Attached files
| file | filename |
|---|---|
| 8-K - ENTERGY CORP /DE/ | a00210.htm |
| EX-99.2 - ENTERGY CORP /DE/ | a00210992.htm |
| EX-99.3 - ENTERGY CORP /DE/ | a00210993.htm |
Exhibit
99.1
|
For
further information:
Michele
Lopiccolo, VP, Investor Relations
Phone
504/576-4879, Fax 504/576-2897
mlopicc@entergy.com
|
INVESTOR
NEWS
February
2, 2010
ENTERGY
REPORTS FOURTH QUARTER EARNINGS
NEW
ORLEANS – Entergy Corporation reported fourth quarter 2009 earnings of
$1.64 per share on an as-reported basis and $1.75 per share on an operational
basis, as shown in Table
1 below. A more detailed
discussion of quarterly results begins on page 2 of this
release.
|
Table
1: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP
Measures
|
||||||
|
Fourth
Quarter and Year-to-Date 2009 vs. 2008
|
||||||
|
(Per
share in U.S. $)
|
||||||
|
Fourth Quarter
|
Year-to-Date
|
|||||
|
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|
|
As-Reported
Earnings
|
1.64
|
0.89
|
0.75
|
6.30
|
6.20
|
0.10
|
|
Less
Special Items
|
(0.11)
|
(0.10)
|
(0.01)
|
(0.37)
|
(0.31)
|
(0.06)
|
|
Operational
Earnings
|
1.75
|
0.99
|
0.76
|
6.67
|
6.51
|
0.16
|
|
Weather
Impact
|
(0.01)
|
(0.03)
|
0.02
|
(0.01)
|
(0.02)
|
0.01
|
Operational
Earnings Highlights for Fourth Quarter 2009
|
·
|
Utility,
Parent & Other’s results were higher due to lower income tax expense,
lower non-fuel operation and maintenance expense and higher net
revenue.
|
|
·
|
Entergy
Nuclear’s earnings decreased as a result of higher income tax and non-fuel
operation and maintenance expenses, partially offset by higher net revenue
and other income.
|
|
·
|
Entergy’s
Non-Nuclear Wholesale Assets’ results improved due to lower income tax
expense.
|
“Both our
utility and non-utility nuclear businesses delivered strong operational
performance during a period of extraordinary global economic and financial
uncertainty,” said J. Wayne
Leonard, Entergy’s chairman and chief executive
officer. “Looking ahead, signs of an improving economic
environment, our market-based point-of-view, adherence to our disciplined risk
management and the strength of our cash position provide a foundation that
supports our strategic, operational and financial goals.”
Entergy’s
business highlights include the following:
|
·
|
Entergy
Texas completed storm recovery for Hurricane Ike in November when it
executed $545.9 million of securitization financing. Also, a
stipulation agreement was reached with the Louisiana Public Service
Commission Staff in the storm proceedings in
Louisiana.
|
|
·
|
Entergy
Texas made a new rate case filing at the Public Utility Commission of
Texas at the end of December
|
|
·
|
The
Nuclear Regulatory Commission agreed to extend the expiration date for the
spin-off approval to August 1,
2010.
|
Entergy
will host a teleconference to discuss this release at 10:00 a.m. CT on Tuesday,
February 2, 2010, with access by telephone, 719-457-2080, confirmation code
6584600. The call and presentation slides can also be accessed via
Entergy’s Web site at www.entergy.com. A
replay of the teleconference will be available through February 9, 2010 by
dialing 719-457-0820, confirmation code 6584600. The replay will also
be available on Entergy’s Web site at www.entergy.com.
|
I.
|
Consolidated
Results
|
Consolidated
Earnings
Table 2
provides a comparative summary of consolidated earnings per share for fourth
quarter 2009 versus 2008, including a reconciliation of GAAP as-reported
earnings to non-GAAP operational earnings. Utility, Parent &
Other’s earnings increased quarter-over-quarter due primarily to lower income
tax expense, as well as lower non-fuel operation and maintenance expense
primarily resulting from the absence of regulatory charges associated with rate
proceedings at Entergy Arkansas in 2008. Entergy Nuclear’s fourth
quarter 2009 earnings were lower than last year as a result of an increase in
income tax and operation and maintenance expenses. Higher net revenue
from the non-utility nuclear fleet, driven by both higher pricing and
production, and higher other income provided a partial offset to the lower
results in the current quarter. Entergy’s Non-Nuclear Wholesale
Assets business reported improved earnings due primarily to a reduction in
income tax expense.
|
Table
2: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP
Measures
Fourth
Quarter and Year-to-Date 2009 vs. 2008 (see Appendix F for definitions of certain
measures)
|
||||||
|
(Per
share in U.S. $)
|
||||||
|
Fourth Quarter
|
Year-to-Date
|
|||||
|
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|
|
As-Reported
|
||||||
|
Utility,
Parent & Other
|
0.56
|
(0.38)
|
0.94
|
2.88
|
2.22
|
0.66
|
|
Entergy
Nuclear
|
0.89
|
1.14
|
(0.25)
|
3.22
|
3.97
|
(0.75)
|
|
Non-Nuclear
Wholesale Assets
|
0.19
|
0.13
|
0.06
|
0.20
|
0.01
|
0.19
|
|
Consolidated
As-Reported Earnings
|
1.64
|
0.89
|
0.75
|
6.30
|
6.20
|
0.10
|
|
Less
Special Items
|
||||||
|
Utility,
Parent & Other
|
(0.05)
|
(0.05)
|
-
|
(0.14)
|
(0.21)
|
0.07
|
|
Entergy
Nuclear
|
(0.06)
|
(0.04)
|
(0.02)
|
(0.23)
|
(0.10)
|
(0.13)
|
|
Non-Nuclear
Wholesale Assets
|
-
|
(0.01)
|
0.01
|
-
|
-
|
-
|
|
Consolidated
Special Items
|
(0.11)
|
(0.10)
|
(0.01)
|
(0.37)
|
(0.31)
|
(0.06)
|
|
Operational
|
||||||
|
Utility,
Parent & Other
|
0.61
|
(0.33)
|
0.94
|
3.02
|
2.43
|
0.59
|
|
Entergy
Nuclear
|
0.95
|
1.18
|
(0.23)
|
3.45
|
4.07
|
(0.62)
|
|
Non-Nuclear
Wholesale Assets
|
0.19
|
0.14
|
0.05
|
0.20
|
0.01
|
0.19
|
|
Consolidated
Operational Earnings
|
1.75
|
0.99
|
0.76
|
6.67
|
6.51
|
0.16
|
|
Weather
Impact
|
(0.01)
|
(0.03)
|
0.02
|
(0.01)
|
(0.02)
|
0.01
|
Detailed
earnings variance analysis is included in Appendix B-1 and Appendix B-2 to this
release. In addition, Appendix B-3 provides details of special items
shown in Table 2 above.
Consolidated Net Cash Flow
Provided by Operating Activities
Entergy’s
net cash flow provided by operating activities in fourth quarter 2009 was $924
million compared to $632 million in fourth quarter 2008. A fourth
quarter intercompany transaction that nets to zero on a consolidated basis
resulted in significant offsetting variances at Utility, Parent & Other and
Entergy Nuclear. Pursuant to Entergy’s intercompany tax allocation
agreement, Entergy Nuclear received $1.3 billion in cash payments from Utility,
Parent & Other.
The
overall quarterly increase was due primarily to:
|
·
|
a
favorable variance from hurricanes Gustav and Ike with net effects
reducing operating cash flow in 2008 by $444 million as a result of costs
for system repairs and lower revenues due to customer
outages
|
|
·
|
higher
net revenue and lower operation and maintenance costs (excluding storm
effects) of $76 million at the
Utility
|
|
·
|
higher
net revenues of $59 million at Entergy
Nuclear
|
|
·
|
a
decrease in refueling outage costs of $32 million at Entergy
Nuclear
|
|
·
|
lower
working capital requirements of $69 million at Entergy
Nuclear
|
Partially
offsetting was:
|
·
|
a
decrease in net deferred fuel recovery of $481 million at the
Utility
|
For the
year 2009, Entergy’s operating cash flow was $2,933 million versus $3,324
million last year. Payments under the intercompany tax allocation
agreement noted above resulted in significant offsetting variances at Utility,
Parent & Other and Entergy Nuclear.
The
overall decrease for the year was due primarily to:
|
·
|
the
absence of $954 million in securitization proceeds received in 2008 at
Entergy Gulf States Louisiana and Entergy Louisiana for hurricanes Katrina
and Rita
|
|
·
|
an
increase in refueling outage costs and spin-off dis-synergies totaling $79
million at Entergy Nuclear
|
Partially
offsetting items include:
|
·
|
a
net decrease in the effects of major storm activity (i.e., the 2008
hurricanes and 2009 ice storm in Arkansas) and receipt of associated
insurance proceeds totaling $91
million
|
|
·
|
an
increase in net deferred fuel recovery of $111 million at the
Utility
|
|
·
|
lower
working capital requirements of $108 million at the
Utility
|
|
·
|
a
decrease of $155 million in pension funding at the Utility and Entergy
Nuclear
|
|
·
|
an
overall net decrease in tax payments of $94
million
|
Table 3
provides the components of net cash flow provided by operating activities
contributed by each business with quarterly and year-to-date
comparisons.
|
Table
3: Consolidated Net Cash Flow Provided by Operating
Activities
|
||||||
|
Fourth
Quarter and Year-to-Date 2009 vs. 2008
|
||||||
|
(U.S.
$ in millions)
|
||||||
|
Fourth Quarter
|
Year-to-Date
|
|||||
|
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|
|
Utility,
Parent & Other
|
(837)
|
272
|
(1,109)
|
462
|
2,051
|
(1,589)
|
|
Entergy
Nuclear
|
1,725
|
285
|
1,440
|
2,434
|
1,255
|
1,179
|
|
Non-Nuclear
Wholesale Assets
|
36
|
75
|
(39)
|
37
|
18
|
19
|
|
Total
Net Cash Flow Provided by Operating Activities
|
924
|
632
|
292
|
2,933
|
3,324
|
(391)
|
|
II.
|
Utility, Parent &
Other Results
|
In fourth
quarter 2009, Utility, Parent & Other’s as-reported earnings were $0.56 per
share compared to a loss of $(0.38) per share in fourth quarter
2008. On an operational basis, fourth quarter 2009 earnings for
Utility, Parent & Other were $0.61 per share versus a loss of $(0.33) per
share in the same quarter last year. Operational earnings for
Utility, Parent & Other in fourth quarter 2009 reflect lower income tax
expense associated with the net effect of annual consolidated income tax
adjustments across the Entergy companies. A favorable tax reserve
adjustment also contributed following issuance by the Louisiana Department of
Revenue of a private letter ruling related to securitization of Katrina and Rita
storm costs. In addition, the absence of regulatory charges
associated with rate proceedings at Entergy Arkansas in 2008 was the primary
driver of lower non-fuel operation and maintenance expense, as well as a
contributor to the lower income tax expense compared to fourth quarter
2008. Also contributing to the earnings improvement versus the same
quarter last year was higher net revenue.
Electricity
usage, in gigawatt-hour sales by customer segment, is included in Table 4. Current
quarter sales reflect the following:
|
·
|
Residential
sales in fourth quarter 2009, on a weather-adjusted basis, increased 4.6
percent compared to fourth quarter
2008.
|
|
·
|
Commercial
and governmental sales, on a weather-adjusted basis, increased 3.0 percent
year over year.
|
|
·
|
Industrial
sales in the fourth quarter increased 7.1 percent compared to the same
quarter of 2008.
|
Residential,
commercial and industrial classes reflected sales growth as a result of
increasing economic activity in Entergy’s service territory. The improvement in
industrial sales in fourth quarter 2009 was driven by the large industrial
customer group, particularly in chemicals and refining. Small and
mid-sized industrial customers are slowly showing signs of recovery from the
recession, but their usage continued to be negatively affected in the current
quarter. Also, a portion of the quarter-over-quarter increase in
sales for all customer classes was the result of the absence of outages for the
September 2008 hurricanes, most notably in the industrial segment. Industrial
customers are typically billed at the beginning of the month, and as such these
outages for hurricanes Gustav and Ike were reflected in October
sales. Near normal weather versus warmer-than-normal weather in
fourth quarter 2008 also provided a modest increase in sales
volume.
For the
year 2009, Utility, Parent and Other earned $2.88 per share on an as-reported
earnings basis, compared to $2.22 per share in 2008. Operational
earnings in 2009 were $3.02 per share compared to $2.43 per share in
2008. The increase in operational earnings in 2009 was driven by
higher Utility net revenue with the absence of hurricanes Gustav and Ike in 2008
contributing. Another factor in the improved results at Utility,
Parent & Other was lower operation and maintenance expense, due primarily to
the absence of Entergy Arkansas regulatory charges noted above. Also
contributing to the earnings improvement was a lower overall effective tax rate
for Utility, Parent & Other in 2009 versus 2008. Partially
offsetting these items was an increase in depreciation and amortization expense
in the current year due to increased plant in service.
Table 4
provides a comparative summary of the Utility’s operational performance
measures.
|
Table
4: Utility Operational Performance Measures
|
||||||||
|
Fourth
Quarter and Year-to-Date 2009 vs. 2008 (see Appendix F for definitions of
measures)
|
||||||||
|
Fourth Quarter
|
Year-to-Date
|
|||||||
|
2009
|
2008
|
%
Change
|
%
Weather Adjusted
|
2009
|
2008
|
%
Change
|
%
Weather Adjusted
|
|
|
GWh
billed
|
||||||||
|
Residential
|
7,421
|
6,992
|
6.1%
|
4.6%
|
33,626
|
33,047
|
1.8%
|
1.5%
|
|
Commercial
and governmental
|
7,240
|
6,992
|
3.5%
|
3.0%
|
29,884
|
29,719
|
0.6%
|
0.5%
|
|
Industrial
|
9,235
|
8,626
|
7.1%
|
7.1%
|
35,638
|
37,843
|
(5.8)%
|
(5.8)%
|
|
Total
Retail Sales
|
23,896
|
22,610
|
5.7%
|
5.0%
|
99,148
|
100,609
|
(1.5)%
|
(1.5)%
|
|
Wholesale
|
998
|
1,240
|
(19.5)%
|
4,862
|
5,401
|
(10.0)%
|
||
|
Total
Sales
|
24,894
|
23,850
|
4.4%
|
104,010
|
106,010
|
(1.9)%
|
||
|
O&M
expense per MWh
|
$20.18
|
$23.95
|
(15.7)%
|
$18.67
|
$18.48
|
1.0%
|
||
|
Number
of retail customers
|
||||||||
|
Residential
|
2,331,433
|
2,304,324
|
1.2%
|
|||||
|
Commercial
and governmental
|
346,925
|
342,152
|
1.4%
|
|||||
|
Industrial
|
40,757
|
42,148
|
(3.3)%
|
|||||
Appendix
C provides information on selected pending local and federal regulatory
cases.
|
III.
|
Competitive Businesses
Results
|
Entergy’s
competitive businesses include Entergy Nuclear and Non-Nuclear Wholesale
Assets.
Entergy
Nuclear
Entergy
Nuclear earned $0.89 per share on an as-reported basis in fourth quarter 2009,
compared to as-reported earnings of $1.14 per share in fourth quarter
2008. On an operational basis, fourth quarter 2009 Entergy Nuclear
earnings were $0.95 per share versus $1.18 per share in the last quarter of the
prior year. Entergy Nuclear’s operational earnings decreased as a
result of higher income tax expense in the current quarter due primarily to the
net effect of the annual consolidated tax adjustments. Also
contributing to the lower results was higher operation and maintenance expense
during the quarter due to the absence of refueling outages in the quarter and
associated deferral of costs. Partially offsetting these items was
higher net revenue as a result of higher generation due to 32 fewer refueling
outage days in the current quarter and increased pricing. Higher
other income associated with decommissioning trusts also provided an offset to
decreased earnings. A smaller impairment recognized on Entergy
Nuclear’s decommissioning trust funds in the current period contributed to
higher other income, as well as higher earnings realized on decommissioning
trust investments in 2009.
For the
year 2009, Entergy Nuclear earned $3.22 per share on an as-reported basis and
$3.45 per share on an operational basis. This compares to as-reported
earnings of $3.97 per share and operational earnings of $4.07 per share at
Entergy Nuclear in the prior year. The decline in Entergy Nuclear’s
operational earnings in 2009 was due primarily to a higher effective income tax
rate as well as an increase in operation and maintenance
expense. Impairments on Entergy Nuclear’s decommissioning trust funds
in 2009 exceeded amounts recognized in 2008, and were partially offset by higher
realized earnings on decommissioning trust investments, also reflected in other
income.
Table 5
provides a comparative summary of Entergy Nuclear’s operational performance
measures.
|
Table
5: Entergy Nuclear Operational Performance
Measures
|
||||||
|
Fourth
Quarter and Year-to-Date 2009 vs. 2008 (see Appendix F for definitions of
measures)
|
||||||
|
Fourth Quarter
|
Year-to-Date
|
|||||
|
2009
|
2008
|
%
Change
|
2009
|
2008
|
%
Change
|
|
|
Net
MW in operation
|
4,998
|
4,998
|
-%
|
4,998
|
4,998
|
-%
|
|
Average
realized price per MWh
|
$59.43
|
$56.69
|
5%
|
$61.07
|
$59.51
|
3%
|
|
Production
cost per MWh
|
$23.20
|
$22.77
|
2%
|
$23.26
|
$21.88
|
6%
|
|
Non-fuel
O&M expense/purchased power per MWh (a)
|
$23.60
|
$23.06
|
2%
|
$23.30
|
$21.95
|
6%
|
|
GWh
billed
|
11,052
|
10,489
|
5%
|
40,981
|
41,710
|
(2)%
|
|
Capacity
factor
|
99%
|
94%
|
5%
|
93%
|
95%
|
(2)%
|
|
Refueling
outage days:
|
||||||
|
FitzPatrick
|
-
|
10
|
-
|
26
|
||
|
Indian
Point 2
|
-
|
-
|
-
|
26
|
||
|
Indian
Point 3
|
-
|
-
|
36
|
-
|
||
|
Palisades
|
-
|
-
|
41
|
-
|
||
|
Pilgrim
|
-
|
-
|
31
|
-
|
||
|
Vermont
Yankee
|
-
|
22
|
-
|
22
|
||
|
|
(a)
|
Fourth
quarter and year-to-date 2009 exclude the effect of the special item for
non-utility nuclear spin-off
dis-synergies.
|
Table 6
provides capacity and generation sold forward projections for Entergy
Nuclear.
|
Table
6: Entergy Nuclear’s Capacity and Generation Projected Sold
Forward
|
|||||
|
2010
through 2014 (see
Appendix
F for definitions of
measures)
|
|||||
|
2010
|
2011
|
2012
|
2013
|
2014
|
|
|
Energy
|
|||||
|
Planned
TWh of generation
|
40
|
41
|
41
|
40
|
41
|
|
Percent
of planned generation sold forward (b)
|
|||||
|
Unit-contingent
|
53%
|
54%
|
18%
|
12%
|
14%
|
|
Unit-contingent
with availability guarantees
|
35%
|
17%
|
13%
|
6%
|
3%
|
|
Firm
LD
|
-%
|
3%
|
-%
|
-%
|
-%
|
|
Total
Energy Sold Forward
|
88%
|
74%
|
31%
|
18%
|
17%
|
|
Average
contract price per MWh (c)
|
$57
|
$56
|
$56
|
$50
|
$50
|
|
Capacity
|
|||||
|
Planned
net MW in operation
|
4,998
|
4,998
|
4,998
|
4,998
|
4,998
|
|
Percent
of capacity sold forward
|
|||||
|
Bundled
capacity and energy contracts
|
26%
|
25%
|
18%
|
16%
|
16%
|
|
Capacity
contracts
|
42%
|
26%
|
30%
|
13%
|
-%
|
|
Total
Capacity Sold Forward
|
68%
|
51%
|
48%
|
29%
|
16%
|
|
Average
capacity contract price per kW per month
|
$3.0
|
$3.6
|
$3.0
|
$2.6
|
-
|
|
Blended Capacity and Energy Recap (based on
revenues)
|
|||||
|
Percent
of planned energy and capacity sold forward
|
87%
|
73%
|
33%
|
16%
|
13%
|
|
Average
contract revenue per MWh (c)
|
$59
|
$58
|
$60
|
$53
|
$50
|
|
|
(b)
A portion of EN’s total planned generation sold forward through March 2012
is associated with the Vermont Yankee contract, for which pricing may be
adjusted.
|
|
|
(c) Average
contract prices exclude payments that may be owed under the value sharing
agreement with the New York Power
Authority.
|
Non-Nuclear Wholesale
Assets
Entergy’s
Non-Nuclear Wholesale Assets’ fourth quarter earnings were $0.19 per share in
2009 compared to as-reported earnings of $0.13 per share and operational
earnings of $0.14 per share in the same quarter a year ago. Income
tax benefits were the primary drivers in both quarters. The current
quarter reflects a tax benefit recognized on a capital loss associated with the
sale of stock of a merchant fossil generation subsidiary to a third
party. In the fourth quarter 2008, a closing agreement was reached
with the Internal Revenue Service allowing a capital loss. As a
result, a provision for tax uncertainties that existed on this item was
reversed.
For the
year 2009, Entergy’s Non-Nuclear Wholesale Assets business earned $0.20 per
share compared to earnings of $0.01 per share in 2008. As-reported
and operational results were the same in both periods. The earnings
increase in 2009 was driven by a decrease in income tax expense due to the
fourth quarter 2009 benefit noted above, plus a second quarter decrease in
valuation allowance on loss carryovers. Quarterly income tax effects
in 2008 were largely offsetting.
|
IV.
|
Other Financial
Performance Highlights
|
Earnings
Guidance
Entergy
is affirming 2010 earnings guidance in the range of $6.15 to $6.95 per share on
an as-reported basis, assuming a business as usual operation for the full
year. Operational earnings per share guidance ranges from $6.40 to
$7.20 per share and excludes $(0.25) per share of projected dis-synergies
associated with the spin-off of Entergy’s non-utility nuclear business and plans
to enter into a nuclear services joint venture. Guidance for 2010
does not incorporate a special item for expenses anticipated in connection with
outside services provided to pursue the spin-off. The level of these
charges in 2010 will vary depending upon resolution of the
spin-off. Year-over-year changes are shown as point estimates and are
applied to 2009 earnings to compute the 2010 guidance
midpoint. Drivers for the 2010 operational guidance range are listed
separately. Because there is a range of possible outcomes associated
with each earnings driver, a range is applied to the calculated guidance
midpoints to produce Entergy’s guidance ranges for as-reported and operational
earnings. Beginning in 2010, Entergy will combine the Non-Nuclear
Wholesale Assets’ results with Utility, Parent & Other’s for earnings
release purposes. The segments in 2010 guidance have been adjusted to
align with the revised presentation format. The 2010 earnings
guidance is detailed in Table 7 below.
|
Table
7: 2010 Earnings Per Share Guidance – As-Reported and
Operational
|
|||||
|
Business
as Usual Basis
|
|||||
|
(Per share in U.S. $) –
Prepared October 2009 (d)
|
|||||
|
Segment
|
Description
of Drivers
|
2009
Earnings per Share
|
Expected
Change
|
2010
Guidance
Midpoint
|
2010
Guidance Range
|
|
Utility, Parent, &
Other (includes Non-Nuclear Wholesale Assets)
|
2009
Operational Earnings per Share
|
3.22
|
|||
|
Adjustment
to normalize weather
|
0.01
|
||||
|
Increased
net revenue due to sales growth and rate actions
|
0.65
|
||||
|
Increased
non-fuel operation and maintenance expense
|
(0.05)
|
||||
|
Increased
depreciation expense
|
(0.08)
|
||||
|
Decreased
other income
|
(0.15)
|
||||
|
Increased
interest expense
|
(0.05)
|
||||
|
Non-nuclear
wholesale assets contribution
|
(0.20)
|
||||
|
Accretion
/ other
|
0.20
|
||||
|
Subtotal
|
3.22
|
0.33
|
3.55
|
||
|
Entergy
Nuclear
|
2009
Operational Earnings per Share
|
3.45
|
|||
|
Decreased
net revenue due to lower pricing and volume
|
(0.15)
|
||||
|
Increased
non-fuel operation and maintenance expense
|
(0.20)
|
||||
|
Increased
depreciation expense
|
(0.05)
|
||||
|
Increased
other income
|
0.20
|
||||
|
Accretion
/ other
|
-
|
||||
|
Subtotal
|
3.45
|
(0.20)
|
3.25
|
||
|
Consolidated
Operational
|
2010
Operational Earnings per Share
|
6.67
|
0.13
|
6.80
|
6.40
– 7.20
|
|
Consolidated
As-Reported
|
2009
As-Reported Earnings per Share
|
||||
|
Changes
detailed above
|
0.13
|
||||
|
2010
Entergy Nuclear spin-off dis-synergies
|
(0.25)
|
||||
|
2009
Entergy Nuclear spin-off dis-synergies
|
0.23
|
||||
|
2009
Non-utility nuclear spin-off expenses for outside services at Utility,
Parent & Other
|
0.14
|
||||
|
2010
As-Reported Earnings per Share Guidance Range
|
6.30
|
0.25
|
6.55
|
6.15
– 6.95
|
|
(d) Updated
February 2010 to reflect 2009 final results.
Key
assumptions supporting 2010 business as usual earnings guidance are as
follows:
Utility,
Parent & Other
|
·
|
Normal
weather
|
|
·
|
Retail
sales growth of around 4.5% on a weather adjusted basis; around 3% on a
normalized basis excluding the effects of industrial
expansion
|
|
·
|
Increased
revenue associated with rate actions, including storm securitization which
is offset by increased interest expense as noted
below
|
|
·
|
Increased
non-fuel operation and maintenance expense resulting from compensation and
benefits expense and increased refueling outage amortization, largely
offset by lower customer write-offs and the absence of 2009 storm related
items
|
|
·
|
Increased
depreciation associated with capital spending at the
Utility
|
|
·
|
Decreased
other income due to lower carrying charges and the absence of the 2009
gain on sale of land at the Utility
|
|
·
|
Increased
interest expense associated with increased debt outstanding at the
Utility, including storm securitization, partially offset by lower debt
outstanding at the Parent
|
|
·
|
Break-even
operations targeted for the Non-Nuclear Wholesale Assets
business
|
|
·
|
Accretion
/ other is primarily driven by the effect of share repurchases in both
2009 and 2010
|
Entergy
Nuclear
|
·
|
40
TWh of total output, reflecting an approximate 92 percent capacity factor,
including 30 day refueling outages at Indian Point 2 and Vermont Yankee in
Spring 2010 and FitzPatrick and Palisades in Fall
2010
|
|
·
|
88
percent of energy sold under existing contracts; 12 percent sold into the
spot market
|
|
·
|
$57/MWh
average energy contract price; $56/MWh average unsold energy price based
on published market prices at the end of September
2009
|
|
·
|
Palisades
PPA revenue amortization of $46 million in 2010, down from $53 million in
2009
|
|
·
|
Non-fuel
operation and maintenance expense, including refueling outage expense and
purchased power, around $25/MWh resulting from increased compensation and
benefits expense, higher NRC fees and increased refueling outage
amortization
|
|
·
|
Increased
depreciation associated with capital
spending
|
|
·
|
Increased
other income due primarily to the absence of 2009 decommissioning trust
other than temporary impairments; earnings guidance does not incorporate
assumptions for other than temporary impairments as financial market
outcomes are outside of Entergy Nuclear’s control and difficult to
predict
|
|
·
|
Offsetting
effects of accretion / other are primarily driven by the effect of share
repurchases in both 2009 and 2010, largely offset by a higher effective
tax rate in 2010
|
Share
Repurchase Program
|
·
|
2010
average fully diluted shares outstanding of approximately 187 million
(including effects of share repurchases in both 2009 and
2010)
|
Effective
Income Tax Rate
|
·
|
2010
assumes an overall effective income tax rate of 36
percent
|
Earnings
guidance for 2010 should be considered in association with earnings
sensitivities as shown in Table 8. These sensitivities illustrate the
estimated change in operational earnings resulting from changes in various
revenue and expense drivers. Traditionally, the most significant
variables for earnings drivers are utility sales for Utility, Parent & Other
and energy prices for Entergy Nuclear. The broader earnings guidance
range for 2010 also takes into consideration the following:
|
·
|
A
number of regulatory initiatives (rate actions) underway across the
Utility jurisdictions
|
|
·
|
Timing
flexibility for executing the share repurchase program across the year
(guidance assumes execution on a ratable
basis)
|
|
·
|
Potential
outcomes for projected pension plan discount rate (guidance assumes
6.75%)
|
Estimated
annual impacts shown in Table 8 are intended to be indicative rather than
precise guidance.
|
Table
8: 2010 Earnings Sensitivities
Business
as Usual Basis
|
|||
|
(Per
share in U.S. $) – Prepared October 2009
|
|||
|
Variable
|
2010
Guidance Assumption
|
Description
of Change
|
Estimated
Annual Impact
(e)
|
|
Utility,
Parent & Other
|
|||
|
Sales
growth
Residential
Commercial
/ Governmental
Industrial
|
Around
4.5% total sales growth on a weather adjusted basis
|
1%
change in Residential MWh sold
1%
change in Comm / Govt MWh sold
1%
change in Industrial MWh sold
|
- /
+ 0.05
- /
+ 0.04
- /
+ 0.02
|
|
Rate
base
|
Growing
rate base
|
$100
million change in rate base
|
- /
+ 0.03
|
|
Return
on equity
|
Authorized
regulatory ROEs
|
1%
change in allowed ROE
|
- /
+ 0.33
|
|
Entergy
Nuclear
|
|||
|
Capacity
factor
|
92%
capacity factor
|
1%
change in capacity factor
|
- /
+ 0.07
|
|
Energy
price
|
12%
energy unsold at $56/MWh in 2010
|
$10/MWh
change for unsold energy
|
- /
+ 0.15
|
|
Non-fuel
operation and maintenance expense
|
$25/MWh
non-fuel operation and maintenance expense/purchased power
|
$1/MWh
change
|
+ /
- 0.13
|
|
Outage
(lost revenue only)
|
92%
capacity factor, including refueling outages for four northeast
units
|
1,000
MW plant for 10 days at average portfolio energy price of $57/MWh for sold
and $56/MWh for unsold volumes in 2010
|
-
0.04 / n/a
|
(e) Based on 2009 average
fully diluted shares outstanding of approximately 196
million.
|
V.
|
Appendices
|
Seven
appendices are presented in this section as follows:
|
·
|
Appendix
A includes information on Entergy’s plan to separate the non-utility
nuclear business from Entergy’s regulated utility business through a
tax-free spin-off of the non-utility nuclear
business.
|
|
·
|
Appendix
B includes earnings per share variance analysis and detail on special
items that relate to the current quarter and year-to-date
results.
|
|
·
|
Appendix
C provides information on selected pending local and federal regulatory
cases.
|
|
·
|
Appendix
D provides financial metrics for both current and historical
periods. In addition, historical financial and operating
performance metrics are included for the trailing eight
quarters.
|
|
·
|
Appendix
E provides a summary of planned capital expenditures for the next three
years.
|
|
·
|
Appendix
F provides definitions of the operational performance measures and GAAP
and non-GAAP financial measures that are used in this
release.
|
|
·
|
Appendix
G provides a reconciliation of GAAP to non-GAAP financial measures used in
this release.
|
|
A.
|
Spin-off of
Non-Utility Nuclear Business
|
Appendix
A provides information on Entergy’s planned spin-off of its non-utility nuclear
business.
|
Appendix
A: Spin-off of Non-Utility Nuclear
Business
|
The
announced spin-off of Entergy’s non-utility nuclear business will establish a
new independent, publicly traded company, Enexus Energy
Corporation. In addition, Entergy and Enexus intend to enter into a
nuclear services joint venture, with equal ownership, with the joint venture
being named EquaGen LLC. The state regulatory decisions and financing
continue as the critical path items in finalizing the spin-off
transaction. The transactions are subject to various approvals,
outlined in the table below. Final terms of the transactions and
spin-off completion are subject to the approval of the Entergy Board of
Directors.
|
Proceeding
|
Pending
Regulatory Approvals – Spin-Off of Non-Utility Nuclear
Business
|
|
Nuclear
Regulatory Commission
|
The
Nuclear Regulatory Commission (NRC) initially approved Entergy Nuclear
Operations, Inc.’s (ENO) application on July 28, 2008 with the approval
effective for a period of one year. Additional extensions of the approval
have been granted with the current extension in effect through August 1,
2010.
|
|
Vermont
Public Service Board
|
Request: In
January 2008, Entergy Nuclear Vermont Yankee, L.L.C. (EVY) and ENO
requested approval from the Vermont Public Service Board (VPSB) for
spin-off transaction and other actions required to effect the
transaction.
Recent
Activity: In an official statement issued on January 27,
2010, Vermont Governor Douglas directed
Commissioner O’Brien to request a stay from any further action by the VPSB
on the Enexus spin-off. This direction came in reaction to
recent events at Vermont Yankee regarding conflicting information provided
about piping systems carrying radioactivity prompted by tritium
discovery. A comprehensive internal investigation, conducted by
an independent counsel, is now underway to not only resolve the known
inconsistencies but to seek out and find any and all discrepancies or less
than clear information supplied in this process and correct the
record.
Next
Steps: Action by the VPSB on the request for approval of
the transaction following resolution of the stay.
Other
Background: Under Vermont law, approval requires a
finding that actions promote the general good of the state. In
October 2009, a Memorandum of Understanding (MOU) was filed with the VPSB
outlining an agreement reached with the Vermont Department of Public
Service, which if approved by the VPSB, would result in approval of the
spin-off transaction in Vermont. The decision on the MOU as
submitted was pending before the VPSB prior to the governor’s direction to
request a stay in the proceeding.
|
|
New
York Public Service Commission
|
Request: In
January 2008, Entergy Nuclear FitzPatrick, L.L.C. (ENFP), Entergy Nuclear
Indian Point 2 and 3, L.L.C. (ENIP2 & 3), ENO and corporate affiliate
Enexus filed a petition with the New York Public Service Commission
(NYPSC) requesting approval for the spin-off transaction and other actions
required to effect the transaction.
Recent
Activity: Various filings were made throughout the
fourth quarter and into January in accordance with the procedures and
schedule ordered by the Administrative Law Judges (ALJs) assigned to the
proceeding.
Next
Steps: The ALJs are expected to submit a report to the
NYPSC. While a definitive date for the submittal of such report
is not known, it is expected that the ALJs will do so on a schedule that
would permit the NYPSC to consider approval of the transaction at its next
scheduled meeting on February 11, 2010.
Other
Background: Entergy’s most recent filing on January 14,
2010 once again presented facts that demonstrate its position that Enexus
will be at least as capable as Entergy of continuing the safe, secure, and
reliable operation of its nuclear facilities in New York. Other
parties to the proceeding continue to oppose the transaction on various
grounds.
|
|
Federal
Energy Regulatory Commission
|
FERC
approved the ENO application on June 12, 2008. In August 2009,
Entergy supplied additional data to FERC given the enhancements to the
transaction and an amended order approving the transaction was received
from FERC on September 11, 2009.
|
|
Securities
and Exchange Commission
|
Request / Recent
Activity: A fifth amendment to the Form 10 was
filed on November 20, 2009.
Next
Steps: Final amendments will be filed, following which
the SEC is expected to ultimately declare the Form 10 effective shortly
before the spin-off is consummated.
Other
Background: Pursuant to Section 12 of the 34 Exchange
Act, a Form 10 information statement is required to be filed to register
securities with the SEC. The Form 10 is subject to review and
comments by the SEC staff and will need to be declared effective prior to
the distribution. The Form 10 was initially filed in May
2008.
|
|
B.
|
Variance Analysis and
Special Items
|
Appendix
B-1 and Appendix B-2 provide details of fourth quarter and year-to-date 2009 vs.
2008 as-reported and operational earnings variance analysis for “Utility, Parent
& Other,” “Competitive Businesses,” and “Consolidated.”
|
Appendix
B-1: As-Reported and Operational Earnings Per Share Variance
Analysis
|
||||||||||
|
Fourth
Quarter 2009 vs. 2008
|
||||||||||
|
(Per
share in U.S. $, sorted in consolidated
as-reported
column, most to least favorable)
|
||||||||||
|
Utility,
Parent & Other
|
Competitive
Businesses
|
Consolidated
|
||||||||
|
As-Reported
|
Opera-
tional
|
As-Reported
|
Opera-
tional
|
As-
Reported
|
Opera-tional
|
|||||
|
2008
earnings
|
(0.38)
|
(0.33)
|
1.27
|
1.32
|
0.89
|
0.99
|
||||
|
Net
revenue
|
0.14
|
0.14
|
(f)
|
0.20
|
0.20
|
(g)
|
0.34
|
0.34
|
||
|
Other
operation & maintenance expense
|
0.30
|
0.25
|
(h)
|
(0.12)
|
(0.08)
|
(i)
|
0.18
|
0.17
|
||
|
Income
taxes – other
|
0.56
|
0.56
|
(j)
|
(0.41)
|
(0.41)
|
(k)
|
0.15
|
0.15
|
||
|
Other
income (deductions)
|
(0.04)
|
(0.04)
|
0.11
|
0.11
|
(l)
|
0.07
|
0.07
|
|||
|
Interest
and other charges
|
0.05
|
0.05
|
(m)
|
-
|
0.02
|
0.05
|
0.07
|
|||
|
Taxes
other than income taxes
|
0.01
|
0.01
|
-
|
-
|
0.01
|
0.01
|
||||
|
Nuclear
refueling outage expense
|
(0.01)
|
(0.01)
|
(0.01)
|
(0.01)
|
(0.02)
|
(0.02)
|
||||
|
Depreciation/amortization
expense
|
(0.02)
|
(0.02)
|
(0.01)
|
(0.01)
|
(0.03)
|
(0.03)
|
||||
|
Prior
year effect of the unsuccessful Equity Units remarketing
|
(0.05)
|
-
|
(n)
|
0.05
|
-
|
(n)
|
-
|
-
|
||
|
2009
earnings
|
0.56
|
0.61
|
1.08
|
1.14
|
1.64
|
1.75
|
||||
|
Appendix
B-2: As-Reported and Operational Earnings Per Share Variance
Analysis
|
||||||||||
|
Year-to-Date
Fourth Quarter 2009 vs. 2008
|
||||||||||
|
(Per
share in U.S. $, sorted in consolidated
as-reported
column, most to least favorable)
|
||||||||||
|
Utility,
Parent & Other
|
Competitive
Businesses
|
Consolidated
|
||||||||
|
As-Reported
|
Opera-
tional
|
As-Reported
|
Opera-
tional
|
As-
Reported
|
Opera-
tional
|
|||||
|
2008
earnings
|
2.22
|
2.43
|
3.98
|
4.08
|
6.20
|
6.51
|
||||
|
Net
revenue
|
0.33
|
0.33
|
(f)
|
(0.03)
|
(0.03)
|
0.30
|
0.30
|
|||
|
Interest
and other charges
|
0.05
|
0.05
|
(m)
|
0.09
|
0.16
|
(o)
|
0.14
|
0.21
|
||
|
Taxes
other than income taxes
|
0.01
|
0.01
|
(0.03)
|
(0.03)
|
(0.02)
|
(0.02)
|
||||
|
Decommissioning
expense
|
(0.01)
|
(0.01)
|
(0.02)
|
(0.02)
|
(0.03)
|
(0.03)
|
||||
|
Other
operation & maintenance expense
|
0.25
|
0.11
|
(h)
|
(0.28)
|
(0.13)
|
(i)
|
(0.03)
|
(0.02)
|
||
|
Income
taxes – other
|
0.22
|
0.22
|
(j)
|
(0.27)
|
(0.27)
|
(k)
|
(0.05)
|
(0.05)
|
||
|
Nuclear
refueling outage expense
|
(0.04)
|
(0.04)
|
(0.02)
|
(0.02)
|
(0.06)
|
(0.06)
|
||||
|
Other
income (deductions)
|
0.04
|
0.04
|
(0.06)
|
(0.06)
|
(l)
|
(0.02)
|
(0.02)
|
|||
|
Depreciation/amortization
expense
|
(0.12)
|
(0.12)
|
(p)
|
(0.04)
|
(0.03)
|
(0.16)
|
(0.15)
|
|||
|
Prior
year effect of the unsuccessful Equity Units remarketing
|
(0.07)
|
-
|
(n)
|
0.10
|
-
|
(n)
|
0.03
|
-
|
||
|
2009
earnings
|
2.88
|
3.02
|
3.42
|
3.65
|
6.30
|
6.67
|
||||
|
Utility
Net Revenue Variance Analysis
2009
vs. 2008
($
EPS)
|
|||
|
Fourth
Quarter
|
Year-to-Date
|
||
|
Weather
|
0.02
|
Weather
|
0.01
|
|
Sales
growth/ pricing
|
0.07
|
Sales
growth/ pricing
|
0.26
|
|
Other
|
0.05
|
Other
|
0.06
|
|
Total
|
0.14
|
Total
|
0.33
|
|
|
(f)
|
Quarter
and year-to-date variances were driven primarily by Utility Operating
Company rate actions in Texas, Louisiana, Mississippi and Arkansas
(capacity acquisition rider). An increase in volume also
benefited both periods, with the year-to-date improvement mainly as a
result of the absence of two hurricanes in 2008 that materially lowered
usage. In addition, fourth quarter net revenue reflected a regulatory
charge resulting from a FERC order related to an Entergy Arkansas
wholesale contract offset by a positive adjustment for changes in the
deferred fuel methodology related to 2008 and 2009 periods at Entergy Gulf
States Louisiana.
|
|
|
(g)
|
The
increase in the quarter is due to higher revenues at Entergy Nuclear from
higher production due to fewer scheduled refueling outage days and higher
pricing. Partially offsetting was lower revenue amortization
associated with the below-market PPA at
Palisades.
|
|
|
(h)
|
The
quarter and year-to-date variances were due primarily to the absence of
regulatory charges at Entergy Arkansas in fourth quarter
2008. Partially offsetting on a year-to-date basis was higher
nuclear spending, increased customer write-offs, settlement of
storm-related costs and the absence of 2008 storm-related restoration cost
deferrals.
|
|
|
(i)
|
The
increases in the quarter and year-to-date were due primarily to spin-off
dis-synergies, higher nuclear spending as a result of higher non-labor
costs and higher nuclear labor, in part due to the absence of refueling
outages in fourth quarter 2009 and the associated deferral of
costs. Higher spending at Non-Nuclear Wholesale Assets also
contributed to both the quarter and year-to-date
variances.
|
|
|
(j)
|
The
quarter and year-to-date variances were due primarily to the net effect of
fourth quarter consolidated income tax adjustments, the absence of tax
flow through items associated with Entergy Arkansas proceedings in fourth
quarter 2008, and a favorable tax reserve adjustment related to a fourth
quarter 2009 Louisiana Department of Revenue private letter
ruling. Also contributing to the year-to-date increase were
decreases in valuation allowances on capital loss carryforwards offset by
the absence of a tax benefit on the liquidation of Entergy Power
Generation in third quarter 2008.
|
|
|
(k)
|
The
quarter and year-to-date variances were driven by the net effect of
consolidated income tax adjustments. In addition, at
Non-Nuclear Wholesale assets a tax benefit was recognized on a capital
loss in fourth quarter 2009, while 2008 fourth quarter results reflected
the reversal of a provision for tax uncertainties given a closing
agreement reached with the IRS. Also affecting the
year-to-date period was the absence of 2008 benefits from a change in
Massachusetts state tax law at Entergy Nuclear and the redemption of an
investment at Non-Nuclear Wholesale Assets, as well as reductions in
valuation allowances on capital loss
carryforwards.
|
|
|
(l)
|
The
increase in the quarter was driven by higher realized earnings on
decommissioning trust investments and a smaller decommissioning impairment
in the current quarter. The decrease year-to-date is due
primarily to impairments associated with decommissioning trust fund
investments for the year exceeding similar impairments in 2008, partially
offset by higher realized earnings on decommissioning trust
investments.
|
|
(m)
|
The
lower interest expense in the quarter and year-to-date is due primarily to
lower Parent company borrowings and debt redemptions and lower affiliate
interest expense, partially offset by higher net borrowings at the
Utility. Higher rates on Utility borrowings also provided a
partial offset in the year-to-date
period.
|
|
|
(n)
|
The
quarter and year-to-date variances reflect the effects of the unsuccessful
remarketing of the Equity Units in February 2009 on 2008 results, which
resulted in a reduction in Parent company interest expense associated with
the note component of the Equity Units (for EPS calculation purposes only)
offset by the dilutive effect of the Entergy common stock projected to be
issued in accordance with the purchase contract component of the Equity
Units. This was classified as a special item in 2008, and as
such only affected as-reported
results.
|
|
|
(o)
|
The
variance in the year-to-date period was due primarily to lower
intercompany interest charges which are eliminated in consolidation and
have no effect on consolidated results. The corresponding
reduction in intercompany other income (deductions) at Utility, Parent
& Other was offset by carrying charges on storm costs for hurricanes
Gustav and Ike in Texas and Louisiana and a gain recorded on a land
sale.
|
|
|
(p)
|
The
increase is due primarily to increased plant in service at the
Utility.
|
Appendix
B-3 lists special items by business with quarter-to-quarter and year-to-date
comparisons. Amounts are shown on both earnings per share and net
income bases. Special items are those events that are less routine,
are related to prior periods, or are related to discontinued
businesses. Special items are included in as-reported earnings per
share consistent with generally accepted accounting principles (GAAP), but are
excluded from operational earnings per share. As a result,
operational earnings per share is considered a non-GAAP measure.
|
Appendix
B-3: Special Items (shown as positive / (negative) impact on
earnings)
|
||||||
|
Fourth
Quarter and Year-to-Date 2009 vs. 2008
|
||||||
|
(Per
share in U.S. $)
|
||||||
|
Fourth Quarter
|
Year-to-Date
|
|||||
|
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|
|
Utility,
Parent & Other
|
||||||
|
Non-utility
nuclear spin-off expenses
|
(0.05)
|
(0.10)
|
0.05
|
(0.14)
|
(0.28)
|
0.14
|
|
Dilution
effect – unsuccessful remarketing
|
-
|
0.05
|
(0.05)
|
-
|
0.07
|
(0.07)
|
|
Total
Utility, Parent & Other
|
(0.05)
|
(0.05)
|
-
|
(0.14)
|
(0.21)
|
0.07
|
|
Competitive
Businesses
|
||||||
|
Entergy
Nuclear
|
||||||
|
Non-utility
nuclear spin-off dis-synergies
|
(0.06)
|
-
|
(0.06)
|
(0.23)
|
-
|
(0.23)
|
|
Dilution
effect – unsuccessful remarketing
|
-
|
(0.04)
|
0.04
|
-
|
(0.10)
|
0.10
|
|
Non-Nuclear
Wholesale Assets
|
||||||
|
Dilution
effect – unsuccessful remarketing
|
-
|
(0.01)
|
0.01
|
-
|
-
|
-
|
|
Total
Competitive Businesses
|
(0.06)
|
(0.05)
|
(0.01)
|
(0.23)
|
(0.10)
|
(0.13)
|
|
Total
Special Items
|
(0.11)
|
(0.10)
|
(0.01)
|
(0.37)
|
(0.31)
|
(0.06)
|
|
(U.S.
$ in millions)
|
||||||
|
Fourth Quarter
|
Year-to-Date
|
|||||
|
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|
|
Utility,
Parent & Other
|
||||||
|
Non-utility
nuclear spin-off expenses
|
(9.1)
|
(20.0)
|
10.9
|
(27.0)
|
(55.4)
|
28.4
|
|
Dilution
effect – unsuccessful remarketing
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total
Utility, Parent & Other
|
(9.1)
|
(20.0)
|
10.9
|
(27.0)
|
(55.4)
|
28.4
|
|
Competitive
Businesses
|
||||||
|
Entergy
Nuclear
|
||||||
|
Non-utility
nuclear spin-off dis-synergies
|
(12.0)
|
-
|
(12.0)
|
(44.0)
|
-
|
(44.0)
|
|
Dilution
effect – unsuccessful remarketing
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Non-Nuclear
Wholesale Assets
|
||||||
|
Dilution
effect – unsuccessful remarketing
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total
Competitive Businesses
|
(12.0)
|
-
|
(12.0)
|
(44.0)
|
-
|
(44.0)
|
|
Total
Special Items
|
(21.1)
|
(20.0)
|
(1.1)
|
(71.0)
|
(55.4)
|
(15.6)
|
|
C.
|
Regulatory
Summary
|
|
|
Appendix
C provides a
summary of selected regulatory cases and events that are
pending.
|
|
Appendix
C: Regulatory Summary Table
|
|
|
Company
|
Pending
Cases / Events
|
|
Retail
Regulation
|
|
|
Entergy
Arkansas
Authorized
ROE: 9.9%
Last
Filed
Rate
Base:
$4.1
billion
Filed
9/09 based on 6/30/09 test year, with known and measurable changes through
6/30/10
|
Recent
activity: Rate case discovery is ongoing as APSC Staff
and Intervenors prepare to file direct testimony on February 26,
2010.
Background: On
September 4, 2009, EAI filed a rate case requesting a $223.2 million
increase reflecting an 11.5% ROE based on a June 30, 2009 test year with
known and measurable changes through June 30, 2010. The filing
also includes a proposed Formula Rate Plan (FRP). Key
provisions include a +/- 25 basis point bandwidth, with earnings outside
the bandwidth reset to the 11.5% midpoint ROE and rates changing on a
prospective basis depending on whether EAI is over or
under-earning. The proposed FRP also includes a recovery
mechanism that provides timely recovery for APSC-approved expense for
additional capacity purchase or construction / acquisition of new
transmission or generating facilities. Finally, the proposed
FRP includes an energy efficiency-related mechanism. Hearings
are scheduled to begin May 2010, with an effective date for new rates of
July 2010. EAI implemented its
last base rate change, a $5.1 million rate reduction, on August 29,
2007.
|
|
Storm Cost
Recovery: On February 1, 2010, EAI requested a financing
order to issue approximately $127.5 million in storm recovery bonds which
included carrying costs of $11.7 million and $4.6 million of up-front
financing costs to pay for ice storm restoration as EAI’s analysis
demonstrates retail customers will benefit from lower costs using
securitization. EAI will remove the associated revenue
requirement from its rate case should the APSC approve
securitization.
Background: In
January 2009, EAI was struck by a severe ice storm with the current
restoration cost estimate approximating $123 million, including $11.7
million in carrying costs, at the lower end of the $120 to $140 million
range. Considering the magnitude of the statewide storm
damages, the Arkansas legislature passed legislation authorizing storm
reserve accounting in March 2009, followed by the enactment of storm
securitization legislation in April. Both pieces of legislation
are effective for storms occurring on or after January 1,
2009. At the end of March 2009, EAI filed a petition with the
APSC to establish storm reserve accounting pursuant to the legislation for
which a hearing is scheduled on March 9, 2010. In the interim,
the APSC approved on March 6, 2009 EAI’s application for an accounting
order authorizing the deferral of the operation and maintenance cost
portion of the ice storm restoration costs pending their
recovery. As part of EAI’s September 4, 2009 rate case filing,
EAI included the 2009 ice storm restoration costs in cost of
service. The ice storm restoration costs would be removed from
the cost-of-service in the pending rate case if the APSC approves EAI’s
request to securitize the ice storm costs. EAI is also seeking
an increase in the annual storm damage accrual from $14.4 million to $22.3
million in its rate case.
|
|
|
White Bluff Environmental
Controls Project: In December, the APSC suspended the
procedural schedule following letters submitted by the United States
Environmental Protection Agency (U.S. EPA) and the U.S. Department of
Agriculture (U.S. DA) to the Arkansas Department of Environmental Quality
(ADEQ) regarding concerns about issuing draft air permits for the SO2
scrubbers and NOx controls. Later that month, EAI and other
interested parties requested a variance from the state’s 2013 compliance
date and suspended all work on the project. EAI also filed a
notice of withdrawal of its Act 310 filing and refunded limited
collections received to date in January. On January 22, 2010,
the Arkansas Pollution Control and Ecology (PC&E) Commission adopted a
procedural schedule to conduct a public hearing in response to Sierra
Club’s petition regarding the variance request with the expectation that
the variance could be considered at the PC&E Commission’s March 26,
2010 meeting. EAI will address cost recovery issues for limited
spending to date in the early stages of the project at such time when
there is more certainty regarding the project disposition.
Background: On
March 27, 2009, EAI petitioned the APSC to undertake the Environmental
Controls project that will install scrubbers and low NOx burners at the
co-owned White Bluff coal plant at an expected total cost of approximately
$1.0 billion, and EAI’s share at $631 million, with estimates revised
downward in October 2009 to $780 million, with EAI’s revised share at $465
million. White Bluff Units 1 and 2 are required to meet more
stringent SO2 and
NOx limits by 2013 in order to comply with the ADEQ State Implementation
Plan regulations implementing the U.S. EPA’s Regional Haze
Rule. To continue operating, White Bluff must install pollution
control technology. EAI conducted economic analysis comparing
the Environmental Controls project to other supply options for capacity
and energy and concluded the project is the lowest reasonable cost
alternative under a wide range of assumptions. EAI had intended
to recover costs pursuant to Act 310 through an interim rate schedule to
be amended approximately every six months to capture ongoing
costs. Act 310 permits utilities to recover costs associated
with government-mandated expenditures and investments required for the
protection of public health, safety and the environment through a
surcharge outside the normal rate case process. The interim
surcharge was to be effective until implementation of new rate schedules
in connection with the next general rate filing of a
utility. EAI and the White Bluff plant co-owners filed
supplemental testimony in the proceeding in early July, with the co-owners
generally indicating that the plant represents a reliable, low cost base
load capacity resource even after considering the cost of installing
scrubbers. The procedural schedule called for hearings in March
2010, which will not occur due to the suspension of the procedural
schedule.
|
|
|
Entergy
Gulf States Louisiana
Authorized
ROE Range: 9.9% - 11.4%
(electric)
Last
Filed
Rate
Base:
$2.1
billion
(electric)
Filed
10/09 based on 12/31/08 test yr
|
Recent activity: In
November 2009, EGSL made its $3.7 million refund and implemented its $44.3
million rate increase pursuant to the settlement approved by the LPSC in
October. In January, EGSL implemented a further $23.9 million
rate increase pursuant to the special rate implementation filing made in
December, primarily for incremental capacity costs approved by the
LPSC. In addition, in December, EGSL filed a joint application
seeking LPSC approval for a $9.7 million revenue requirement to provide
supplemental funding for the decommissioning trust maintained for the
LPSC-regulated 70% share of River Bend, in response to the NRC
notification of a projected shortfall of decommissioning funding
assurance. Currently, EGSL has no funding in retail rates for
decommissioning.
Background: At
its October 2009 Business and Executive Session, the LPSC approved an
uncontested settlement resolving the 2007 test year FRP filing and
extending the FRP regulatory process for an additional three
years. The new FRP was adopted for the 2008-2010 test years and
retains the 10.65% ROE midpoint with a +/- 75 basis point bandwidth and a
recovery mechanism for Commission-approved capacity
additions. Earnings outside the bandwidth are allocated
prospectively, 60% to customers and 40% to the company. As part
of the settlement, EGSL implemented the one-time rate reset noted
previously to achieve its 10.65% midpoint ROE for the 2008 test year
filing, which was filed October 21, 2009. This filing reflected
an 8.64% earned ROE and total rate increase of $44.3 million, including a
$36.9 million cost of service adjustment, plus $7.4 million net for
increased capacity costs and a base rate reclassification. New rates took
|
|
Appendix
C: Regulatory Summary Table (continued)
|
|
|
Company
|
Pending
Cases / Events
|
|
Retail
Regulation
|
|
|
Entergy
Gulf States Louisiana
(continued)
|
effect
coincident with the November billing cycle and are subject to review and
final approval by the LPSC. All parties also committed to work
together to attempt to develop a transmission rider for EGSL with a
schedule to be set that provides for the LPSC to address this matter at
its March 2010 Business and Executive session. Finally, the
settlement included a $3.7 million refund commencing with the November
billing cycle for the 2007 test year FRP filing.
|
|
Storm Cost
Recovery: On December 30, 2009, EGSL entered into a
black box stipulation agreement with the LPSC Staff that, if approved,
provides for total recoverable costs of nearly $234 million (greater than
98 percent of EGSL’s request) and permits replenishing EGSL’s storm
reserve in the amount of $90 million when Act 55 securitization is
accomplished. Storm costs will be deemed prudent and
recoverable and will not be tried (at least between the Staff and EGSL) at
the hearings scheduled to take place in March 2010. Intervenors
are required to state their position regarding the stipulation by February
15, 2010.
Background: In
lieu of seeking interim recovery, on October 9, 2008, EGSL accessed $85
million of storm reserves funded by securitized debt
proceeds. On October 15, 2008, the LPSC approved EGSL’s request
to defer and accrue carrying cost on unrecovered storm expenditures during
the period the company seeks regulatory recovery. The approval
was without prejudice to the ultimate resolution of the total amount of
prudently incurred storm cost or final carrying cost rate. New
securitization legislation was not needed, as existing legislation extends
to Gustav and Ike. EGSL initiated its storm recovery proceeding
for hurricanes Gustav and Ike on May 11, 2009. EGSL also sought
to replenish its storm reserve in the amount of $90 million. On
September 29, 2009, EGSL filed its first and second supplemental and
amending joint applications in the storm proceeding requesting that the
LPSC approve and authorize alternative (Act 55)
securitization. EGSL expects significant potential financing
savings from pursuing Act 55 alternative securitization and plans to
guarantee customer savings, consistent with results achieved from the same
approach used for hurricanes Katrina and Rita recovery. The procedural
schedule established concludes with hearings in March
2010.
|
|
|
Entergy
Louisiana
Authorized
ROE Range: 9.45% - 11.05%
Last
Filed
Rate
Base:
$2.9
billion
Filed
10/09 based on 12/31/08 test year
|
Recent activity: In
November 2009, ELL made its $12.9 million refund and implemented its $2.5
million rate increase pursuant to the settlement approved by the LPSC in
October. In addition, in December, ELL filed a joint
application seeking LPSC approval for a $10.3 million revenue requirement
to provide supplemental funding for the decommissioning trust maintained
for the LPSC-jurisdictional portion of Waterford 3, in response to the NRC
notification of a projected shortfall of decommissioning funding
assurance. Currently, ELL has $2.2 million in retail rates for
decommissioning.
Background: At
its October 2009 Business and Executive Session, the LPSC approved an
uncontested settlement resolving the 2006 and 2007 test year FRP filings
and extending the FRP regulatory process for an additional three
years. The new FRP was adopted for the 2008-2010 test years and
retains the 10.25% ROE midpoint with a +/- 80 basis point bandwidth and a
recovery mechanism for Commission-approved capacity
additions. Earnings outside the bandwidth are allocated
prospectively, 60% to customers and 40% to the company. As part
of the settlement, ELL implemented the one-time rate reset noted
previously to achieve its 10.25% midpoint ROE for the 2008 test year
filing, which was filed October 21, 2009. This filing reflected
a 9.35% earned ROE and total rate increase of $2.5 million, including a
$16.3 million cost of service adjustment, less a $13.8 million net
reduction for decreased capacity costs and a base rate reclassification.
New rates took effect coincident with the November billing cycle and are
subject to review and final approval by the LPSC. All parties
also committed to work together to attempt to develop a transmission rider
for ELL with a schedule to be set that provides for the LPSC to address
this matter at its March 2010 Business and Executive
session. Finally, the settlement included a $12.9 million
refund commencing with the November billing cycle for the 2006 and 2007
test year FRP filings.
|
|
Storm Cost
Recovery: On December 30, 2009, ELL entered into a black
box stipulation agreement with the LPSC Staff that, if approved, provides
for total recoverable costs of approximately $394 million (greater than 98
percent of ELL’s request) and permits replenishing ELL’s storm reserve in
the amount of $200 million when Act 55 securitization is
accomplished. Storm costs will be deemed prudent and
recoverable and will not be tried (at least between the Staff and ELL) at
the hearings scheduled to take place in March 2010. Intervenors
are required to state their position regarding the stipulation by February
15, 2010.
Background: In
lieu of seeking interim recovery, on October 9, 2008, ELL accessed $134
million of storm reserves funded by securitized debt
proceeds. On October 15, 2008, the LPSC approved ELL’s request
to defer and accrue carrying cost on unrecovered storm expenditures during
the period the company seeks regulatory recovery. The approval
was without prejudice to the ultimate resolution of the total amount of
prudently incurred storm cost or final carrying cost rate. New
securitization legislation was not needed, as existing legislation extends
to Gustav and Ike. ELL initiated its storm recovery proceeding
for hurricanes Gustav and Ike on May 11, 2009. ELL also sought
to replenish its storm reserve in the amount of $200
million. On September 29, 2009, ELL filed its first and second
supplemental and amending joint applications in the storm proceeding
requesting that the LPSC approve and authorize alternative (Act 55)
securitization. ELL expects significant potential financing
savings from pursuing Act 55 alternative securitization and plans to
guarantee customer savings, consistent with results achieved from the same
approach used for hurricanes Katrina and Rita recovery. The procedural
schedule established concludes with hearings in March
2010.
|
|
|
Acadia Unit 2
Acquisition: On January 29, 2010, ELL initiated its
Section 203 filing at FERC seeking authorization to acquire Power Block
Two of the Acadia Energy Center from Acadia Power Partners,
LLC. A procedural schedule is expected to be established by the
LPSC on February 2, 2010.
Background: ELL
signed a purchase and sale agreement to acquire the 580MW Unit 2 of the
Acadia Energy Center for $300 million ($517/kW). ELL proposes
to acquire 100 percent of Acadia Unit 2 and a 50 percent ownership
interest in the facility’s common assets. Cleco Power will
serve as operator for the entire facility. ELL has committed to
sell one third of the output to Entergy Gulf States Louisiana in
accordance with terms and conditions detailed under the existing System
Agreement. The purchase is contingent upon, among other things,
obtaining necessary approvals, including full cost recovery, from various
federal and state regulatory and permitting agencies and the filing of
notification under Hart-Scott-Rodino antitrust law. Closing is
expected to occur in late 2010 or early 2011. ELL has also
entered into a power purchase agreement for 100 percent of the output of
Acadia Unit that will commence on May 1, 2010 and is set to expire at the
closing of the acquisition transaction. A procedural schedule
to approve the power purchase agreement provides for hearings in February
if the approval is contested, and EGSL is seeking LPSC approval of this
agreement in April.
|
|
|
Appendix
C: Regulatory Summary Table (continued)
|
|
|
Company
|
Pending
Cases/Events
|
|
Retail
Regulation
|
|
|
Entergy
Louisiana
(continued)
|
Little Gypsy
Repowering: On October 27, 2009, ELL filed an
application and testimony seeking LPSC authorization to cancel the Little
Gypsy Unit 3 repowering project allowing ELL to cancel permits,
eliminating the requirement to monitor the project for potential
restart. This approach requires starting over should the
decision be made to engage in a similar future project. In
addition, ELL sought to recover cost incurred on a levelized five-year
recovery basis to be trued up. In the event ELL’s costs exceed
the authorized amount, ELL proposed that it be required to justify any
additional recovery. Pursuant to the procedural schedule, in
January, ELL filed an updated cost estimate of nearly $215 million,
including nearly $193 million of costs incurred through December 31, 2009
and $22 million of net cancellation / project termination costs including
AFUDC through March 2011. Hearings are scheduled for October
2010.
Background: On
November 8, 2007, the LPSC voted unanimously to approve ELL’s request to
repower the 538 MW Little Gypsy unit to utilize CFB technology relying on
a dual-fuel approach (petroleum coke and coal), an action that could
reduce Louisiana customers’ dependence on natural gas. The
approval was subject to a number of conditions, including the development
and approval of a construction monitoring plan. The order also
included a recovery provision for prudently incurred costs in the event
circumstances changed materially. The project later experienced
a delay resulting from the need to conduct additional environmental
analysis (Maximum Achievable Control Technology application) as a result
of a federal court decision in February 2008 unrelated to the
project. The additional analysis estimated construction could
commence by mid-year 2009 leading to a targeted in service date by
mid-year 2013 and resulting in a project cost estimate increase to $1.76
billion. In February 2009, the Louisiana Department of
Environmental Quality issued the new air permit. On March 11,
2009, the LPSC issued an order directing ELL to temporarily suspend the
Little Gypsy Repowering Project and file a report with the LPSC on the
economic viability of the project and develop a recommendation regarding
whether to delay the project for an extended time. This action
was based upon a number of factors including the recent decline in natural
gas prices, as well as environmental concerns, the unknown costs of carbon
legislation and changes in the capital / financial markets. On
April 1, 2009, ELL recommended to the LPSC that it continue the temporary
project suspension and make a filing with the LPSC seeking a longer-term
suspension (three years or more) of the project. The filing
indicated approximately $160 million of spending through February 28, 2009
and estimated approximately $300 million of total costs if the project is
cancelled. ELL had obtained all major environmental permits
required to begin construction. A longer-term delay places
these permits at risk and may adversely affect the project’s economics and
technological feasibility in the event the project is
re-initiated. In May 2009, the LPSC unanimously accepted ELL’s
recommendation and issued an order finding that ELL’s decision to place
the Little Gypsy project in longer-term suspension of 3 years or more was
in the public interest and prudent, without prejudice to issues of
prudence of timing of decisions, project management, whether ELL may
recover project costs from retail customers and the manner of that
recovery and whether the project should be canceled or abandoned as
opposed to merely suspended. The quarterly monitoring plan was
suspended indefinitely, with ELL instead working cooperatively with the
LPSC Staff keeping them informed of activities associated with suspending
the project and terminating current contracts related to the
project. On or before, December 15, 2011, ELL was required to
report to the LPSC and its Staff whether or not it intends to re-initiate
the project, including a detailed discussion of the basis for the
decision. ELL also dismissed its proceeding to recover cash
earnings on Construction Work in Progress (CWIP) for the Little Gypsy
project.
|
|
Entergy
Mississippi
Authorized
ROE Range: 11.91% - 14.42%
Last
Filed
Rate
Base:
$1.5
billion
Filed
3/09 based on 12/31/08 test year
|
Recent
activity: EMI continues to pursue proposed modifications
to its FRP. The MPSC approved a similar plan for another
Mississippi regulated electric utility company in fourth quarter
2009.
Background: EMI
has been operating under a FRP last approved in December
2002. The FRP allows the company’s earned ROE to increase or
decrease within a bandwidth with no change in rates. Earnings
outside the bandwidth are allocated 50% to customers and 50% to the
company, but on a prospective basis only. The plan also
provides for performance incentives that can increase or decrease the
benchmark ROE by as much as 100 basis points. On June 30, 2009,
the MPSC approved EMI’s 2008 FRP adjustment increase of $14.5 million
effective July 1, 2009. As a result, EMI filed a voluntary
motion to dismiss its Mississippi Supreme Court appeal of the 2007
FRP. On September 18, 2009, EMI filed proposed modifications to
its FRP rider. EMI is proposing changes to better achieve the
goal of an FRP by providing a reasonable opportunity to earn its allowed
return. The proposed modifications also more closely align
EMI’s FRP with the FRPs of the other regulated gas and electric utilities
in Mississippi, which would allow for a more uniform and streamlined
review process. Key changes include (1) resetting EMI’s return
to the middle of the FRP bandwidth each year and eliminating the 50 / 50
sharing in the current plan, (2) replacing the current rate change limit
of two percent of revenues subject to a $14.5 million revenue adjustment
cap, with a proposed limit of four percent of revenues, (3) implementing a
projected test year for the annual filing and subsequent look-back for the
prior year, and (4) modifying the performance measurement
process.
|
|
Fuel Recovery/Attorney General
Complaint: The MPSC continues to investigate issues
associated with EMI fuel costs and claims raised by the Mississippi
Attorney General (AG) going back some 30 years. The financial
portion of the fuel audit undertaken at the request of the MPSC performed
by Horne Group LLP (Horne) for the years ended September 30, 2008 and 2009
does not recommend that any costs be disallowed for
recovery. The January 2010 report did suggest that some costs
(less than one percent of the $1.66 billion in fuel and purchased energy
during the period) may have been more reasonably charged to customers
through base rates rather than through fuel charges, but the report did
not suggest that customers should not have paid for those costs. In
November 2009, the MPSC also engaged another firm, McFadden Consulting
Group, Inc., to review processes and practices related to fuel and
purchased energy.
Background: The
Commission has been reviewing state utilities’ practices and procedures,
most notably related to fuel recovery. EMI understands the
MPSC’s need to obtain more information about past Commission actions,
system tariffs, and issues including fuel purchases, fuel costs and power
generation needs, and will continue to work with the Commission to inform,
respond to questions and develop alternative policies on tariffs if they
are found to be in the best interests of customers and fairly balanced
with other stakeholder rights. In addition, the AG issued civil
investigative demands directed at EMI and other Entergy companies related
to EMI’s fuel adjustment clause and other matters. The AG
voluntarily dismissed this proceeding, and instead filed a complaint in
state court in December 2008 against EMI and other Entergy companies
alleging, among other things, violations of Mississippi statutes, fraud,
and breach of good faith and fair dealing, and requesting an accounting
and restitution. The litigation is wide ranging and relates to
tariffs and procedures under which EMI obtains power in the wholesale
market to meet electricity demand. EMI believes the complaint
is unfounded, and should be resolved in the appropriate regulatory
forum.
|
|
|
Appendix
C: Regulatory Summary Table (continued)
|
|
|
Company
|
Pending
Cases/Events
|
|
Retail
Regulation
|
|
|
Entergy
Mississippi
(continued)
|
On
December 29, 2008, the affected Entergy companies filed to remove the AG’s
suit to U.S. District Court where it is currently pending, and
additionally answered the complaint and filed a counter-claim for
injunctive and other relief based upon the Mississippi Public Utilities
Act and the Federal Power Act. The AG has filed a pleading
seeking to remand the case to state court. On February 10,
2009, an independent audit report commissioned by the MPSC to review fuel
recovery was released. The report indicated that many of EMI’s
fuel procurement and adjustment practices are sound and in the customers’
best interest. On June 30, 2009, the MPSC issued an order
authorizing an audit of EMI’s fuel adjustment clause by an independent
audit firm which was undertaken by Horne, as previously
described.
|
|
Entergy
New Orleans
Authorized
ROE Range:
10.7%
- 11.5%
(electric)
10.25%
-
11.25%
(gas)
Last
Filed
Rate
Base:
$0.3
billion
(electric)
$0.1
billion (gas)
Filed
7/08 based on 12/31/07 test year
|
Recent
activity: None.
Background: A
new three year FRP beginning with the 2009 test year was adopted in ENOI’s
rate case settled in April 2009. Key provisions include an
11.1% electric ROE and a +/- 40 basis point bandwidth and a 10.75% gas ROE
with a
+/-
50 basis point bandwidth. Earnings outside the bandwidth reset
to the midpoint ROE, with rates changing on a prospective basis depending
on whether ENOI is over or under-earning. The FRP also includes
a recovery mechanism for Council-approved capacity additions, plus
provisions for extraordinary cost changes and force
majeure. The FRP may be extended by the mutual agreement of
ENOI and the City Council of New Orleans (CCNO). The settlement
also implemented energy conservation and demand
programs. Effective June 1, 2009, pursuant to its April rate
case settlement, ENOI implemented a total electric bill reduction of $35.3
million, including conversion of the $10.6 million voluntary recovery
credit to a permanent reduction and complete realignment of Grand Gulf
recovery from fuel to base rates, and a $4.95 million gas rate increase.
On September 17, 2009, the City Council of New Orleans approved the Energy
Smart Resolution. Energy Smart is the energy efficiency program
that was filed pursuant to ENOI’s April 2009 rate case
settlement.
|
|
Entergy
Texas
Authorized
ROE: 10.0%
Last
Filed
Rate
Base:
$1.6
billion
Filed
12/09 based on 6/30/09 adjusted test year
|
Recent
activity: In November, a procedural schedule was
established in the Power Cost Recovery Factor (PCRF) proceeding with
hearings scheduled for February. On December 30, 2009, ETI
filed a rate case requesting a $198.7 million increase reflecting an 11.5%
ROE based on an adjusted June 30, 2009 test year. The filing
includes a proposed cost of service adjustment (COSA) rider with a three
year term beginning with the 2010 calendar test year. Key
provisions include a +/- 15 basis point bandwidth, with earnings outside
the bandwidth reset to the bottom or top of the band and rates changing
prospectively depending upon whether ETI is over or
under-earning. The annual change in revenue requirement is
limited to a percentage change in Consumer Price Index for urban areas,
and the FRP includes a provision for extraordinary events greater than $10
million per year which would be considered separately. The
filing also proposes a purchased power recovery rider, a competitive
generation service tariff and will establish test year baseline values to
be used in the transmission cost recovery factor rider authorized for use
by ETI in the 2009 legislative session. Finally, the rate case
included a $2.8 million revenue requirement to provide supplemental
funding for the decommissioning trust maintained for the 70% share of
River Bend for which Texas retail customers have responsibility, in
response to the NRC notification of a projected shortfall of
decommissioning funding assurance. A prehearing conference is
scheduled for February 3, 2010. Entergy Texas is negotiating
with parties to develop a procedural schedule that will provide a
Commission decision before the end of 2010.
Background: ETI
implemented a $46.7 million base rate increase pursuant to its black box
rate case settlement effective January 28, 2009, for usage beginning
December 19, 2008. ETI is in need of baseload resources, and
EAI recently elected to offer its wholesale baseload (WBL) capacity to the
Entergy system as a three-year cost based deal beginning January 1,
2010. ETI projects that the purchase can save customers in the
range of $9.5 to $16.0 million over three years. Given expected
savings, on September 18, 2009, ETI requested a cost recovery mechanism to
recover the annual capacity costs of approximately $26 million through the
PCRF until such time as the costs are reflected in rates after a general
rate case or the transaction expires, whichever occurs
first.
|
|
Storm Cost
Recovery: On November 6, 2009, ETI closed its
securitization financing. Entergy Texas Restoration Funding,
LLC issued $545.9 million in securitization bonds; $540.6 million for
system restoration costs, including adjusted carrying costs of $44.2
million, plus $5.3 million of up-front qualified
costs. Securitization proceeds were net of an estimated $70
million for projected insurance proceeds, subject to true-up, for which
ETI received $75.5 million in the third quarter of 2009 following
resolution of the Hurricane Ike claim.
Background: On
April 16, 2009, Governor Perry signed Senate Bill (SB) 769 enacting
evergreen securitization legislation for recovery of system restoration
costs. ETI initiated its storm recovery proceeding on April 21,
2009 seeking recovery of system restoration costs, and authorization to
recover in a financing proceeding to be subsequently filed, carrying costs
on the approved system restoration costs at ETI’s WACC. ETI
initiated its financing order request on July 16, 2009. On
August 5, 2009, ETI reached an unopposed “black box” settlement agreement
in the storm cost recovery proceeding and later that month reached a
unanimous settlement in its financing order docket, both of which were
subsequently approved by the PUCT.
|
|
|
Appendix
C: Regulatory Summary Table (continued)
|
|
|
Company/
Proceeding
|
Pending
Cases/Events
|
|
Wholesale
Regulation
|
|
|
System
Energy Resources, Inc.
|
Recent
activity: None.
Background: 10.94%
ROE approved by July 2001 FERC order.
Last Filed Rate Base:
$1.2 billion filed 12/31/09 in monthly cost of service
filing
|
|
System
Agreement
|
Recent
activity: On November 19, 2009, FERC accepted notices of
cancellation and determined EAI and EMI are permitted to withdraw from the
System Agreement following the 96 month notice period without payment of a
fee or being required to otherwise compensate the remaining Entergy
Operating Companies as a result of withdrawal. FERC stated it
expected Entergy and all interested parties to move forward and develop
details of all needed successor arrangements and encouraged Entergy to
file its Section 205 filing for post 2013 arrangements as soon as
possible. With the certainty provided by the FERC order,
Entergy is again moving forward with further development of successor
arrangements. Efforts will be pursued in parallel with
evaluation by the Entergy Regional State Committee (E-RSC) of the
Southwest Power Pool Regional Transmission Organization (SPP RTO) and
modified Independent Coordinator of Transmission (ICT)
alternatives. EAI also continues to evaluate systems,
facilities and resources necessary to operate the generation fleet on a
stand alone basis. The LPSC and CCNO have requested rehearing
of the FERC’s decision.
On
December 17, 2009, FERC set a paper hearing for the appropriateness of
refunds resulting from changes in the treatment of interruptible load in
the allocation of capacity costs by the Operating
Companies. FERC also deferred further action until resolution
of the paper hearing on the question of whether it provided sufficient
rationale for not ordering refunds, and whether it impermissibly delayed
implementation of the bandwidth remedy.
On
January 11, 2010, FERC issued its decision in the first bandwidth
proceeding, both affirming and overturning certain ALJ
rulings. FERC’s conclusion related to a 1999 wholesale contract
with AmerenUE did not permit EAI to recover a portion of its bandwidth
payment from AmerenUE, resulting in EAI recording a regulatory charge
during fourth quarter 2009. The Operating Companies continue to
review the decision and expect to file a request for rehearing /
clarification on certain issues. On that date, FERC also issued
a decision affirming the ALJ’s ruling that certain revisions to the
bandwidth formula proposed by ESI on behalf of the Operating Companies in
March of 2007 were just and reasonable.
Background: The
System Agreement case addresses the allocation of production costs among
the utility Operating Companies. In June 2005, the FERC issued
its decision and established a bandwidth of +/- 11% to reallocate
production costs and ordered that this approach be applied
prospectively. In December 2005, FERC established, among other
things, that 1) the bandwidth would be applied to calendar year 2006
actual production costs and 2) 2007 would be the first possible year of
payments among Entergy’s Operating Companies. The orders were
appealed and the DC Circuit remanded to the FERC for reconsideration of
the FERC's conclusion it did not have the authority to order refunds and
the decision to delay the implementation of the bandwidth
remedy. The remand is pending at FERC. Oral
arguments were held on May 8, 2009 on the LPSC’s DC Circuit appeal of FERC
Orders approving the Operating Companies compliance filing implementing
the bandwidth remedy. On July 6, 2009, the DC Circuit denied
the LPSC’s appeal.
The
Entergy Operating Companies submitted bandwidth filings for the calendar
years 2006 through 2008 production costs. The calendar year
2008 filing indicates a payment from EAI in the amount of $390 million
collectively to EGSL, ETI, ELL and EMI. On September 23, 2008,
the ALJ issued a decision regarding the initial bandwidth proceeding
related to calendar year 2006 production costs, that concluded that, with
one exception, the Operating Company calculation was appropriate and that
the Operating Companies' production costs were prudently incurred. The one
exception would require the Operating Companies to calculate nuclear
depreciation / decommissioning for each facility based on the NRC license
life. On September 19, 2008, FERC also issued an order on
rehearing in the proceeding involving the exclusion of interruptible loads
from certain System Agreement calculations that concluded that FERC had
authority to order refunds and that refunds were
appropriate. The APSC and the Operating Companies appealed the
FERC's orders to the DC Circuit.
On
September 10, 2009, the ALJ issued its initial decision regarding the 2007
production cost bandwidth filing that concluded, with two exceptions, the
Operating Company calculation was appropriate and the production costs
were prudently incurred. The two exceptions related to
depreciation expense for which new studies are needed and accumulated
deferred income tax related to the Waterford 3 sale-leaseback that should
not have been excluded from the bandwidth calculation. Parties
have since filed briefs on exceptions to the ALJ decision with the
FERC. In addition, the FERC set the 2008 production cost
bandwidth filing for hearing in April 2010.
The
System Agreement has been and continues to be the subject of ongoing
litigation. As a result, EAI and EMI submitted their eight year
notices to withdraw from the System Agreement in December 2005 and
November 2007, respectively, and on February 2, 2009 filed with the FERC
their notices of cancellation of their respective System Agreement rate
schedules, effective December 2013 and November 2015,
respectively. EAI and EMI requested FERC issue a decision on
the notices of cancellation. The Operating Companies are
considering a Successor Arrangement for the System
Agreement. Further progress on a proposed framework for a
Successor Arrangement to the System Agreement could be stalled until FERC
resolves EAI’s and EMI’s notices of cancellation filing made February 2,
2009. Given EAI must take action well before its termination
date to prepare to act as a stand-alone utility in the event successor
arrangements are not implemented, EAI reported the results of a related
study to the APSC in September 2009. Total estimated cost to
establish the systems and staff the organizations to perform the necessary
functions for a stand-alone EAI operation are estimated at approximately
$23 million, including $18 million to establish generation-related
functionality and $5 million to modify the transmission
system. Incremental costs for ongoing staffing and systems
costs are estimated at approximately $8 million. Cost and
implementation schedule estimates will continue to be re-evaluated and
refined as additional, more detailed analysis is completed. EAI
expects it will take approximately two years to implement stand-alone
operations for EAI.
|
|
Appendix
C: Regulatory Summary Table (continued)
|
|
|
Company/
Proceeding
|
Pending
Cases/Events
|
|
Wholesale
Regulation
|
|
|
Independent
Coordinator of Transmission
Authorized
ROE: 11.0% (q)
Last
Filed
Rate
Base:
$2.1
billion (r)
Filed
5/09 based on 12/31/08
test
year
|
Recent
activity: Representatives from all of the Entergy
Operating Company retail regulators formed the E-RSC to consider several
of the issues related to the Entergy transmission system and conducted a
preliminary meeting on October 12, 2009. In its November 17,
2009 FERC filing, in anticipation of the expiration of the initial term of
the ICT, a process was proposed for the evaluation of modifications to, or
the replacement of, the current ICT and Weekly Procurement Process (WPP)
arrangements. The process will facilitate review by the FERC,
Entergy’s retail regulators, and interested stakeholders of two primary
alternatives; 1) the adoption of certain modifications to the current ICT
arrangements, or 2) a transition to membership in the SPP
RTO. A critical factor in the Operating Companies’ proposal
will be the opinion and recommendation of the newly formed
E-RSC. The Utility Operating Companies expect that the E-RSC
will rely heavily on the cost-benefit analysis that is being jointly
sponsored by the E-RSC and FERC that will compare the current ICT
arrangement to joining SPP. The target date for completion of
the cost-benefit analysis is third quarter 2010. In addition,
the E-RSC is currently considering potential modifications to the ICT
arrangement, including, among others, providing the E-RSC with authority
(upon a unanimous vote) to propose modifications to the cost allocation
policy for transmission upgrades and the ability to add projects to the
Operating Companies’ transmission construction plan. Given the
timing required to complete this work, an extension of the ICT for some
period will likely be required under either scenario being
considered. If the SPP RTO is ultimately deemed the preferred
alternative, SPP has indicated the implementation process may take at
least 12-18 months after a decision is made. While alternatives
are being explored, Entergy has already taken the voluntary step to more
closely align its transmission planning criteria with the anticipated
modifications to the NERC planning standards. Entergy believes
that the current ICT arrangements have produced benefits, and, if modified
as a result of this process, can continue to benefit customers and
competition. The SPP RTO alternative also has the potential to
produce benefits. The progress of cost-benefit analysis will be
closely monitored, including its treatment of the costs associated with
any socialization of transmission upgrades constructed to integrate wind
development.
Background: In
November 2006, the Utility Operating Companies installed SPP as their ICT
with an initial term of four years unless Entergy files and the FERC
approves an extension beyond that four year period. The ICT did
not transfer control of the transmission system but rather vested the ICT
with responsibility, among others, for granting or denying transmission
service, administering the OASIS node, developing a base plan for the
transmission system including a determination on whether costs of
transmission upgrades should be rolled into transmission rates or directly
assigned to customers requesting or causing the upgrade, serving as
reliability coordinator the transmission system and overseeing the
WPP.
|
(q) Applies to sales made
under Entergy’s FERC jurisdictional Open Access Transmission
Tariff.
(r) Reflects transmission rate
base in Entergy’s FERC OATT filing, for which such amounts are also reflected in
the rate base figures for each of the Operating Companies shown
above.
|
D.
|
Financial Performance
Measures and Historical Performance
Measures
|
Appendix D-1 provides
comparative financial performance measures for the current
quarter. Appendix D-2 provides
historical financial performance measures and operating performance metrics for
the trailing eight quarters. Financial performance measures in both tables
include those calculated and presented in accordance with generally accepted
accounting principles (GAAP), as well as those that are considered non-GAAP
measures.
As-reported
measures are computed in accordance with GAAP as they include all components of
net income, including special items. Operational measures are
non-GAAP measures as they are calculated using operational net income, which
excludes the impact of special items. A reconciliation of operational
measures to as-reported measures is provided in Appendix
G.
|
Appendix
D-1: GAAP and Non-GAAP Financial Performance
Measures
|
||||
|
Fourth
Quarter 2009 vs. 2008
(see Appendix F for definitions of certain
measures)
|
||||
|
For
12 months ending December 31
|
2009
|
2008
|
Change
|
|
|
GAAP
Measures
|
||||
|
Return
on average invested capital – as-reported
|
7.7%
|
8.1%
|
(0.4)%
|
|
|
Return
on average common equity – as-reported
|
14.9%
|
15.4%
|
(0.5)%
|
|
|
Net
margin – as-reported
|
11.5%
|
9.3%
|
2.2%
|
|
|
Cash
flow interest coverage
|
6.1
|
6.5
|
(0.4)
|
|
|
Book
value per share
|
$45.54
|
$42.07
|
$3.47
|
|
|
End
of period shares outstanding (millions)
|
189.1
|
189.4
|
(0.3)
|
|
|
Non-GAAP
Measures
|
||||
|
Return
on average invested capital – operational
|
8.1%
|
8.4%
|
(0.3)%
|
|
|
Return
on average common equity – operational
|
15.7%
|
16.1%
|
(0.4)%
|
|
|
Net
margin – operational
|
12.1%
|
9.7%
|
2.4%
|
|
|
As
of December 31 ($ in millions)
|
2009
|
2008
|
Change
|
|
|
GAAP
Measures
|
||||
|
Cash
and cash equivalents
|
1,710
|
1,920
|
(210)
|
|
|
Revolver
capacity
|
1,464
|
645
|
819
|
|
|
Total
debt
|
12,014
|
12,279
|
(265)
|
|
|
Debt
to capital ratio
|
57.4%
|
59.7%
|
(2.3)%
|
|
|
Off-balance
sheet liabilities:
|
||||
|
Debt
of joint ventures – Entergy’s share
|
116
|
125
|
(9)
|
|
|
Leases
– Entergy’s share
|
530
|
449
|
81
|
|
|
Total
off-balance sheet liabilities
|
646
|
574
|
72
|
|
|
Non-GAAP
Measures
|
||||
|
Total
gross liquidity
|
3,174
|
2,565
|
609
|
|
|
Net
debt to net capital ratio
|
53.6%
|
55.6%
|
(2.0)%
|
|
|
Net
debt ratio including off-balance sheet liabilities
|
55.1%
|
56.9%
|
(1.8)%
|
|
|
Appendix
D-2: Historical Performance Measures
(see
Appendix
F
for definitions of measures)
|
|||||||||||||||
|
1Q08
|
2Q08
|
3Q08
|
4Q08
|
1Q09
|
2Q09
|
3Q09
|
4Q09
|
08YTD
|
09YTD
|
||||||
|
Financial
|
|||||||||||||||
|
EPS
– as-reported ($)
|
1.56
|
1.37
|
2.41
|
0.89
|
1.20
|
1.14
|
2.32
|
1.64
|
6.20
|
6.30
|
|||||
|
Less
– special items ($)
|
0.00
|
(0.09)
|
(0.09)
|
(0.10)
|
(0.09)
|
(0.09)
|
(0.08)
|
(0.11)
|
(0.31)
|
(0.37)
|
|||||
|
EPS
– operational ($)
|
1.56
|
1.46
|
2.50
|
0.99
|
1.29
|
1.23
|
2.40
|
1.75
|
6.51
|
6.67
|
|||||
|
Trailing
Twelve Months
|
|||||||||||||||
|
ROIC
– as-reported (%)
|
8.8
|
8.6
|
8.1
|
8.1
|
7.6
|
7.5
|
7.1
|
7.7
|
|||||||
|
ROIC
– operational (%)
|
9.0
|
8.8
|
8.4
|
8.4
|
8.0
|
7.8
|
7.5
|
8.1
|
|||||||
|
ROE
– as-reported (%)
|
15.9
|
16.3
|
15.6
|
15.4
|
14.1
|
13.7
|
13.2
|
14.9
|
|||||||
|
ROE
– operational (%)
|
16.3
|
17.0
|
16.4
|
16.1
|
15.0
|
14.6
|
14.1
|
15.7
|
|||||||
|
Cash
flow interest coverage
|
4.9
|
5.0
|
7.0
|
6.5
|
6.5
|
6.7
|
5.5
|
6.1
|
|||||||
|
Debt
to capital ratio (%)
|
58.6
|
60.7
|
60.4
|
59.7
|
57.4
|
55.9
|
56.7
|
57.4
|
|||||||
|
Net
debt/net capital ratio (%)
|
56.5
|
58.3
|
54.9
|
55.6
|
53.4
|
53.0
|
54.2
|
53.6
|
|||||||
|
Utility
|
|||||||||||||||
|
GWh
billed
|
|||||||||||||||
|
Residential
|
8,011
|
7,372
|
10,671
|
6,992
|
7,893
|
7,100
|
11,213
|
7,421
|
33,047
|
33,626
|
|||||
|
Commercial
& Gov’t
|
6,807
|
7,275
|
8,646
|
6,992
|
6,756
|
7,095
|
8,794
|
7,240
|
29,719
|
29,884
|
|||||
|
Industrial
|
9,377
|
9,730
|
10,110
|
8,626
|
8,139
|
8,790
|
9,473
|
9,235
|
37,843
|
35,638
|
|||||
|
Wholesale
|
1,290
|
1,440
|
1,431
|
1,240
|
1,387
|
1,313
|
1,164
|
998
|
5,401
|
4,862
|
|||||
|
O&M
expense/MWh
|
$17.26
|
$19.48
|
$14.43
|
$23.95
|
$18.51
|
$20.96
|
$15.77
|
$20.18
|
$18.48
|
$18.67
|
|||||
|
Reliability
|
|||||||||||||||
|
SAIFI
|
1.9
|
1.9
|
1.9
|
1.9
|
1.8
|
1.7
|
1.7
|
1.8
|
1.9
|
1.8
|
|||||
|
SAIDI
|
191
|
215
|
227
|
216
|
208
|
194
|
203
|
210
|
216
|
210
|
|||||
|
Nuclear
|
|||||||||||||||
|
Net
MW in operation
|
4,998
|
4,998
|
4,998
|
4,998
|
4,998
|
4,998
|
4,998
|
4,998
|
4,998
|
4,998
|
|||||
|
Avg.
realized price per MWh
|
$61.47
|
$58.22
|
$61.59
|
$56.69
|
$63.84
|
$59.22
|
$61.70
|
$59.43
|
$59.51
|
$61.07
|
|||||
|
Production
cost/MWh (s)
|
$19.98
|
$23.11
|
$21.77
|
$22.77
|
$23.14
|
$24.30
|
$22.57
|
$23.20
|
$21.88
|
$23.26
|
|||||
|
Non-fuel
O&M expense/ purchased power per MWh (s)
|
$20.20
|
$23.42
|
$21.19
|
$23.06
|
$22.44
|
$25.33
|
$22.11
|
$23.60
|
$21.95
|
$23.30
|
|||||
|
GWh
billed
|
10,760
|
10,145
|
10,316
|
10,489
|
10,074
|
8,980
|
10,876
|
11,052
|
41,710
|
40,981
|
|||||
|
Capacity
factor (%)
|
97
|
92
|
95
|
94
|
92
|
81
|
100
|
99
|
95
|
93
|
|||||
|
|
(s)
2009 excludes the effect of the non-utility nuclear spin-off dis-synergies
special item at Entergy Nuclear.
|
|
E.
|
Planned Capital
Expenditures
|
The
capital plan for 2010 through 2012 anticipates $7.1 billion for investment,
including $2.8 billion of maintenance capital, as shown in Appendix
E. The remaining $4.3 billion is for specific investments (as well as
other initiatives) such as:
|
·
|
Utility: the
Utility’s portfolio transformation strategy including the 580 MW Acadia
Unit 2 purchase for $300 million, or $517/kW, pending regulatory approval
and assuming closing by March 31, 2011, with a total expected cost of $329
million (or $567/kW) including planned plant upgrades, transaction costs,
and contingencies (but excluding transmission upgrades); the steam
generator replacement at Entergy Louisiana’s Waterford 3 nuclear unit; an
approximate 178 MW uprate project at Grand Gulf; transmission upgrades and
spending to comply with revised NERC Transmission Planning rules and NRC
security requirements. The three year capital plan also
includes $420 million for the installation of scrubbers and low NOx
burners at White Bluff which could ultimately be delayed pending the
outcome of the variance request from the October 2013 compliance date as
discussed more fully in Appendix E.
|
|
·
|
Entergy
Nuclear: dry cask storage, nuclear license renewal
efforts, component replacement across the fleet, NYPA value sharing, the
Indian Point Independent Safety Evaluation and spending to comply with
revised NRC security requirements.
|
|
Appendix
E: 2010 – 2012 Planned Capital Expenditures
|
||||
|
($ in millions) – Prepared February
2010
|
||||
|
2010
|
2011
|
2012
|
Total
|
|
|
Maintenance
capital
|
||||
|
Utility,
Parent & Other (including Non-Nuclear
Wholesale Assets)
|
785
|
790
|
830
|
2,405
|
|
Entergy
Nuclear
|
92
|
140
|
123
|
355
|
|
Subtotal
|
877
|
930
|
953
|
2,760
|
|
Other
capital commitments
|
||||
|
Utility,
Parent & Other (including Non-Nuclear
Wholesale Assets)
|
991
|
1,578
|
926
|
3,495
|
|
Entergy
Nuclear
|
349
|
220
|
219
|
788
|
|
Subtotal
|
1,340
|
1,798
|
1,145
|
4,283
|
|
Total
Planned Capital Expenditures
|
2,217
|
2,728
|
2,098
|
7,043
|
|
Storm
Capital
|
35
|
13
|
13
|
61
|
|
Total
Planned Capital Expenditures Including Storm Capital
|
2,252
|
2,741
|
2,111
|
7,104
|
|
F.
|
Definitions
|
Appendix
F provides definitions of certain operational performance measures, as well as
GAAP and non-GAAP financial measures, all of which are referenced in this
release.
|
Appendix
F: Definitions of Operational Performance Measures and GAAP and
Non-GAAP Financial Measures
|
|
|
Utility
|
|
|
GWh
billed
|
Total
number of GWh billed to all retail and wholesale
customers
|
|
Operation
& maintenance expense
|
Operation,
maintenance and refueling expenses per MWh of billed sales, excluding
fuel
|
|
SAIFI
|
System
average interruption frequency index; average number per customer per
year, excluding the impact of major storm activity
|
|
SAIDI
|
System
average interruption duration index; average minutes per customer per
year, excluding the impact of major storm activity
|
|
Number
of customers
|
Number
of customers at end of period
|
|
Competitive
Businesses
|
|
|
Planned
TWh of generation
|
Amount
of output expected to be generated by Entergy Nuclear for nuclear units
considering plant operating characteristics, outage schedules, and
expected market conditions which impact dispatch, assuming timely renewal
of plant operating licenses
|
|
Percent
of planned generation sold
forward
|
Percent
of planned generation output sold forward under contracts, forward
physical contracts, forward financial contracts or options (consistent
with assumptions used in earnings guidance) that may or may not require
regulatory approval
|
|
Unit-contingent
|
Transaction
under which power is supplied from a specific generation asset; if the
asset is not operating, seller is generally not liable to buyer for any
damages
|
|
Unit-contingent
with availability
guarantees
|
Transaction
under which power is supplied from a specific generation asset; if the
asset is not operating, seller is generally not liable to buyer for any
damages, unless the actual availability over a specified period of time is
below an availability threshold specified in the
contract
|
|
Firm
LD
|
Transaction
that requires receipt or delivery of energy at a specified delivery point
(usually at a market hub not associated with a specific asset) or settles
financially on notional quantities; if a party fails to deliver or receive
energy, defaulting party must compensate the other party as specified in
the contract
|
|
Planned
net MW in operation
|
Amount
of capacity to be available to generate power considering uprates planned
to be completed within the calendar year
|
|
Bundled
energy & capacity contract
|
A
contract for the sale of installed capacity and related energy, priced per
megawatt-hour sold
|
|
Capacity
contract
|
A
contract for the sale of the installed capacity product in regional
markets managed by ISO New England and the New York Independent System
Operator
|
|
Average
contract price per MWh or per kW per month
|
Price
at which generation output and/or capacity is expected to be sold to third
parties, given existing contract or option exercise prices based on
expected dispatch or capacity, excluding the revenue associated with the
amortization of the below-market PPA for Palisades
|
|
Average
contract revenue per MWh
|
Price
at which the combination of generation output and capacity are expected to
be sold to third parties, given existing contract or option exercise
prices based on expected dispatch, excluding the revenue associated with
the amortization of the below-market PPA for Palisades
|
|
Entergy
Nuclear
|
|
|
Net
MW in operation
|
Installed
capacity owned and operated by Entergy Nuclear
|
|
Average
realized price per MWh
|
As-reported
revenue per MWh billed for all non-utility nuclear operations, excluding
revenue from the amortization of the Palisades below-market Power Purchase
Agreement
|
|
Production
cost per MWh
|
Fuel
and non-fuel operation and maintenance expenses according to accounting
standards that directly relate to the production of electricity per
MWh
|
|
Non-fuel
O&M expense/purchased power per MWh
|
Operation,
maintenance and refueling expenses and purchased power per MWh billed,
excluding fuel
|
|
GWh
billed
|
Total
number of GWh billed to all customers
|
|
Capacity
factor
|
Normalized
percentage of the period that the plants generate power
|
|
Refueling
outage duration
|
Number
of days lost for scheduled refueling outage during the
period
|
Financial
measures defined in the below table include measures prepared in accordance with
generally accepted accounting principles, (GAAP), as well as non-GAAP
measures. Non-GAAP measures are included in this release in order to
provide metrics that remove the effect of less routine financial impacts from
commonly used financial metrics.
|
Appendix
F: Definitions of Operational Performance Measures and GAAP and
Non-GAAP Financial Measures (continued)
|
|
|
Financial
Measures – GAAP
|
|
|
Return
on average invested capital – as-reported
|
12-months
rolling net income attributable to Entergy Corporation (Net Income)
adjusted to include preferred dividends and tax-effected interest expense
divided by average invested capital
|
|
Return
on average common equity – as-reported
|
12-months
rolling Net Income divided by average common equity
|
|
Net
margin – as-reported
|
12-months
rolling Net Income divided by 12 months rolling revenue
|
|
Cash
flow interest coverage
|
12-months
cash flow from operating activities plus 12-months rolling interest paid,
divided by interest expense
|
|
Book
value per share
|
Common
equity divided by end of period shares outstanding
|
|
Revolver
capacity
|
Amount
of undrawn capacity remaining on corporate and subsidiary
revolvers
|
|
Total
debt
|
Sum
of short-term and long-term debt, notes payable, capital leases, and
preferred stock with sinking fund on the balance sheet less non-recourse
debt, if any
|
|
Debt
of joint ventures (Entergy’s share)
|
Debt
issued by Non-Nuclear Wholesale Assets business joint
ventures
|
|
Leases
(Entergy’s share)
|
Operating
leases held by subsidiaries capitalized at implicit interest
rate
|
|
Debt
to capital
|
Gross
debt divided by total capitalization
|
|
Financial
Measures – Non-GAAP
|
|
|
Operational
earnings
|
As-reported
Net Income applicable to common stock adjusted to exclude the impact of
special items
|
|
Return
on average invested capital – operational
|
12-months
rolling operational Net Income adjusted to include preferred dividends and
tax-effected interest expense divided by average invested
capital
|
|
Return
on average common equity – operational
|
12-months
rolling operational Net Income divided by average common
equity
|
|
Net
margin – operational
|
12-months
rolling operational Net Income divided by 12 months rolling
revenue
|
|
Total
gross liquidity
|
Sum
of cash and revolver capacity
|
|
Net
debt to net capital
|
Gross
debt less cash and cash equivalents divided by total capitalization less
cash and cash equivalents
|
|
Net
debt including off-balance sheet liabilities
|
Sum
of gross debt and off-balance sheet debt less cash and cash equivalents
divided by sum of total capitalization and off-balance sheet debt less
cash and cash equivalents
|
|
G.
|
GAAP to Non-GAAP
Reconciliations
|
Appendix G-1 and
Appendix G-2
provide reconciliations of various non-GAAP financial measures disclosed in this
release to their most comparable GAAP measure.
|
Appendix
G-1: Reconciliation of GAAP to Non-GAAP Financial Measures – Return on
Equity, Return on Invested Capital and Net Margin
Metrics
|
||||||||
|
($
in millions)
|
||||||||
|
1Q08
|
2Q08
|
3Q08
|
4Q08
|
1Q09
|
2Q09
|
3Q09
|
4Q09
|
|
|
As-reported
Net Income-rolling 12 months (A)
|
1,231
|
1,235
|
1,244
|
1,221
|
1,147
|
1,103
|
1,088
|
1,231
|
|
Preferred
dividends
|
24
|
23
|
21
|
20
|
20
|
20
|
20
|
20
|
|
Tax
effected interest expense
|
396
|
390
|
375
|
374
|
366
|
368
|
361
|
351
|
|
As-reported
Net Income, rolling 12 months including preferred dividends and tax
effected interest expense (B)
|
1,651
|
1,648
|
1,640
|
1,615
|
1,533
|
1,491
|
1,469
|
1,602
|
|
Special
items in prior quarters
|
(32)
|
(32)
|
(50)
|
(35)
|
(55)
|
(54)
|
(54)
|
(49)
|
|
Special
items in current quarter
|
||||||||
|
Nuclear
spin-off costs
|
(18)
|
(17)
|
(20)
|
(17)
|
(17)
|
(15)
|
(21)
|
|
|
Total special items
(C)
|
(32)
|
(50)
|
(67)
|
(55)
|
(72)
|
(71)
|
(69)
|
(71)
|
|
Operational
earnings, rolling 12 months including preferred dividends and tax effected
interest expense (B-C)
|
1,683
|
1,698
|
1,707
|
1,670
|
1,605
|
1,562
|
1,538
|
1,673
|
|
Operational
earnings, rolling 12 months (A-C)
|
1,263
|
1,285
|
1,311
|
1,276
|
1,219
|
1,174
|
1,157
|
1,302
|
|
Average
invested capital (D)
|
18,790
|
19,244
|
20,236
|
19,927
|
20,126
|
19,995
|
20,629
|
20,748
|
|
Average
common equity (E)
|
7,756
|
7,555
|
7,973
|
7,915
|
8,152
|
8,045
|
8,230
|
8,290
|
|
Operating
revenues (F)
|
11,655
|
12,150
|
12,825
|
13,094
|
13,018
|
12,275
|
11,248
|
10,746
|
|
ROIC
– as-reported % (B/D)
|
8.8
|
8.6
|
8.1
|
8.1
|
7.6
|
7.5
|
7.1
|
7.7
|
|
ROIC
– operational % ((B-C)/D)
|
9.0
|
8.8
|
8.4
|
8.4
|
8.0
|
7.8
|
7.5
|
8.1
|
|
ROE
– as-reported % (A/E)
|
15.9
|
16.3
|
15.6
|
15.4
|
14.1
|
13.7
|
13.2
|
14.9
|
|
ROE
– operational % ((A-C)/E)
|
16.3
|
17.0
|
16.4
|
16.1
|
15.0
|
14.6
|
14.1
|
15.7
|
|
Net
margin – as-reported % (A/F)
|
10.6
|
10.2
|
9.7
|
9.3
|
8.8
|
9.0
|
9.7
|
11.5
|
|
Net
margin – operational % ((A-C)/F)
|
10.8
|
10.6
|
10.2
|
9.7
|
9.4
|
9.6
|
10.3
|
12.1
|
|
Appendix
G-2: Reconciliation of GAAP to Non-GAAP Financial Measures – Credit and
Liquidity Metrics
|
||||||||
|
($
in millions)
|
||||||||
|
1Q08
|
2Q08
|
3Q08
|
4Q08
|
1Q09
|
2Q09
|
3Q09
|
4Q09
|
|
|
Gross
debt (A)
|
11,292
|
11,768
|
12,656
|
12,279
|
12,034
|
11,510
|
11,522
|
12,014
|
|
Less
cash and cash equivalents (B)
|
916
|
1,086
|
2,556
|
1,920
|
1,803
|
1,281
|
1,131
|
1,710
|
|
Net
debt (C)
|
10,376
|
10,682
|
10,100
|
10,359
|
10,231
|
10,229
|
10,391
|
10,304
|
|
Total
capitalization (D)
|
19,276
|
19,401
|
20,944
|
20,557
|
20,975
|
20,588
|
20,315
|
20,939
|
|
Less
cash and cash equivalents (B)
|
916
|
1,086
|
2,556
|
1,920
|
1,803
|
1,281
|
1,131
|
1,710
|
|
Net
capital (E)
|
18,360
|
18,315
|
18,388
|
18,637
|
19,172
|
19,307
|
19,184
|
19,229
|
|
Debt
to capital ratio % (A/D)
|
58.6
|
60.7
|
60.4
|
59.7
|
57.4
|
55.9
|
56.7
|
57.4
|
|
Net
debt to net capital ratio % (C/E)
|
56.5
|
58.3
|
54.9
|
55.6
|
53.4
|
53.0
|
54.2
|
53.6
|
|
Off-balance
sheet liabilities (F)
|
642
|
638
|
637
|
574
|
573
|
569
|
567
|
646
|
|
Net
debt to net capital ratio including off-balance sheet liabilities %
((C+F)/(E+F))
|
58.0
|
59.7
|
56.4
|
56.9
|
54.7
|
54.3
|
55.5
|
55.1
|
|
Revolver
capacity (G)
|
1,503
|
826
|
374
|
645
|
725
|
1,585
|
1,647
|
1,464
|
|
Gross
liquidity (B+G)
|
2,419
|
1,912
|
2,930
|
2,565
|
2,528
|
2,866
|
2,778
|
3,174
|
Entergy
Corporation’s common stock is listed on the New York and Chicago exchanges under
the symbol “ETR”.
Additional
investor information can be accessed on-line at
www.entergy.com/investor_relations
**********************************************************************************************************************
In this
news release, and from time to time, Entergy Corporation makes certain
“forward-looking statements” within the meaning of the Private Securities
Litigation Reform Act of 1995. Except to the extent required by the
federal securities laws, Entergy undertakes no obligation to publicly update or
revise any forward-looking statements, whether as a result of new information,
future events, or otherwise.
Forward-looking
statements involve a number of risks and uncertainties. There are
factors that could cause actual results to differ materially from those
expressed or implied in the forward-looking statements, including (a) those
factors discussed in (i) Entergy’s Form 10-K for the year ended December 31,
2008, (ii) Entergy’s Form 10-Q for the quarters ended March 31, June 30 and
September 30, 2009, and (iii) Entergy’s other reports and filings made under the
Securities Exchange Act of 1934, (b) the uncertainties associated with efforts
to remediate the effects of Hurricanes Gustav and Ike and the January 2009
Arkansas ice storm and recovery of costs associated with restoration, and (c)
the following transactional factors (in addition to others described elsewhere
in this news release and in subsequent securities filings): (i) risks inherent
in the contemplated spin-off, joint venture and related transactions (including
the level of debt to be incurred by Enexus Energy Corporation and the terms and
costs related thereto), (ii) legislative and regulatory actions, and (iii)
conditions of the capital markets during the periods covered by the
forward-looking statements. Entergy cannot provide any assurances
that the spin-off or any of the proposed transactions related thereto will be
completed, nor can it give assurances as to the terms on which such transactions
will be consummated. The transaction is subject to certain conditions
precedent, including regulatory approvals and the final approval by the Board of
Directors of Entergy.
|
VI.
|
Financial
Statements
|
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Balance Sheet
|
||||||||||||||||
|
December
31, 2009
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
ASSETS
|
||||||||||||||||
|
CURRENT
ASSETS
|
||||||||||||||||
|
Cash
and cash equivalents:
|
||||||||||||||||
|
Cash
|
$ | 82,155 | $ | 3,706 | $ | - | $ | 85,861 | ||||||||
|
Temporary
cash investments
|
1,208,025 | 415,665 | - | 1,623,690 | ||||||||||||
|
Total
cash and cash equivalents
|
1,290,180 | 419,371 | - | 1,709,551 | ||||||||||||
|
Securitization
recovery trust account
|
13,098 | - | - | 13,098 | ||||||||||||
|
Notes
receivable
|
203,916 | 1,760,420 | (1,964,336 | ) | - | |||||||||||
|
Accounts
receivable:
|
||||||||||||||||
|
Customer
|
331,936 | 221,756 | - | 553,692 | ||||||||||||
|
Allowance
for doubtful accounts
|
(27,428 | ) | (203 | ) | - | (27,631 | ) | |||||||||
|
Associated
companies
|
25,381 | 117,483 | (142,864 | ) | - | |||||||||||
|
Other
|
137,968 | 14,335 | - | 152,303 | ||||||||||||
|
Accrued
unbilled revenues
|
302,463 | - | - | 302,463 | ||||||||||||
|
Total
accounts receivable
|
770,320 | 353,371 | (142,864 | ) | 980,827 | |||||||||||
|
Deferred
fuel costs
|
126,798 | - | - | 126,798 | ||||||||||||
|
Accumulated
deferred income taxes
|
- | - | - | - | ||||||||||||
|
Fuel
inventory - at average cost
|
194,827 | 2,028 | - | 196,855 | ||||||||||||
|
Materials
and supplies - at average cost
|
526,543 | 299,159 | - | 825,702 | ||||||||||||
|
Deferred
nuclear refueling outage costs
|
106,428 | 118,862 | - | 225,290 | ||||||||||||
|
System
agreement cost equalization
|
70,000 | - | - | 70,000 | ||||||||||||
|
Prepayments
and other
|
79,084 | 417,960 | (111,004 | ) | 386,040 | |||||||||||
|
TOTAL
|
3,381,194 | 3,371,171 | (2,218,204 | ) | 4,534,161 | |||||||||||
|
OTHER
PROPERTY AND INVESTMENTS
|
||||||||||||||||
|
Investment
in affiliates - at equity
|
6,871,604 | 1,042,565 | (7,874,589 | ) | 39,580 | |||||||||||
|
Decommissioning
trust funds
|
1,325,863 | 1,885,320 | - | 3,211,183 | ||||||||||||
|
Non-utility
property - at cost (less accumulated depreciation)
|
239,956 | 7,708 | - | 247,664 | ||||||||||||
|
Other
|
110,645 | 9,628 | - | 120,273 | ||||||||||||
|
TOTAL
|
8,548,068 | 2,945,221 | (7,874,589 | ) | 3,618,700 | |||||||||||
|
PROPERTY,
PLANT, AND EQUIPMENT
|
||||||||||||||||
|
Electric
|
32,446,351 | 3,897,421 | - | 36,343,772 | ||||||||||||
|
Property
under capital lease
|
783,096 | - | - | 783,096 | ||||||||||||
|
Natural
gas
|
314,256 | - | - | 314,256 | ||||||||||||
|
Construction
work in progress
|
1,133,823 | 413,496 | - | 1,547,319 | ||||||||||||
|
Nuclear
fuel under capital lease
|
527,521 | - | - | 527,521 | ||||||||||||
|
Nuclear
fuel
|
219,317 | 520,510 | - | 739,827 | ||||||||||||
|
TOTAL
PROPERTY, PLANT AND EQUIPMENT
|
35,424,364 | 4,831,427 | - | 40,255,791 | ||||||||||||
|
Less
- accumulated depreciation and amortization
|
16,159,041 | 707,348 | - | 16,866,389 | ||||||||||||
|
PROPERTY,
PLANT AND EQUIPMENT - NET
|
19,265,323 | 4,124,079 | - | 23,389,402 | ||||||||||||
|
DEFERRED
DEBITS AND OTHER ASSETS
|
||||||||||||||||
|
Regulatory
assets:
|
||||||||||||||||
|
SFAS
109 regulatory asset - net
|
619,500 | - | - | 619,500 | ||||||||||||
|
Other
regulatory assets
|
3,647,154 | - | - | 3,647,154 | ||||||||||||
|
Deferred
fuel costs
|
172,202 | - | - | 172,202 | ||||||||||||
|
Goodwill
|
374,099 | 3,073 | - | 377,172 | ||||||||||||
|
Other
|
649,258 | 873,457 | (516,409 | ) | 1,006,306 | |||||||||||
|
TOTAL
|
5,462,213 | 876,530 | (516,409 | ) | 5,822,334 | |||||||||||
| - | ||||||||||||||||
|
TOTAL
ASSETS
|
$ | 36,656,798 | $ | 11,317,001 | $ | (10,609,202 | ) | $ | 37,364,597 | |||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
| Entergy Corporation | ||||||||||||||||
| Consolidating Balance Sheet | ||||||||||||||||
| December 31, 2009 | ||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
| U.S. Utilities/ Parent & Other | Competitive Businesses |
Eliminations
|
Consolidated
|
|||||||||||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||
|
CURRENT
LIABILITIES
|
||||||||||||||||
|
Currently
maturing long-term debt
|
$ | 681,016 | $ | 30,941 | $ | - | $ | 711,957 | ||||||||
|
Notes
payable:
|
||||||||||||||||
|
Associated
companies
|
1,964,336 | - | (1,964,336 | ) | - | |||||||||||
|
Other
|
30,031 | - | - | 30,031 | ||||||||||||
|
Account
payable:
|
||||||||||||||||
|
Associated
companies
|
130,229 | 10,612 | (140,841 | ) | - | |||||||||||
|
Other
|
753,362 | 244,866 | - | 998,228 | ||||||||||||
|
Customer
deposits
|
323,092 | 250 | - | 323,342 | ||||||||||||
|
Taxes
accrued
|
107,944 | - | (107,944 | ) | - | |||||||||||
|
Accumulated
deferred income taxes
|
48,584 | - | - | 48,584 | ||||||||||||
|
Interest
accrued
|
191,375 | 908 | - | 192,283 | ||||||||||||
|
Deferred
fuel costs
|
219,639 | - | - | 219,639 | ||||||||||||
|
Obligations
under capital leases
|
212,496 | - | - | 212,496 | ||||||||||||
|
Pension
and other postretirement liabilities
|
49,912 | 5,119 | - | 55,031 | ||||||||||||
|
System
agreement cost equalization
|
187,204 | - | - | 187,204 | ||||||||||||
|
Other
|
54,279 | 163,983 | (3,060 | ) | 215,202 | |||||||||||
|
TOTAL
|
4,953,499 | 456,679 | (2,216,181 | ) | 3,193,997 | |||||||||||
|
NON-CURRENT
LIABILITIES
|
||||||||||||||||
|
Accumulated
deferred income taxes and taxes accrued
|
4,609,839 | 2,812,480 | - | 7,422,319 | ||||||||||||
|
Accumulated
deferred investment tax credits
|
308,395 | - | - | 308,395 | ||||||||||||
|
Obligations
under capital leases
|
354,233 | - | - | 354,233 | ||||||||||||
|
Other
regulatory liabilities
|
421,985 | - | - | 421,985 | ||||||||||||
|
Decommissioning
and retirement cost liabilities
|
1,618,845 | 1,320,694 | - | 2,939,539 | ||||||||||||
|
Accumulated
provisions
|
132,225 | 9,090 | - | 141,315 | ||||||||||||
|
Pension
and other postretirement liabilities
|
1,771,350 | 469,689 | - | 2,241,039 | ||||||||||||
|
Long-term
debt
|
10,549,181 | 156,557 | - | 10,705,738 | ||||||||||||
|
Other
|
451,438 | 786,443 | (526,547 | ) | 711,334 | |||||||||||
|
TOTAL
|
20,217,491 | 5,554,953 | (526,547 | ) | 25,245,897 | |||||||||||
|
Subsidiaries'
preferred stock without sinking fund
|
186,510 | 82,953 | (52,120 | ) | 217,343 | |||||||||||
|
EQUITY
|
||||||||||||||||
|
Common
Shareholders' Equity:
|
||||||||||||||||
|
Common
stock, $.01 par value, authorized 500,000,000 shares;
|
||||||||||||||||
|
issued
254,752,788 shares in 2009
|
2,163,815 | 982,040 | (3,143,307 | ) | 2,548 | |||||||||||
|
Paid-in
capital
|
8,915,541 | 1,882,103 | (5,427,602 | ) | 5,370,042 | |||||||||||
|
Retained
earnings
|
5,103,166 | 2,316,101 | 623,855 | 8,043,122 | ||||||||||||
|
Accumulated
other comprehensive income (loss)
|
(130,057 | ) | 54,872 | - | (75,185 | ) | ||||||||||
|
Less
- treasury stock, at cost (65,634,580 shares in 2009)
|
4,847,167 | 12,700 | (132,700 | ) | 4,727,167 | |||||||||||
|
Total
common shareholders' equity
|
11,205,298 | 5,222,416 | (7,814,354 | ) | 8,613,360 | |||||||||||
|
Subsidiaries'
preferred stock without sinking fund
|
94,000 | - | - | 94,000 | ||||||||||||
|
TOTAL
|
11,299,298 | 5,222,416 | (7,814,354 | ) | 8,707,360 | |||||||||||
|
TOTAL
LIABILITIES AND EQUITY
|
$ | 36,656,798 | $ | 11,317,001 | $ | (10,609,202 | ) | $ | 37,364,597 | |||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Balance Sheet
|
||||||||||||||||
|
December
31, 2008
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
ASSETS
|
||||||||||||||||
|
CURRENT
ASSETS
|
||||||||||||||||
|
Cash
and cash equivalents:
|
||||||||||||||||
|
Cash
|
$ | 110,203 | $ | 5,673 | $ | - | $ | 115,876 | ||||||||
|
Temporary
cash investments
|
1,355,498 | 449,117 | - | 1,804,615 | ||||||||||||
|
Total
cash and cash equivalents
|
1,465,701 | 454,790 | - | 1,920,491 | ||||||||||||
|
Securitization
recovery trust account
|
12,062 | - | - | 12,062 | ||||||||||||
|
Notes
receivable
|
99,330 | 1,333,123 | (1,432,453 | ) | - | |||||||||||
|
Accounts
receivable:
|
||||||||||||||||
|
Customer
|
523,348 | 210,856 | - | 734,204 | ||||||||||||
|
Allowance
for doubtful accounts
|
(25,610 | ) | - | - | (25,610 | ) | ||||||||||
|
Associated
companies
|
139,912 | 84,341 | (224,253 | ) | - | |||||||||||
|
Other
|
179,207 | 27,420 | - | 206,627 | ||||||||||||
|
Accrued
unbilled revenues
|
282,914 | - | - | 282,914 | ||||||||||||
|
Total
accounts receivable
|
1,099,771 | 322,617 | (224,253 | ) | 1,198,135 | |||||||||||
|
Deferred
fuel costs
|
167,092 | - | - | 167,092 | ||||||||||||
|
Accumulated
deferred income taxes
|
7,307 | - | - | 7,307 | ||||||||||||
|
Fuel
inventory - at average cost
|
213,313 | 2,832 | - | 216,145 | ||||||||||||
|
Materials
and supplies - at average cost
|
505,720 | 270,450 | - | 776,170 | ||||||||||||
|
Deferred
nuclear refueling outage costs
|
106,514 | 115,289 | - | 221,803 | ||||||||||||
|
System
agreement cost equalization
|
394,000 | - | - | 394,000 | ||||||||||||
|
Prepayments
and other
|
106,044 | 144,200 | (3,060 | ) | 247,184 | |||||||||||
|
TOTAL
|
4,176,854 | 2,643,301 | (1,659,766 | ) | 5,160,389 | |||||||||||
|
OTHER
PROPERTY AND INVESTMENTS
|
||||||||||||||||
|
Investment
in affiliates - at equity
|
7,354,792 | (296,465 | ) | (6,992,080 | ) | 66,247 | ||||||||||
|
Decommissioning
trust funds
|
1,143,391 | 1,688,852 | - | 2,832,243 | ||||||||||||
|
Non-utility
property - at cost (less accumulated depreciation)
|
226,333 | 4,782 | - | 231,115 | ||||||||||||
|
Other
|
103,308 | 10,019 | (5,388 | ) | 107,939 | |||||||||||
|
TOTAL
|
8,827,824 | 1,407,188 | (6,997,468 | ) | 3,237,544 | |||||||||||
|
PROPERTY,
PLANT, AND EQUIPMENT
|
||||||||||||||||
|
Electric
|
30,878,491 | 3,616,915 | - | 34,495,406 | ||||||||||||
|
Property
under capital lease
|
745,504 | - | - | 745,504 | ||||||||||||
|
Natural
gas
|
303,769 | - | - | 303,769 | ||||||||||||
|
Construction
work in progress
|
1,458,181 | 254,580 | - | 1,712,761 | ||||||||||||
|
Nuclear
fuel under capital lease
|
465,374 | - | - | 465,374 | ||||||||||||
|
Nuclear
fuel
|
130,675 | 506,138 | - | 636,813 | ||||||||||||
|
TOTAL
PROPERTY, PLANT AND EQUIPMENT
|
33,981,994 | 4,377,633 | - | 38,359,627 | ||||||||||||
|
Less
- accumulated depreciation and amortization
|
15,365,659 | 564,854 | - | 15,930,513 | ||||||||||||
|
PROPERTY,
PLANT AND EQUIPMENT - NET
|
18,616,335 | 3,812,779 | - | 22,429,114 | ||||||||||||
|
DEFERRED
DEBITS AND OTHER ASSETS
|
||||||||||||||||
|
Regulatory
assets:
|
||||||||||||||||
|
SFAS
109 regulatory asset - net
|
581,719 | - | - | 581,719 | ||||||||||||
|
Other
regulatory assets
|
3,615,104 | - | - | 3,615,104 | ||||||||||||
|
Deferred
fuel costs
|
168,122 | - | - | 168,122 | ||||||||||||
|
Goodwill
|
374,099 | 3,073 | - | 377,172 | ||||||||||||
|
Other
|
744,499 | 868,454 | (565,299 | ) | 1,047,654 | |||||||||||
|
TOTAL
|
5,483,543 | 871,527 | (565,299 | ) | 5,789,771 | |||||||||||
| - | ||||||||||||||||
|
TOTAL
ASSETS
|
$ | 37,104,556 | $ | 8,734,795 | $ | (9,222,533 | ) | $ | 36,616,818 | |||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Balance Sheet
|
||||||||||||||||
|
December
31, 2008
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
| (Unaudited) | ||||||||||||||||
| U.S. Utilities/ Parent & Other | Competitive Businesses | Eliminations |
Consolidated
|
|||||||||||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||
|
CURRENT
LIABILITIES
|
||||||||||||||||
|
Currently
maturing long-term debt
|
$ | 514,911 | $ | 29,549 | $ | - | $ | 544,460 | ||||||||
|
Notes
payable:
|
||||||||||||||||
|
Associated
companies
|
1,341,198 | 91,255 | (1,432,453 | ) | - | |||||||||||
|
Other
|
55,034 | - | - | 55,034 | ||||||||||||
|
Account
payable:
|
||||||||||||||||
|
Associated
companies
|
97,530 | 126,413 | (223,943 | ) | - | |||||||||||
|
Other
|
1,222,415 | 253,330 | - | 1,475,745 | ||||||||||||
|
Customer
deposits
|
302,303 | - | - | 302,303 | ||||||||||||
|
Taxes
accrued
|
175,920 | (100,710 | ) | - | 75,210 | |||||||||||
|
Accumulated
deferred income taxes
|
- | - | - | - | ||||||||||||
|
Interest
accrued
|
185,778 | 1,532 | - | 187,310 | ||||||||||||
|
Deferred
fuel costs
|
183,539 | - | - | 183,539 | ||||||||||||
|
Obligations
under capital leases
|
162,393 | - | - | 162,393 | ||||||||||||
|
Pension
and other postretirement liabilities
|
41,653 | 4,635 | - | 46,288 | ||||||||||||
|
System
agreement cost equalization
|
460,315 | - | - | 460,315 | ||||||||||||
|
Other
|
146,808 | 129,549 | (3,060 | ) | 273,297 | |||||||||||
|
TOTAL
|
4,889,797 | 535,553 | (1,659,456 | ) | 3,765,894 | |||||||||||
|
NON-CURRENT
LIABILITIES
|
||||||||||||||||
|
Accumulated
deferred income taxes and taxes accrued
|
5,718,488 | 847,282 | - | 6,565,770 | ||||||||||||
|
Accumulated
deferred investment tax credits
|
325,570 | - | - | 325,570 | ||||||||||||
|
Obligations
under capital leases
|
343,093 | - | - | 343,093 | ||||||||||||
|
Other
regulatory liabilities
|
280,643 | - | - | 280,643 | ||||||||||||
|
Decommissioning
and retirement cost liabilities
|
1,447,659 | 1,229,836 | - | 2,677,495 | ||||||||||||
|
Accumulated
provisions
|
136,449 | 11,003 | - | 147,452 | ||||||||||||
|
Pension
and other postretirement liabilities
|
1,731,824 | 446,169 | - | 2,177,993 | ||||||||||||
|
Long-term
debt
|
10,991,204 | 188,473 | (5,388 | ) | 11,174,289 | |||||||||||
|
Other
|
735,252 | 720,223 | (574,477 | ) | 880,998 | |||||||||||
|
TOTAL
|
21,710,182 | 3,442,986 | (579,865 | ) | 24,573,303 | |||||||||||
|
Subsidiaries'
preferred stock without sinking fund
|
186,511 | 82,280 | (51,762 | ) | 217,029 | |||||||||||
|
EQUITY
|
||||||||||||||||
|
Common
Shareholders' Equity:
|
||||||||||||||||
|
Common
stock, $.01 par value, authorized 500,000,000 shares;
|
||||||||||||||||
|
issued
248,174,087 shares in 2008
|
2,163,749 | 911,494 | (3,072,761 | ) | 2,482 | |||||||||||
|
Paid-in
capital
|
6,979,623 | 2,138,165 | (4,248,485 | ) | 4,869,303 | |||||||||||
|
Retained
earnings
|
5,494,812 | 1,631,437 | 256,470 | 7,382,719 | ||||||||||||
|
Accumulated
other comprehensive income (loss)
|
(118,904 | ) | 5,580 | 626 | (112,698 | ) | ||||||||||
|
Less
- treasury stock, at cost (58,815,518 shares in 2008)
|
4,295,214 | 12,700 | (132,700 | ) | 4,175,214 | |||||||||||
|
Total
common shareholders' equity
|
10,224,066 | 4,673,976 | (6,931,450 | ) | 7,966,592 | |||||||||||
|
Subsidiaries'
preferred stock without sinking fund
|
94,000 | - | - | 94,000 | ||||||||||||
|
TOTAL
|
10,318,066 | 4,673,976 | (6,931,450 | ) | 8,060,592 | |||||||||||
|
TOTAL
LIABILITIES AND EQUITY
|
$ | 37,104,556 | $ | 8,734,795 | $ | (9,222,533 | ) | $ | 36,616,818 | |||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Balance Sheet
|
||||||||||||||||
|
December
31, 2009 vs December 31, 2008
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
ASSETS
|
||||||||||||||||
|
CURRENT
ASSETS
|
||||||||||||||||
|
Cash
and cash equivalents:
|
||||||||||||||||
|
Cash
|
$ | (28,048 | ) | $ | (1,967 | ) | $ | - | $ | (30,015 | ) | |||||
|
Temporary
cash investments
|
(147,473 | ) | (33,452 | ) | - | (180,925 | ) | |||||||||
|
Total
cash and cash equivalents
|
(175,521 | ) | (35,419 | ) | - | (210,940 | ) | |||||||||
|
Securitization
recovery trust account
|
1,036 | - | - | 1,036 | ||||||||||||
|
Notes
receivable
|
104,586 | 427,297 | (531,883 | ) | - | |||||||||||
|
Accounts
receivable:
|
||||||||||||||||
|
Customer
|
(191,412 | ) | 10,900 | - | (180,512 | ) | ||||||||||
|
Allowance
for doubtful accounts
|
(1,818 | ) | (203 | ) | - | (2,021 | ) | |||||||||
|
Associated
companies
|
(114,531 | ) | 33,142 | 81,389 | - | |||||||||||
|
Other
|
(41,239 | ) | (13,085 | ) | - | (54,324 | ) | |||||||||
|
Accrued
unbilled revenues
|
19,549 | - | - | 19,549 | ||||||||||||
|
Total
accounts receivable
|
(329,451 | ) | 30,754 | 81,389 | (217,308 | ) | ||||||||||
|
Deferred
fuel costs
|
(40,294 | ) | - | - | (40,294 | ) | ||||||||||
|
Accumulated
deferred income taxes
|
(7,307 | ) | - | - | (7,307 | ) | ||||||||||
|
Fuel
inventory - at average cost
|
(18,486 | ) | (804 | ) | - | (19,290 | ) | |||||||||
|
Materials
and supplies - at average cost
|
20,823 | 28,709 | - | 49,532 | ||||||||||||
|
Deferred
nuclear refueling outage costs
|
(86 | ) | 3,573 | - | 3,487 | |||||||||||
|
System
agreement cost equalization
|
(324,000 | ) | - | - | (324,000 | ) | ||||||||||
|
Prepayments
and other
|
(26,960 | ) | 273,760 | (107,944 | ) | 138,856 | ||||||||||
|
TOTAL
|
(795,660 | ) | 727,870 | (558,438 | ) | (626,228 | ) | |||||||||
|
OTHER
PROPERTY AND INVESTMENTS
|
||||||||||||||||
|
Investment
in affiliates - at equity
|
(483,188 | ) | 1,339,030 | (882,509 | ) | (26,667 | ) | |||||||||
|
Decommissioning
trust funds
|
182,472 | 196,468 | - | 378,940 | ||||||||||||
|
Non-utility
property - at cost (less accumulated depreciation)
|
13,623 | 2,926 | - | 16,549 | ||||||||||||
|
Other
|
7,337 | (391 | ) | 5,388 | 12,334 | |||||||||||
|
TOTAL
|
(279,756 | ) | 1,538,033 | (877,121 | ) | 381,156 | ||||||||||
|
PROPERTY,
PLANT, AND EQUIPMENT
|
||||||||||||||||
|
Electric
|
1,567,860 | 280,506 | - | 1,848,366 | ||||||||||||
|
Property
under capital lease
|
37,592 | - | - | 37,592 | ||||||||||||
|
Natural
gas
|
10,487 | - | - | 10,487 | ||||||||||||
|
Construction
work in progress
|
(324,358 | ) | 158,916 | - | (165,442 | ) | ||||||||||
|
Nuclear
fuel under capital lease
|
62,147 | - | - | 62,147 | ||||||||||||
|
Nuclear
fuel
|
88,642 | 14,372 | - | 103,014 | ||||||||||||
|
TOTAL
PROPERTY, PLANT AND EQUIPMENT
|
1,442,370 | 453,794 | - | 1,896,164 | ||||||||||||
|
Less
- accumulated depreciation and amortization
|
793,382 | 142,494 | - | 935,876 | ||||||||||||
|
PROPERTY,
PLANT AND EQUIPMENT - NET
|
648,988 | 311,300 | - | 960,288 | ||||||||||||
|
DEFERRED
DEBITS AND OTHER ASSETS
|
||||||||||||||||
|
Regulatory
assets:
|
||||||||||||||||
|
SFAS
109 regulatory asset - net
|
37,781 | - | - | 37,781 | ||||||||||||
|
Other
regulatory assets
|
32,050 | - | - | 32,050 | ||||||||||||
|
Deferred
fuel costs
|
4,080 | - | - | 4,080 | ||||||||||||
|
Goodwill
|
- | - | - | - | ||||||||||||
|
Other
|
(95,241 | ) | 5,003 | 48,890 | (41,348 | ) | ||||||||||
|
TOTAL
|
(21,330 | ) | 5,003 | 48,890 | 32,563 | |||||||||||
|
TOTAL
ASSETS
|
$ | (447,758 | ) | $ | 2,582,206 | $ | (1,386,669 | ) | $ | 747,779 | ||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
| Consolidating Balance Sheet | ||||||||||||||||
| December 31, 2009 vs December 31, 2008 | ||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
| (Unaudited) | ||||||||||||||||
| U.S. Utilities/ Parent & Other | Competitive Businesses |
Eliminations
|
Consolidated
|
|||||||||||||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||
|
CURRENT
LIABILITIES
|
||||||||||||||||
|
Currently
maturing long-term debt
|
$ | 166,105 | $ | 1,392 | $ | - | $ | 167,497 | ||||||||
|
Notes
payable:
|
||||||||||||||||
|
Associated
companies
|
623,138 | (91,255 | ) | (531,883 | ) | - | ||||||||||
|
Other
|
(25,003 | ) | - | - | (25,003 | ) | ||||||||||
|
Account
payable:
|
||||||||||||||||
|
Associated
companies
|
32,699 | (115,801 | ) | 83,102 | - | |||||||||||
|
Other
|
(469,053 | ) | (8,464 | ) | - | (477,517 | ) | |||||||||
|
Customer
deposits
|
20,789 | 250 | - | 21,039 | ||||||||||||
|
Taxes
accrued
|
(67,976 | ) | 100,710 | (107,944 | ) | (75,210 | ) | |||||||||
|
Accumulated
deferred income taxes
|
48,584 | - | - | 48,584 | ||||||||||||
|
Interest
accrued
|
5,597 | (624 | ) | - | 4,973 | |||||||||||
|
Deferred
fuel costs
|
36,100 | - | - | 36,100 | ||||||||||||
|
Obligations
under capital leases
|
50,103 | - | - | 50,103 | ||||||||||||
|
Pension
and other postretirement liabilities
|
8,259 | 484 | - | 8,743 | ||||||||||||
|
System
agreement cost equalization
|
(273,111 | ) | - | - | (273,111 | ) | ||||||||||
|
Other
|
(92,529 | ) | 34,434 | - | (58,095 | ) | ||||||||||
|
TOTAL
|
63,702 | (78,874 | ) | (556,725 | ) | (571,897 | ) | |||||||||
|
NON-CURRENT
LIABILITIES
|
||||||||||||||||
|
Accumulated
deferred income taxes and taxes accrued
|
(1,108,649 | ) | 1,965,198 | - | 856,549 | |||||||||||
|
Accumulated
deferred investment tax credits
|
(17,175 | ) | - | - | (17,175 | ) | ||||||||||
|
Obligations
under capital leases
|
11,140 | - | - | 11,140 | ||||||||||||
|
Other
regulatory liabilities
|
141,342 | - | - | 141,342 | ||||||||||||
|
Decommissioning
and retirement cost liabilities
|
171,186 | 90,858 | - | 262,044 | ||||||||||||
|
Accumulated
provisions
|
(4,224 | ) | (1,913 | ) | - | (6,137 | ) | |||||||||
|
Pension
and other postretirement liabilities
|
39,526 | 23,520 | - | 63,046 | ||||||||||||
|
Long-term
debt
|
(442,023 | ) | (31,916 | ) | 5,388 | (468,551 | ) | |||||||||
|
Other
|
(283,814 | ) | 66,220 | 47,930 | (169,664 | ) | ||||||||||
|
TOTAL
|
(1,492,691 | ) | 2,111,967 | 53,318 | 672,594 | |||||||||||
|
Subsidiaries'
preferred stock without sinking fund
|
(1 | ) | 673 | (358 | ) | 314 | ||||||||||
|
EQUITY
|
||||||||||||||||
|
Common
Shareholders' Equity:
|
||||||||||||||||
|
Common
stock, $.01 par value, authorized 500,000,000 shares;
|
||||||||||||||||
|
issued
254,772,087 shares in 2009 and 248,174,087 shares in 2008
|
66 | 70,546 | (70,546 | ) | 66 | |||||||||||
|
Paid-in
capital
|
1,935,918 | (256,062 | ) | (1,179,117 | ) | 500,739 | ||||||||||
|
Retained
earnings
|
(391,646 | ) | 684,664 | 367,385 | 660,403 | |||||||||||
|
Accumulated
other comprehensive income (loss)
|
(11,153 | ) | 49,292 | (626 | ) | 37,513 | ||||||||||
|
Less
- treasury stock, at cost
|
551,953 | - | - | 551,953 | ||||||||||||
|
Total
common shareholders' equity
|
981,232 | 548,440 | (882,904 | ) | 646,768 | |||||||||||
|
Subsidiaries'
preferred stock without sinking fund
|
- | - | - | - | ||||||||||||
|
TOTAL
|
981,232 | 548,440 | (882,904 | ) | 646,768 | |||||||||||
|
TOTAL
LIABILITIES AND EQUITY
|
$ | (447,758 | ) | $ | 2,582,206 | $ | (1,386,669 | ) | $ | 747,779 | ||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Income Statement
|
||||||||||||||||
|
Three
Months Ended December 31, 2009
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Electric
|
$ | 1,739,732 | $ | - | $ | (539 | ) | $ | 1,739,193 | |||||||
|
Natural
gas
|
45,298 | - | - | 45,298 | ||||||||||||
|
Competitive
businesses
|
7,088 | 712,442 | (5,368 | ) | 714,163 | |||||||||||
|
Total
|
1,792,118 | 712,442 | (5,907 | ) | 2,498,654 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Operating
and Maintenance:
|
||||||||||||||||
|
Fuel,
fuel related expenses, and gas purchased for resale
|
305,730 | 77,662 | (1,253 | ) | 382,139 | |||||||||||
|
Purchased
power
|
353,774 | 11,543 | (4,596 | ) | 360,721 | |||||||||||
|
Nuclear
refueling outage expenses
|
27,654 | 35,202 | - | 62,856 | ||||||||||||
|
Other
operation and maintenance
|
471,376 | 258,144 | (172 | ) | 729,348 | |||||||||||
|
Decommissioning
|
25,272 | 25,672 | - | 50,945 | ||||||||||||
|
Taxes
other than income taxes
|
93,750 | 24,461 | - | 118,211 | ||||||||||||
|
Depreciation
and amortization
|
244,970 | 38,623 | - | 283,592 | ||||||||||||
|
Other
regulatory charges (credits) - net
|
7,643 | - | - | 7,643 | ||||||||||||
|
Total
|
1,530,169 | 471,307 | (6,021 | ) | 1,995,455 | |||||||||||
|
OPERATING
INCOME
|
261,949 | 241,135 | 114 | 503,199 | ||||||||||||
|
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
|
Allowance
for equity funds used during construction
|
12,046 | - | - | 12,046 | ||||||||||||
|
Interest
and dividend income
|
26,176 | 70,334 | (29,859 | ) | 66,651 | |||||||||||
|
Other
than temporary impairment losses
|
- | (703 | ) | - | (703 | ) | ||||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates
|
(3,433 | ) | (3,916 | ) | - | (7,350 | ) | |||||||||
|
Miscellaneous
- net
|
(6,843 | ) | (5,176 | ) | (114 | ) | (12,133 | ) | ||||||||
|
Total
|
27,946 | 60,539 | (29,973 | ) | 58,511 | |||||||||||
|
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
|
Interest
on long-term debt
|
134,835 | 2,627 | - | 137,462 | ||||||||||||
|
Other
interest - net
|
35,868 | 7,548 | (29,859 | ) | 13,557 | |||||||||||
|
Allowance
for borrowed funds used during construction
|
(6,688 | ) | - | - | (6,688 | ) | ||||||||||
|
Total
|
164,015 | 10,175 | (29,859 | ) | 144,331 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
125,880 | 291,499 | - | 417,379 | ||||||||||||
|
Income
taxes
|
14,502 | 84,137 | - | 98,639 | ||||||||||||
|
CONSOLIDATED
NET INCOME
|
111,378 | 207,362 | - | 318,740 | ||||||||||||
|
Preferred
dividend requirements of subsidiaries
|
4,332 | 633 | - | 4,965 | ||||||||||||
|
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 107,046 | $ | 206,729 | $ | - | $ | 313,775 | ||||||||
|
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
|
BASIC
|
$ | 0.57 | $ | 1.09 | $ | 1.66 | ||||||||||
|
DILUTED
|
$ | 0.56 | $ | 1.08 | $ | 1.64 | ||||||||||
|
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
|
BASIC
|
188,996,969 | |||||||||||||||
|
DILUTED
|
191,255,405 | |||||||||||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Income Statement
|
||||||||||||||||
|
Three
Months Ended December 31, 2008
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Electric
|
$ | 2,294,707 | $ | - | $ | (997 | ) | $ | 2,293,710 | |||||||
|
Natural
gas
|
56,495 | - | - | 56,495 | ||||||||||||
|
Competitive
businesses
|
6,736 | 647,696 | (3,770 | ) | 650,662 | |||||||||||
|
Total
|
2,357,938 | 647,696 | (4,767 | ) | 3,000,867 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Operating
and Maintenance:
|
||||||||||||||||
|
Fuel,
fuel related expenses, and gas purchased for resale
|
964,747 | 75,520 | - | 1,040,267 | ||||||||||||
|
Purchased
power
|
352,695 | 10,275 | (4,738 | ) | 358,232 | |||||||||||
|
Nuclear
refueling outage expenses
|
23,622 | 32,960 | - | 56,582 | ||||||||||||
|
Other
operation and maintenance
|
565,774 | 218,565 | (143 | ) | 784,196 | |||||||||||
|
Decommissioning
|
24,597 | 24,485 | - | 49,082 | ||||||||||||
|
Taxes
other than income taxes
|
97,355 | 24,265 | - | 121,620 | ||||||||||||
|
Depreciation
and amortization
|
238,947 | 35,296 | - | 274,243 | ||||||||||||
|
Other
regulatory charges (credits) - net
|
(40,088 | ) | - | - | (40,088 | ) | ||||||||||
|
Total
|
2,227,649 | 421,366 | (4,881 | ) | 2,644,134 | |||||||||||
|
OPERATING
INCOME
|
130,289 | 226,330 | 114 | 356,733 | ||||||||||||
|
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
|
Allowance
for equity funds used during construction
|
15,740 | - | - | 15,740 | ||||||||||||
|
Interest
and dividend income
|
40,607 | 46,995 | (33,003 | ) | 54,599 | |||||||||||
|
Other
than temporary impairment losses
|
- | (14,463 | ) | - | (14,463 | ) | ||||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates
|
48 | (9,689 | ) | - | (9,641 | ) | ||||||||||
|
Miscellaneous
- net
|
(13,238 | ) | 4,024 | (114 | ) | (9,328 | ) | |||||||||
|
Total
|
43,157 | 26,867 | (33,117 | ) | 36,907 | |||||||||||
|
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
|
Interest
on long-term debt
|
129,155 | (49 | ) | - | 129,106 | |||||||||||
|
Other
interest - net
|
58,889 | 13,607 | (33,003 | ) | 39,493 | |||||||||||
|
Allowance
for borrowed funds used during construction
|
(9,274 | ) | - | - | (9,274 | ) | ||||||||||
|
Total
|
178,770 | 13,558 | (33,003 | ) | 159,325 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
(5,324 | ) | 239,639 | - | 234,315 | |||||||||||
|
Income
taxes
|
72,959 | (14,215 | ) | - | 58,744 | |||||||||||
|
CONSOLIDATED
NET INCOME
|
(78,283 | ) | 253,854 | - | 175,571 | |||||||||||
|
Preferred
dividend requirements of subsidiaries
|
4,332 | 665 | - | 4,997 | ||||||||||||
|
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | (82,615 | ) | $ | 253,189 | $ | - | $ | 170,574 | |||||||
|
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
|
BASIC
|
$ | (0.44 | ) | $ | 1.34 | $ | 0.90 | |||||||||
|
DILUTED
|
$ | (0.38 | ) | $ | 1.27 | $ | 0.89 | |||||||||
|
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
|
BASIC
|
189,379,904 | |||||||||||||||
|
DILUTED
|
198,257,675 | |||||||||||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Income Statement
|
||||||||||||||||
|
Three
Months Ended December 31, 2009 vs. 2008
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Electric
|
$ | (554,975 | ) | $ | - | $ | 458 | $ | (554,517 | ) | ||||||
|
Natural
gas
|
(11,197 | ) | - | - | (11,197 | ) | ||||||||||
|
Competitive
businesses
|
352 | 64,746 | (1,598 | ) | 63,501 | |||||||||||
|
Total
|
(565,820 | ) | 64,746 | (1,140 | ) | (502,213 | ) | |||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Operating
and Maintenance:
|
||||||||||||||||
|
Fuel,
fuel related expenses, and gas purchased for resale
|
(659,017 | ) | 2,142 | (1,253 | ) | (658,128 | ) | |||||||||
|
Purchased
power
|
1,079 | 1,268 | 142 | 2,489 | ||||||||||||
|
Nuclear
refueling outage expenses
|
4,032 | 2,242 | - | 6,274 | ||||||||||||
|
Other
operation and maintenance
|
(94,398 | ) | 39,579 | (29 | ) | (54,848 | ) | |||||||||
|
Decommissioning
|
675 | 1,187 | - | 1,863 | ||||||||||||
|
Taxes
other than income taxes
|
(3,605 | ) | 196 | - | (3,409 | ) | ||||||||||
|
Depreciation
and amortization
|
6,023 | 3,327 | - | 9,349 | ||||||||||||
|
Other
regulatory charges (credits )- net
|
47,731 | - | - | 47,731 | ||||||||||||
|
Total
|
(697,480 | ) | 49,941 | (1,140 | ) | (648,679 | ) | |||||||||
|
OPERATING
INCOME
|
131,660 | 14,805 | - | 146,466 | ||||||||||||
|
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
|
Allowance
for equity funds used during construction
|
(3,694 | ) | - | - | (3,694 | ) | ||||||||||
|
Interest
and dividend income
|
(14,431 | ) | 23,339 | 3,144 | 12,052 | |||||||||||
|
Other
than temporary impairment losses
|
- | 13,760 | - | 13,760 | ||||||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates
|
(3,481 | ) | 5,773 | - | 2,291 | |||||||||||
|
Miscellaneous
- net
|
6,395 | (9,200 | ) | - | (2,805 | ) | ||||||||||
|
Total
|
(15,211 | ) | 33,672 | 3,144 | 21,604 | |||||||||||
|
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
|
Interest
on long-term debt
|
5,680 | 2,676 | - | 8,356 | ||||||||||||
|
Other
interest - net
|
(23,021 | ) | (6,059 | ) | 3,144 | (25,936 | ) | |||||||||
|
Allowance
for borrowed funds used during construction
|
2,586 | - | - | 2,586 | ||||||||||||
|
Total
|
(14,755 | ) | (3,383 | ) | 3,144 | (14,994 | ) | |||||||||
|
INCOME
BEFORE INCOME TAXES
|
131,204 | 51,860 | - | 183,064 | ||||||||||||
|
Income
taxes
|
(58,457 | ) | 98,352 | - | 39,895 | |||||||||||
|
CONSOLIDATED
NET INCOME
|
189,661 | (46,492 | ) | - | 143,169 | |||||||||||
|
Preferred
dividend requirements of subsidiaries
|
- | (32 | ) | - | (32 | ) | ||||||||||
|
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 189,661 | $ | (46,460 | ) | $ | - | $ | 143,201 | |||||||
|
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
|
BASIC
|
$ | 1.01 | $ | (0.25 | ) | $ | 0.76 | |||||||||
|
DILUTED
|
$ | 0.94 | $ | (0.19 | ) | $ | 0.75 | |||||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Income Statement
|
||||||||||||||||
|
Year
to Date December 31, 2009
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Electric
|
$ | 7,883,140 | $ | - | $ | (3,124 | ) | $ | 7,880,016 | |||||||
|
Natural
gas
|
172,213 | - | - | 172,213 | ||||||||||||
|
Competitive
businesses
|
29,953 | 2,686,806 | (23,338 | ) | 2,693,421 | |||||||||||
|
Total
|
8,085,306 | 2,686,806 | (26,462 | ) | 10,745,650 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Operating
and Maintenance:
|
||||||||||||||||
|
Fuel,
fuel related expenses, and gas purchased for resale
|
2,026,893 | 284,191 | (1,253 | ) | 2,309,831 | |||||||||||
|
Purchased
power
|
1,356,418 | 62,586 | (23,801 | ) | 1,395,203 | |||||||||||
|
Nuclear
refueling outage expenses
|
105,016 | 136,293 | - | 241,310 | ||||||||||||
|
Other
operation and maintenance
|
1,851,090 | 901,585 | (1,864 | ) | 2,750,810 | |||||||||||
|
Decommissioning
|
99,683 | 99,380 | - | 199,063 | ||||||||||||
|
Taxes
other than income taxes
|
403,957 | 99,903 | - | 503,859 | ||||||||||||
|
Depreciation
and amortization
|
933,758 | 149,017 | - | 1,082,775 | ||||||||||||
|
Other
regulatory charges (credits) - net
|
(21,727 | ) | - | - | (21,727 | ) | ||||||||||
|
Total
|
6,755,088 | 1,732,955 | (26,918 | ) | 8,461,124 | |||||||||||
|
OPERATING
INCOME
|
1,330,218 | 953,851 | 456 | 2,284,526 | ||||||||||||
|
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
|
Allowance
for equity funds used during construction
|
59,545 | - | - | 59,545 | ||||||||||||
|
Interest
and dividend income
|
153,400 | 211,805 | (128,577 | ) | 236,628 | |||||||||||
|
Other
than temporary impairment losses
|
- | (86,069 | ) | - | (86,069 | ) | ||||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates
|
(3,327 | ) | (4,466 | ) | - | (7,793 | ) | |||||||||
|
Miscellaneous
- net
|
(11,998 | ) | (20,149 | ) | (456 | ) | (32,603 | ) | ||||||||
|
Total
|
197,620 | 101,121 | (129,033 | ) | 169,708 | |||||||||||
|
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
|
Interest
on long-term debt
|
511,451 | 9,265 | - | 520,716 | ||||||||||||
|
Other
interest - net
|
162,370 | 49,170 | (128,577 | ) | 82,963 | |||||||||||
|
Allowance
for borrowed funds used during construction
|
(33,235 | ) | - | - | (33,235 | ) | ||||||||||
|
Total
|
640,586 | 58,435 | (128,577 | ) | 570,444 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
887,252 | 996,537 | - | 1,883,790 | ||||||||||||
|
Income
taxes
|
308,552 | 324,187 | - | 632,740 | ||||||||||||
|
CONSOLIDATED
NET INCOME
|
578,700 | 672,350 | - | 1,251,050 | ||||||||||||
|
Preferred
dividend requirements of subsidiaries
|
17,329 | 2,629 | - | 19,958 | ||||||||||||
|
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 561,371 | $ | 669,721 | $ | - | $ | 1,231,092 | ||||||||
|
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
|
BASIC
|
$ | 2.91 | $ | 3.48 | $ | 6.39 | ||||||||||
|
DILUTED
|
$ | 2.88 | $ | 3.42 | $ | 6.30 | ||||||||||
|
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
|
BASIC
|
192,772,032 | |||||||||||||||
|
DILUTED
|
195,838,068 | |||||||||||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Income Statement
|
||||||||||||||||
|
Year
to Date December 31, 2008
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Electric
|
$ | 10,076,774 | $ | - | $ | (3,614 | ) | $ | 10,073,160 | |||||||
|
Natural
gas
|
241,856 | - | - | 241,856 | ||||||||||||
|
Competitive
businesses
|
29,011 | 2,771,082 | (21,353 | ) | 2,778,740 | |||||||||||
|
Total
|
10,347,641 | 2,771,082 | (24,967 | ) | 13,093,756 | |||||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Operating
and Maintenance:
|
||||||||||||||||
|
Fuel,
fuel related expenses, and gas purchased for resale
|
3,212,404 | 365,360 | - | 3,577,764 | ||||||||||||
|
Purchased
power
|
2,457,741 | 57,008 | (23,549 | ) | 2,491,200 | |||||||||||
|
Nuclear
refueling outage expenses
|
92,221 | 129,538 | - | 221,759 | ||||||||||||
|
Other
operation and maintenance
|
1,929,781 | 814,855 | (1,874 | ) | 2,742,762 | |||||||||||
|
Decommissioning
|
95,821 | 93,588 | - | 189,409 | ||||||||||||
|
Taxes
other than income taxes
|
405,677 | 91,275 | - | 496,952 | ||||||||||||
|
Depreciation
and amortization
|
896,632 | 134,228 | - | 1,030,860 | ||||||||||||
|
Other
regulatory charges (credits) - net
|
59,883 | - | - | 59,883 | ||||||||||||
|
Total
|
9,150,160 | 1,685,852 | (25,423 | ) | 10,810,589 | |||||||||||
|
OPERATING
INCOME
|
1,197,481 | 1,085,230 | 456 | 2,283,167 | ||||||||||||
|
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
|
Allowance
for equity funds used during construction
|
44,523 | - | - | 44,523 | ||||||||||||
|
Interest
and dividend income
|
156,293 | 154,688 | (113,109 | ) | 197,872 | |||||||||||
|
Other
than temporary impairment losses
|
- | (49,656 | ) | - | (49,656 | ) | ||||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates
|
(2,161 | ) | (9,523 | ) | - | (11,684 | ) | |||||||||
|
Miscellaneous
- net
|
(14,048 | ) | 2,736 | (456 | ) | (11,768 | ) | |||||||||
|
Total
|
184,607 | 98,245 | (113,565 | ) | 169,287 | |||||||||||
|
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
|
Interest
on long-term debt
|
499,679 | 1,219 | - | 500,898 | ||||||||||||
|
Other
interest - net
|
176,375 | 70,024 | (113,109 | ) | 133,290 | |||||||||||
|
Allowance
for borrowed funds used during construction
|
(25,267 | ) | - | - | (25,267 | ) | ||||||||||
|
Total
|
650,787 | 71,243 | (113,109 | ) | 608,921 | |||||||||||
|
INCOME
BEFORE INCOME TAXES
|
731,301 | 1,112,232 | - | 1,843,533 | ||||||||||||
|
Income
taxes
|
291,994 | 311,004 | - | 602,998 | ||||||||||||
|
CONSOLIDATED
NET INCOME
|
439,307 | 801,228 | - | 1,240,535 | ||||||||||||
|
Preferred
dividend requirements of subsidiaries
|
17,307 | 2,662 | - | 19,969 | ||||||||||||
|
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 422,000 | $ | 798,566 | $ | - | $ | 1,220,566 | ||||||||
|
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
|
BASIC
|
$ | 2.21 | $ | 4.18 | $ | 6.39 | ||||||||||
|
DILUTED
|
$ | 2.22 | $ | 3.98 | $ | 6.20 | ||||||||||
|
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
|
BASIC
|
190,925,613 | |||||||||||||||
|
DILUTED
|
201,011,588 | |||||||||||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||||||
|
Consolidating
Income Statement
|
||||||||||||||||
|
Year
to Date December 31, 2009 vs. 2008
|
||||||||||||||||
|
(Dollars
in thousands)
|
||||||||||||||||
|
(Unaudited)
|
||||||||||||||||
|
U.S.
Utilities/ Parent & Other
|
Competitive
Businesses
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING
REVENUES
|
||||||||||||||||
|
Electric
|
$ | (2,193,634 | ) | $ | - | $ | 490 | $ | (2,193,144 | ) | ||||||
|
Natural
gas
|
(69,643 | ) | - | - | (69,643 | ) | ||||||||||
|
Competitive
businesses
|
942 | (84,276 | ) | (1,985 | ) | (85,319 | ) | |||||||||
|
Total
|
(2,262,335 | ) | (84,276 | ) | (1,495 | ) | (2,348,106 | ) | ||||||||
|
OPERATING
EXPENSES
|
||||||||||||||||
|
Operating
and Maintenance:
|
||||||||||||||||
|
Fuel,
fuel related expenses, and gas purchased for resale
|
(1,185,511 | ) | (81,169 | ) | (1,253 | ) | (1,267,933 | ) | ||||||||
|
Purchased
power
|
(1,101,323 | ) | 5,578 | (252 | ) | (1,095,997 | ) | |||||||||
|
Nuclear
refueling outage expenses
|
12,795 | 6,755 | - | 19,551 | ||||||||||||
|
Other
operation and maintenance
|
(78,691 | ) | 86,730 | 10 | 8,048 | |||||||||||
|
Decommissioning
|
3,862 | 5,792 | - | 9,654 | ||||||||||||
|
Taxes
other than income taxes
|
(1,720 | ) | 8,628 | - | 6,907 | |||||||||||
|
Depreciation
and amortization
|
37,126 | 14,789 | - | 51,915 | ||||||||||||
|
Other
regulatory charges (credits )- net
|
(81,610 | ) | - | - | (81,610 | ) | ||||||||||
|
Total
|
(2,395,072 | ) | 47,103 | (1,495 | ) | (2,349,465 | ) | |||||||||
|
OPERATING
INCOME
|
132,737 | (131,379 | ) | - | 1,359 | |||||||||||
|
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
|
Allowance
for equity funds used during construction
|
15,022 | - | - | 15,022 | ||||||||||||
|
Interest
and dividend income
|
(2,893 | ) | 57,117 | (15,468 | ) | 38,756 | ||||||||||
|
Other
than temporary impairment losses
|
- | (36,413 | ) | - | (36,413 | ) | ||||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates
|
(1,166 | ) | 5,057 | - | 3,891 | |||||||||||
|
Miscellaneous
- net
|
2,050 | (22,885 | ) | - | (20,835 | ) | ||||||||||
|
Total
|
13,013 | 2,876 | (15,468 | ) | 421 | |||||||||||
|
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
|
Interest
on long-term debt
|
11,772 | 8,046 | - | 19,818 | ||||||||||||
|
Other
interest - net
|
(14,005 | ) | (20,854 | ) | (15,468 | ) | (50,327 | ) | ||||||||
|
Allowance
for borrowed funds used during construction
|
(7,968 | ) | - | - | (7,968 | ) | ||||||||||
|
Total
|
(10,201 | ) | (12,808 | ) | (15,468 | ) | (38,477 | ) | ||||||||
|
INCOME
BEFORE INCOME TAXES
|
155,951 | (115,695 | ) | - | 40,257 | |||||||||||
|
Income
taxes
|
16,558 | 13,183 | - | 29,742 | ||||||||||||
|
CONSOLIDATED
NET INCOME
|
139,393 | (128,878 | ) | - | 10,515 | |||||||||||
|
Preferred
dividend requirements of subsidiaries
|
21 | (33 | ) | - | (11 | ) | ||||||||||
|
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 139,372 | $ | (128,845 | ) | $ | - | $ | 10,526 | |||||||
|
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
|
BASIC
|
$ | 0.70 | $ | (0.70 | ) | - | ||||||||||
|
DILUTED
|
$ | 0.66 | $ | (0.56 | ) | $ | 0.10 | |||||||||
|
*Totals
may not foot due to rounding.
|
||||||||||||||||
|
Entergy
Corporation
|
||||||||||||
|
Consolidated
Cash Flow Statement
|
||||||||||||
|
Three
Months Ended December 31, 2009 vs. 2008
|
||||||||||||
|
(Dollars
in thousands)
|
||||||||||||
|
(Unaudited)
|
||||||||||||
|
2009
|
2008
|
Variance
|
||||||||||
|
OPERATING
ACTIVITIES
|
||||||||||||
|
Consolidated
net income
|
$ | 318,740 | $ | 175,572 | $ | 143,168 | ||||||
|
Adjustments
to reconcile consolidated net income to net cash flow
|
||||||||||||
|
provided
by operating activities:
|
||||||||||||
|
Reserve
for regulatory adjustments
|
572 | (6,424 | ) | 6,996 | ||||||||
|
Other
regulatory charges (credits) - net
|
7,643 | (40,087 | ) | 47,730 | ||||||||
|
Depreciation,
amortization, and decommissioning
|
334,537 | 323,324 | 11,213 | |||||||||
|
Deferred
income taxes, investment tax credits, and non-current taxes
accrued
|
355,854 | (227,756 | ) | 583,610 | ||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates - net of
dividends
|
7,350 | 9,642 | (2,292 | ) | ||||||||
|
Changes
in working capital:
|
||||||||||||
|
Receivables
|
101,588 | 344,002 | (242,414 | ) | ||||||||
|
Fuel
inventory
|
9,461 | 12,320 | (2,859 | ) | ||||||||
|
Accounts
payable
|
175,335 | (149,890 | ) | 325,225 | ||||||||
|
Taxes
accrued
|
(122,141 | ) | 75,210 | (197,351 | ) | |||||||
|
Interest
accrued
|
17,150 | 7,500 | 9,650 | |||||||||
|
Deferred
fuel
|
(123,797 | ) | 357,118 | (480,915 | ) | |||||||
|
Other
working capital accounts
|
(110,539 | ) | 16,045 | (126,584 | ) | |||||||
|
Provision
for estimated losses and reserves
|
(1,704 | ) | (218,372 | ) | 216,668 | |||||||
|
Changes
in other regulatory assets
|
(82,610 | ) | (1,265,836 | ) | 1,183,226 | |||||||
|
Changes
in pensions and other postretirement liabilities
|
124,503 | 1,049,839 | (925,336 | ) | ||||||||
|
Other
|
(88,115 | ) | 169,307 | (257,422 | ) | |||||||
|
Net
cash flow provided by operating activities
|
923,827 | 631,514 | 292,313 | |||||||||
|
INVESTING
ACTIVITIES
|
||||||||||||
|
Construction/capital
expenditures
|
(588,405 | ) | (756,598 | ) | 168,193 | |||||||
|
Allowance
for equity funds used during construction
|
12,046 | 15,741 | (3,695 | ) | ||||||||
|
Nuclear
fuel purchases
|
(233,753 | ) | (96,345 | ) | (137,408 | ) | ||||||
|
Proceeds
from sale/leaseback of nuclear fuel
|
87,291 | 46,650 | 40,641 | |||||||||
|
Proceeds
from sale of assets and businesses
|
500 | - | 500 | |||||||||
|
Insurance
proceeds received for property damages
|
20,846 | (6 | ) | 20,852 | ||||||||
|
Changes
in transition charge account
|
7,323 | 9,362 | (2,039 | ) | ||||||||
|
Decrease
(increase) in other investments
|
69,849 | 155,143 | (85,294 | ) | ||||||||
|
Proceeds
from nuclear decommissioning trust fund sales
|
837,153 | 423,517 | 413,636 | |||||||||
|
Investment
in nuclear decommissioning trust funds
|
(859,583 | ) | (444,893 | ) | (414,690 | ) | ||||||
|
Net
cash flow used in investing activities
|
(646,733 | ) | (647,429 | ) | 696 | |||||||
|
FINANCING
ACTIVITIES
|
||||||||||||
|
Proceeds
from the issuance of:
|
||||||||||||
|
Long-term
debt
|
1,221,972 | 23,511 | 1,198,461 | |||||||||
|
Common
stock and treasury stock
|
10,983 | (1,066 | ) | 12,049 | ||||||||
|
Retirement
of long-term debt
|
(758,437 | ) | (482,688 | ) | (275,749 | ) | ||||||
|
Repurchase
of common stock
|
- | (44,272 | ) | 44,272 | ||||||||
|
Changes
in credit line borrowings - net
|
(25,000 | ) | 30,000 | (55,000 | ) | |||||||
|
Dividends
paid:
|
||||||||||||
|
Common
stock
|
(141,778 | ) | (142,013 | ) | 235 | |||||||
|
Preferred
stock
|
(4,965 | ) | (4,997 | ) | 32 | |||||||
|
Net
cash flow provided by (used in) financing activities
|
302,775 | (621,525 | ) | 924,300 | ||||||||
|
Effect
of exchange rates on cash and cash equivalents
|
(1,098 | ) | 2,043 | (3,141 | ) | |||||||
|
Net
increase (decrease) in cash and cash equivalents
|
578,771 | (635,397 | ) | 1,214,168 | ||||||||
|
Cash
and cash equivalents at beginning of period
|
1,130,780 | 2,555,888 | (1,425,108 | ) | ||||||||
|
Cash
and cash equivalents at end of period
|
$ | 1,709,551 | $ | 1,920,491 | $ | (210,940 | ) | |||||
|
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION:
|
||||||||||||
|
Cash
paid (received) during the period for:
|
||||||||||||
|
Interest
- net of amount capitalized
|
$ | 126,073 | $ | 156,497 | $ | (30,424 | ) | |||||
|
Income
taxes
|
$ | 24,142 | $ | 9,281 | $ | 14,861 | ||||||
|
Entergy
Corporation
|
||||||||||||
|
Consolidated
Cash Flow Statement
|
||||||||||||
|
Year
to Date December 31, 2009 vs. 2008
|
||||||||||||
|
(Dollars
in thousands)
|
||||||||||||
|
(Unaudited)
|
||||||||||||
|
2009
|
2008
|
Variance
|
||||||||||
|
OPERATING
ACTIVITIES
|
||||||||||||
|
Consolidated
net income
|
$ | 1,251,050 | $ | 1,240,535 | $ | 10,515 | ||||||
|
Adjustments
to reconcile consolidated net income to net cash flow
|
||||||||||||
|
provided
by operating activities:
|
||||||||||||
|
Reserve
for regulatory adjustments
|
(508 | ) | (8,285 | ) | 7,777 | |||||||
|
Other
regulatory charges (credits) - net
|
(21,727 | ) | 59,883 | (81,610 | ) | |||||||
|
Depreciation,
amortization, and decommissioning
|
1,281,838 | 1,220,269 | 61,569 | |||||||||
|
Deferred
income taxes, investment tax credits, and non-current taxes
accrued
|
868,649 | 333,948 | 534,701 | |||||||||
|
Equity
in earnings (loss) of unconsolidated equity affiliates - net of
dividends
|
7,793 | 11,684 | (3,891 | ) | ||||||||
|
Changes
in working capital:
|
||||||||||||
|
Receivables
|
116,444 | 78,653 | 37,791 | |||||||||
|
Fuel
inventory
|
19,291 | (7,561 | ) | 26,852 | ||||||||
|
Accounts
payable
|
(14,251 | ) | (23,225 | ) | 8,974 | |||||||
|
Taxes
accrued
|
(75,210 | ) | 75,210 | (150,420 | ) | |||||||
|
Interest
accrued
|
4,974 | (652 | ) | 5,626 | ||||||||
|
Deferred
fuel
|
72,314 | (38,500 | ) | 110,814 | ||||||||
|
Other
working capital accounts
|
(228,210 | ) | (72,372 | ) | (155,838 | ) | ||||||
|
Provision
for estimated losses and reserves
|
(12,030 | ) | 12,462 | (24,492 | ) | |||||||
|
Changes
in other regulatory assets
|
(415,157 | ) | (324,211 | ) | (90,946 | ) | ||||||
|
Changes
in pensions and other postretirement liabilities
|
71,789 | 828,160 | (756,371 | ) | ||||||||
|
Other
|
6,109 | (61,670 | ) | 67,779 | ||||||||
|
Net
cash flow provided by operating activities
|
2,933,158 | 3,324,328 | (391,170 | ) | ||||||||
|
INVESTING
ACTIVITIES
|
||||||||||||
|
Construction/capital
expenditures
|
(1,931,245 | ) | (2,212,255 | ) | 281,010 | |||||||
|
Allowance
for equity funds used during construction
|
59,545 | 44,523 | 15,022 | |||||||||
|
Nuclear
fuel purchases
|
(525,474 | ) | (423,951 | ) | (101,523 | ) | ||||||
|
Proceeds
from sale/leaseback of nuclear fuel
|
284,997 | 297,097 | (12,100 | ) | ||||||||
|
Proceeds
from sale of assets and businesses
|
39,554 | 30,725 | 8,829 | |||||||||
|
Payment
for purchase of plant
|
- | (266,823 | ) | 266,823 | ||||||||
|
Insurance
proceeds received for property damages
|
53,760 | 130,114 | (76,354 | ) | ||||||||
|
Changes
in transition charge account
|
(1,036 | ) | 7,211 | (8,247 | ) | |||||||
|
NYPA
value sharing payment
|
(72,000 | ) | (72,000 | ) | - | |||||||
|
Decrease
(increase) in other investments
|
94,154 | (72,833 | ) | 166,987 | ||||||||
|
Proceeds
from nuclear decommissioning trust fund sales
|
2,570,523 | 1,652,277 | 918,246 | |||||||||
|
Investment
in nuclear decommissioning trust funds
|
(2,667,172 | ) | (1,704,181 | ) | (962,991 | ) | ||||||
|
Net
cash flow used in investing activities
|
(2,094,394 | ) | (2,590,096 | ) | 495,702 | |||||||
|
FINANCING
ACTIVITIES
|
||||||||||||
|
Proceeds
from the issuance of:
|
||||||||||||
|
Long-term
debt
|
2,003,469 | 3,456,695 | (1,453,226 | ) | ||||||||
|
Common
stock and treasury stock
|
28,198 | 34,775 | (6,577 | ) | ||||||||
|
Retirement
of long-term debt
|
(1,843,169 | ) | (2,486,806 | ) | 643,637 | |||||||
|
Repurchase
of common stock
|
(613,125 | ) | (512,351 | ) | (100,774 | ) | ||||||
|
Redemption
of preferred stock
|
(1,847 | ) | - | (1,847 | ) | |||||||
|
Changes
in credit line borrowings - net
|
(25,000 | ) | 30,000 | (55,000 | ) | |||||||
|
Dividends
paid:
|
||||||||||||
|
Common
stock
|
(576,956 | ) | (573,045 | ) | (3,911 | ) | ||||||
|
Preferred
stock
|
(19,958 | ) | (20,025 | ) | 67 | |||||||
|
Net
cash flow used in financing activities
|
(1,048,388 | ) | (70,757 | ) | (977,631 | ) | ||||||
|
Effect
of exchange rates on cash and cash equivalents
|
(1,316 | ) | 3,288 | (4,604 | ) | |||||||
|
Net
increase (decrease) in cash and cash equivalents
|
(210,940 | ) | 666,763 | (877,703 | ) | |||||||
|
Cash
and cash equivalents at beginning of period
|
1,920,491 | 1,253,728 | 666,763 | |||||||||
|
Cash
and cash equivalents at end of period
|
$ | 1,709,551 | $ | 1,920,491 | $ | (210,940 | ) | |||||
|
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION:
|
||||||||||||
|
Cash
paid (received) during the period for:
|
||||||||||||
|
Interest
- net of amount capitalized
|
$ | 568,417 | $ | 612,288 | $ | (43,871 | ) | |||||
|
Income
taxes
|
$ | 43,057 | $ | 137,234 | $ | (94,177 | ) | |||||
|
Noncash
financing activities:
|
||||||||||||
|
Long-term
debt retired (equity unit notes)
|
$ | (500,000 | ) | - | $ | (500,000 | ) | |||||
|
Common
stock issued in settlement of equity unit purchase
contracts
|
$ | 500,000 | - | $ | 500,000 | |||||||