | 9 | 3 | 3 | ||||||||||||
Expected
return on plan assets
|
(10 | ) | (10 | ) | — | — | ||||||||||
Recognized
net actuarial loss
|
3 | 1 | — | — | ||||||||||||
Net
periodic benefit cost
|
$ | 11 | $ | 8 | $ | 5 | $ | 5 |
Contributions. During
the nine months ended September 30, 2009, we made $24 million in contributions
to our pension plans and other postretirement benefit plans. We made
$29 million in contributions to our pension plans and other postretirement
benefit plans during the nine months ended September 30, 2008. We
made an additional $3 million of contributions
to our pension and other postretirement benefit plans in October
2009.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
15—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,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions, except rates)
|
||||||||||||||||
Income
tax benefit (expense)
|
$ | 34 | $ | (392 | ) | $ | 147 | $ | (121 | ) | ||||||
Effective
tax rate
|
27 | % | 41 | % | 16 | % | 42 | % |
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 proposed sale of assets to LS Power, 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. The third quarter provision also considers the impact of $39
million of disallowed losses associated with the proposed sale of assets to LS
Power. For the three and nine months ended September 30, 2008,
Dynegy’s overall effective tax rate on continuing operations was different than
the statutory rate of 35 percent due primarily to state income
taxes.
DHI’s
income taxes included in continuing operations were as
follows:
Three Months Ended
September 30,
|
Nine Months Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
(in
millions, except rates)
|
||||||||||||||||
Income
tax benefit (expense)
|
$ | 35 | $ | (391 | ) | $ | 152 | $ | (127 | ) | ||||||
Effective
tax rate
|
27 | % | 41 | % | 17 | % | 43 | % |
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 proposed sale of assets to LS Power, 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. The third quarter provision also considers the impact of $39
million of disallowed losses associated with the proposed sale of assets to LS
Power. For the three and nine months ended September 30, 2008, DHI’s
overall effective tax rate on continuing operations was different than the
statutory rate of 35 percent due primarily to state income
taxes.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Note
16—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, 2009 and 2008 is presented below:
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, 2009 and 2008
Dynegy’s
Segment Data as of and for the Three Months Ended September 30,
2008
(in
millions)
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Unaffiliated
revenues:
|
||||||||||||||||||||
Domestic
|
$ | 997 | $ | 323 | $ | 426 | $ | (4 | ) | $ | 1,742 | |||||||||
Other
|
— | — | 17 | — | 17 | |||||||||||||||
Total
revenues
|
$ | 997 | $ | 323 | $ | 443 | $ | (4 | ) | $ | 1,759 | |||||||||
Depreciation
and amortization
|
$ | (49 | ) | $ | (20 | ) | $ | (14 | ) | $ | (2 | ) | $ | (85 | ) | |||||
Operating
income (loss)
|
$ | 757 | $ | 153 | $ | 204 | $ | (51 | ) | $ | 1,063 | |||||||||
Losses
from unconsolidated investments
|
— | (5 | ) | — | — | (5 | ) | |||||||||||||
Other
items, net
|
— | 1 | (1 | ) | 11 | 11 | ||||||||||||||
Interest
expense
|
(105 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
964 | |||||||||||||||||||
Income
tax expense
|
(392 | ) | ||||||||||||||||||
Income
from continuing operations
|
572 | |||||||||||||||||||
Income
from discontinued operations, net of taxes
|
32 | |||||||||||||||||||
Net
income
|
604 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(1 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Inc.
|
$ | 605 | ||||||||||||||||||
Identifiable
assets:
|
||||||||||||||||||||
Domestic
|
$ | 6,637 | $ | 3,406 | $ | 2,458 | $ | 1,677 | $ | 14,178 | ||||||||||
Other
|
— | — | 16 | 8 | 24 | |||||||||||||||
Total
|
$ | 6,637 | $ | 3,406 | $ | 2,474 | $ | 1,685 | $ | 14,202 | ||||||||||
Unconsolidated
investments
|
$ | — | $ | — | $ | — | $ | 62 | $ | 62 | ||||||||||
Capital
expenditures and investments in unconsolidated affiliates
|
$ | (145 | ) | $ | (5 | ) | $ | (7 | ) | $ | (4 | ) | $ | (161 | ) |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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 | ) | |||||||||||
Impairment
and other charges
|
(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, 2009 and 2008
Dynegy’s
Segment Data as of and for the Nine Months Ended September 30, 2008
(in
millions)
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Unaffiliated
revenues:
|
||||||||||||||||||||
Domestic
|
$ | 1,226 | $ | 556 | $ | 661 | $ | (4 | ) | $ | 2,439 | |||||||||
Other
|
— | — | 111 | — | 111 | |||||||||||||||
Total
revenues
|
$ | 1,226 | $ | 556 | $ | 772 | $ | (4 | ) | $ | 2,550 | |||||||||
Depreciation
and amortization
|
$ | (153 | ) | $ | (57 | ) | $ | (41 | ) | $ | (7 | ) | $ | (258 | ) | |||||
Operating
income (loss)
|
$ | 529 | $ | 104 | $ | 41 | $ | (95 | ) | $ | 579 | |||||||||
Losses
from unconsolidated investments
|
— | (7 | ) | — | (10 | ) | (17 | ) | ||||||||||||
Other
items, net
|
— | 5 | 5 | 36 | 46 | |||||||||||||||
Interest
expense
|
(322 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
286 | |||||||||||||||||||
Income
tax expense
|
(121 | ) | ||||||||||||||||||
Income
from continuing operations
|
165 | |||||||||||||||||||
Income
from discontinued operations, net of taxes
|
13 | |||||||||||||||||||
Net
income
|
178 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(3 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Inc.
|
$ | 181 | ||||||||||||||||||
Identifiable
assets:
|
||||||||||||||||||||
Domestic
|
$ | 6,637 | $ | 3,406 | $ | 2,458 | $ | 1,677 | $ | 14,178 | ||||||||||
Other
|
— | — | 16 | 8 | 24 | |||||||||||||||
Total
|
$ | 6,637 | $ | 3,406 | $ | 2,474 | $ | 1,685 | $ | 14,202 | ||||||||||
Unconsolidated
investments
|
$ | — | $ | — | $ | — | $ | 62 | $ | 62 | ||||||||||
Capital
expenditures and investments in unconsolidated affiliates
|
$ | (394 | ) | $ | (26 | ) | $ | (29 | ) | $ | (22 | ) | $ | (471 | ) |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
Reportable
segment information for DHI, including intercompany transactions accounted for
at prevailing market rates, for the three and nine months ended September 30,
2009 and 2008 is presented below:
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, 2009 and 2008
DHI’s
Segment Data as of and for the Three Months Ended September 30,
2008
(in
millions)
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Unaffiliated
revenues:
|
||||||||||||||||||||
Domestic
|
$ | 997 | $ | 323 | $ | 426 | $ | (4 | ) | $ | 1,742 | |||||||||
Other
|
— | — | 17 | — | 17 | |||||||||||||||
Total
revenues
|
$ | 997 | $ | 323 | $ | 443 | $ | (4 | ) | $ | 1,759 | |||||||||
Depreciation
and amortization
|
$ | (49 | ) | $ | (20 | ) | $ | (14 | ) | $ | (2 | ) | $ | (85 | ) | |||||
Operating
income (loss)
|
$ | 757 | $ | 153 | $ | 204 | $ | (51 | ) | $ | 1,063 | |||||||||
Losses
from unconsolidated investments
|
— | (5 | ) | — | — | (5 | ) | |||||||||||||
Other
items, net
|
— | 1 | (1 | ) | 11 | 11 | ||||||||||||||
Interest
expense
|
(105 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
964 | |||||||||||||||||||
Income
tax expense
|
(391 | ) | ||||||||||||||||||
Income
from continuing operations
|
573 | |||||||||||||||||||
Income
from discontinued operations, net of taxes
|
32 | |||||||||||||||||||
Net
income
|
605 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(1 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Holdings Inc.
|
$ | 606 | ||||||||||||||||||
Identifiable
assets:
|
||||||||||||||||||||
Domestic
|
$ | 6,637 | $ | 3,406 | $ | 2,458 | $ | 1,575 | $ | 14,076 | ||||||||||
Other
|
— | — | 16 | 8 | 24 | |||||||||||||||
Total
|
$ | 6,637 | $ | 3,406 | $ | 2,474 | $ | 1,583 | $ | 14,100 | ||||||||||
Capital
expenditures
|
$ | (145 | ) | $ | (5 | ) | $ | (7 | ) | $ | (4 | ) | $ | (161 | ) |
DYNEGY
INC. and DYNEGY HOLDINGS INC.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
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 | ) | |||||||||||
Impairment
and other charges
|
(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.
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Unaudited)
For
the Interim Periods Ended September 30, 2009 and 2008
DHI’s
Segment Data as of and for the Nine Months Ended September 30, 2008
(in
millions)
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Unaffiliated
revenues:
|
||||||||||||||||||||
Domestic
|
$ | 1,226 | $ | 556 | $ | 661 | $ | (4 | ) | $ | 2,439 | |||||||||
Other
|
— | — | 111 | — | 111 | |||||||||||||||
Total
revenues
|
$ | 1,226 | $ | 556 | $ | 772 | $ | (4 | ) | $ | 2,550 | |||||||||
Depreciation
and amortization
|
$ | (153 | ) | $ | (57 | ) | $ | (41 | ) | $ | (7 | ) | $ | (258 | ) | |||||
Operating
income (loss)
|
$ | 529 | $ | 104 | $ | 41 | $ | (95 | ) | $ | 579 | |||||||||
Losses
from unconsolidated investments
|
— | (7 | ) | — | — | (7 | ) | |||||||||||||
Other
items, net
|
— | 5 | 5 | 35 | 45 | |||||||||||||||
Interest
expense
|
(322 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
295 | |||||||||||||||||||
Income
tax expense
|
(127 | ) | ||||||||||||||||||
Income
from continuing operations
|
168 | |||||||||||||||||||
Income
from discontinued operations, net of taxes
|
13 | |||||||||||||||||||
Net
income
|
181 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(3 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Holdings Inc.
|
$ | 184 | ||||||||||||||||||
Identifiable
assets:
|
||||||||||||||||||||
Domestic
|
$ | 6,637 | $ | 3,406 | $ | 2,458 | $ | 1,575 | $ | 14,076 | ||||||||||
Other
|
— | — | 16 | 8 | 24 | |||||||||||||||
Total
|
$ | 6,637 | $ | 3,406 | $ | 2,474 | $ | 1,583 | $ | 14,100 | ||||||||||
Capital
expenditures
|
$ | (394 | ) | $ | (26 | ) | $ | (29 | ) | $ | (11 | ) | $ | (460 | ) |
Note
17—Subsequent Events
We have
evaluated subsequent events through November 5, 2009, the date our financial
statements were issued and up to the time of the filing of our financial
statements with the SEC.
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, 2009 and 2008
Item 2—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS—DYNEGY INC. AND DYNEGY HOLDINGS INC.
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, as supplemented by our Current Report on Form 8-K
dated September 28, 2009, which we refer to as each registrant’s “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.
In
addition to our operating generation facilities, we own an approximate 37
percent interest in PPEA Holding, which through its wholly owned subsidiary owns
a 57 percent undivided interest in the Plum Point Project, a 665 MW coal-fired
power generation facility under construction in Arkansas, which is included in
GEN-MW. We also own a 50 percent interest in SCEA, which owns an
approximate 64 percent undivided interest in the Sandy Creek Project, an 898 MW
power generation facility under construction in McLennan County, Texas, which is
included in GEN-WE. On August 9, 2009, we entered into an agreement
with LS Power to sell our interests in various power generation facilities,
including the Sandy Creek Project together with certain other
assets. Please read Recent Developments below for further
information.
Recent
Developments
LS Power
Transaction. On August 9, 2009, we entered into a purchase and
sale agreement with LS Power pursuant to which we agreed: (i) to sell our
ownership interests in 4,788 MW of peaking and combined-cycle power generation
assets, as well as our remaining interests in the Sandy Creek Project under
construction in Texas and (ii) to issue $235 million principal amount of DHI
7.50 percent senior unsecured notes due 2015 to Adio Bond, LLC, an affiliate of
LS Power. We will receive at closing approximately $1.025 billion in
cash (consisting, in part, of the release of $175 million of restricted cash on
our unaudited condensed consolidated balance sheets that was used to support our
funding commitment to Sandy Creek and approximately $200 million for the
unsecured notes), subject to working capital adjustments, and 245 million of
Dynegy’s Class B shares from LS Power.
Upon
closing of the transaction, the remaining 95 million shares of Dynegy’s Class B
common stock held by LS Power will be converted into the same number of shares
of Dynegy’s Class A common stock, representing approximately 15 percent of
Dynegy’s outstanding Class A common stock. Concurrent with the
execution of the purchase and sale agreement, LS Power and Dynegy entered into a
new shareholder agreement, which, upon closing of the transaction, generally
will restrict LS Power from increasing their future ownership for a specified
period and eliminate special approval, board representation and certain other
rights associated with the former Class B common shares. We expect to
close the LS Power transaction in the fourth quarter 2009 assuming all necessary
closing conditions are satisfied. Please read Note 2—Dispositions and
Discontinued Operations—Dispositions—LS Power Transaction for further
information.
Based on
the fair value at September 30, 2009 of the consideration to be received from LS
Power, we recorded further pre-tax impairment charges of approximately $382
million in the third quarter 2009 upon the asset groups meeting the criteria of
held for sale. Of the $382 million, approximately $235 million is
included in Income (loss) from discontinued operations in our unaudited
condensed consolidated statements of operations in the GEN-WE
segment. The impairment charges recorded in the third quarter were
based on our estimate of the fair value of the proceeds to be received from LS
Power and its affiliates which reflects Dynegy’s stock price at September 30,
2009 of $2.55 per share. We will record additional gains or losses on
the sale based on changes between September 30, 2009 and the closing of the
transaction in the fair value of consideration received. Any such
gains or losses could be material. Additionally, we expect to record
a fourth quarter net loss on the sale of assets of approximately $85 million,
related to the sale of our Sandy Creek investment. However, this
estimate could change materially based on changes in the value of our investment
in Sandy Creek from September 30, 2009 through the time the transaction is
closed. Please read Note 6—Impairment Charges for further discussion
of these impairments.
Credit Facility
Amendment. On August 5, 2009, we entered into Amendment No. 4
to the Credit Facility. Among certain other changes, Amendment No. 4
(i) modified the financial covenants relating to the ratios of Secured Debt to
EBITDA and of EBITDA to Consolidated Interest Expense; (ii) further modified
certain conditions precedent to incurring of certain DHI indebtedness, adding
revolver commitments, making certain investments or certain sales of assets and
engaging in certain other permitted activities; (iii) increased the amount of
assets eligible for disposition outside the asset sale, reinvestment and
prepayment provisions of the Credit Facility; (iv) expanded our ability to
prepay additional debt of DHI under certain conditions; and (v) increased
applicable margin for borrowings and the unused commitment fee payable on the
unused portion of the revolving facility. Please read Note
10—Debt—Credit Facility Amendment for further discussion.
Multi-Year Cost
Savings Initiative. Separate from the LS Power transaction, on
August 10, 2009, we announced an extensive, multi-year program to eliminate
certain costs throughout the company. Cumulative savings, relative to
our original plan, are expected to be $400 million to $450 million over a
four-year period beginning in 2010. Annual savings are expected to be
generated through reduced capital expenditures, operational expenditures and
general and administrative expenditures.
LIQUIDITY
AND CAPITAL RESOURCES
Overview
In this
section, we describe our liquidity and capital requirements and our internal and
external liquidity and capital resources. Our liquidity and capital
requirements are primarily a function of our debt maturities and debt service
requirements, fixed capacity payments and contractual obligations, capital
expenditures (including required environmental expenditures) and working capital
needs. Examples of working capital needs include prepayments or cash
collateral associated with purchases of commodities, particularly natural gas,
fuel oil and coal, 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 is scheduled to mature in April 2012 and the term letter of credit
capacity of $850 million is scheduled to mature in April
2013. Additionally, DHI may borrow money from time to time from
Dynegy. Our primary sources of external liquidity are proceeds from
asset sales and proceeds from capital market transactions to the extent we
engage in these transactions.
Operating
cash flows provided by our power generation assets and the available cash we
currently hold are expected to be sufficient to fund the operation of our
business, as well as our planned capital expenditure program, including
expenditures in connection with the Midwest consent decree (“Midwest Consent
Decree”), and debt service requirements over the next twelve
months. We maintain capacity under the Credit Facility in order to
post collateral in the form of letters of credit or cash, and we believe we have
sufficient capacity should we be required to post additional
collateral. Please read Note 10—Debt—Credit Facility Amendment for a
discussion of the financial covenants contained in the Credit
Facility.
Current
Liquidity. The following table summarizes our consolidated
revolver capacity and liquidity position at October 29, 2009, September 30, 2009
and December 31, 2008:
October 29,
2009
|
September 30,
2009
|
December 31,
2008
|
||||||||||
(in
millions)
|
||||||||||||
Revolver
capacity (1) (2)
|
$ | 1,080 | $ | 903 | $ | 1,080 | ||||||
Borrowings
against revolver capacity
|
— | — | — | |||||||||
Term
letter of credit capacity, net of required reserves
|
825 | 825 | 825 | |||||||||
Plum
Point and Sandy Creek letter of credit capacity (3)
|
377 | 377 | 377 | |||||||||
Outstanding
letters of credit
|
(894 | ) | (886 | ) | (1,135 | ) | ||||||
Unused
capacity
|
1,388 | 1,219 | 1,147 | |||||||||
Cash—DHI
|
486 | 519 | 670 | |||||||||
Total
available liquidity—DHI
|
1,874 | 1,738 | 1,817 | |||||||||
Cash—Dynegy
|
183 | 184 | 23 | |||||||||
Total
available liquidity—Dynegy
|
$ | 2,057 | $ | 1,922 | $ | 1,840 |
____________________________
|
(1)
|
We
currently have a syndicate of lenders participating in the revolving
portion of our Credit Facility with commitments ranging from $10 million
to $165 million. We have not experienced, nor do we currently
anticipate, any difficulties in obtaining funding from any of the current
lenders at this time. However, we continue to monitor the
environment, and any lack of or delay in funding by a significant member
or multiple members of our banking group would negatively affect our
liquidity position.
|
|
(2)
|
From
July 1, 2009 to September 30, 2009, DHI’s ability to draw on its available
liquidity under the Credit Facility was reduced temporarily as a result of
borrowing limitations under the covenant regarding the ratio of secured
debt to EBITDA. As of October 1, 2009, the capacity was
restored.
|
|
(3)
|
Includes
$275 million of capacity related to our investment in Sandy
Creek. Under the terms of our purchase and sale agreement with
LS Power, this capacity will be eliminated, and $175 million of the $275
million of restricted cash supporting this letter of credit facility will
be released to us upon completion of the sale of Sandy Creek to LS
Power. See Note 2—Dispositions and Discontinued
Operations—Dispositions—LS Power Transaction for further
discussion.
|
Cash on
Hand. At October 29, 2009 and September 30, 2009, Dynegy had
cash on hand of $669 million and $703 million, respectively, as compared to $693
million at December 31, 2008.
At
October 29, 2009 and September 30, 2009, DHI had cash on hand of $486 million
and $519 million, respectively, as compared to $670 million at December 31,
2008. The decrease in cash on hand through October 29, 2009 and
September 30, 2009 as compared to the end of 2008 is primarily attributable to a
dividend of $175 million paid to Dynegy in January 2009.
Operating
Activities
Historical
Operating Cash Flows. 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.
Dynegy’s
cash flow provided by operations totaled $397 million for the nine months ended
September 30, 2008. DHI’s cash flow provided by operations totaled
$393 million for the nine months ended September 30, 2008. During the
period, our power generation business provided positive cash flow from
operations of $757 million. Cash provided by the operations of our
power generation facilities was partly offset by a $79 million increase in
collateral postings, including 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 include a use of approximately $360 million and $364 million in cash
by Dynegy and DHI, respectively, primarily due to interest payments to service
debt, general and administrative expenses and a $17 million legal settlement
payment previously reserved, partially offset by interest income.
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 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 and our ability to
capture value associated with commodity price
volatility. Additionally, the increased costs associated with the
Credit Facility amendment and decreased cash outflows related to our cost
savings initiative will impact our future operating cash flows. Over
the longer term, our operating cash flows also will be impacted by, among other
things, our ability to tightly manage our operating costs, including maintenance
and environmental costs, in balance with ensuring that our plants are available
to operate when markets offer attractive returns.
Collateral
Postings. We use a significant portion of our capital
resources, in the form of cash 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 October 29,
2009, September 30, 2009 and December 31, 2008:
October 29, 2009
|
September 30, 2009
|
December 31, 2008
|
||||||||||
(in
millions)
|
||||||||||||
By
Business:
|
||||||||||||
Generation
|
$ | 1,003 | $ | 975 | $ | 1,064 | ||||||
Other
|
188 | 189 | 189 | |||||||||
Total
|
$ | 1,191 | $ | 1,164 | $ | 1,253 | ||||||
By
Type:
|
||||||||||||
Cash
(1)
|
$ | 297 | $ | 278 | $ | 118 | ||||||
Letters
of Credit
|
894 | 886 | 1,135 | |||||||||
Total
|
$ | 1,191 | $ | 1,164 | $ | 1,253 |
__________________
|
(1)
|
Cash
collateral, including initial margin postings exclude 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.
|
The
changes in collateral postings from December 31, 2008 to September 30, 2009 and
to October 29, 2009 are primarily related to a increase (decrease) in letters of
credit related to certain hedge positions partially offset by increases in
initial margin requirements associated with the volume of forward commodity
transactions.
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 $429 million and
$460 million in capital expenditures during the nine months ended September 30,
2009 and 2008. Our capital spending by reportable segment was as
follows:
For the Nine Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
(in
millions)
|
||||||||
GEN-MW
|
$ | 394 | $ | 394 | ||||
GEN-WE
|
10 | 26 | ||||||
GEN-NE
|
20 | 29 | ||||||
Other
|
5 | 11 | ||||||
Total
|
$ | 429 | $ | 460 |
Capital
spending in our GEN-MW segment primarily consisted of environmental and
maintenance capital projects, as well as approximately $66 million and $165
million spent on development capital related to the Plum Point Project during
the nine months ended September 30, 2009 and 2008,
respectively. Capital spending in our GEN-WE and GEN-NE segments
primarily consisted of maintenance projects.
During
the first quarter 2009, we revised our estimate of the timing regarding a
maintenance capital project at our Moss Landing facility in
GEN-WE. We expect capital expenditures for the fourth quarter 2009 to
be approximately $40 million higher than originally planned, primarily due to
the change in timing.
Asset
Dispositions. 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. Please read Note 2—Dispositions
and Discontinued Operations—Discontinued Operations—Heard County for further
discussion.
On August
9, 2009, we entered into a purchase and sale agreement with LS Power in which we
agreed to: (i) sell our ownership interests in 4,788 MW of peaking and
combined-cycle power generation assets, as well as our remaining interest in the
Sandy Creek Project under construction in Texas and (ii) issue $235 million
principal amount of DHI 7.50 percent senior unsecured notes due
2015. We will receive $1.025 billion in cash (consisting, in part, of
$175 million of restricted cash that was used to support our funding commitment
to Sandy Creek and approximately $200 million for the unsecured notes), subject
to working capital adjustments, and 245 million of Dynegy’s Class B shares held
by LS Power. The $175 million of Sandy Creek restricted cash
currently appears on our unaudited condensed consolidated balance sheet as part
of Restricted cash and investments. Please see Note 2—Dispositions
and Discontinued Operations—Dispositions—LS Power Transaction for further
information.
Proceeds
from asset sales, net of transaction costs, during the nine months ended
September 30, 2008 totaled $452 million and primarily related to the sale of our
Rolling Hills power generation facility, our Calcasieu power generating
facility, the NYMEX shares and seats, and the beneficial interest in Oyster
Creek. Please read Note 2—Dispositions and Discontinued
Operations—Discontinued Operations.
Consistent
with industry practice, we regularly evaluate our generation fleet based
primarily on geographic location, fuel supply, market structure and market
recovery expectations. We consider divestitures of non-core assets
where the balance of the above factors suggests that such assets’ earnings
potential is limited or that the value that can be captured through a
divestiture outweighs the benefits of continuing to own and operate such
assets. We have previously indicated that we consider Plum Point a
non-core asset and intend to pursue alternatives regarding our remaining
ownership interest.
Other Investing
Activities. 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.
Dynegy
made $11 million in contributions to DLS Power Holdings during the nine months
ended September 30, 2008. We received a distribution of approximately
$7 million and repayment of approximately $3 million of an affiliate receivable
upon the sale of a partial interest in Sandy Creek during the nine months ended
September 30, 2008. Please see Note 8—Variable Interest
Entities—Sandy Creek for further discussion.
Cash
outflows related to short-term investments increased by $127 million and $120
million for the nine months ended September 30, 2008 for Dynegy and DHI,
respectively, as a result of a reclassification from cash equivalents to
short-term investments. Additionally, there was a $17 million cash
inflow during the nine months ended September 30, 2008 related to changes in
restricted cash balances primarily due to a reduction of our cash collateral as
a result of SCEA’s sale of an 11 percent undivided interest in the Sandy Creek
Project, the release of restricted cash and the use of restricted cash for the
ongoing construction of the Plum Point Project, partially offset by interest
income. Finally, Other included $7 million of insurance
proceeds. Dynegy received $4 million of proceeds from the liquidation
of an investment during the nine months ended September 30, 2008.
Financing
Activities
Historical Cash
Flow from Financing Activities. 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.
Dynegy’s
cash provided by financing activities during the nine months ended September 30,
2008 totaled $133 million, which primarily related to proceeds of $158 million
from long-term borrowings under the Plum Point Credit Agreement Facility, partly
offset by a $21 million principal payment on our 9.00 percent secured bonds due
2013. DHI’s cash provided by financing activities during the nine
months ended September 30, 2008 totaled $131 million, which primarily related to
proceeds of $158 million from long-term borrowings under the Plum Point Credit
Agreement Facility, partly offset by a $21 million principal payment on our 9.00
percent secured bonds due 2013.
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
financial covenants, insolvency events, defaults on scheduled principal or
interest payments, acceleration of other financial obligations and change of
control provisions. 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.
On
October 16, 2009, Standard & Poor’s downgraded PPEA’s credit
rating. Because of this downgrade, certain interest rate swaps to
which Plum Point is a party may be terminated by the counterparties
if there is also a default by the insurer, Ambac, which has provided
credit insurance for the swaps. The termination value of the Plum
Point interest rate swaps at September 30, 2009 was approximately $135
million. Termination of the interest rate swaps, if not paid by PPEA,
could result in the acceleration of the PPEA debt. Our obligations
related to our investment in PPEA, excluding the noncontrolling interest
holders’ obligation, are limited to our $15 million letter of credit issued
under our Credit Facility to support our contingent equity contribution to the
Plum Point Project. Please read Note 10—Debt—Plum Point Credit
Agreement Facility for further discussion.
Capital-Structuring
Transactions. Following the completion of the pending
transaction with LS Power, we will be focused on deploying the proceeds from the
transaction in a manner that best aligns with our capital allocation
objectives. We are considering the pursuit of one or more financing
transactions in the near-term designed to reduce existing debt or other
obligations. Capital allocation determinations generally are subject
to the discretion of Dynegy’s Board of Directors as well as availability of
capital and related investment opportunities, and may be limited by the
provisions of our financing agreements as well as the provisions of the
agreements with LS Power. Any particular use of capital in an amount
that is not considered material may be made without any prior public disclosure
and could occur at any time.
Further,
as part of our ongoing efforts to maintain a capital structure that is closely
aligned with the cash-generating potential of our asset-based business, which is
subject to cyclical changes in commodity prices, we may explore additional
sources of external liquidity, including public or private debt or equity
issuances. Matters to be considered will include reducing cash
interest expense, covenant flexibility, return on investment and maturity
profile, all to be balanced with maintaining adequate liquidity. The
timing of any transaction may be impacted by events, such as strategic growth
opportunities, legal judgments or regulatory or environmental requirements as
well as any decisions to seek an improved credit profile. The
receptiveness of the 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, long-term
business prospects and other factors beyond our control, including current
market conditions. Any issuance of equity by Dynegy likely would have
other effects as well, including stockholder dilution, and our ability to issue
equity securities is limited by the shareholder agreement with LS Power entered
into on August 9, 2009. This agreement provides that we will not
issue Dynegy’s equity securities for our own purposes until the earlier of (i)
121 days following the closing of the transaction with LS Power and (ii) the
first date following closing of the transaction in which LS Power owns, in
aggregate, less than 10 percent of Dynegy’s then outstanding Class A common
stock. Our ability to issue debt securities is limited by our
financing agreements, including our Credit Facility, and the note purchase
agreement with Adio Bond, LLC, an affiliate of LS Power, for a period of five
business days following the closing of the LS Power transaction and
for a period of five business days following Adio Bond's request for
support in connection with an underwritten resale.
In
addition, we continually review and discuss opportunities to participate in what
we believe will be continuing consolidation of the power generation
industry. No such definitive transaction has been agreed to and none
can be guaranteed to occur; however, we have successfully executed on similar
opportunities in the past and could do so again in the
future. Depending on the terms and structure of any such transaction,
we could issue significant debt and/or equity securities for capital-raising
purposes. We also could be required to assume substantial debt
obligations and the underlying payment obligations.
Dividends and
Dynegy Common Stock. Dividend payments on Dynegy’s common
stock are at the discretion of its Board of Directors. Dynegy did not
declare or pay a dividend on its common stock during the third quarter 2009, and
does not expect to pay a dividend on its common stock in the foreseeable
future.
Credit
Ratings
Our
credit rating status is currently “non-investment grade”; our senior unsecured
debt is rated “B” by Standard & Poor’s, “B3” by Moody’s, and “B” by
Fitch. On April 8, 2009, Moody’s downgraded our corporate family and
probability of default ratings to “B2” from “B1” based on projected lower power
prices affecting credit metrics. The agency also cut our senior
secured bank facilities rating to “Ba2” from “Ba1”, and senior unsecured debt
rating to “B3” from “B2”. On August 12, 2009, Fitch Ratings
downgraded our issuer default ratings to “B-” from “B”; downgraded our senior
secured to “BB-” from “BB”; downgraded our senior unsecured to “B” from “B+”,
based on projected lower power prices affecting credit metrics. On
August 18, 2009, Standard and Poor’s issued a rating action revising their
outlook to negative from stable. The ratings were affirmed at
corporate family rating at “B”; senior secured rating at “BB-”; and senior
unsecured rating at “B”. The downgrades did not trigger any
obligations under our financing arrangements or other obligations and otherwise
have not impacted our operations or liquidity.
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.
As of
September 30, 2009, there were no material changes to our contractual
obligations and contingent financial commitments since December 31,
2008.
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, 2009 and 2008. 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, 2009 and 2008
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, 2009 and 2008,
respectively:
Dynegy’s
Results of Operations for the Three Months Ended September 30, 2009
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
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 | ) |
Dynegy’s
Results of Operations for the Three Months Ended September 30, 2008
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Revenues
|
$ | 997 | $ | 323 | $ | 443 | $ | (4 | ) | $ | 1,759 | |||||||||
Cost
of sales
|
(194 | ) | (127 | ) | (179 | ) | 2 | (498 | ) | |||||||||||
Operating
and maintenance expense, exclusive of depreciation and amortization
expense shown separately below
|
(54 | ) | (23 | ) | (46 | ) | 1 | (122 | ) | |||||||||||
Depreciation
and amortization expense
|
(49 | ) | (20 | ) | (14 | ) | (2 | ) | (85 | ) | ||||||||||
Gain
on sale of assets, net
|
57 | — | — | — | 57 | |||||||||||||||
General
and administrative expense
|
— | — | — | (48 | ) | (48 | ) | |||||||||||||
Operating
income (loss)
|
$ | 757 | $ | 153 | $ | 204 | $ | (51 | ) | $ | 1,063 | |||||||||
Losses
from unconsolidated investments
|
— | (5 | ) | — | — | (5 | ) | |||||||||||||
Other
items, net
|
— | 1 | (1 | ) | 11 | 11 | ||||||||||||||
Interest
expense
|
(105 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
964 | |||||||||||||||||||
Income
tax expense
|
(392 | ) | ||||||||||||||||||
Income
from continuing operations
|
572 | |||||||||||||||||||
Income
from discontinued operations, net of taxes.
|
32 | |||||||||||||||||||
Net
income
|
604 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(1 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Inc.
|
$ | 605 |
The
following tables provide summary financial data regarding DHI’s consolidated and
segmented results of operations for the three month periods ended September 30,
2009 and 2008, respectively:
DHI’s
Results of Operations for the Three Months Ended September 30, 2009
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
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 | ) |
DHI’s
Results of Operations for the Three Months Ended September 30, 2008
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Revenues
|
$ | 997 | $ | 323 | $ | 443 | $ | (4 | ) | $ | 1,759 | |||||||||
Cost
of sales
|
(194 | ) | (127 | ) | (179 | ) | 2 | (498 | ) | |||||||||||
Operating
and maintenance expense, exclusive of depreciation and amortization
expense shown separately below
|
(54 | ) | (23 | ) | (46 | ) | 1 | (122 | ) | |||||||||||
Depreciation
and amortization expense
|
(49 | ) | (20 | ) | (14 | ) | (2 | ) | (85 | ) | ||||||||||
Gain
on sale of assets, net
|
57 | — | — | — | 57 | |||||||||||||||
General
and administrative expense
|
— | — | — | (48 | ) | (48 | ) | |||||||||||||
Operating
income (loss)
|
$ | 757 | $ | 153 | $ | 204 | $ | (51 | ) | $ | 1,063 | |||||||||
Losses
from unconsolidated investments
|
— | (5 | ) | — | — | (5 | ) | |||||||||||||
Other
items, net
|
— | 1 | (1 | ) | 11 | 11 | ||||||||||||||
Interest
expense
|
(105 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
964 | |||||||||||||||||||
Income
tax expense
|
(391 | ) | ||||||||||||||||||
Income
from continuing operations
|
573 | |||||||||||||||||||
Income
from discontinued operations, net of taxes.
|
32 | |||||||||||||||||||
Net
income
|
605 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(1 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Holdings Inc.
|
$ | 606 |
The
following table provides summary segmented operating statistics for the three
months ended September 30, 2009 and 2008, respectively:
Three Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
GEN-MW
|
||||||||
Million
Megawatt Hours Generated (1)
|
6.6 | 7.1 | ||||||
In
Market Availability for Coal Fired Facilities (2)
|
92 | % | 95 | % | ||||
Average
Capacity Factor for Combined Cycle Facilities (3)
|
38 | % | 28 | % | ||||
Average
Quoted On-Peak Market Power Prices ($/MWh) (4):
|
||||||||
Cinergy
(Cin Hub)
|
$ | 31 | $ | 74 | ||||
Commonwealth
Edison (NI Hub)
|
$ | 31 | $ | 73 | ||||
PJM
West
|
$ | 40 | $ | 95 | ||||
Average
Market Spark Spreads ($/MWh) (5):
|
||||||||
PJM
West
|
$ | 16 | $ | 27 | ||||
GEN-WE
|
||||||||
Million
Megawatt Hours Generated (6) (7)
|
2.4 | 2.6 | ||||||
Average
Capacity Factor for Combined Cycle Facilities (3)
|
56 | % | 72 | % | ||||
Average
Quoted On-Peak Market Power Prices ($/MWh) (4):
|
||||||||
North
Path 15 (NP 15)
|
$ | 38 | $ | 86 | ||||
Average
Market Spark Spreads ($/MWh) (5):
|
||||||||
North
Path 15 (NP 15)
|
$ | 12 | $ | 25 | ||||
GEN-NE
|
||||||||
Million
Megawatt Hours Generated
|
2.6 | 2.2 | ||||||
In
Market Availability for Coal Fired Facilities (2)
|
95 | % | 93 | % | ||||
Average
Capacity Factor for Combined Cycle Facilities (3)
|
44 | % | 29 | % | ||||
Average
Quoted On-Peak Market Power Prices ($/MWh) (4):
|
||||||||
New
York—Zone G
|
$ | 44 | $ | 113 | ||||
New
York—Zone A
|
$ | 29 | $ | 76 | ||||
Mass
Hub
|
$ | 37 | $ | 95 | ||||
Average
Market Spark Spreads ($/MWh) (5):
|
||||||||
New
York—Zone A
|
$ | 4 | $ | 10 | ||||
Mass
Hub
|
$ | 13 | $ | 28 | ||||
Fuel
Oil
|
$ | (72 | ) | $ | (60 | ) | ||
Average
natural gas price—Henry Hub ($/MMBtu) (8)
|
$ | 3.15 | $ | 9.10 |
__________________
|
(1)
|
Excludes
less than 0.1 million MWh generated by our Bluegrass power generation
facility, which is classified in discontinued operations, for each of the
periods.
|
|
(2)
|
Reflects
the percentage of generation available during periods when market prices
are such that these units could be profitably
dispatched.
|
|
(3)
|
Reflects
actual production as a percentage of available
capacity. Excludes the Arlington Valley and Griffith power
generation facilities which are reported as discontinued operations with
respect to the GEN-WE segment.
|
|
(4)
|
Reflects
the average of day-ahead quoted prices for the periods presented and does
not necessarily reflect prices realized by
us.
|
|
(5)
|
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.
|
|
(6)
|
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, 2009 and 2008,
respectively.
|
|
(7)
|
Excludes
approximately 0.1 MWh generated by the Heard County power generation
facility, which we sold in April 2009, for the three months ended
September 30, 2008. Excludes 0.5 MWh and 0.5 MWh generated by
our Arlington Valley power generation facility and 1.1 MWh and 1.0 MWh
generated by our Griffith power generation facility, which are
collectively classified in discontinued operations, for the three months
ended September 30, 2009 and 2008
respectively.
|
|
(8)
|
Reflects
the average of daily quoted prices for the periods presented and does not
reflect costs incurred by us.
|
The
following table summarizes significant items on a pre-tax basis, with the
exception of the tax items, affecting net income (loss) for the period
presented:
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.
|
Three Months Ended September 30,
2008
|
||||||||||||||||||||
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||
Gain
on sale of Rolling Hills
|
$ | 57 | $ | — | $ | — | $ | — | $ | 57 | ||||||||||
Total
|
$ | 57 | $ | — | $ | — | $ | — | $ | 57 |
Operating
Income (Loss)
Dynegy’s
and DHI’s operating loss was $7 million for the three months ended September 30,
2009, compared to an operating income of $1,063 million for the three months
ended September 30, 2008.
Our
operating loss for the three months ended September 30, 2009 was driven, in
large part, by $148 million of asset impairments. Please read Note
6—Impairment Charges for further discussion.
Mark-to-market
losses on forward sales of power associated with our generating assets are
included in Revenues in the unaudited condensed consolidated statements of
operations. Such losses, which totaled $122 million for the three
months ended September 30, 2009, were a result of the expiration of certain risk
management positions during the third quarter 2009, for which earnings were
recognized in prior periods. These losses compared to $865 million of
mark-to-market gains for the three months ended September 30, 2008.
We do not
designate our commodity derivative instruments as cash flow hedges for
accounting purposes. Please read Note 4—Risk Management Activities,
Derivatives and Financial Instruments for further discussion. The
resulting mark-to-market accounting treatment results in the immediate
recognition of gains and losses within revenues in the unaudited condensed
consolidated statements of operations due to changes in the fair value of the
derivative instruments. 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 power sales from generation
activity for which the derivative instruments serve as economic
hedges. Except for those positions that settled in the three months
ended September 30, 2009, the expected cash impact of the settlement of these
positions will be recognized over time largely through the end of 2010 based on
the prices at which such positions are contracted. Our overall
mark-to-market position and the related mark-to-market value will change as we
buy or sell volumes within the forward market and as forward commodity prices
fluctuate.
Power
Generation—Midwest Segment. Operating income for GEN-MW was $5
million for the three months ended September 30, 2009, compared to income of
$757 million for the three months ended September 30, 2008. Such
amounts do not include results from our Bluegrass power generating facility,
which has been reclassified as a discontinued operation for all periods
presented.
Revenues
for the three months ended September 30, 2009 decreased by $606 million compared
to the three months ended September 30, 2008, cost of sales decreased by $65
million and operating and maintenance expense decreased by $1 million, resulting
in a net decrease of $540 million. The decrease was primarily driven
by the following:
|
·
|
Mark-to-market
losses – GEN-MW’s results for the three months ended September 30, 2009
included mark-to-market losses of $44 million related to forward sales,
compared to $568 million of mark-to-market gains for the three months
ended September 30, 2008. Of the $44 million in 2009
mark-to-market losses, $92 million of losses related to positions that
settled or will settle in 2009, partly offset by $48 million of gains
related to positions that will settle in 2010 and
beyond;
|
|
·
|
Decreased
volumes —Generated volumes decreased by 7 percent, from 7.1 million MWh
for the three months ended September 30, 2008, to 6.6 million MWh for the
three months ended September 30, 2009;
and
|
|
·
|
Results
were favorably impacted in 2008 by $7 million from the sale of emission
credits.
|
These
items were partly offset by the following:
|
·
|
A
$50 million payment received to assign our rights to a third party
pursuant to a power sales agreement. This agreement would have
been in effect through 2011; and
|
|
·
|
Benefit
of economic hedging activity – The average actual on-peak prices in the
Cin Hub pricing region decreased from $74 per MWh for the three months
ended September 30, 2008 to $31 per MWh for the three months ended
September 30, 2009. However, the impact of lower market prices
was mitigated by economic hedging, resulting in realized prices that were
higher in the three months ended September 30, 2009 than in the three
months ended September 30, 2008.
|
Depreciation
expense increased from $49 million for the third quarter 2008 to $57 million for
the third quarter 2009 as a result of capital projects placed into service
during 2009. These capital projects were primarily related to the
Midwest Consent Decree.
In
addition, in 2009, we recorded a $147 million impairment of our 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. Please read Note
6—Impairment Charges for further discussion.
Operating
income for the three months ended September 30, 2008 included a $57 million gain
from the sale of our Rolling Hills power generating facility, reflected in Gain
on sale of assets in our unaudited condensed consolidated statements of
operations.
Power
Generation—West Segment. Operating income for GEN-WE was $34
million for three months ended September 30, 2009, compared to income of $153
million for the three months ended September 30, 2008. Such amounts
do not include results from our Arizona and Heard County power generating
facilities, which have been reclassified as discontinued operations for all
periods presented.
Revenues
for the three months ended September 30, 2009 decreased by $213 million compared
to the three months ended September 30, 2008, cost of sales decreased by $91
million and operating and maintenance expense increased by $2 million, resulting
in a net decrease of $124 million. The decrease was primarily driven
by the following:
|
·
|
Mark-to-market
losses – GEN-WE’s results for the three months ended September 30, 2009
included mark-to-market losses of $33 million, compared to $122 million of
mark-to-market gains for the three months ended September 30,
2008. Of the $33 million in 2009 mark-to-market losses, $3
million related to positions that settled or will settle in 2009, and the
remaining $30 million related to positions that will settle in 2010 and
beyond; and
|
|
·
|
Decreased
volumes - Generated volumes were 2.4 million MWh for the three months
ended September 30, 2009, down from 2.6 million MWh for the three months
ended September 30, 2008. The volume decrease was driven in
large part by decreased market spark spreads and reduced dispatch
opportunities.
|
These
items were partly offset by increased tolling and capacity revenues of $30
million.
Depreciation
expense decreased from $20 million for the third quarter 2008 to $15 million for
the third quarter 2009, largely as a result of an increase in the estimated
useful life of one of our generation facilities.
Power
Generation—Northeast Segment. Operating income for GEN-NE was
$1 million for the three months ended September 30, 2009, compared to income of
$204 million for the three months ended September 30, 2008.
Revenues
for the three months ended September 30, 2009 decreased by $269 million compared
to the three months ended September 30, 2008, cost of sales decreased by $58
million and operating and maintenance expense decreased by $3 million, resulting
in a net decrease of $208 million. The decrease was primarily driven
by the following:
|
·
|
Mark-to-market
losses – GEN-NE’s results for the three months ended September 30, 2009
included mark-to-market losses of $45 million related to forward sales,
compared to gains of $175 million for the three months ended September 30,
2008. Of the $45 million in 2009 mark-to-market losses, $31
million related to positions that settled or will settle in 2009, and the
remaining $14 million related to positions that will settle in 2010 and
beyond; and
|
|
·
|
Decreased
prices – On-peak market prices in New York Zone G, New York Zone A and
Mass Hub decreased by 61 percent, 62 percent and 61 percent, respectively,
resulting in compressed spreads. The decrease in New York Zone
G prices led to a decrease in generated volumes at our Danskammer power
generation facility.
|
These
items were partly offset by increased volumes from our natural gas-fired
facilities. Volumes produced by our natural gas-fired combined cycle
fleet increased despite compressed market spark spreads as a result of reduced
congestion and improved dispatch opportunities at our Independence power
generation facility, as well as a reduction in transmission outages at our Casco
Bay power generation facility.
Depreciation
expense decreased from $14 million for the third quarter 2008 to $8 million for
the third quarter 2009, primarily as a result of the impairment of our Roseton
and Danskammer power generation facilities at June 30, 2009 and September 30,
2009.
Other. Dynegy’s
and DHI’s other operating loss for the three months ended September 30, 2009 was
$47 million, compared to an operating loss of $51 million for the three months
ended September 30, 2008. Operating losses in both periods were
comprised primarily of general and administrative expenses.
Consolidated
general and administrative expenses were $42 million and $48 million for the
three months ended September 30, 2009 and 2008, respectively. General
and administrative expenses included legal and settlement charges of $7 million
for the three months ended September 30, 2008.
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. 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. Losses from unconsolidated investments were $5
million for the three months ended September 30, 2008, related to
the GEN-WE investment in the Sandy Creek Project. Please
see Note 8—Variable Interest Entities—Sandy Creek for further
discussion.
Other
Items, Net
Dynegy’s
and DHI’s other items, net, totaled $2 million of income for the three months
ended September 30, 2009, compared to $11 million of income for the three months
ended September 30, 2008. The decrease is primarily associated with
lower interest income due to lower LIBOR rates in 2009.
Interest
Expense
Dynegy’s
and DHI’s interest expense totaled $115 million for the three months ended
September 30, 2009, compared to $105 million for the three months ended
September 30, 2008. The increase was primarily attributable to $14
million of expense related to the change in value and settlement of interest
rate swaps associated with our PPEA Credit Agreement Facility in 2009, partly
offset by lower LIBOR rates on our variable-rate debt in 2009.
Income
Tax Benefit (Expense)
Dynegy
reported an income tax benefit from continuing operations of $34 million for the
three months ended September 30, 2009, compared to an income tax expense from
continuing operations of $392 million for the three months ended September 30,
2008. The 2009 effective tax rate was 27 percent, compared to 41
percent in 2008.
DHI
reported an income tax benefit from continuing operations of $35 million for the
three months ended September 30, 2009, compared to an income tax expense of $391
million from continuing operations for the three months ended September 30,
2008. The 2009 effective tax rate was 27 percent, compared to 41
percent in 2008.
As a
result of the planned LS Power transaction, the 2009 income tax benefit was
partly offset by the impact of disallowed losses associated with the planned
transaction with LS Power. For the period ended September 30, 2008,
the difference between the effective rate of 41 percent for Dynegy and DHI,
respectively and the statutory rate of 35 percent resulted primarily from the
effect of state income taxes in the taxing jurisdictions in which our assets
operate.
Discontinued
Operations
Income
(Loss) From Discontinued Operations Before Taxes
For the
three months ended September 30, 2009, our pre-tax loss from discontinued
operations was $213 million, related to our Arizona and Bluegrass power
generation facilities. This loss included a pre-tax impairment charge
of $235 million related to our Arizona power generation facilities, as these
facilities met the criteria for classification as held for sale at August 9,
2009. For the three months ended September 30, 2008, our pre-tax
income from discontinued operations was $54 million, related to the operations
of the Calcasieu, Heard County, Bluegrass and Arizona power generation
facilities.
Income
Tax (Expense) Benefit From Discontinued Operations
Dynegy
recorded an income tax benefit from discontinued operations of $84 million
during the three months ended September 30, 2009, compared to an income tax
expense of $22 million during the three months ended September 30,
2008. These amounts reflect effective rates of 39 percent and 41
percent, respectively. DHI recorded an income tax benefit from
discontinued operations of $74 million during the three months ended September
30, 2009, compared to an income tax expense of $22 million during the three
months ended September 30, 2008. These amounts reflect effective
rates of 35 percent and 41 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.
Noncontrolling
Interest
We
recorded $11 million of noncontrolling interest expense for the three months
ended September 30, 2009, compared with $1 million of noncontrolling interest
expense for the three months ended September 30, 2008 related to the Plum Point
Project. The change in noncontrolling interest expense is primarily
related to the mark-to-market losses related to the interest rate swap
agreements associated with the Plum Point Credit Agreement
Facility. Effective July 28, 2009, the interest rate swap agreements
were no longer accounted for as cash flow hedges; therefore, the change in
value is reflected in the unaudited condensed consolidated statement of
operations and is no longer reflected in accumulated other comprehensive
loss.
Nine
Months Ended September 30, 2009 and 2008
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, 2009 and 2008, respectively:
Dynegy’s
Results of Operations for the Nine Months Ended September 30, 2009
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
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 | ) |
Dynegy’s
Results of Operations for the Nine Months Ended September 30, 2008
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Revenues
|
$ | 1,226 | $ | 556 | $ | 772 | $ | (4 | ) | $ | 2,550 | |||||||||
Cost
of sales
|
(455 | ) | (334 | ) | (547 | ) | 10 | (1,326 | ) | |||||||||||
Operating
and maintenance expense, exclusive of depreciation and amortization
expense shown separately below
|
(146 | ) | (72 | ) | (143 | ) | 17 | (344 | ) | |||||||||||
Depreciation
and amortization expense
|
(153 | ) | (57 | ) | (41 | ) | (7 | ) | (258 | ) | ||||||||||
Gain
on sale of assets, net
|
57 | 11 | — | 15 | 83 | |||||||||||||||
General
and administrative expense
|
— | — | — | (126 | ) | (126 | ) | |||||||||||||
Operating
income (loss)
|
$ | 529 | $ | 104 | $ | 41 | $ | (95 | ) | $ | 579 | |||||||||
Losses
from unconsolidated investments
|
— | (7 | ) | — | (10 | ) | (17 | ) | ||||||||||||
Other
items, net
|
— | 5 | 5 | 36 | 46 | |||||||||||||||
Interest
expense
|
(322 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
286 | |||||||||||||||||||
Income
tax expense
|
(121 | ) | ||||||||||||||||||
Income
from continuing operations
|
165 | |||||||||||||||||||
Income
from discontinued operations, net of tax
|
13 | |||||||||||||||||||
Net
income
|
178 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(3 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Inc.
|
$ | 181 |
The
following tables provide summary financial data regarding DHI’s consolidated and
segmented results of operations for the nine month periods ended September 30,
2009 and 2008, respectively:
DHI’s
Results of Operations for the Nine Months Ended September 30, 2009
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
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 | ) |
DHI’s
Results of Operations for the Nine Months Ended September 30, 2008
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
Revenues
|
$ | 1,226 | $ | 556 | $ | 772 | $ | (4 | ) | $ | 2,550 | |||||||||
Cost
of sales
|
(455 | ) | (334 | ) | (547 | ) | 10 | (1,326 | ) | |||||||||||
Operating
and maintenance expense, exclusive of depreciation and amortization
expense shown separately below
|
(146 | ) | (72 | ) | (143 | ) | 17 | (344 | ) | |||||||||||
Depreciation
and amortization expense
|
(153 | ) | (57 | ) | (41 | ) | (7 | ) | (258 | ) | ||||||||||
Gain
on sale of assets
|
57 | 11 | — | 15 | 83 | |||||||||||||||
General
and administrative expense
|
— | — | — | (126 | ) | (126 | ) | |||||||||||||
Operating
income (loss)
|
$ | 529 | $ | 104 | $ | 41 | $ | (95 | ) | $ | 579 | |||||||||
Losses
from unconsolidated investments
|
— | (7 | ) | — | — | (7 | ) | |||||||||||||
Other
items, net
|
— | 5 | 5 | 35 | 45 | |||||||||||||||
Interest
expense
|
(322 | ) | ||||||||||||||||||
Income
from continuing operations before income taxes
|
295 | |||||||||||||||||||
Income
tax expense
|
(127 | ) | ||||||||||||||||||
Income
from continuing operations
|
168 | |||||||||||||||||||
Income
from discontinued operations, net of tax
|
13 | |||||||||||||||||||
Net
income
|
181 | |||||||||||||||||||
Less:
Net loss attributable to the noncontrolling interests
|
(3 | ) | ||||||||||||||||||
Net
income attributable to Dynegy Holdings Inc.
|
$ | 184 |
The
following table provides summary segmented operating statistics for the nine
months ended September 30, 2009 and 2008, respectively:
Nine Months Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
GEN-MW
|
||||||||
Million
Megawatt Hours Generated (1)
|
19.1 | 18.5 | ||||||
In
Market Availability for Coal Fired Facilities (2)
|
89 | % | 89 | % | ||||
Average
Capacity Factor for Combined Cycle Facilities (3)
|
32 | % | 17 | % | ||||
Average
Quoted On-Peak Market Power Prices ($/MWh) (4):
|
||||||||
Cinergy
(Cin Hub)
|
$ | 35 | $ | 73 | ||||
Commonwealth
Edison (NI Hub)
|
$ | 34 | $ | 72 | ||||
PJM
West
|
$ | 45 | $ | 91 | ||||
Average
Market Spark Spreads ($/MWh) (5):
|
||||||||
PJM
West
|
$ | 13 | $ | 17 | ||||
GEN-WE
|
||||||||
Million
Megawatt Hours Generated (6) (7)
|
4.7 | 6.5 | ||||||
Average
Capacity Factor for Combined Cycle Facilities (3)
|
44 | % | 65 | % | ||||
Average
Quoted On-Peak Market Power Prices ($/MWh) (4):
|
||||||||
North
Path 15 (NP 15)
|
$ | 36 | $ | 88 | ||||
Average
Market Spark Spreads ($/MWh) (5):
|
||||||||
North
Path 15 (NP 15)
|
$ | 8 | $ | 20 | ||||
GEN-NE
|
||||||||
Million
Megawatt Hours Generated
|
7.8 | 5.7 | ||||||
In
Market Availability for Coal Fired Facilities (2)
|
94 | % | 92 | % | ||||
Average
Capacity Factor for Combined Cycle Facilities (3)
|
44 | % | 25 | % | ||||
Average
Quoted On-Peak Market Power Prices ($/MWh) (4):
|
||||||||
New
York—Zone G
|
$ | 50 | $ | 111 | ||||
New
York—Zone A
|
$ | 36 | $ | 73 | ||||
Mass
Hub
|
$ | 45 | $ | 100 | ||||
Average
Market Spark Spreads ($/MWh) (5):
|
||||||||
New
York—Zone A
|
$ | 5 | $ | 2 | ||||
Mass
Hub
|
$ | 11 | $ | 25 | ||||
Fuel
Oil
|
$ | (45 | ) | $ | (45 | ) | ||
Average
natural gas price—Henry Hub ($/MMBtu) (8)
|
$ | 3.80 | $ | 9.67 |
_______
|
(1)
|
Excludes
approximately 0.1 million MWh and less than 0.1 million MWh generated by
our Bluegrass power generation facility, which is classified in
discontinued operations, for the nine months ended September 30, 2009 and
2008, respectively.
|
|
(2)
|
Reflects
the percentage of generation available during periods when market prices
are such that these units could be profitably
dispatched.
|
|
(3)
|
Reflects
actual production as a percentage of available
capacity. Excludes Arlington Valley and Griffith power
generation facilities which are reported as discontinued operations with
respect to the GEN-WE segment.
|
|
(4)
|
Reflects
the average of day-ahead quoted prices for the periods presented and does
not necessarily reflect prices realized by
us.
|
|
(5)
|
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.
|
|
(6)
|
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, 2009 and 2008,
respectively.
|
|
(7)
|
Excludes
less than 0.1 MWh generated by the Heard County power generation facility,
which we sold in April 2009, for the nine months ended September, 30, 2009
and 2008, respectively. Excludes approximately 0.7
MWh and 0.8 MWh generated by our Arlington Valley power generation
facility and 1.4 MWh and 1.6 MWh generated by our Griffith power
generation facility, which are collectively classified in discontinued
operations, for the nine months ended September 30, 2009 and 2008
respectively.
|
|
(8)
|
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,
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.
|
|
(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.
|
Nine Months Ended September 30,
2008
|
||||||||||||||||||||
Power Generation
|
||||||||||||||||||||
GEN-MW
|
GEN-WE
|
GEN-NE
|
Other
|
Total
|
||||||||||||||||
(in
millions)
|
||||||||||||||||||||
Gain
on sale of Rolling Hills
|
$ | 57 | $ | — | $ | — | $ | — | $ | 57 | ||||||||||
Release
of state sales and franchise tax liabilities
|
— | — | — | 16 | 16 | |||||||||||||||
Gain
on sale of NYMEX shares
|
— | — | — | 15 | 15 | |||||||||||||||
Gain
on sale of Oyster Creek ownership interest
|
— | 11 | — | — | 11 | |||||||||||||||
Gain
on sale of Sandy Creek ownership interest
|
— | 13 | — | — | 13 | |||||||||||||||
Total
|
$ | 57 | $ | 24 | $ | — | $ | 31 | $ | 112 |
Operating
Income (Loss)
Operating
loss for Dynegy was $624 million for the nine months ended September 30, 2009,
compared to operating income of $579 million for the nine months ended September
30, 2008. Operating loss for DHI was $626 million for the nine months
ended September 30, 2009, compared to operating income of $579 million for the
nine months ended September 30, 2008.
Our
operating loss for the nine months ended September 30, 2009 was driven, in large
part, by a $433 million impairment of goodwill and by $535 million of asset
impairments. Please read Note 9—Goodwill for further discussion of
the goodwill impairment and Note 6—Impairment Charges for further discussion of
the asset impairments.
Mark-to-market
losses on forward sales of power associated with our generating assets are
included in Revenues in the unaudited condensed consolidated statements of
operations. Such losses, which totaled $64 million for the nine
months ended September 30, 2009, were a result of the expiration of certain risk
management positions during the first nine months of 2009. These
losses compared to $122 million of mark-to-market gains for the nine months
ended September 30, 2008, when forward market power prices decreased during the
period.
We do not
designate our commodity derivative instruments as cash flow hedges for
accounting purposes. Please read Note 4—Risk Management Activities,
Derivatives and Financial Instruments for further discussion. The
resulting mark-to-market accounting treatment results in the immediate
recognition of gains and losses within revenues in the unaudited condensed
consolidated statements of operations due to changes in the fair value of the
derivative instruments. 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 power sales from generation
activity for which the derivative instruments serve as economic
hedges. Except for those positions that settled in the nine months
ended September 30, 2009, the expected cash impact of the settlement of these
positions will be recognized over time largely through the end of 2010 based on
the prices at which such positions are contracted. Our overall
mark-to-market position and the related mark-to-market value will change as we
buy or sell volumes within the forward market and as forward commodity prices
fluctuate.
Power
Generation—Midwest Segment. Operating income for GEN-MW was
$143 million for the nine months ended September 30, 2009, compared to income of
$529 million for
the nine months ended September 30, 2008. Such amounts do not include
results from our Bluegrass power generating facility, which has been
reclassified as a discontinued operation for all periods presented.
Revenues
for the nine months ended September 30, 2009 decreased by $141 million compared
to the nine months ended September 30, 2008, cost of sales decreased by $66
million and operating and maintenance expense increased by $19 million,
resulting in a net decrease of $94 million. The decrease was
primarily driven by the following:
|
·
|
Mark-to-market
losses – GEN-MW’s results for the nine months ended September 30, 2009
included mark-to-market losses of $4 million related to forward sales,
compared to $89 million of mark-to-market gains for the nine months ended
September 30, 2008. Of the $4 million in 2009 mark-to-market
losses, $53 million of losses related to positions that settled or will
settle in 2009, partly offset by $49 million of gains related to positions
that will settle in 2010 and
beyond;
|
·
|
Decreased toll revenues -
Tolling and capacity revenues decreased by $12 million as a result of
expiring contracts at our Kendall and Rocky Road power generation
facilities;
|
|
·
|
Increased
operating expense – operating expense increased from $146 million for
the nine months ended September 30, 2008 to $165 million for the nine
months ended September 30, 2009, primarily as a result of planned outages
at our coal-fired power generating facilities;
and
|
|
·
|
Lower
revenues of $13 million from sales of emissions
credits.
|
These
items were partly offset by the following:
|
·
|
A
$50 million payment received to assign our rights to a third party
pursuant to a power sales agreement. This contract would have
been in effect through 2011;
|
|
·
|
Increased
volumes – Generated volumes increased by 3 percent, from 18.5 million MWh
for the nine months ended September 30, 2008, to 19.1 million MWh for the
nine months ended September 30, 2009. The increase in volumes
was primarily driven by lower natural gas prices and higher market heat
rates at our Kendall and Ontelaunee facilities partially offset by outages
at our coal fired facilities;
|
|
·
|
Additional
capacity sales of approximately $37 million, as a result of improved
capacity prices for 2009 compared with 2008;
and
|
|
·
|
Benefit
of hedging activity – The average actual on-peak prices in the Cin Hub
pricing region decreased from $73 per MWh for the nine months ended
September 30, 2008 to $35 per MWh for the nine months ended September 30,
2009. However, the impact of lower market prices was mitigated
by economic hedging, resulting in higher realized prices that were higher
in the nine months ended September 30, 2009 than in the nine months ended
September 30, 2008;
|
Depreciation
expense increased from $153 million for the nine months ended September 30, 2008
to $165 million for the nine months ended September 30, 2009, primarily as a
result of projects associated with the Midwest Consent Decree being placed into
service.
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
impairment in our unaudited condensed consolidated statements of
operations. Please read Note 9—Goodwill for further
discussion.
In
addition, during 2009, we recorded a $147 million impairment of our 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. Please read Note
6—Impairment Charges for further discussion.
Operating
income for the nine months ended September 30, 2008 included a $57 million gain
from the sale of our Rolling Hills power generation facility, reflected in Gain
on sale of assets in our unaudited condensed consolidated statements of
operations.
Power
Generation—West Segment. Operating loss for GEN-WE was $209
million for nine months ended September 30, 2009, compared to operating income
of $104 million for the nine months ended September 30, 2008. Such
amounts do not include results from our Arizona and Heard County power
generating facilities, which have been classified as discontinued operations for
all periods presented.
Revenues
for the nine months ended September 30, 2009 decreased by $263 million compared
to the nine months ended September 30, 2008, cost of sales decreased by $213
million and operating and maintenance expense increased by $4 million, resulting
in a net decrease of $54 million. The decrease was primarily driven
by the following:
|
·
|
Mark-to-market
losses – GEN-WE’s results for the nine months ended September 30, 2009
included mark to-market losses of $52 million, compared to $42 million of
mark-to-market gains for the nine months ended September 30,
2008. Of the $52 million in 2009 mark-to-market losses, $18
million related to positions that settled or will settle in 2009, and the
remaining $34 million related to positions that will settle in 2010 and
beyond; and
|
|
·
|
Decreased
volumes – Generated volumes were 4.7 million MWh for the nine months ended
September 30, 2009, down from 6.5 million MWh for the nine months ended
September 30, 2008. The volume decrease was driven in large
part by decreased market spark spreads and reduced dispatch
opportunities.
|
These
decreases were partly offset by increased tolling and capacity revenues of $40
million.
Depreciation
expense decreased from $57 million for the nine months ended September 30, 2008
to $45 million for the nine months ended September 30, 2009, largely as a result
of an increase in the estimated useful life of one of our generation
facilities.
Operating
loss for the nine months ended September 30, 2009 included a pre-tax charge of
approximately $260 million for the impairment of goodwill, reflected in Goodwill
impairment in our unaudited condensed consolidated statements of
operations. Please read Note 9—Goodwill for further
discussion.
In May
2008, we sold our beneficial interest in Oyster Creek Limited for approximately
$11 million, and recognized a gain on the sale of approximately $11 million,
reflected in Gain on sale of assets in our unaudited condensed consolidated
statements of operations. Please read Note 2—Dispositions and
Discontinued Operations for further discussion.
Power
Generation—Northeast Segment. Operating loss for GEN-NE was
$424 million for the nine months ended September 30, 2009, compared to operating
income of $41 million for the nine months ended September 30, 2008.
Revenues
for the nine months ended September 30, 2009 decreased by $120 million compared
to the nine months ended September 30, 2008, cost of sales decreased by $130
million and operating and maintenance expense decreased by $8 million, resulting
in a net increase of $18 million. The increase was primarily driven
by the following:
|
·
|
Additional
capacity sales of $9 million;
|
|
·
|
Increased
sales of emission credits of $8
million;
|
|
·
|
Increased
volumes – Volumes produced by our natural gas-fired combined cycle fleet
increased as a result of reduced congestion and improved dispatch
opportunities at our Independence facility, as well as a reduction in
transmission outages at our Casco Bay
facility;
|
|
·
|
Reduced
mark-to-market losses – GEN-NE’s results for the nine months ended
September 30, 2009 included mark-to-market losses of $8 million related to
forward sales, compared to losses of $9 million for the nine months ended
September 30, 2008. Of the $8 million in 2009 mark-to-market
losses, $7 million in gains related to positions that settled or will
settle in 2009, offset by $15 million of losses related to positions that
will settle in 2010 and beyond; and
|
|
·
|
Reduced
operating expense of $8 million, largely as a result of a reduction in
property taxes.
|
These
items were partly offset by the following:
|
·
|
A
coal inventory write-down of approximately $11 million recorded during the
nine months ended September 30, 2009;
and
|
|
·
|
Lower
market prices – on-peak market prices in New York Zone G and Mass Hub
decreased by 55 percent in each of these
regions.
|
Depreciation
expense decreased from $41 million for the nine months ended September 30, 2008
to $39 million for the nine months ended September 30, 2009.
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. Please read Note 9—Goodwill for further
discussion.
In
addition, we recorded a $179 million impairment of our Bridgeport power
generating facility and related assets, reflected in Impairment and other
charges in our unaudited condensed consolidated statements of
operations. We also recorded a $209 million impairment of our Roseton
and Danskammer power generation facilities and related assets. Please
read Note 6—Impairment Charges for further discussion.
Other. Dynegy’s
other operating loss for the nine months ended September 30, 2009 was $134
million, compared to an operating loss of $95 million for the nine months ended
September 30, 2008. DHI’s other operating loss for the nine months
ended September 30, 2009 was $136 million, compared to an operating loss of $95
million for the nine months ended September 30, 2008. Operating
losses in both periods were comprised primarily of general and administrative
expenses.
Cost of
sales for the nine months ended September 30, 2008 included a benefit from the
release of a $9 million liability associated with an assignment of a natural gas
transportation contract. Operating and maintenance expense for the
nine months ended September 30, 2008 included a benefit from the release of $16
million of sales and use tax liability, as well as a $9 million benefit from the
release of a liability associated with an assignment of a natural gas
transportation contract.
Gain on
sale of assets for the nine months ended September 30, 2008 included an
approximate $15 million gain related to our sale of our remaining NYMEX shares
and both membership seats for approximately $15 million.
Consolidated
general and administrative expenses decreased from $126 million from the
nine months ended September 30, 2008 to $125 million for the nine months ended
September 30, 2009.
Earnings
(Losses) from Unconsolidated Investments
Dynegy’s
earnings from unconsolidated investments were $13 million for the nine
months ended September 30, 2009 of which $12 million related to the GEN-WE
investment in Sandy Creek. The $12 million consisted of $20 million mark-to-market
gains primarily related to interest rate swap contracts offset by
$8 million of financing costs. The remaining $1 million of
earnings relates to Dynegy’s former investment in DLS Power Development,
included in Other. Losses from unconsolidated investments were $17
million for the nine months ended September 30, 2008. GEN-WE
recognized $7 million of losses related to its investment in the Sandy Creek
Project. These losses were comprised of $20 million primarily
associated with our share of the partnership’s losses, partially offset by our
$13 million share of the gain on SCEA’s sale of an 11 percent undivided interest
in the Sandy Creek Project. Please see Note 8—Variable Interest
Entities—Sandy Creek for further discussion. The remaining $10
million loss related to Dynegy’s investment in DLS Power Development, included
in Other.
DHI’s
earnings from unconsolidated investments of $12 million for the nine months
ended September 30, 2009 related to the GEN-WE investment in Sandy
Creek. The $12 million consisted of $20 million mark-to-market
gains primarily related to interest rate swap contracts offset by $8 million of
financing costs. Losses from unconsolidated investments for the nine
months ended September 30, 2008 were $7 million. GEN-WE recognized $7
million of losses related to its investment in the Sandy Creek
Project. These losses were comprised of $20 million primarily
associated with our share of the partnership’s losses, partially offset by our
$13 million share of the gain on SCEA’s sale of an 11 percent undivided interest
in the Sandy Creek Project. Please see Note 8—Variable Interest
Entities—Sandy Creek for further discussion.
Other
Items, Net
Dynegy’s
and DHI’s other items, net, totaled $10 million and $9 million, respectively, of
income for the nine months ended September 30, 2009, compared to $46 million and
$45 million, respectively, of income for the nine months ended September 30,
2008. The decrease is primarily associated with lower interest income
due to lower LIBOR rates in 2009. In addition, during the first
quarter 2008, we recognized income of $6 million related to insurance proceeds
received in excess of the book value of damaged assets.
Interest
Expense
Dynegy’s
and DHI’s interest expense totaled $311 million for the nine months ended
September 30, 2009, compared to $322 million for the nine months ended September
30, 2008. The decrease was primarily attributable to lower LIBOR
rates on our variable-rate debt in 2009, partly offset by $14 million of expense
related to the change in value and settlement of interest rate swaps associated
with our PPEA Credit Agreement Facility in 2009.
Income
Tax Benefit (Expense)
Dynegy
reported an income tax benefit from continuing operations of $147 million
for the nine months ended September 30, 2009, compared to an income tax expense
from continuing operations of $121 million for the nine months ended
September 30, 2008. The 2009 effective tax rate was 16 percent,
compared to 42 percent in 2008.
DHI
reported an income tax benefit from continuing operations of $152 million for
the nine months ended September 30, 2009, compared to an income tax expense of
$127 million from continuing operations for the nine months ended September 30,
2008. The 2009 effective tax rate was 17 percent, compared to 43
percent in 2008.
The
primary difference between the effective rates of 16 and 17 percent for
Dynegy and DHI, respectively, for the nine months ended September 30, 2009 and
the statutory rate of 35 percent 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 transaction, 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. The third quarter provision also
considered the impact of disallowed losses in connection with the planned
transaction with LS Power. For the period ended September 30, 2008,
the difference between the effective rates of 42 and 43 percent for Dynegy and
DHI, respectively and the statutory rate of 35 percent resulted primarily from
the effect of state income taxes in the taxing jurisdictions in which our assets
operate.
Discontinued
Operations
Income
(Loss) From Discontinued Operations Before Taxes
For the
nine months ended September 30, 2009, our pre-tax loss from discontinued
operations was $232 million, related to the operation of our Arlington Valley,
Griffith, Bluegrass and Heard County facilities. We recorded
impairment charges of $235 million related to our 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 our Bluegrass
facility. For the nine months ended September 30, 2008, our pre-tax
income from discontinued operations was $23 million, related to the operation of
the Calcasieu, Heard County, Bluegrass, Arlington Valley and Griffith power
generation facilities.
Income
Tax (Expense) Benefit From Discontinued Operations
We
recorded an income tax benefit from discontinued operations of $91 million
during the nine months ended September 30, 2009, compared to an income tax
expense of $10 million during the nine months ended September 30,
2008. These amounts reflect effective rates of 39 percent and 43
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.
Noncontrolling
Interest
We
recorded $14 million of noncontrolling interest expense for the nine months
ended September 30, 2009, compared with $3 million of noncontrolling interest
expense for the nine months ended September 30, 2008 related to the Plum Point
Project. The change in noncontrolling interest expense is primarily
related to the mark-to-market losses related to the interest rate swap
agreements associated with the Plum Point Credit Agreement
Facility. Effective July 28, 2009, the interest rate swap agreements
were no longer accounted for as a cash flow hedges; therefore, the change in
value is reflected in the unaudited condensed consolidated statement of
operations and is no longer reflected in accumulated other comprehensive
loss.
Outlook
On August
9, 2009, we entered into a purchase and sale agreement with LS Power in which we
agreed to sell our ownership interests in 4,788 MW of peaking and combined-cycle
power generation assets, as well as our remaining interests in the Sandy Creek
Project under construction in Texas, and to issue $235 million principal amount
of DHI 7.50 percent senior unsecured notes due 2015. Upon closing of
the transaction, which is expected in the fourth quarter 2009 assuming all
necessary closing conditions are satisfied or waived, we will receive from
LS Power approximately $1.025 billion in cash (consisting, in part, of the
release of $175 million of restricted cash that was used to support our funding
commitment to Sandy Creek and approximately $200 million for the unsecured
notes), subject to working capital adjustments, and 245 million of Dynegy’s
Class B shares.
Upon
closing of the transaction, the remaining 95 million shares of Dynegy’s Class B
common stock held by LS Power will be converted into the same number of shares
of Dynegy’s Class A common stock, representing approximately 15 percent of
Dynegy’s outstanding Class A common stock. Concurrent with the
execution of the purchase and sale agreement, LS Power and Dynegy entered into a
new shareholder agreement, which, upon closing of the transaction, generally
will restrict LS Power from increasing their ownership for a specified period
and eliminates special approval, board representation and certain other rights
associated with the Class B common shares. Please see Note
2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for
further information.
Assuming
the LS Power transaction is consummated, our power generation capacity will
consist of almost 13,000 MW of generating capacity and will continue to be
diversified by fuel source (i.e., coal, natural gas and fuel oil) and dispatch
type (i.e., baseload, intermediate and peaking
facilities). Approximately 34 percent of our power generation fleet
will be natural gas-fired, combined-cycle capacity, 31 percent will be baseload
coal-fired capacity, 25 percent will be natural gas-fired peaking capacity, and
the remaining 10 percent will be dual-fuel capable. We believe that
our fuel and dispatch type diversity positions us to capture market
opportunities that may not be available to less diverse generators.
Our power
generation capacity also will be diversified by geographic location across seven
U.S. states, as approximately 43 percent of our generating capacity will be
located in the Midwest, 25 percent will be located in the Northeast, and 32
percent will be located in the West. We believe that this geographic
diversity will continue to position us to benefit from the portfolio effect of
different supply/demand characteristics across broad geographic regions,
including in the Northeast and California where new supply options may be
limited.
These
different supply/demand characteristics can occur over the short-term (e.g.,
based on weather patterns or the unavailability of other suppliers) or over the
long-term (e.g., based on long-term demand growth that exceeds supply
additions).
In
commercializing our assets, we seek to achieve a balance between providing
greater cash flow predictability in the near/intermediate term, while
maintaining the ability to capture value longer term as markets
tighten. We expect that a majority of our revenues will be achieved
by selling energy and capacity through a combination of spot market sales and
near-term contracts over a rolling 12–36 month time frame in time periods that
we describe as Current, Current +1 and Current +2. At any given point
in time, we will seek to balance predictability of earnings and cash flow with
achieving the highest level of earnings and cash flow possible over the Current,
Current +1 and Current +2 periods. In these periods, short-term
market volatility can negatively impact our profitability and we will seek to
reduce those negative impacts through the disciplined use of near- and
intermediate-term forward sales. As a result, our fleet-wide forward
sales profile is fluid and subject to change. We expect to make fewer
forward sales beyond the Current+2 period in order to realize the anticipated
benefit of improved market prices over time as the supply and demand balance
tightens.
Beginning
in 2009, we set specific limits for “gross margin at risk” for the entire
portfolio and require power hedging up to minimum levels, while seeking to
ensure that corresponding fuel supplies also are appropriately hedged, as we
progress through time. We will also attempt to specifically manage basis risk to
hubs that are not the natural sales hub for a facility and implement other
changes that sharpen our focus on optimizing the commercial factors that we can
control and mitigating commodity risk where appropriate and
possible.
We expect
that our future financial results will continue to be sensitive to fuel and
commodity prices, market structure and prices for electric energy, ancillary
services and capacity, transportation and transmission logistics, weather
conditions and IMA. Our commercial team actively manages commodity
price risk associated with our unsold power production by trading in the forward
markets that are correlated with our assets. We also participate in
various regional auctions and bilateral opportunities. Our regional
commercial strategies are particularly driven by the types of units that we have
within a given region and the operating characteristics of those
units.
We have
volumetrically hedged substantially all of our expected generation volumes
through 2010 and approximately 50 percent of such expected generation volumes
for 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. We may do this by buying back
positions and selling at more attractive prices in an attempt to capture margin
opportunities or mitigate downside risk associated with changes in commodity
prices. However, our future operating cash flows may vary based on a
number of factors, including the value of capacity and ancillary services, the
operational performance of our generating facilities, and legal, environmental
and regulatory requirements.
To the
extent that we choose not to enter into forward transactions, the gross margin
from our assets is highly sensitive to price movements in the coal, natural gas,
fuel oil, electric energy and capacity markets.
The
following summarizes unique business issues impacting the outlook of each of our
three regions.
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 Midwest Consent Decree projects, which we expect to incur
through 2013, to be approximately $960 million, which includes approximately
$490 million spent to date. This estimate includes a number of
assumptions about uncertainties beyond our control, including an assumption that
labor and material costs will increase at four percent per year over the
remaining project term. If the costs of these capital expenditures
become great enough to render the operation of the affected facility or
facilities uneconomical, we could, at our option, cease to operate the facility
or facilities and forego these capital expenditures without incurring any
further obligations under the Midwest Consent Decree.
Our Midwest
coal and transportation requirements are 100 percent contracted and priced
through 2010. For 2011 and 2012, approximately 35 percent of our coal
requirements are contracted, and the price for these volumes will be determined
in 2010 under the terms of the coal purchase contract.
More wind
generation has come online in the Midwest, resulting in lower off-peak prices
and an increase in minimum generation events. During these events,
baseload generation may be directed to shut down or run at minimum
loads. As additional wind generation enters the grid, these events
will occur more frequently. We seek to mitigate the price impacts of
these minimum generation events through hedging. However, continued
cycling of coal-fired units over time could reduce our in-market availability as
these events could lead to an increase in overall maintenance costs and plant
outages.
GEN-WE. Approximately
seventy percent of Dynegy’s power plant capacity in the West is contracted
through 2010 under a variety of tolling agreements with load-serving entities
and RMR agreements with the Cal ISO. 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 Cal ISO through December 31, 2009. For 2010, the Cal ISO has
designated Oakland and three of the five units at South Bay as RMR
facilities. The RMR designation by the Cal ISO for the South Bay
facility is subject to being terminated early if the Cal ISO determines other
San Diego-area generation projects or transmission upgrades are completed
successfully.
GEN-NE. The
northeast portfolio includes several generating units with dual fuel
capability. We have fully contracted our 2009 coal supply and freight
requirements and have secured approximately 80 percent of our 2010 expected
supply needs for our Danskammer power generation facility.
While we
have sourced most of our coal from South America, we have access to and are
exploring multiple options for the balance of our 2010 supply
needs. Coal prices in both the international and domestic markets
have retreated from their historic highs reached in the middle of
2008. We continue to explore various alternative contractual
commitments and financial options, as well as facility modifications, to ensure
stable fuel supplies and to mitigate further supply risks for near and long-term
coal supplies.
The
volatility in fuel oil and natural gas commodity pricing and changes to spark
spreads may provide us opportunities to capture short-term market value through
strategic purchases of fuel oil and sales of power in the spot or forward
markets.
The
ISO-NE is in the process of restructuring its capacity market and will be
transitioning from a fixed payment structure to implementation of a forward
capacity market structure in 2010. The transitional payments for capacity
commenced in December 2006, with a price of $3.05 KW/month, and have risen
gradually to $4.10 KW/month through May 31, 2010. The delivery of
capacity under the forward capacity market will be fully effective on June 1,
2010. Capacity auctions for the
2010/2011, 2011/2012 and 2012/2013 market periods were
held in 2008 and 2009 and resulted in capacity payments of $4.50 KW/month, $3.60
KW/month and $2.95 KW/month respectively for our asset in
ISO-NE. Discussions to address identified flaws with the forward
capacity market design are currently underway by the ISO and its
stakeholders.
Environmental
Matters
Climate Change
and Greenhouse Gases. For the last several years, there has
been an ongoing public debate about climate change and the need to and potential
for addressing the climate change issue by reducing emissions of GHGs, primarily
CO2
and methane. Our position is that since climate change is a global
issue, any regulation of GHG emission sources in the United States should be
undertaken by the federal government in coordination with developed and
developing countries around the world. We believe that the focus of
any federal program addressing climate change should include three critical,
interrelated elements: the environment, the economy and energy
security.
Federal
Legislation Regarding Greenhouse Gases. Several bills have
been introduced in Congress since 2003 that would compel reductions in CO2 emissions
from power plants, but only recently has any proposed bill received majority
support in the House of Representatives or Senate. On June 26, 2009
the House of Representatives passed the American Clean Energy and Security Act
of 2009 (“H.R. 2454”). Title III of H.R. 2454 would add a new Title
VII to the CAA creating a Global Warming Pollution Reduction
Program. H.R. 2454 would create a national cap-and-trade program
aimed at reducing CO2 emissions
to 3 percent below 2005 levels by 2012, 17 percent below 2005 levels by 2020, 42
percent below 2005 levels by 2030 and 83 percent below 2005 levels by
2050.
On
September 30, 2009, the Senate Environment and Public Works Committee introduced
the Clean Energy Jobs and American Power Act (“S. 1733”), a bill similar to H.R.
2454. The targets for GHG emission reductions in S. 1733 are 3
percent below 2005 levels by 2012, 20 percent below 2005 levels by 2020, 42
percent below 2005 levels by 2030 and 83 percent below 2005 levels by
2050.
The House
and Senate bills represent a comprehensive effort to restructure the energy
market in the United States. We cannot confidently predict the
content of federal legislation that ultimately may be enacted to control GHG
emissions. However, depending on various factors that are outside our
control, including the specific provisions of any approved legislation and our
ability to recover any additional costs through market pricing, the significant
mandatory reductions of CO2 emissions
from the electric generating sector contemplated by these bills could have a
material adverse effect on our financial condition, results of operations and
cash flows.
Federal
Regulation of Greenhouse Gases. Several federal regulatory
initiatives and actions under the CAA are being developed or implemented that
address GHG emissions. On April 17, 2009, the Administrator of the
U.S. EPA issued a proposed finding that GHG emissions from mobile sources cause
or contribute to air pollution that endangers the public health and
welfare. The endangerment finding was proposed under Section 202(a)
of the CAA in response to the U.S. Supreme Court’s ruling in Massachusetts v. EPA, 549
U.S. 497 (2007) that GHGs are pollutants as defined in the CAA. If
the proposal becomes final, the U.S. EPA will be required to promulgate GHG
emission standards for mobile sources.
On June
30, 2009, the Administrator of the U.S. EPA granted California’s request for a
waiver to allow the state to enforce its motor vehicle GHG emission
regulations. The California motor vehicle GHG emission regulations
establish manufacturer fleet average emission standards for passenger cars and
light trucks, and for heavier trucks phased in from 2009 through
2016. In granting the waiver, the Administrator declined to address
whether her action renders GHGs “subject to regulation” under the
CAA. If GHGs become “subject to regulation” under the CAA, they may
become subject to other sections of the CAA including the best available control
technology requirements under the prevention of significant deterioration
provisions.
On
September 15, 2009, the U.S. EPA and the U.S. Department of Transportation
released a proposed joint rule that would regulate GHG emissions from passenger
cars and light trucks. If the rule becomes final, it may render GHGs,
including CO2, “subject
to regulation” under the Act.
On
September 22, 2009, the U.S. EPA released its final rule requiring mandatory
reporting of GHG emissions from all sectors of the economy. The rule
will require that sources above certain threshold levels monitor and report GHG
emissions. Our power generating facilities will be subject to these
new reporting requirements; we are currently reviewing our systems and
procedures for measuring and inventorying the subject emissions to prepare to
meet these new requirements.
On
September 30, 2009, the U.S. EPA proposed to “phase in” new GHG emission
applicability thresholds for its PSD permit program and for the operating permit
program under Title V of the CAA. The proposed rule would establish a
temporary GHG applicability threshold for these programs at 25,000 tons per year
of CO2
equivalent (CO2e: an
expression of the global warming potential of the various GHGs relative to the
global warming potential of CO2) for new
sources, and a temporary GHG significance level under the PSD Permit Program
between 10,000 and 25,000 tons per year CO2e for
modifications to major sources. According to the agency, this rule is
being proposed on the basis of the legal doctrines of “absurd results” and
“administrative necessity” in anticipation of GHG becoming subject to regulation
under the CAA and to avoid subjecting small sources to individualized PSD permit
and control technology requirements that would otherwise be required by the
thresholds set forth in the CAA. Our power generation facilities’ GHG
emissions would become subject to these programs when GHG emissions become
subject to regulation regardless of the U.S. EPA’s proposal to amend the
statutory thresholds in this rulemaking. Public debate is ongoing as
to the U.S. EPA’s legal authority to adopt this rule, making legal challenges
likely. We cannot predict with certainty the outcome of this
rulemaking process or a specific impact on our generating
portfolio.
State Regulation
of Greenhouse Gases. Many states where we have generation
facilities are considering or are in some stage of implementing regulatory
programs intended to reduce emissions of GHGs from stationary sources as a means
of addressing climate change issues. Beginning in 2009, certain of
our generating facilities were required to obtain CO2
allowances, through purchases from the states where they operate, in sufficient
quantity to cover CO2
emissions. We do not know the extent to which the costs of obtaining
CO2
allowances and of meeting mandated emission reductions may be borne by power
generators or the ultimate users of electricity. The imposition of limits on
emissions of CO2, from the
power generation sector, whether implemented by the federal or state
governments, could have the effect of altering the manner in which generating
facilities are dispatched.
GEN-WE. Our
assets in California will be subject to various additional state environmental
initiatives. As previously disclosed, our California facilities
continue to be subject to the California Global Warming Solutions Act, effective
January 1, 2007, which requires development of a GHG control program that will
reduce the state’s GHG emissions to their 1990 levels by
2020. Regulations to achieve required emission reductions are to be
adopted by January 2011.
In late
June 2009, the California State Water Resources Control Board issued draft
regulations for power plants with once-through cooling. Our options
include closed system cooling structures and other measures for reducing
impingement/entrainment. Our low heat rate plants, Moss Landing units
1 and 2, would have until 2017 to develop solutions. Some of our
older, less efficient units may not be profitable if the rule becomes final, and
therefore may be considered for retirement. As an active stakeholder
in the process, we are continuing to monitor the development of draft
regulations, and will continue to provide input as solutions move from their
current draft status to final regulations.
GEN-NE. Effective
January 1, 2009, our GEN-NE segment facilities in New York, Connecticut and
Maine became subject to compliance requirements under the RGGI
program. The participating RGGI states have implemented a rule
regulating GHG emissions using a cap-and-trade program to reduce CO2 emissions
by at least 10 percent of base-year emission levels by the year
2018. Compliance with the allowance requirement under the RGGI
cap-and-trade program can be achieved by reducing emissions, purchasing or
trading allowances or securing offset allowances from an approved offset
project. While allowances are sold by year, actual compliance is
measured across a three year control period. The first control period
is for the 2009-2011 timeframe.
On
September 9, 2009, RGGI held its fifth auction, in which approximately 28
million of allowances for allocation year 2009, and over two million allowances
for allocation year 2012, were sold at clearing prices of $2.19 per allowance
and $1.87 per allowance, respectively. We have participated in each
of the quarterly RGGI auctions (or in secondary markets, as appropriate) to
secure allowances based on our actual or forecast needs for our affected
assets. One additional auction is scheduled for 2009 with auctions
expected to be held quarterly throughout 2010.
We
project that 2009 CO2 emissions
from our generating facilities in New York and Maine will be approximately 4.6
million tons. Therefore, based on the average cost of allowances sold
to date for the 2009 allocation year, our estimated cost of allowances necessary
to operate these facilities in 2009 is approximately $15 million.
Coal Combustion
Ash. The combustion of coal to generate electric power creates
large quantities of ash which is managed at power generation facilities in dry
form in landfills and in liquid or slurry form in surface
impoundments. Each of our coal-fired plants has at least one CCA
management unit. At present, CCA management is regulated by the
states as solid waste. The U.S. EPA has considered whether CCA should
be regulated as a hazardous waste on two separate occasions and each time has
declined to do so. The December 2008 failure of a CCA surface
impoundment dike at the Tennessee Valley Authority’s Kingston Plant in
Tennessee, accompanied by a very large release of ash slurry, has resulted in
renewed scrutiny of CCA management.
The U.S.
EPA has initiated an investigation of the structural integrity of certain CCA
surface impoundment dams and has announced plans to develop regulations by the
end of 2009 to address the management of CCA. Certain environmental
non-government organizations have advocated designation of CCA as a hazardous
waste. The regulations being developed by the U.S. EPA could lead to
new requirements related to CCA management units, the nature of which cannot be
predicted with confidence at this time, but which could have a material adverse
effect on our financial condition, results of operations and cash
flows.
Regulatory
Matters
GEN-MW. Our
market-based rate authority is predicated on a finding by FERC that our entities
with market-based rates do not have market power, and a market power analysis is
generally conducted every three years for each region on a rolling basis
(“triennial market power review”). The triennial market power review
for our MISO assets was filed with FERC in June 2009. In September
2009, FERC issued a letter order accepting our filing and stating that our
submittal satisfies its requirements for market-based rates regarding horizontal
and vertical market power in this region. On December 24, 2008, we
filed the triennial market power review for our assets in FERC’s Southeast
Region. In August 2009, FERC issued a letter order accepting our
filing and stating that our submittal satisfies its requirements for
market-based rates regarding horizontal and vertical market power in this
region.
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,
2009
|
||||
(in
millions)
|
||||
Balance
Sheet Risk-Management Accounts
|
||||
Fair
value of portfolio at January 1, 2009
|
$ | (30 | ) | |
Risk-management
gains recognized through the income statement in the period,
net
|
297 | |||
Cash
received related to risk-management contracts settled in the period,
net
|
(359 | ) | ||
Changes
in fair value as a result of a change in valuation technique
(1)
|
— | |||
Non-cash
adjustments and other (2)
|
176 | |||
Fair
value of portfolio at September 30, 2009 (3)
|
$ | 84 |
__________________
|
(1)
|
Our
modeling methodology has been consistently
applied.
|
|
(2)
|
This
amount consists of changes in value associated with fair value and cash
flow hedges on debt.
|
|
(3)
|
Includes
$9 million of risk management assets classified as held for sale as of
September 30, 2009.
|
The net
risk management asset of $84 million is the aggregate of the following line
items on our unaudited condensed consolidated balance sheets: Current
Assets—Assets from risk-management activities, Current Assets—Assets held for
sale, Current Liabilities—Liabilities from risk-management activities, Current
Liabilities—Liabilities associated with assets held for sale 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, 2009, based on
our valuation methodology:
Net
Fair Value of Risk-Management Portfolio
Total
|
2009
|
2010
|
2011
|
2012
|
2013
|
Thereafter
|
||||||||||||||||||||||
(in
millions)
|
||||||||||||||||||||||||||||
Market
quotations (1)
|
$ | 114 | $ | 80 | $ | 55 | $ | (21 | ) | $ | — | $ | — | $ | — | |||||||||||||
Prices
based on models
|
(30 | ) | 12 | 19 | (30 | ) | (4 | ) | (3 | ) | (24 | ) | ||||||||||||||||
Total
(2)
|
$ | 84 | $ | 92 | $ | 74 | $ | (51 | ) | $ | (4 | ) | $ | (3 | ) | $ | (24 | ) |
__________________
|
(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 5—Fair Value Measurements for
further discussion.
|
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” by both Dynegy and DHI. 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:
|
·
|
beliefs
and expectations regarding the benefits to be derived from the transaction
with LS Power, expected use of any proceeds from the transaction and any
impairments and charges related to such
transaction;
|
·
|
beliefs
and expectations regarding the closing of the LS power transaction and the
timing, terms and success thereof;
|
|
·
|
the
timing and anticipated benefits to be achieved through our 2010-2013
company-wide cost savings program;
|
|
·
|
beliefs
about commodity pricing and generation
volumes;
|
|
·
|
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;
|
|
·
|
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;
|
|
·
|
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;
|
|
·
|
beliefs
regarding the current economic downturn, its trajectory and its
impacts;
|
|
·
|
beliefs
and expectations associated with minimum generation events and the impact
of wind generation in the Midwest;
|
|
·
|
projected
operating or financial results, including anticipated cash flows from
operations, revenues and
profitability;
|
|
·
|
beliefs
associated with Dynegy’s market
capitalization;
|
|
·
|
beliefs
and expectations regarding financing and associated credit ratings,
development and timing of the Plum Point
Project;
|
|
·
|
expectations
regarding our revolver capacity, collateral demands, capital expenditures,
interest expense and other
payments;
|
|
·
|
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
impact of executing, or failing to execute, any acquisition, disposition
or combination transactions.
|
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
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.
Item
3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.
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, 2009.
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 “normal purchase normal sale”, nor does it include expected
future production from our generating assets. The increase in the
September 30, 2009 VaR was primarily due to increased forward commodity
transactions as compared to December 31, 2008. 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, 2009
|
December 31,
2008
|
|||||||
(in
millions)
|
||||||||
One
day VaR—95 percent confidence level
|
$ | 41 | $ | 21 | ||||
One
day VaR—99 percent confidence level
|
$ | 58 | $ | 29 | ||||
Average
VaR for the year-to-date period—95 percent confidence
level
|
$ | 32 | $ | 42 |
Credit
Risk. The following table represents our credit exposure at
September 30, 2009 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
|
$ | 76 | $ | — | $ | 76 | ||||||
Utility
and power generators
|
14 | 5 | 19 | |||||||||
Commercial,
industrial and end users
|
— | 5 | 5 | |||||||||
Other
|
1 | 2 | 3 | |||||||||
Total
|
$ | 91 | $ | 12 | $ | 103 |
Of the
$12 million in credit exposure to non-investment grade counterparties, none is
collateralized or subject to other credit exposure protection.
Interest Rate
Risk. We are exposed to fluctuating interest rates related to
variable rate financial obligations. As of September 30, 2009, our
fixed rate debt instruments, as a percentage of total debt instruments, were
approximately 73 percent. Adjusted for interest rate swaps, net
notional fixed rate debt as a percentage of total debt was approximately 82
percent. Based on sensitivity analysis of the variable rate financial
obligations in our debt portfolio as of September 30, 2009, 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 $11
million. This exposure would be partially offset by an approximate $9
million increase 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.
Derivative
Contracts. The notional financial contract amounts associated
with our interest rate contracts were as follows at September 30, 2009 and
December 31, 2008, respectively:
Absolute
Notional Contract Amounts
September 30,
2009
|
December 31,
2008
|
|||||||
Cash
flow hedge interest rate swaps (in millions of U.S.
dollars)
|
$ | — | $ | 471 | ||||
Fixed
interest rate paid on swaps (percent)
|
— | 5.32 | ||||||
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)
|
$ | 763 | $ | 231 | ||||
Fixed
interest rate paid on swaps (percent)
|
5.33 | 5.35 | ||||||
Interest
rate risk-management contract (in millions of U.S.
dollars)
|
$ | 206 | $ | 206 | ||||
Fixed
interest rate received on swaps (percent)
|
5.28 | 5.28 |
Item 4—CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS
INC.
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 and DHI’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,
2009.
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, 2009.
DYNEGY
INC. and DYNEGY HOLDINGS INC.
PART
II. OTHER INFORMATION
Item 1—LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS
INC.
See Note
13—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.
Item
1A—RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.
See Item
1A—Risk Factors, of our Form 10-K for factors, risks and uncertainties that may
affect future results.
Item 2—UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS—DYNEGY INC.
Upon
vesting of restricted stock awarded by Dynegy to employees, shares are withheld
to cover the employees’ withholding taxes. Information on Dynegy’s
purchases of equity securities 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
|
77 | $ | 1.83 | — | N/A | |||||||||||
September
1-30
|
— | $ | — | — | N/A | |||||||||||
Total
|
77 | $ | 1.83 | — | N/A |
These
were the only purchases of equity securities made by us during the three months
ended September 30, 2009. Dynegy does not have a stock repurchase
program.
Item
6—EXHIBITS—DYNEGY
INC. AND DYNEGY HOLDINGS INC.
The
following documents are included as exhibits to this Form
10-Q
Exhibit Number
|
Description
|
|
2.1
|
Purchase
and Sale Agreement, dated August 9, 2009 (incorporated by reference to
Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on
August 13, 2009, File No. 001-33443).
|
|
10.1
|
Amendment
No. 4 to the Fifth Amended and Restated Credit Agreement dated as of April
2, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report
on Form 8-K of Dynegy Inc. filed on August 10, 2009, File No.
001-33443).
|
|
10.2
|
Shareholder
Agreement between Dynegy Inc. and LS Power and its affiliates, dated
August 9, 2009 (incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K of Dynegy Inc. filed on August 13, 2009, File No.
001-33443).
|
Exhibit Number
|
Description
|
|
10.3
|
Amendment
No. 1 to the Registration Rights Agreement dated September 14, 2006 by and
between Dynegy Inc. and LS Power and affiliates, dated August 9, 2009
(incorporated by reference to Exhibit 10.2 to the Current Report on Form
8-K of Dynegy Inc. filed on August 13, 2009, File No.
001-33443).
|
|
10.4
|
Note
Purchase Agreement by and between Dynegy Holdings Inc. and Adio Bond, LLC,
dated August 9, 2009 (incorporated by reference to Exhibit 10.3 to the
Current Report on Form 8-K of Dynegy Inc. filed on August 13, 2009, File
No. 001-33443).
|
|
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.
|
||
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.
|
||
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.
|
||
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.
|
||
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.
|
||
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.
|
||
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.
|
||
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.
|
|
**
|
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.
|
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 5, 2009
|
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 5, 2009
|
By:
|
/s/ HOLLI C. NICHOLS
|
Holli
C. Nichols
Executive
Vice President and Chief Financial Officer
(Duly
Authorized Officer and Principal Financial
Officer)
|
92