Attached files
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8-K - ENTERGY CORP /DE/ | a02310.htm |
EX-99.2 - ENTERGY CORP /DE/ | a02310992.htm |
EX-99.3 - ENTERGY CORP /DE/ | a02310993.htm |
For
further information:
Michele
Lopiccolo, VP, Investor Relations
Phone
504/576-4879, Fax 504/576-2897
mlopicc@entergy.com
|
INVESTOR
NEWS
Exhibit
99.1
April
29, 2010
ENTERGY
REPORTS FIRST QUARTER EARNINGS
NEW
ORLEANS – Entergy Corporation (NYSE: ETR) reported first quarter 2010
earnings of $1.12 per share on an as-reported basis and $1.33 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
|
|||
First
Quarter 2010 vs. 2009
|
|||
(Per
share in U.S. $)
|
|||
First Quarter
|
|||
2010
|
2009
|
Change
|
|
As-Reported
Earnings
|
1.12
|
1.20
|
(0.08)
|
Less
Special Items
|
(0.21)
|
(0.09)
|
(0.12)
|
Operational
Earnings
|
1.33
|
1.29
|
0.04
|
Weather
Impact
|
0.17
|
(0.02)
|
0.19
|
Operational
Earnings Highlights for First Quarter 2010
·
|
Utility’s
results were higher due to higher net revenue driven by increased sales
volumes across all customer classes, including the effect of significantly
colder-than-normal weather.
|
·
|
Entergy
Nuclear’s earnings decreased as a result of lower net revenue resulting
primarily from lower pricing, higher non-fuel operation and
maintenance expense and a higher effective income tax
rate.
|
·
|
Parent
& Other’s results were higher due primarily to lower interest
expense.
|
“Results
for the quarter reflect an improving economy and its positive effects on our
utility business, and the continuing volatility in commodity markets and its
effect on our non-utility nuclear business,” said J. Wayne Leonard, Entergy’s chairman
and chief executive officer. “Looking forward, we will remain
focused on managing cash flows and operating within our risk capacity and
stakeholders’ risk tolerance. We continue to believe our strategies
drive long-term success and sustainability.”
Entergy’s
business highlights include the following:
·
|
The
Mississippi Public Service Commission approved revisions to Entergy
Mississippi’s formula rate plan positioning the company to timely recover
its business investments and bolstering its ability to provide safe,
affordable and reliable power to its
customers.
|
·
|
Entergy
Texas achieved a unanimous settlement for an interim $17.5 million rate
increase effective May 1, 2010. The settlement also calls
for a final rate case order to be issued November 1, 2010, with permanent
rates to be effective relating back to service rendered on / after
September 13, 2010.
|
·
|
Entergy
was awarded the Edison Electric Institute Emergency Recovery Award for the
12th
consecutive year for its work restoring power following a destructive ice
storm in Arkansas last year. Entergy is the only company to be
honored every year since inception of the EEI awards in
1998.
|
Entergy
will host a teleconference to discuss this release at 10 a.m. CT on Thursday,
April 29, 2010, with access by telephone, 719-457-2080, confirmation code
3884569. The call and presentation slides can also be accessed via
Entergy’s website at www.entergy.com. A
replay of the teleconference will be available through May 6, 2010 by dialing
719-457-0820, confirmation code 3884569. The replay will also be
available on Entergy’s website at www.entergy.com.
I.
|
Consolidated
Results
|
Consolidated
Earnings
Table 2
provides a comparative summary of consolidated earnings per share for first
quarter 2010 versus 2009, including a reconciliation of GAAP as-reported
earnings to non-GAAP operational earnings. Utility’s earnings
increased quarter-over-quarter as a result of higher net revenue due primarily
to increased sales volumes across all customer classes, including significantly
colder-than-normal weather. The effect of this increase was partially
offset by higher non-fuel operation and maintenance expense and higher interest
expense. Entergy Nuclear’s first quarter 2010 earnings were lower
than last year as a result of lower net revenue due primarily to lower
pricing. Also contributing to the lower results at Entergy Nuclear
were increases in non-fuel operation and maintenance expense and a higher
effective income tax rate. Partially offsetting was higher other
income from decommissioning trusts. Parent and Other’s results
improved in the current period compared to a year ago due primarily to lower
interest expense. Beginning with first quarter 2010, Parent &
Other includes the results from the non-nuclear wholesale assets
business.
Table
2: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP
Measures
First
Quarter 2010 vs. 2009 (see
Appendix E for definitions of certain
measures)
|
|||
(Per
share in U.S. $)
|
|||
First Quarter
|
|||
2010
|
2009
|
Change
|
|
As-Reported
|
|||
Utility
|
0.73
|
0.56
|
0.17
|
Entergy
Nuclear
|
0.49
|
0.91
|
(0.42)
|
Parent
& Other
|
(0.10)
|
(0.27)
|
0.17
|
Consolidated
As-Reported Earnings
|
1.12
|
1.20
|
(0.08)
|
Less
Special Items
|
|||
Utility
|
-
|
-
|
-
|
Entergy
Nuclear
|
(0.29)
|
(0.04)
|
(0.25)
|
Parent
& Other
|
0.08
|
(0.05)
|
0.13
|
Consolidated
Special Items
|
(0.21)
|
(0.09)
|
(0.12)
|
Operational
|
|||
Utility
|
0.73
|
0.56
|
0.17
|
Entergy
Nuclear
|
0.78
|
0.95
|
(0.17)
|
Parent
& Other
|
(0.18)
|
(0.22)
|
0.04
|
Consolidated
Operational Earnings
|
1.33
|
1.29
|
0.04
|
Weather
Impact
|
0.17
|
(0.02)
|
0.19
|
Detailed
earnings variance analysis is included in Appendix A-1 to this
release. In addition, Appendix A-2 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 first quarter 2010 was $674
million compared to $375 million in first quarter 2009. The overall
quarterly increase was due primarily to:
·
|
the
absence of hurricane and ice storm restoration spending of $314 million,
which affected cash flow during first quarter
2009
|
·
|
higher
net revenue at the Utility resulting from increased
sales
|
Partially
offsetting was:
·
|
a
decrease in net deferred fuel recovery of $275 million at the
Utility
|
Table 3
provides the components of net cash flow provided by operating activities
contributed by each business with quarterly comparisons.
Table
3: Consolidated Net Cash Flow Provided by Operating
Activities
|
|||
First
Quarter 2010 vs. 2009
|
|||
(U.S.
$ in millions)
|
|||
First Quarter
|
|||
2010
|
2009
|
Change
|
|
Utility
|
416
|
151
|
265
|
Entergy
Nuclear
|
306
|
254
|
52
|
Parent
& Other
|
(48)
|
(30)
|
(18)
|
Total
Net Cash Flow Provided by Operating Activities
|
674
|
375
|
299
|
II.
|
Utility
|
In first
quarter 2010, Utility’s as-reported and operational earnings were $0.73 per
share compared to $0.56 per share on the same bases in first quarter
2009. Earnings for the Utility in the current quarter reflect higher
net revenue due to increased sales across all customer classes and rate
adjustments at Entergy Gulf States Louisiana, Entergy Louisiana and Entergy
Mississippi under their formula rate plans. Significantly
colder-than-normal weather was a key contributor to the increase in sales
volume. Partially offsetting was higher non-fuel operation and
maintenance expense resulting primarily from higher pension and benefits
expense, as well as the absence of a nuclear insurance premium refund typically
received from Nuclear Electric Insurance Limited included in first quarter
results. In addition, higher interest expense associated with
additional debt issuances served as another partial offset to the positive
effect of higher net revenue during the quarter.
Electricity
usage, in gigawatt-hour sales by customer segment, is included in Table 4. Current
quarter sales reflect the following:
·
|
Residential
sales in first quarter 2010, on a weather-adjusted basis, increased 3.9
percent compared to first quarter
2009.
|
·
|
Commercial
and governmental sales, on a weather-adjusted basis, increased 3.2 percent
year over year.
|
·
|
Industrial
sales in the first quarter increased 7.3 percent compared to the same
quarter of 2009.
|
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 first quarter 2010 was driven by economic recovery that had
a positive effect particularly in the chemicals, pulp and paper and primary
metals sectors partially offset by a decline in refining due to maintenance
outages. Small and mid-sized industrial customers began to also show
signs of recovery as they benefited from global industrial
expansion. As noted above, colder-than-normal weather provided a
significant increase in sales volume.
Table 4
provides a comparative summary of the Utility’s operational performance
measures.
Table
4: Utility Operational Performance Measures
|
||||
First
Quarter 2010 vs. 2009 (see
Appendix E for definitions of
measures)
|
||||
First Quarter
|
||||
2010
|
2009
|
%
Change
|
%
Weather Adjusted
|
|
GWh
billed
|
||||
Residential
|
9,645
|
7,893
|
22.2%
|
3.9%
|
Commercial
and governmental
|
7,064
|
6,756
|
4.6%
|
3.2%
|
Industrial
|
8,733
|
8,139
|
7.3%
|
7.3%
|
Total
Retail Sales
|
25,442
|
22,788
|
11.7%
|
4.9%
|
Wholesale
|
1,317
|
1,387
|
(5.0)%
|
|
Total
Sales
|
26,759
|
24,175
|
10.7%
|
|
O&M
expense per MWh
|
$17.29
|
$18.51
|
(6.6)%
|
|
Number
of retail customers
|
||||
Residential
|
2,348,838
|
2,321,488
|
1.2%
|
|
Commercial
and governmental
|
348,414
|
343,871
|
1.3%
|
|
Industrial
|
38,782
|
38,892
|
(0.3)%
|
|
Appendix
B provides information on selected pending local and federal regulatory
cases.
III.
|
Entergy
Nuclear
|
Entergy
Nuclear earned $0.49 per share on an as-reported basis in first quarter 2010,
compared to as-reported earnings of $0.91 per share in first quarter
2009. On an operational basis, first quarter 2010 Entergy Nuclear
earnings were $0.78 per share versus $0.95 per share in the first quarter of the
prior year. Entergy Nuclear’s operational earnings decreased as a
result of lower net revenue due primarily to lower
pricing. Contributing to the decrease in earnings were higher
non-fuel operation and maintenance expense due primarily to tritium remediation
work at the Vermont Yankee site, higher pension and benefits expense, refueling
amortization expense, and insurance expense. A higher effective
income tax rate also contributed to the decrease in results this quarter driven
primarily by the change in tax laws associated with recently enacted federal
health care legislation. Higher other income associated with
decommissioning trusts provided an offset to decreased earnings.
Table 5
provides a comparative summary of Entergy Nuclear’s operational performance
measures.
Table
5: Entergy Nuclear Operational Performance
Measures
|
|||
First
Quarter 2010 vs. 2009 (see
Appendix E for definitions of
measures)
|
|||
First Quarter
|
|||
2010
|
2009
|
%
Change
|
|
Net
MW in operation
|
4,998
|
4,998
|
-%
|
Average
realized price per MWh
|
$58.72
|
$63.84
|
-8%
|
Production
cost per MWh (a)
|
$23.70
|
$23.14
|
2%
|
Non-fuel
O&M expense/purchased power per MWh (a)
|
$23.63
|
$22.44
|
5%
|
GWh
billed
|
10,255
|
10,074
|
2%
|
Capacity
factor
|
94%
|
92%
|
2%
|
Refueling
outage days:
|
|||
Indian
Point 2 (b)
|
22
|
-
|
|
Indian
Point 3
|
-
|
21
|
|
Palisades
|
-
|
9
|
|
|
|
(a)
First quarter 2009 and 2010 exclude the effect of the special item
for non-utility nuclear spin-off
expenses.
|
|
(b) Table
reflects the duration of refueling outages that occurred in first quarter
2010. For the Indian Point 2 plant, approximately 11 refueling outage days
occurred in second quarter 2010.
|
Table 6
provides capacity and generation sold forward projections for Entergy
Nuclear.
Table
6: Entergy Nuclear’s Capacity and Generation Projected Sold
Forward
|
|||||
Second
Quarter 2010 through 2014 (see
Appendix E for definitions of
measures)
|
|||||
Balance
of
2010
|
2011
|
2012
|
2013
|
2014
|
|
Energy
|
|||||
Planned
TWh of generation
|
30
|
41
|
41
|
40
|
41
|
Percent
of planned generation sold forward (c)
|
|||||
Unit-contingent
|
54%
|
63%
|
31%
|
12%
|
14%
|
Unit-contingent
with availability guarantees
|
37%
|
17%
|
14%
|
6%
|
3%
|
Firm
LD
|
-%
|
2%
|
2%
|
-%
|
-%
|
Total
Energy Sold Forward
|
91%
|
82%
|
47%
|
18%
|
17%
|
Average
contract price per MWh (d)
|
$57
|
$55
|
$55
|
$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
|
27%
|
25%
|
18%
|
16%
|
16%
|
Capacity
contracts
|
46%
|
26%
|
30%
|
13%
|
-%
|
Total
Capacity Sold Forward
|
73%
|
51%
|
48%
|
29%
|
16%
|
Average
capacity contract price per kW per month
|
$3.1
|
$3.6
|
$3.0
|
$2.6
|
-
|
Blended Capacity and Energy Recap (based on
revenues)
|
|||||
Percent
of planned energy and capacity sold forward
|
92%
|
84%
|
51%
|
18%
|
15%
|
Average
contract revenue per MWh (d)
|
$59
|
$57
|
$57
|
$53
|
$50
|
(c) 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.
|
(d) Average
contract prices exclude payments that may be owed under the value sharing
agreement with the New York Power Authority.
IV.
|
Parent &
Other
|
Parent
& Other reported a loss of $(0.10) per share on an as-reported basis in
first quarter 2010 compared to an as-reported loss of $(0.27) per share in first
quarter 2009. On an operational basis, Parent & Other reported a
loss of $(0.18) per share in the current quarter and a loss of $(0.22) per share
in first quarter 2009. Lower interest expense due to lower
borrowings, including Parent debt redemptions, was the primary factor that
resulted in the change in results at Parent & Other for the
quarter.
V.
|
Other Financial
Performance Highlights
|
Earnings
Guidance
On April
15, 2010, Entergy revised its 2010 as-reported earnings guidance to a range of
$5.95 to $6.80 per share from $6.15 to $6.95 per share to reflect the potential
charge in connection with the previously announced business unwind of the
internal organizations created for Enexus and EquaGen. This charge
will be classified as a special item in 2010. The total potential
charge estimated at $0.40 to $0.45 per share includes previously identified
special items for spin-off dis-synergies and expenses for outside services
provided to pursue the spin-off, for which $0.25 per share had already been
reflected in as-reported earnings guidance. Entergy has initiated
efforts to eliminate spin-off dis-synergies as soon as possible during
2010.
On an
operational basis, Entergy affirmed its earnings per share guidance range of
$6.40 to $7.20, which was based on the current business structure and excluded
the special items described above. 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. The 2010 earnings guidance is detailed in Table 7
below.
Table
7: 2010 Earnings Per Share Guidance – As-Reported and
Operational
|
|||||
(Per
share in U.S. $) – Prepared October 2009; As-Reported Updated April 2010
(e)
|
|||||
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 Parent &
Other
|
0.14
|
||||
2010
As-Reported Earnings per Share Guidance Range
|
6.30
|
0.25
|
6.55
|
6.15
– 6.95
|
|
Incremental
special items related to the spin-off in connection with the business
unwind
|
(0.15)
– (0.20)
|
||||
Revised
2010 As-Reported Earnings per Share Guidance Range
|
6.30
|
0.05
– 0.10
|
6.35
– 6.40
|
5.95
– 6.80
|
|
|
(e) Updated
February 2010 to reflect 2009 final results and in April 2010 to reflect
the special item for the total potential charge for the business unwind of
Enexus and EquaGen.
|
Key
assumptions supporting 2010 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 (market prices
have since declined with 2010 now averaging near $40 per
MWh)
|
·
|
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
income 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
|
Revised
2010 As-Reported Earnings Guidance Range
·
|
In
connection with the business unwind of the internal organizations for
Enexus Energy Corporation and EquaGen LLC, the estimated range of a total
potential charge of $0.40 to $0.45 per share reflects the write-off of
capitalized costs incurred to date and certain other costs in accordance
with generally accepted accounting principles. This charge will
be reported as a special item. The range for this charge also
includes the previously identified special items for spin-off
dis-synergies and expenses for outside services provided to pursue the
spin-off in 2010.
|
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 assumed 6.75%;
actual is 6.1 – 6.3%)
|
Estimated
annual impacts shown in Table 8 are intended to be indicative rather than
precise guidance.
Table
8: 2010 Earnings Sensitivities
|
|||
(Per
share in U.S. $) – Prepared October 2009
|
|||
Variable
|
2010
Guidance Assumption
|
Description
of Change
|
Estimated
Annual
Impact (f)
|
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
|
(f) Based on 2009 average
fully diluted shares outstanding of approximately 196
million.
VI.
|
Long-term Financial
Outlook
|
Overarching Financial
Aspiration
Entergy
continues to aspire to deliver superior value to owners as measured by total
shareholder return. The company believes top-quartile total
shareholder returns are achieved by:
·
|
Operating
the business with the highest expectations and
standards,
|
·
|
Executing
on earnings growth opportunities while managing commodity and other
business risks,
|
·
|
Delivering
returns at or above the risk-adjusted cost of capital for each initiative,
project, business, etc.,
|
·
|
Maintaining
credit quality and flexibility,
|
·
|
Deploying
capital in a disciplined manner, whether for new investments, share
repurchases, dividends or debt retirements,
and
|
·
|
Being
disciplined as either a buyer or a seller consistent with the market or
Entergy’s proprietary
point-of-view.
|
Long-term Financial
Outlook
Over the
next five years, Entergy believes it offers a competitive utility investment
opportunity combined with a valuable option represented by a unique, clean,
non-utility nuclear generation business located in attractive power
markets. Table 9 summarizes the current long-term financial
outlook.
Table
9: Long-term Financial Outlook
|
||
Prepared
April 2010
|
||
Category
|
Long-term
Outlook
|
Assumption
|
Earnings
|
Utility
net income
|
5
to 6 percent compound annual net income growth rate over the 2010 – 2014
horizon (2009 base year).
|
Entergy
Nuclear results
|
Revenue
projections over the next five years are expected to routinely fluctuate
based on commodity markets – one of the most important fundamental drivers
for this business. While current forward power prices would
show a decline in the long-term financial outlook for this business
compared to 2010, Entergy Nuclear offers a valuable option taking into
consideration the contango forward curve and the potential positive
effects of an economic rebound (on market heat rates, capacity markets and
natural gas prices), new legislation and / or regulation over the longer
term.
|
|
Corporate
results
|
Results
will vary depending upon factors including future effective income tax and
interest rates, the amount of share repurchases and the ability to achieve
the targeted break-even financial result for the non-nuclear wholesale
assets business.
|
|
Capital
Deployment
|
A
balanced capital investment / return program
|
Entergy
continues to see productive investment opportunities at the Utility in the
coming years, as well as an investment outlook at Entergy Nuclear that
supports continued safe, secure and reliable operations and opportunistic
investments. Entergy aspires to fund this capital program
without issuing traditional common equity, while maintaining a competitive
capital return program. Given the company’s financial profile
with a mix of utility and non-utility businesses, return of capital is
expected to be provided similar to the past through a combination of
common stock dividends and share repurchases. Absent other
attractive investment opportunities, capital deployment through dividends
and share repurchases could total as much as $5 billion over the next five
years under the current long-term business outlook. The amount of share
repurchases may vary as a result of material changes in business results
or capital spending or new investment opportunities.
|
Credit
Quality
|
Strong
liquidity.
|
|
Solid
credit metrics that support ready access to capital on reasonable
terms.
|
||
The
long-term financial outlook should be considered in association with 2014
financial sensitivities as shown in Table 10. These sensitivities
illustrate the estimated change in earnings or Adjusted EBITDA resulting from
changes in business drivers. Estimated impacts shown in Table 10 are
intended to be illustrative.
Table 10: 2014
Financial Sensitivities – Illustrative
|
|||
Prepared
April 2010
|
|||
Long-term
Outlook
|
Assumption
|
Drivers
|
Estimated
Annual
Impact
|
Utility
|
(Per
share in U.S. $) (g)
|
||
Earnings
growth
|
5 –
6% compound annual net income growth rate from 2010 through 2014 (2009
base)
|
1%
retail sales growth
$100
million/year investment in service
1%
change in allowed ROE
1%
change in non-fuel operation and maintenance expense
$100
million change in debt
|
- /
+ 0.13
- /
+ 0.03
- /
+ 0.44
+ /
- 0.07
+ /
- 0.02
|
Entergy
Nuclear
|
(Adjusted
EBITDA
in
U.S. $; millions) (h)
|
||
Adjusted
EBITDA
|
Decline
in Adjusted EBITDA at current forward power prices compared to 2010, plus
option value
|
+0
– 1,500 Btu/kWh heat rate expansion
+$0
– 30/ton CO2
+$0
– 4/kW-mo. capacity price
- /
+ $0 – 2/MMBtu change in gas price
|
Up
to 300
Up
to 500
Up
to 200
Down
/ Up to 600
|
Corporate
|
(Per
share in U.S. $) (g)
|
||
Balanced
capital investment / return / credit quality
|
1%
change in interest rate on $1 billion debt
1%
change in overall effective tax rate
$500
million share repurchase
|
+ /
- 0.03
+ /
- 0.10
+
0.20 – 0.25
|
|
(g)
Based on estimated 2010 average fully diluted shares outstanding of
approximately 187 million.
(h)
Adjusted EBITDA, a non-GAAP financial measure, is defined as earnings
before interest, income taxes, depreciation and amortization and interest
and dividend income, excluding decommissioning expense and other than
temporary impairment losses on decommissioning trust fund
assets.
|
VII.
|
Appendices
|
Six
appendices are presented in this section as follows:
·
|
Appendix
A includes earnings per share variance analysis and detail on special
items that relate to the current quarter
results.
|
·
|
Appendix
B provides
information on selected pending local and federal regulatory
cases.
|
·
|
Appendix
C 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
D provides a summary of planned capital expenditures for the next three
years.
|
·
|
Appendix
E provides definitions of the operational performance measures and GAAP
and non-GAAP financial measures that are used in this
release.
|
·
|
Appendix
F provides a reconciliation of GAAP to non-GAAP financial measures used in
this release.
|
A.
|
Variance Analysis and
Special Items
|
Appendix
A-1 provides details of first quarter 2010 vs. 2009 as-reported and operational
earnings variance analysis for “Utility,” “Entergy Nuclear,” “Parent &
Other,” and “Consolidated.”
Appendix
A-1: As-Reported and Operational Earnings Per Share Variance
Analysis
|
|||||||||||
First
Quarter 2010 vs. 2009
|
|||||||||||
(Per
share in U.S. $, sorted in consolidated
as-reported
column, most to least favorable)
|
|||||||||||
Utility
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
||||||||
As-Reported
|
Opera-
tional
|
As-Reported
|
Opera-tional
|
As-
Reported
|
Opera-tional
|
As-
Reported
|
Opera-tional
|
||||
2009
earnings
|
0.56
|
0.56
|
0.91
|
0.95
|
(0.27)
|
(0.22)
|
1.20
|
1.29
|
|||
Net
revenue
|
0.29
|
0.29
|
(i)
|
(0.15)
|
(0.15)
|
(j)
|
0.01
|
0.01
|
0.15
|
0.15
|
|
Other
than temporary impairment losses
|
-
|
-
|
0.05
|
0.05
|
(k)
|
-
|
-
|
0.05
|
0.05
|
||
Share
repurchase effect
|
0.02
|
0.02
|
0.02
|
0.02
|
-
|
-
|
0.04
|
0.04
|
|||
Other
income (deductions)
|
(0.02)
|
(0.02)
|
0.05
|
0.05
|
(l)
|
-
|
-
|
0.03
|
0.03
|
||
Interest
and other charges
|
(0.05)
|
(0.05)
|
(m)
|
(0.10)
|
0.03
|
0.05
|
0.05
|
(n)
|
(0.10)
|
0.03
|
|
Taxes
other than income taxes
|
(0.01)
|
(0.01)
|
0.01
|
0.01
|
-
|
-
|
-
|
-
|
|||
Decommissioning
expense
|
-
|
-
|
(0.01)
|
(0.01)
|
-
|
-
|
(0.01)
|
(0.01)
|
|||
Depreciation/
amortization expense
|
(0.02)
|
(0.02)
|
(0.01)
|
-
|
-
|
-
|
(0.03)
|
(0.02)
|
|||
Nuclear
refueling outage expense
|
(0.01)
|
(0.01)
|
(0.01)
|
(0.01)
|
-
|
-
|
(0.02)
|
(0.02)
|
|||
Other
operation & maintenance expense
|
(0.04)
|
(0.04)
|
(0.15)
|
(0.04)
|
0.01
|
(0.02)
|
(0.18)
|
(0.10)
|
|||
Income
taxes – other
|
0.01
|
0.01
|
(0.12)
|
(0.12)
|
(o)
|
0.10
|
-
|
(0.01)
|
(0.11)
|
||
2010
earnings
|
0.73
|
0.73
|
0.49
|
0.78
|
(0.10)
|
(0.18)
|
1.12
|
1.33
|
|||
Utility
Net Revenue Variance Analysis
2010
vs. 2009
($
EPS)
|
|
First
Quarter
|
|
Weather
|
0.19
|
Sales
growth/ pricing
|
0.08
|
Other
|
0.02
|
Total
|
0.29
|
|
(i)
|
The
increase is due primarily to colder-than-normal weather during the current
period. Also, higher pricing resulting from adjustments to the
formula rate plans for Entergy Gulf States Louisiana, Entergy Louisiana
and Entergy Mississippi, as well as an increase in weather-adjusted sales
across all customer classes and jurisdictions, increased revenues during
the period.
|
|
(j)
|
The
decrease is due primarily to lower revenues at Entergy Nuclear in the
current period resulting from lower
pricing.
|
|
(k)
|
The
increase is due to the absence in the current period of impairments
recorded in first quarter 2009 associated with decommissioning trust fund
investments.
|
|
(l)
|
The
increase is due primarily to higher earnings resulting from sales of
securities held in decommissioning trust
investments.
|
(m)
|
The
decrease is due to higher interest expense on increased debt
borrowings.
|
|
(n)
|
The
increase is due primarily to lower interest expense on lower parent
borrowings including parent debt
redemptions.
|
|
(o)
|
The
decrease is due primarily to the change in tax law associated with
recently enacted federal health care
legislation.
|
Appendix
A-2 lists special items by business with quarter-to-quarter
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
A-2: Special Items (shown as positive / (negative) impact on
earnings)
|
|||
First
Quarter 2010 vs. 2009
|
|||
(Per
share in U.S. $)
|
|||
First Quarter
|
|||
2010
|
2009
|
Change
|
|
Utility
|
|||
None
|
-
|
-
|
-
|
Entergy
Nuclear
|
|||
Non-utility
nuclear spin-off expenses (p)
|
(0.29)
|
(0.04)
|
(0.25)
|
Parent
& Other
|
|||
Non-utility
nuclear spin-off expenses (p)
|
0.08
|
(0.05)
|
0.13
|
Total
Special Items
|
(0.21)
|
(0.09)
|
(0.12)
|
(U.S.
$ in millions)
|
|||
First Quarter
|
|||
2010
|
2009
|
Change
|
|
Utility
|
|||
None
|
-
|
-
|
-
|
Entergy
Nuclear
|
|||
Non-utility
nuclear spin-off expenses (p)
|
(54.3)
|
(6.6)
|
(47.7)
|
Parent
& Other
|
|||
Non-utility
nuclear spin-off expenses (p)
|
14.4
|
(10.6)
|
25.0
|
Total
Special Items
|
(39.9)
|
(17.2)
|
(22.7)
|
|
(p) Includes spin-off
dis-synergies and previously contracted expenses for outside services to
pursue the spin-off in both periods and the charge in connection with the
business unwind in 2010.
|
B.
|
Regulatory
Summary
|
|
Appendix
provides
a summary of selected regulatory cases and events that are
pending.
|
Appendix
B: 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
|
Rate Case Recent
Activity: All testimony has been filed. Current APSC Staff
position proposes a $49 million revenue requirement increase reflecting a
10.1% ROE and $10 million for the 2009 ice storm. In the event
a Formula Rate Plan (FRP) is adopted, Staff recommends a further ROE
reduction to 9.6%. EAI reduced its request to $168 million
reflecting a lower ROE at 10.65% and the reduction to remove the revenue
requirement associated with ice storm recovery from its case as discussed
below. Also, on February 11, 2010, the APSC requested comments
from parties in the rate case on various issues raised related to
transmission cost recovery mechanisms. On March 3, 2010, EAI
filed supplemental testimony regarding transmission costs and investments
and potential recovery through a transmission rider or the proposed
FRP.
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 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 purchases or construction /
acquisition of new transmission or generating
facilities. Finally, the proposed FRP includes an energy
efficiency-related mechanism. Hearings are scheduled to begin
in 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 Recent
Activity: The Administrative Law Judge approved the
establishment of EAI’s storm cost reserve account on April 16, 2010 using
the annual amount of $14.449 million previously
established. Hearings are scheduled in the securitization
docket for April 29, 2010, and an APSC order is due no later than June 15,
2010. Since EAI’s analysis demonstrated that retail customers
will benefit from lower costs using securitization versus conventional
utility financing, EAI conditionally removed ice storm recovery from the
pending rate case filing in its rebuttal testimony filed on March 24,
2010, pending authorization by the APSC to securitize these
costs.
Background: EAI
incurred approximately $123 million in estimated restoration costs
resulting from the severe ice storm that struck in January
2009. 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 was scheduled for 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,
indicating the ice storm restoration costs would be removed from the
pending rate case if the APSC approved EAI’s request to securitize the ice
storm costs. 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.
|
|
White Bluff Environmental
Controls Project Recent Activity: On February 26, 2010,
the APSC approved EAI’s request to withdraw its Act 310
application. On March 26, 2010, the Arkansas Pollution Control
and Ecology Commission voted to grant EAI’s variance request from the
state’s 2013 compliance date and tie the date to a compliance requirement
within five years of the United States Environmental Protection Agency’s
(U.S. EPA) approval of the state’s implementation plan.
Background: In
March 2009, EAI petitioned the APSC to undertake a project that would have
installed 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 had been required to meet more stringent SO2 and
NOx limits by 2013 in order to comply with the Arkansas Department of
Environmental Quality (ADEQ) State Implementation Plan regulations
implementing the U.S. EPA’s Regional Haze Rule. EAI conducted
economic analysis comparing the project to other supply options and
concluded the project was the lowest reasonable cost alternative. EAI had intended
to recover the project costs pursuant to Act 310 through an interim rate
schedule to be amended periodically. In December, the APSC
suspended the procedural schedule following letters submitted by the U.S.
EPA and the U.S. Department of Agriculture to the 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.
|
|
Show Cause Order Regarding
System Agreement / Future Operation and Control of EAI’s Generation and
Transmission Assets Recent Activity: In March, EAI filed
testimony and participated in a hearing in response to the APSC Show Cause
proceeding initiated in February 2010. Another hearing is
scheduled to take place in May 2010 following the filing of additional
testimony ordered by the APSC.
Background: On
February 11, 2010, the APSC issued a Show Cause order opening an inquiry
to conduct an investigation, with the intent to render its decision by the
end of 2010, regarding the prudence of EAI entering a successor Entergy
System Agreement, as opposed to becoming a stand-alone entity upon exit
from the System Agreement in December 2013, and whether EAI, as a
stand-alone utility should join the Southwest Power Pool Regional
Transmission Organization (SPP RTO) (the APSC subsequently added
participation as a member in the Midwest ISO as an alternative to be
evaluated). As a parallel matter, the APSC will also monitor
whether Entergy will make any meaningful enhancements to its Independent
Coordinator of Transmission (ICT) arrangement in 2010 with filings at
FERC. EAI noted in its
testimony
|
Appendix
B: Regulatory Summary Table (continued)
|
|
Company
|
Pending
Cases / Events
|
Retail
Regulation
|
|
Entergy
Arkansas (continued)
|
that
it is not reasonable to complete a comprehensive evaluation of strategic
options by the end of 2010 and that forcing a decision would place parties
in the untenable position of making critical decisions based on
insufficient information. EAI outlined three options for
post-System Agreement operation of its electrical system: EAI Self Provide
– as a stand-alone company for resource planning; EAI plus new
Coordination Agreements with Third Parties – EAI self provides or
contracts some functions, but also enters into one or more coordinating
and / or pooling agreements with third parties, such as SPP RTO; and
Successor Arrangements – EAI plans for its own generation resources but
enters into a new generation agreement with other Entergy operating
companies under a successor agreement that benefits all, but avoids the
litigation previously experienced. EAI’s plan is expected to
lead to a decision regarding critical path issues in late 2011; however,
EAI anticipates several transition plan elements will move forward in 2010
and require ongoing dialogue. In an attempt to reach
understanding of complex issues, EAI proposes to hold a series of five
technical conferences in the coming months targeting specific subject
matter. The initial technical conference is scheduled for May
5, 2010.
|
Entergy
Gulf States Louisiana
Authorized
ROE Range: 9.9% - 11.4%
(electric)
Last
Filed
Rate
Base:
$2.2
billion
(electric)
Filed
12/09 based on 12/31/08 test year
|
Formula Rate Plan Recent
Activity: Discovery continues on 2008 test year
filing. EGSL will make its 2009 test year filing by May 31,
2010.
Background: At
its October 2009 Business and Executive Session, the LPSC approved an
uncontested settlement 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 a one-time
rate reset 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 effect coincident with the November 2009 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 the latest schedule anticipating the LPSC could address this
matter at its May 2010 Business and Executive session. 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 2009, 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.
|
Storm Cost Recovery Recent
Activity: At its April 21, 2010 Business and Executive
Session, the LPSC approved uncontested stipulated settlements resolving
all issues in Phase I (level of storm cost recovery, level of recovery for
storm reserves and the allocation of the revenue requirements associated
with those amounts among retail customers) and Phases II and III (issuance
of system restoration bonds, the structure of the proposed financings and
non-shareholder capital contributions, system restoration charges and
storm cost offset riders).
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
financing 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) financing. EGSL
expects significant potential financing savings from pursuing Act 55
alternative financing and plans to guarantee customer savings, consistent
with the approach used for hurricanes Katrina and Rita. On
December 30, 2009, EGSL entered into a black box stipulation agreement
with the LPSC Staff that provided for total recoverable costs of nearly
$234 million (greater than 98% of EGSL’s request) and permitted
replenishing EGSL’s storm reserve in the amount of $90 million when Act 55
financing is accomplished.
|
|
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
|
Formula Rate Plan Recent
Activity: At its April 21, 2010 Business and Executive Session, the
LPSC accepted the joint LPSC Staff / ELL report indicating agreement to
implement a prospective reduction in ELL’s rates of $144.4 thousand
beginning with the May 2010 billing cycle and to refund $72.2 thousand
plus judicial interest through the fuel adjustment
clause. Further, ELL will move the recovery of approximately
$12.5 million of capacity costs associated with EAI’s Wholesale Baseload
Capacity Resource from fuel adjustment clause recovery to base rate
recovery. ELL will make its 2009 test year filing by May 15,
2010.
Background: At its
October 2009 Business and Executive Session, the LPSC approved an
uncontested settlement 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 2009 billing cycle and were 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 latest
schedule anticipating the LPSC could address this matter at its May 2010
Business and Executive session. In addition, in December 2009,
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.
|
Appendix
B: Regulatory Summary Table (continued)
|
|
Company
|
Pending
Cases/Events
|
Retail
Regulation
|
|
Entergy
Louisiana
(continued)
|
Storm Cost Recovery Recent
Activity: At its April 21, 2010 Business and Executive
Session, the LPSC approved uncontested stipulated settlements resolving
all issues in Phase I (level of storm cost recovery, level of recovery for
storm reserves and the allocation of the revenue requirements associated
with those amounts among retail customers) and Phases II and III (issuance
of system restoration bonds, the structure of the proposed financings and
non-shareholder capital contributions, system restoration charges and
storm cost offset riders).
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
financing 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) financing. ELL
expects significant potential financing savings from pursuing Act 55
alternative financing and plans to guarantee customer savings, consistent
with approach used for hurricanes Katrina and Rita. On December
30, 2009, ELL entered into a black box stipulation agreement with the LPSC
Staff that provided for total recoverable costs of approximately $394
million (greater than 98% of ELL’s request) and permitted replenishing
ELL’s storm reserve in the amount of $200 million when Act 55 financing is
accomplished.
|
Acadia Unit 2 Acquisition
Recent Activity: Hearings are scheduled to begin in
September 2010 pursuant to the procedural schedule established February 9,
2010. Consideration of the application at the January 2011 LPSC
Business and Executive Session would accommodate a closing by the March
31, 2011 deadline triggering certain price increases. The
Hart-Scott-Rodino Antitrust Improvements Act filing was made in March
2010. On April 9, 2010, the LPSC approved ELL and EGSL’s
uncontested request concerning the limited-term Interim Tolling Agreement
(ITA) associated with the Acadia acquisition. The ITA,
originally scheduled to begin on May 1, 2010, is now anticipated to begin
on June 1, 2010 to allow the companies time to appropriately address
various regulatory considerations.
Background: ELL
signed a purchase and sale agreement to acquire the 580 MW Unit 2 of the
Acadia Energy Center for $300 million ($517/kW). ELL proposes
to acquire 100% of Acadia Unit 2 and a 50% 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 early 2011. ELL has also entered into an Interim Tolling
Agreement (ITA) to purchase the capacity and energy output of Acadia Unit
2. The ITA, originally scheduled to begin on May 1, 2010, is
now anticipated to begin on June 1, 2010 to allow the companies time to
appropriately address various regulatory considerations. 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.
|
|
Little Gypsy Repowering Recent
Activity: Discovery continues, and hearings are
scheduled for October 2010.
Background: In
November 2007, the LPSC voted unanimously, subject to conditions, to
approve ELL’s request to repower the 538 MW Little Gypsy unit to utilize
CFB technology. 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). 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 March 2009, the
LPSC issued an order directing ELL to temporarily suspend the 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. In April 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. 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. ELL dismissed its proceeding to
recover cash earnings on Construction Work in Progress (CWIP) for the
Little Gypsy project. In October 2009, ELL filed 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 2010, 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.
|
Appendix
B: Regulatory Summary Table (continued)
|
|
Company
|
Pending
Cases/Events
|
Retail
Regulation
|
|
Entergy
Mississippi
Authorized
ROE
Range: 10.79% -
13.05%
(subject
to
review
/ approval)
Last
Filed
Rate
Base:
$1.5
billion
Filed
3/10 based on 12/31/09
test
year
|
Formula Rate Plan Recent
Activity: On March 4, 2010, the MPSC approved
modifications to EMI’s FRP that (1) aligns EMI’s FRP more closely with the
FRPs of the other regulated gas and electric utilities in Mississippi, (2)
resets the ROE and bandwidth based upon performance ratings, (3) rescores
the performance adjustment factors, (4) eliminates the current $14.5
million revenue adjustment limit and changes the 2% of revenues limit to a
4% limit, with any adjustment over 2% requiring a hearing, and (5) directs
EMI to phase-out the summer / winter rate differential in residential
rates over two years. On March 15, 2010, EMI filed its first
evaluation report under its new FRP for the 2009 test year. The
filing reflected a 10.66% earned ROE and total rate increase of $11.8
million. The calculated 11.92% FRP midpoint ROE includes the
benefit of a 0.76% performance incentive. The FRP calls for new
rates to be implemented in the June 2010 billing cycle, subject to review
and final approval by the MPSC.
Background: EMI
had been operating under a FRP last approved in December
2002. The FRP allowed the company’s earned ROE to increase or
decrease within a bandwidth with no change in rates. Earnings
outside the bandwidth were allocated 50% to customers and 50% to the
company, but on a prospective basis only. The plan also
provided 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.
|
Fuel Recovery / Attorney
General Complaint Recent Activity: 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. On
March 9, 2010, the MPSC established a Fuel Adjustment Clause (FAC)
rulemaking to consider various issues, including an analysis of the
advantages / disadvantages of using monthly, quarterly, semi-annual or
annual FACs. A proposed rule is expected to be issued by May
20, 2010. On March 30, 2010, McFadden Consulting Group, Inc.
presented their report on the management review of EMI’s fuel practices
and procedures for the two year period October 2007 through September
2009. In the report, McFadden indicated that the fuel and
purchased power costs for Mississippi are reasonable and at the lowest
cost possible given the operations and design of the Entergy
system.
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 FAC 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. 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 FAC by an independent audit
firm. The financial portion of the fuel audit undertaken at the
request of the MPSC performed by Horne Group LLP 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. At the January 2010 MPSC open / public meeting, the
Mississippi Public Utilities Staff stated that costs identified by Horne
as excludable were indeed properly recoverable in EMI’s
FAC.
|
|
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
|
Formula Rate Plan Recent
activity: None. ENOI will make its 2009 test
year filing by May 31, 2010.
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 CCNO approved the Energy Smart
Resolution. Energy Smart is the energy efficiency program that
was filed pursuant to ENOI’s April 2009 rate case
settlement.
|
Appendix
B: Regulatory Summary Table (continued)
|
|
Company/
Proceeding
|
Pending
Cases/Events
|
Retail
Regulation
|
|
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: On February 18, 2010, the Administrative Law
Judge issued an order approving a unanimous settlement on interim rates
and the procedural schedule reached on February 11, 2010 with the parties
in the rate case. The settlement calls for an interim rate
increase of $17.5 million to begin on May 1, 2010 and the withdrawal of
the Purchased Power Recovery Factor (PCRF) docket pertaining to the
Arkansas wholesale baseload (WBL) capacity. The procedural
schedule calls for hearings in July 2010, with a final order to be issued
November 1, 2010 and permanent rates to be effective relating back to
service rendered on / after September 13, 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 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 had 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. 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.
|
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: The Operating Companies continue to meet with
Staffs and / or advisors of retail regulatory commissions to discuss a
proposed framework for Successor Arrangements to the current System
Agreement, which is being pursued in parallel with evaluation by the
Entergy Regional State Committee (E-RSC) of the SPP RTO and modified
Independent Coordinator of Transmission (ICT) alternatives. In
early April, Entergy Corporation and the Entergy Operating Companies
determined in connection with their decision-making process that it is
appropriate to agree and commit that no Entergy Operating Company will
enter voluntarily into successor arrangements with the other Entergy
Operating Companies if its retail regulator finds successor arrangements
are not in the public interest.
Paper
hearings concluded in February 2010 in the interruptible / curtailable
case on the appropriateness of refunds resulting from changes in the
treatment of interruptible load in the allocation of costs among the
Operating Companies under the System Agreement. Resolution of
this proceeding is expected to have implications regarding the question of
whether FERC provided sufficient rationale for not ordering refunds in the
System Agreement case; this issue as well as whether FERC
impermissibly delayed implementation of the bandwidth remedy are also
pending before the FERC.
On
a preliminary basis, the 2010 rough production cost equalization payment
by EAI, based on calendar year 2009 production costs, was estimated at $70
million to be paid collectively to EGSL, ELL and ENOI. This
payment reflects a reduction of approximately $320 million versus calendar
year 2008 production costs, due primarily to lower natural gas prices. The
actual payments / receipts will not be calculated until the Operating
Companies' FERC Form 1s have been filed.
On
April 16, 2010, the LPSC made a filing at the FERC alleging that Entergy
violated the System Agreement by permitting EAI to make non-requirements
sales to non-affiliated third parties rather than making such energy
available to the other utility Operating Companies’
customers. The LPSC filing also stated these non-requirements
sales caused harm to the Operating Companies’ customers of $144.4 million
over the period 2000-2009, and these customers should be compensated for
this harm by Entergy’s shareholders. The Utility operating
companies believe the LPSC’s allegations are without merit and are
scheduled to file rebuttal testimony May 25.
Background: The
System Agreement case addresses the allocation of production costs among
the Utility Operating Companies. In 2005, the FERC issued
orders that require each Operating Company’s production costs to be
within
+ /
- 11% of System average production costs and set 2007 as the first
possible year of payments among Entergy’s Operating Companies, based on
calendar year 2006 actual production costs. Upon appeal, 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.
Bandwidth
filings for the calendar years 2006 through 2008 production costs required
payments from EAI to various other Operating Companies of approximately
$252 million, $252 million and $390 million for test years 2006, 2007 and
2008 respectively. FERC set each of these bandwidth filings for
hearing following protests from retail regulatory commissions and / or
third parties. A final order in the bandwidth proceeding
related to 2006 calendar year production costs has been issued by the
FERC, and requests for rehearing and clarification have been
filed. Bandwidth proceedings based on 2007 and 2008 calendar
year production costs remain outstanding.
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 effective December 2013 and
November 2015, respectively. On November 19, 2009, FERC
accepted notices of cancellation and determined EAI and EMI are
permitted
|
Appendix
B: Regulatory Summary Table (continued)
|
|
Company/
Proceeding
|
Pending
Cases/Events
|
Wholesale
Regulation
|
|
System
Agreement
(continued)
|
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. The LPSC and CCNO
have requested rehearing of the FERC’s decision. EAI continues to evaluate
alternatives, including stand-alone operation of its generation
facilities, EAI participating as a member of the SPP RTO or Midwest ISO
and potential Successor Arrangements.
|
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: The E-RSC is generally conducting meetings
monthly and in March 2010 selected the consulting firm ESPY Energy
Solutions to assist in their evaluations. In March 2010, FERC
also selected Charles Rivers & Associates to perform the cost-benefit
analysis associated with the current ICT versus SPP RTO
evaluation.
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
Operating Companies 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 that is used to determine whether
costs of transmission upgrades should be rolled into transmission rates or
directly assigned to customers requesting or causing the upgrade to be
built, serving as reliability coordinator the transmission system and
overseeing the WPP.
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 E-RSC
formed in the Fall of 2009, including one representative from each of the
Entergy Operating Company retail regulators, to consider several of the
issues related to the Entergy transmission system. The Utility
Operating Companies expect that the E-RSC will reflect in its evaluation
process the cost-benefit analysis that is being jointly sponsored by the
E-RSC and FERC that will compare the current ICT arrangement to joining
the SPP RTO. 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 (1) require the Entergy Operating
Companies to file with the FERC proposed modifications to the cost
allocation policy for transmission upgrades and (2) add projects to the
Operating Companies’ transmission construction plan. It is
anticipated certain potential modifications to the ICT will be implemented
in November 2010, with other potential modifications being considered if
the ICT is ultimately determined to be the appropriate longer term
option. 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.
|
(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.
C.
|
Financial Performance
Measures and Historical Performance
Measures
|
Appendix
C-1 provides comparative financial performance measures for the current
quarter. Appendix C-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
F.
Appendix
C-1: GAAP and Non-GAAP Financial Performance
Measures
|
||||
First
Quarter 2010 vs. 2009
(see
Appendix E for definitions of certain
measures)
|
||||
For
12 months ending March 31
|
2010
|
2009
|
Change
|
|
GAAP
Measures
|
||||
Return
on average invested capital – as-reported
|
7.6%
|
7.6%
|
-
|
|
Return
on average common equity – as-reported
|
13.8%
|
14.1%
|
(0.3%)
|
|
Net
margin – as-reported
|
11.3%
|
8.8%
|
2.5%
|
|
Cash
flow interest coverage
|
6.3
|
6.5
|
(0.2)
|
|
Book
value per share
|
$46.81
|
$44.02
|
$2.79
|
|
End
of period shares outstanding (millions)
|
189.3
|
196.1
|
(6.8)
|
|
Non-GAAP
Measures
|
||||
Return
on average invested capital – operational
|
8.0%
|
8.0%
|
-
|
|
Return
on average common equity – operational
|
14.9%
|
15.0%
|
(0.1%)
|
|
Net
margin – operational
|
12.2%
|
9.4%
|
2.8%
|
|
As
of March 31 ($ in millions)
|
2010
|
2009
|
Change
|
|
GAAP
Measures
|
||||
Cash
and cash equivalents
|
1,657
|
1,803
|
(146)
|
|
Revolver
capacity
|
1,417
|
725
|
692
|
|
Total
debt
|
12,152
|
12,034
|
118
|
|
Securitization
debt
|
838
|
310
|
528
|
|
Debt
to capital ratio
|
57.0%
|
57.4%
|
(0.4%)
|
|
Off-balance
sheet liabilities:
|
||||
Debt
of joint ventures – Entergy’s share
|
114
|
124
|
(10)
|
|
Leases
– Entergy’s share
|
530
|
449
|
81
|
|
Total
off-balance sheet liabilities
|
644
|
573
|
71
|
|
Non-GAAP
Measures
|
||||
Debt
to capital ratio, excluding securitization debt
|
55.2%
|
56.7%
|
(1.5%)
|
|
Total
gross liquidity
|
3,074
|
2,528
|
546
|
|
Net
debt to net capital ratio, excluding securitization debt
|
51.3%
|
52.6%
|
(1.3%)
|
|
Net
debt ratio including off-balance sheet liabilities, excluding
securitization debt
|
52.9%
|
54.0%
|
(1.1%)
|
|
Appendix
C-2: Historical Performance Measures
(see
Appendix
E
for definitions of measures)
|
||||||||||||||||
2Q08
|
3Q08
|
4Q08
|
1Q09
|
2Q09
|
3Q09
|
4Q09
|
1Q10
|
09YTD
|
10YTD
|
|||||||
Financial
|
||||||||||||||||
EPS
– as-reported ($)
|
1.37
|
2.41
|
0.89
|
1.20
|
1.14
|
2.32
|
1.64
|
1.12
|
1.20
|
1.12
|
||||||
Less
– special items ($)
|
(0.09)
|
(0.09)
|
(0.10)
|
(0.09)
|
(0.09)
|
(0.08)
|
(0.11)
|
(0.21)
|
(0.09)
|
(0.21)
|
||||||
EPS
– operational ($)
|
1.46
|
2.50
|
0.99
|
1.29
|
1.23
|
2.40
|
1.75
|
1.33
|
1.29
|
1.33
|
||||||
Trailing
Twelve Months
|
||||||||||||||||
ROIC
– as-reported (%)
|
8.6
|
8.1
|
8.1
|
7.6
|
7.5
|
7.1
|
7.7
|
7.6
|
7.6
|
7.6
|
||||||
ROIC
– operational (%)
|
8.8
|
8.4
|
8.4
|
8.0
|
7.8
|
7.5
|
8.1
|
8.0
|
8.0
|
8.0
|
||||||
ROE
– as-reported (%)
|
16.3
|
15.6
|
15.4
|
14.1
|
13.7
|
13.2
|
14.9
|
13.8
|
14.1
|
13.8
|
||||||
ROE
– operational (%)
|
17.0
|
16.4
|
16.1
|
15.0
|
14.6
|
14.1
|
15.7
|
14.9
|
15.0
|
14.9
|
||||||
Cash
flow interest coverage
|
5.0
|
7.0
|
6.5
|
6.5
|
6.7
|
5.5
|
6.1
|
6.3
|
6.5
|
6.3
|
||||||
Debt
to capital ratio (%)
|
60.7
|
60.4
|
59.7
|
57.4
|
55.9
|
56.7
|
57.4
|
57.0
|
57.4
|
57.0
|
||||||
Debt
to capital ratio, excluding securitization debt (%)
|
60.0
|
59.8
|
59.1
|
56.7
|
55.3
|
56.1
|
55.6
|
55.2
|
56.7
|
55.2
|
||||||
Net
debt to net capital ratio, excluding securitization debt
(%)
|
57.6
|
54.1
|
54.8
|
52.6
|
52.2
|
53.4
|
51.5
|
51.3
|
52.6
|
51.3
|
||||||
Utility
|
||||||||||||||||
GWh
billed
|
||||||||||||||||
Residential
|
7,372
|
10,671
|
6,992
|
7,893
|
7,100
|
11,213
|
7,421
|
9,645
|
7,893
|
9,645
|
||||||
Commercial
& Gov’t
|
7,275
|
8,646
|
6,992
|
6,756
|
7,095
|
8,794
|
7,240
|
7,064
|
6,756
|
7,064
|
||||||
Industrial
|
9,730
|
10,110
|
8,626
|
8,139
|
8,790
|
9,473
|
9,235
|
8,733
|
8,139
|
8,733
|
||||||
Wholesale
|
1,440
|
1,431
|
1,240
|
1,387
|
1,313
|
1,164
|
998
|
1,317
|
1,387
|
1,317
|
||||||
O&M
expense/MWh
|
$19.48
|
$14.43
|
$23.95
|
$18.51
|
$20.96
|
$15.77
|
$20.18
|
$17.29
|
$18.51
|
$17.29
|
||||||
Reliability
|
||||||||||||||||
SAIFI
|
1.9
|
1.9
|
1.9
|
1.8
|
1.7
|
1.7
|
1.8
|
1.7
|
1.8
|
1.7
|
||||||
SAIDI
|
215
|
227
|
216
|
208
|
194
|
203
|
210
|
213
|
208
|
213
|
||||||
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
|
$58.22
|
$61.59
|
$56.69
|
$63.84
|
$59.22
|
$61.70
|
$59.43
|
$58.72
|
$63.84
|
$58.72
|
||||||
Production
cost/MWh (s)
|
$23.11
|
$21.77
|
$22.77
|
$23.14
|
$24.30
|
$22.57
|
$23.20
|
$23.70
|
$23.14
|
$23.70
|
||||||
Non-fuel
O&M expense/ purchased power per MWh (s)
|
$23.42
|
$21.19
|
$23.06
|
$22.44
|
$25.33
|
$22.11
|
$23.60
|
$23.63
|
$22.44
|
$23.63
|
||||||
GWh
billed
|
10,145
|
10,316
|
10,489
|
10,074
|
8,980
|
10,876
|
11,052
|
10,255
|
10,074
|
10,255
|
||||||
Capacity
factor (%)
|
92
|
95
|
94
|
92
|
81
|
100
|
99
|
94
|
92
|
94
|
||||||
|
(s)
2009 and 2010 excludes the effect of the non-utility nuclear spin-off
expenses special item at Entergy
Nuclear.
|
D.
|
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
D. 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 $420 million for the installation of scrubbers and low NOx
burners at White Bluff which was delayed upon approval of a variance from
the October 2013 compliance date by the Arkansas Pollution Control and
Ecology Commission as discussed more fully in Appendix
B.
|
·
|
Entergy
Nuclear: dry cask storage, nuclear license renewal
efforts, component replacement across the fleet, NYPA value sharing, the
Indian Point Independent Safety Evaluation and spending to comply with
revised NRC security requirements.
|
Appendix
D: 2010 – 2012 Planned Capital Expenditures
|
||||
($ in millions) – Prepared February
2010
|
||||
2010
|
2011
|
2012
|
Total
|
|
Maintenance
capital
|
||||
Utility
and 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
and 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
|
E.
|
Definitions
|
Appendix
E 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
E: 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 Power Purchase Agreement 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
PPA
|
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
E: 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 business joint ventures at non-nuclear wholesale
assets
|
Leases
(Entergy’s share)
|
Operating
leases held by subsidiaries capitalized at implicit interest
rate
|
Debt
to capital
|
Gross
debt divided by total capitalization
|
Securitization
debt
|
Debt
associated with securitization bonds issued to recover storm costs from
hurricanes Rita, Ike and Gustav at Entergy Texas
|
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
|
Debt
to capital, excluding securitization debt
|
Gross
debt divided by total capitalization, excluding securitization
debt
|
Net
debt to net capital, excluding securitization debt
|
Gross
debt less cash and cash equivalents divided by total capitalization less
cash and cash equivalents, excluding securitization
debt
|
Net
debt including off-balance sheet liabilities, excluding securitization
debt
|
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; both gross debt and total capitalization are
also adjusted to exclude securitization debt
|
F.
|
GAAP to Non-GAAP
Reconciliations
|
Appendix F-1 and
Appendix F-2
provide reconciliations of various non-GAAP financial measures disclosed in this
release to their most comparable GAAP measure.
Appendix
F-1: Reconciliation of GAAP to Non-GAAP Financial Measures – Return on
Equity, Return on Invested Capital and Net Margin
Metrics
|
||||||||
($
in millions)
|
||||||||
2Q08
|
3Q08
|
4Q08
|
1Q09
|
2Q09
|
3Q09
|
4Q09
|
1Q10
|
|
As-reported
Net Income-rolling 12 months (A)
|
1,235
|
1,244
|
1,221
|
1,147
|
1,103
|
1,088
|
1,231
|
1,210
|
Preferred
dividends
|
23
|
21
|
20
|
20
|
20
|
20
|
20
|
20
|
Tax
effected interest expense
|
390
|
375
|
374
|
366
|
368
|
361
|
351
|
372
|
As-reported
Net Income, rolling 12 months including preferred dividends and tax
effected interest expense (B)
|
1,648
|
1,640
|
1,615
|
1,533
|
1,491
|
1,469
|
1,602
|
1,602
|
Special
items in prior quarters
|
(32)
|
(50)
|
(35)
|
(55)
|
(54)
|
(54)
|
(49)
|
(53)
|
Special
items in current quarter
|
||||||||
Nuclear
spin-off expenses
|
(18)
|
(17)
|
(20)
|
(17)
|
(17)
|
(15)
|
(21)
|
(40)
|
Total special items
(C)
|
(50)
|
(67)
|
(55)
|
(72)
|
(71)
|
(69)
|
(71)
|
(94)
|
Operational
earnings, rolling 12 months including preferred dividends and tax effected
interest expense (B-C)
|
1,698
|
1,707
|
1,670
|
1,605
|
1,562
|
1,538
|
1,673
|
1,696
|
Operational
earnings, rolling 12 months (A-C)
|
1,285
|
1,311
|
1,276
|
1,219
|
1,174
|
1,157
|
1,302
|
1,304
|
Average
invested capital (D)
|
19,244
|
20,236
|
19,927
|
20,126
|
19,995
|
20,629
|
20,748
|
21,149
|
Average
common equity (E)
|
7,555
|
7,973
|
7,915
|
8,152
|
8,045
|
8,230
|
8,290
|
8,745
|
Operating
revenues (F)
|
12,150
|
12,825
|
13,094
|
13,018
|
12,275
|
11,248
|
10,746
|
10,716
|
ROIC
– as-reported % (B/D)
|
8.6
|
8.1
|
8.1
|
7.6
|
7.5
|
7.1
|
7.7
|
7.6
|
ROIC
– operational % ((B-C)/D)
|
8.8
|
8.4
|
8.4
|
8.0
|
7.8
|
7.5
|
8.1
|
8.0
|
ROE
– as-reported % (A/E)
|
16.3
|
15.6
|
15.4
|
14.1
|
13.7
|
13.2
|
14.9
|
13.8
|
ROE
– operational % ((A-C)/E)
|
17.0
|
16.4
|
16.1
|
15.0
|
14.6
|
14.1
|
15.7
|
14.9
|
Net
margin – as-reported % (A/F)
|
10.2
|
9.7
|
9.3
|
8.8
|
9.0
|
9.7
|
11.5
|
11.3
|
Net
margin – operational % ((A-C)/F)
|
10.6
|
10.2
|
9.7
|
9.4
|
9.6
|
10.3
|
12.1
|
12.2
|
Appendix
F-2: Reconciliation of GAAP to Non-GAAP Financial Measures – Credit and
Liquidity Metrics
|
||||||||
($
in millions)
|
||||||||
2Q08
|
3Q08
|
4Q08
|
1Q09
|
2Q09
|
3Q09
|
4Q09
|
1Q10
|
|
Gross
debt (A)
|
11,768
|
12,656
|
12,279
|
12,034
|
11,510
|
11,522
|
12,014
|
12,152
|
Less
securitization debt (B)
|
318
|
318
|
310
|
310
|
301
|
301
|
838
|
838
|
Gross
debt, excluding securitization debt (C)
|
11,450
|
12,338
|
11,969
|
11,724
|
11,209
|
11,221
|
11,176
|
11,314
|
Less
cash and cash equivalents (D)
|
1,086
|
2,556
|
1,920
|
1,803
|
1,281
|
1,131
|
1,710
|
1,657
|
Net
debt, excluding securitization debt (E)
|
10,364
|
9,782
|
10,049
|
9,921
|
9,928
|
10,090
|
9,466
|
9,657
|
Total
capitalization (F)
|
19,401
|
20,944
|
20,557
|
20,975
|
20,588
|
20,315
|
20,939
|
21,322
|
Less
securitization debt (B)
|
318
|
318
|
310
|
310
|
301
|
301
|
838
|
838
|
Total
capitalization, excluding securitization debt (G)
|
19,083
|
20,626
|
20,247
|
20,665
|
20,287
|
20,014
|
20,101
|
20,484
|
Less
cash and cash equivalents (D)
|
1,086
|
2,556
|
1,920
|
1,803
|
1,281
|
1,131
|
1,710
|
1,657
|
Net
capital, excluding securitization debt (H)
|
17,997
|
18,070
|
18,327
|
18,862
|
19,006
|
18,883
|
18,391
|
18,827
|
Debt
to capital ratio % (A/F)
|
60.7
|
60.4
|
59.7
|
57.4
|
55.9
|
56.7
|
57.4
|
57.0
|
Debt
to capital ratio, excluding securitization debt % (C/G)
|
60.0
|
59.8
|
59.1
|
56.7
|
55.3
|
56.1
|
55.6
|
55.2
|
Net
debt to net capital ratio, excluding securitization debt %
(E/H)
|
57.6
|
54.1
|
54.8
|
52.6
|
52.2
|
53.4
|
51.5
|
51.3
|
Off-balance
sheet liabilities (I)
|
638
|
637
|
574
|
573
|
569
|
567
|
646
|
644
|
Net
debt to net capital ratio including off-balance sheet liabilities,
excluding securitization debt % ((E+I)/(H+I))
|
59.0
|
55.7
|
56.2
|
54.0
|
53.6
|
54.8
|
53.1
|
52.9
|
Revolver
capacity (J)
|
826
|
374
|
645
|
725
|
1,585
|
1,647
|
1,464
|
1,417
|
Gross
liquidity (D+J)
|
1,912
|
2,930
|
2,565
|
2,528
|
2,866
|
2,778
|
3,174
|
3,074
|
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 Entergy’s Form 10-K for the year ended December 31, 2009,
and Entergy’s other reports and filings made under the Securities Exchange Act
of 1934, (b) uncertainties associated with rate proceedings, formula rate plans
and other cost recovery mechanisms, (c) uncertainties associated with efforts to
remediate the effects of major storms and recover related restoration costs, (d)
nuclear operating and regulatory risks, and (e) legislative and regulatory
actions, and conditions in commodity and capital markets during the periods
covered by the forward-looking statements, in addition to other factors
described elsewhere in this release and in subsequent securities
filings.
VIII.
|
Financial
Statements
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Balance Sheet
|
||||||||||||||||
March
31, 2010
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
ASSETS
|
||||||||||||||||
CURRENT
ASSETS
|
||||||||||||||||
Cash
and cash equivalents:
|
||||||||||||||||
Cash
|
$ | 70,339 | $ | 1,171 | $ | 3,936 | $ | 75,446 | ||||||||
Temporary
cash investments
|
968,572 | 558,764 | 54,252 | 1,581,588 | ||||||||||||
Total
cash and cash equivalents
|
1,038,911 | 559,935 | 58,188 | 1,657,034 | ||||||||||||
Securitization
recovery trust account
|
35,037 | - | - | 35,037 | ||||||||||||
Notes
receivable
|
- | 1,137,023 | (1,137,023 | ) | - | |||||||||||
Accounts
receivable:
|
||||||||||||||||
Customer
|
406,039 | 164,618 | - | 570,657 | ||||||||||||
Allowance
for doubtful accounts
|
(28,230 | ) | - | (202 | ) | (28,432 | ) | |||||||||
Associated
companies
|
25,150 | 43,695 | (68,845 | ) | - | |||||||||||
Other
|
127,921 | - | 16,195 | 144,116 | ||||||||||||
Accrued
unbilled revenues
|
250,480 | - | 177 | 250,657 | ||||||||||||
Total
accounts receivable
|
781,360 | 208,313 | (52,675 | ) | 936,998 | |||||||||||
Deferred
fuel costs
|
24,678 | - | - | 24,678 | ||||||||||||
Accumulated
deferred income taxes
|
27,221 | 1,403 | (4,469 | ) | 24,155 | |||||||||||
Fuel
inventory - at average cost
|
200,654 | 528 | 1,997 | 203,179 | ||||||||||||
Materials
and supplies - at average cost
|
531,347 | 300,348 | 2,020 | 833,715 | ||||||||||||
Deferred
nuclear refueling outage costs
|
92,034 | 122,121 | - | 214,155 | ||||||||||||
System
agreement cost equalization
|
70,000 | - | - | 70,000 | ||||||||||||
Prepayments
and other
|
221,200 | 302,010 | 210,459 | 733,669 | ||||||||||||
TOTAL
|
3,022,442 | 2,631,681 | (921,503 | ) | 4,732,620 | |||||||||||
OTHER
PROPERTY AND INVESTMENTS
|
||||||||||||||||
Investment
in affiliates - at equity
|
734,578 | 1,330,589 | (2,025,516 | ) | 39,651 | |||||||||||
Decommissioning
trust funds
|
1,388,755 | 1,941,926 | - | 3,330,681 | ||||||||||||
Non-utility
property - at cost (less accumulated depreciation)
|
158,499 | 5,972 | 82,825 | 247,296 | ||||||||||||
Other
|
70,067 | 6,100 | 35,173 | 111,340 | ||||||||||||
TOTAL
|
2,351,899 | 3,284,587 | (1,907,518 | ) | 3,728,968 | |||||||||||
PROPERTY,
PLANT, AND EQUIPMENT
|
||||||||||||||||
Electric
|
32,580,678 | 3,555,991 | 371,491 | 36,508,160 | ||||||||||||
Property
under capital lease
|
782,722 | - | - | 782,722 | ||||||||||||
Natural
gas
|
315,697 | - | 439 | 316,136 | ||||||||||||
Construction
work in progress
|
1,213,053 | 451,291 | 3,376 | 1,667,720 | ||||||||||||
Nuclear
fuel under capital lease
|
- | - | - | - | ||||||||||||
Nuclear
fuel
|
729,229 | 511,216 | - | 1,240,445 | ||||||||||||
TOTAL
PROPERTY, PLANT AND EQUIPMENT
|
35,621,379 | 4,518,498 | 375,306 | 40,515,183 | ||||||||||||
Less
- accumulated depreciation and amortization
|
16,243,939 | 581,809 | 150,440 | 16,976,188 | ||||||||||||
PROPERTY,
PLANT AND EQUIPMENT - NET
|
19,377,440 | 3,936,689 | 224,866 | 23,538,995 | ||||||||||||
DEFERRED
DEBITS AND OTHER ASSETS
|
||||||||||||||||
Regulatory
assets:
|
||||||||||||||||
Regulatory
asset for income taxes - net
|
625,391 | - | - | 625,391 | ||||||||||||
Other
regulatory assets
|
3,738,435 | - | - | 3,738,435 | ||||||||||||
Deferred
fuel costs
|
172,202 | - | - | 172,202 | ||||||||||||
Goodwill
|
374,099 | 3,073 | - | 377,172 | ||||||||||||
Accumulated
deferred income taxes
|
8,592 | - | 65,436 | 74,028 | ||||||||||||
Other
|
270,015 | 883,187 | (31,611 | ) | 1,121,591 | |||||||||||
TOTAL
|
5,188,734 | 886,260 | 33,825 | 6,108,819 | ||||||||||||
- | ||||||||||||||||
TOTAL
ASSETS
|
$ | 29,940,515 | $ | 10,739,217 | $ | (2,570,330 | ) | $ | 38,109,402 | |||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Balance Sheet
|
||||||||||||||||
March
31, 2010
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||
CURRENT
LIABILITIES
|
||||||||||||||||
Currently
maturing long-term debt
|
$ | 411,002 | $ | 28,412 | $ | 361,000 | $ | 800,414 | ||||||||
Notes
payable:
|
||||||||||||||||
Associated
companies
|
5,388 | - | (5,388 | ) | - | |||||||||||
Other
|
175,498 | - | - | 175,498 | ||||||||||||
Account
payable:
|
||||||||||||||||
Associated
companies
|
17,724 | 5,851 | (23,575 | ) | - | |||||||||||
Other
|
631,717 | 235,294 | 10,082 | 877,093 | ||||||||||||
Customer
deposits
|
325,859 | - | - | 325,859 | ||||||||||||
Taxes
accrued
|
244,009 | 947,167 | (1,191,176 | ) | - | |||||||||||
Accumulated
deferred income taxes
|
7,100 | - | - | 7,100 | ||||||||||||
Interest
accrued
|
152,398 | 1,811 | 7,134 | 161,343 | ||||||||||||
Deferred
fuel costs
|
118,483 | - | - | 118,483 | ||||||||||||
Obligations
under capital leases
|
2,395 | - | - | 2,395 | ||||||||||||
Pension
and other postretirement liabilities
|
50,433 | 5,277 | - | 55,710 | ||||||||||||
System
agreement cost equalization
|
187,314 | - | - | 187,314 | ||||||||||||
Other
|
146,548 | 200,275 | 1,749 | 348,572 | ||||||||||||
TOTAL
|
2,475,868 | 1,424,087 | (840,174 | ) | 3,059,781 | |||||||||||
NON-CURRENT
LIABILITIES
|
||||||||||||||||
Accumulated
deferred income taxes and taxes accrued
|
6,528,558 | 1,975,191 | (597,388 | ) | 7,906,361 | |||||||||||
Accumulated
deferred investment tax credits
|
304,132 | - | - | 304,132 | ||||||||||||
Obligations
under capital leases
|
36,620 | - | - | 36,620 | ||||||||||||
Other
regulatory liabilities
|
534,523 | - | - | 534,523 | ||||||||||||
Decommissioning
and retirement cost liabilities
|
1,645,578 | 1,343,760 | 1,266 | 2,990,604 | ||||||||||||
Accumulated
provisions
|
85,813 | 2,501 | 4,593 | 92,907 | ||||||||||||
Pension
and other postretirement liabilities
|
1,743,979 | 455,497 | - | 2,199,476 | ||||||||||||
Long-term
debt
|
8,565,934 | 157,131 | 2,413,669 | 11,136,734 | ||||||||||||
Other
|
735,668 | 301,185 | (359,389 | ) | 677,464 | |||||||||||
TOTAL
|
20,180,805 | 4,235,265 | 1,462,751 | 25,878,821 | ||||||||||||
Subsidiaries'
preferred stock without sinking fund
|
186,510 | - | 30,211 | 216,721 | ||||||||||||
EQUITY
|
||||||||||||||||
Common
Shareholders' Equity:
|
||||||||||||||||
Common
stock, $.01 par value, authorized 500,000,000 shares;
|
||||||||||||||||
issued
254,752,788 shares in 2010
|
2,161,268 | 774,274 | (2,932,994 | ) | 2,548 | |||||||||||
Paid-in
capital
|
2,416,633 | 1,027,064 | 1,929,727 | 5,373,424 | ||||||||||||
Retained
earnings
|
2,673,668 | 3,059,278 | 2,382,064 | 8,115,010 | ||||||||||||
Accumulated
other comprehensive income (loss)
|
(128,237 | ) | 219,249 | (5,620 | ) | 85,392 | ||||||||||
Less
- treasury stock, at cost (65,483,672 shares in 2010)
|
120,000 | - | 4,596,295 | 4,716,295 | ||||||||||||
Total
common shareholders' equity
|
7,003,332 | 5,079,865 | (3,223,118 | ) | 8,860,079 | |||||||||||
Subsidiaries'
preferred stock without sinking fund
|
94,000 | - | - | 94,000 | ||||||||||||
TOTAL
|
7,097,332 | 5,079,865 | (3,223,118 | ) | 8,954,079 | |||||||||||
TOTAL
LIABILITIES AND EQUITY
|
$ | 29,940,515 | $ | 10,739,217 | $ | (2,570,330 | ) | $ | 38,109,402 | |||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Balance Sheet
|
||||||||||||||||
December
31, 2009
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
ASSETS
|
||||||||||||||||
CURRENT
ASSETS
|
||||||||||||||||
Cash
and cash equivalents:
|
||||||||||||||||
Cash
|
$ | 81,255 | $ | 1,187 | $ | 3,419 | $ | 85,861 | ||||||||
Temporary
cash investments
|
1,158,014 | 392,088 | 73,588 | 1,623,690 | ||||||||||||
Total
cash and cash equivalents
|
1,239,269 | 393,275 | 77,007 | 1,709,551 | ||||||||||||
Securitization
recovery trust account
|
13,098 | - | - | 13,098 | ||||||||||||
Notes
receivable
|
- | 1,132,023 | (1,132,023 | ) | - | |||||||||||
Accounts
receivable:
|
||||||||||||||||
Customer
|
331,936 | 221,756 | - | 553,692 | ||||||||||||
Allowance
for doubtful accounts
|
(27,428 | ) | - | (203 | ) | (27,631 | ) | |||||||||
Associated
companies
|
27,783 | 28,940 | (56,723 | ) | - | |||||||||||
Other
|
135,307 | - | 16,996 | 152,303 | ||||||||||||
Accrued
unbilled revenues
|
302,293 | - | 170 | 302,463 | ||||||||||||
Total
accounts receivable
|
769,891 | 250,696 | (39,760 | ) | 980,827 | |||||||||||
Deferred
fuel costs
|
126,798 | - | - | 126,798 | ||||||||||||
Accumulated
deferred income taxes
|
- | - | - | - | ||||||||||||
Fuel
inventory - at average cost
|
194,826 | 529 | 1,500 | 196,855 | ||||||||||||
Materials
and supplies - at average cost
|
526,543 | 297,132 | 2,027 | 825,702 | ||||||||||||
Deferred
nuclear refueling outage costs
|
106,428 | 118,862 | - | 225,290 | ||||||||||||
System
agreement cost equalization
|
70,000 | - | - | 70,000 | ||||||||||||
Prepayments
and other
|
68,406 | 432,968 | (115,334 | ) | 386,040 | |||||||||||
TOTAL
|
3,115,259 | 2,625,485 | (1,206,583 | ) | 4,534,161 | |||||||||||
OTHER
PROPERTY AND INVESTMENTS
|
||||||||||||||||
Investment
in affiliates - at equity
|
734,578 | 1,330,589 | (2,025,587 | ) | 39,580 | |||||||||||
Decommissioning
trust funds
|
1,325,863 | 1,885,320 | - | 3,211,183 | ||||||||||||
Non-utility
property - at cost (less accumulated depreciation)
|
156,333 | 6,038 | 85,293 | 247,664 | ||||||||||||
Other
|
77,418 | 7,730 | 35,125 | 120,273 | ||||||||||||
TOTAL
|
2,294,192 | 3,229,677 | (1,905,169 | ) | 3,618,700 | |||||||||||
PROPERTY,
PLANT, AND EQUIPMENT
|
||||||||||||||||
Electric
|
32,426,732 | 3,540,860 | 376,180 | 36,343,772 | ||||||||||||
Property
under capital lease
|
783,096 | - | - | 783,096 | ||||||||||||
Natural
gas
|
313,817 | - | 439 | 314,256 | ||||||||||||
Construction
work in progress
|
1,134,194 | 411,523 | 1,602 | 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
|
35,404,677 | 4,472,893 | 378,221 | 40,255,791 | ||||||||||||
Less
- accumulated depreciation and amortization
|
16,150,763 | 561,698 | 153,928 | 16,866,389 | ||||||||||||
PROPERTY,
PLANT AND EQUIPMENT - NET
|
19,253,914 | 3,911,195 | 224,293 | 23,389,402 | ||||||||||||
DEFERRED
DEBITS AND OTHER ASSETS
|
||||||||||||||||
Regulatory
assets:
|
||||||||||||||||
Regulatory
asset for income taxes - 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 | ||||||||||||
Accumulated
deferred income taxes
|
- | - | - | - | ||||||||||||
Other
|
231,156 | 821,382 | (46,232 | ) | 1,006,306 | |||||||||||
TOTAL
|
5,044,111 | 824,455 | (46,232 | ) | 5,822,334 | |||||||||||
- | ||||||||||||||||
TOTAL
ASSETS
|
$ | 29,707,476 | $ | 10,590,812 | $ | (2,933,691 | ) | $ | 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
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||
CURRENT
LIABILITIES
|
||||||||||||||||
Currently
maturing long-term debt
|
$ | 406,016 | $ | 30,941 | $ | 275,000 | $ | 711,957 | ||||||||
Notes
payable:
|
||||||||||||||||
Associated
companies
|
207,161 | - | (207,161 | ) | - | |||||||||||
Other
|
30,031 | - | - | 30,031 | ||||||||||||
Account
payable:
|
||||||||||||||||
Associated
companies
|
6,920 | 7,543 | (14,463 | ) | - | |||||||||||
Other
|
758,886 | 231,119 | 8,223 | 998,228 | ||||||||||||
Customer
deposits
|
323,092 | 250 | - | 323,342 | ||||||||||||
Taxes
accrued
|
12,742 | - | (12,742 | ) | - | |||||||||||
Accumulated
deferred income taxes
|
41,125 | - | 7,459 | 48,584 | ||||||||||||
Interest
accrued
|
187,154 | 908 | 4,221 | 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
|
48,643 | 163,328 | 3,231 | 215,202 | ||||||||||||
TOTAL
|
2,691,021 | 439,208 | 63,768 | 3,193,997 | ||||||||||||
NON-CURRENT
LIABILITIES
|
||||||||||||||||
Accumulated
deferred income taxes and taxes accrued
|
6,506,974 | 3,052,967 | (2,137,622 | ) | 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
|
1,618,844 | 1,319,450 | 1,245 | 2,939,539 | ||||||||||||
Accumulated
provisions
|
127,634 | 9,090 | 4,591 | 141,315 | ||||||||||||
Pension
and other postretirement liabilities
|
1,771,351 | 469,688 | - | 2,241,039 | ||||||||||||
Long-term
debt
|
7,897,032 | 156,556 | 2,652,150 | 10,705,738 | ||||||||||||
Other
|
750,024 | 317,661 | (356,351 | ) | 711,334 | |||||||||||
TOTAL
|
19,756,472 | 5,325,412 | 164,013 | 25,245,897 | ||||||||||||
Subsidiaries'
preferred stock without sinking fund
|
186,510 | - | 30,833 | 217,343 | ||||||||||||
EQUITY
|
||||||||||||||||
Common
Shareholders' Equity:
|
||||||||||||||||
Common
stock, $.01 par value, authorized 500,000,000 shares;
|
||||||||||||||||
issued
254,752,788 shares in 2009
|
2,161,268 | 774,274 | (2,932,994 | ) | 2,548 | |||||||||||
Paid-in
capital
|
2,416,633 | 1,027,164 | 1,926,245 | 5,370,042 | ||||||||||||
Retained
earnings
|
2,651,629 | 2,965,052 | 2,426,441 | 8,043,122 | ||||||||||||
Accumulated
other comprehensive income (loss)
|
(130,057 | ) | 59,702 | (4,830 | ) | (75,185 | ) | |||||||||
Less
- treasury stock, at cost (65,634,580 shares in 2009)
|
120,000 | - | 4,607,167 | 4,727,167 | ||||||||||||
Total
common shareholders' equity
|
6,979,473 | 4,826,192 | (3,192,305 | ) | 8,613,360 | |||||||||||
Subsidiaries'
preferred stock without sinking fund
|
94,000 | - | - | 94,000 | ||||||||||||
TOTAL
|
7,073,473 | 4,826,192 | (3,192,305 | ) | 8,707,360 | |||||||||||
TOTAL
LIABILITIES AND EQUITY
|
$ | 29,707,476 | $ | 10,590,812 | $ | (2,933,691 | ) | $ | 37,364,597 | |||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Balance Sheet
|
||||||||||||||||
March
31, 2010 vs December 31, 2009
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
ASSETS
|
||||||||||||||||
CURRENT
ASSETS
|
||||||||||||||||
Cash
and cash equivalents:
|
||||||||||||||||
Cash
|
$ | (10,916 | ) | $ | (16 | ) | $ | 517 | $ | (10,415 | ) | |||||
Temporary
cash investments
|
(189,442 | ) | 166,676 | (19,336 | ) | (42,102 | ) | |||||||||
Total
cash and cash equivalents
|
(200,358 | ) | 166,660 | (18,819 | ) | (52,517 | ) | |||||||||
Securitization
recovery trust account
|
21,939 | - | - | 21,939 | ||||||||||||
Notes
receivable
|
- | 5,000 | (5,000 | ) | - | |||||||||||
Accounts
receivable:
|
||||||||||||||||
Customer
|
74,103 | (57,138 | ) | - | 16,965 | |||||||||||
Allowance
for doubtful accounts
|
(802 | ) | - | 1 | (801 | ) | ||||||||||
Associated
companies
|
(2,633 | ) | 14,755 | (12,122 | ) | - | ||||||||||
Other
|
(7,386 | ) | - | (801 | ) | (8,187 | ) | |||||||||
Accrued
unbilled revenues
|
(51,813 | ) | - | 7 | (51,806 | ) | ||||||||||
Total
accounts receivable
|
11,469 | (42,383 | ) | (12,915 | ) | (43,829 | ) | |||||||||
Deferred
fuel costs
|
(102,120 | ) | - | - | (102,120 | ) | ||||||||||
Accumulated
deferred income taxes
|
27,221 | 1,403 | (4,469 | ) | 24,155 | |||||||||||
Fuel
inventory - at average cost
|
5,828 | (1 | ) | 497 | 6,324 | |||||||||||
Materials
and supplies - at average cost
|
4,804 | 3,216 | (7 | ) | 8,013 | |||||||||||
Deferred
nuclear refueling outage costs
|
(14,394 | ) | 3,259 | - | (11,135 | ) | ||||||||||
System
agreement cost equalization
|
- | - | - | - | ||||||||||||
Prepayments
and other
|
152,794 | (130,958 | ) | 325,793 | 347,629 | |||||||||||
TOTAL
|
(92,817 | ) | 6,196 | 285,080 | 198,459 | |||||||||||
OTHER
PROPERTY AND INVESTMENTS
|
||||||||||||||||
Investment
in affiliates - at equity
|
- | - | 71 | 71 | ||||||||||||
Decommissioning
trust funds
|
62,892 | 56,606 | - | 119,498 | ||||||||||||
Non-utility
property - at cost (less accumulated depreciation)
|
2,166 | (66 | ) | (2,468 | ) | (368 | ) | |||||||||
Other
|
(7,351 | ) | (1,630 | ) | 48 | (8,933 | ) | |||||||||
TOTAL
|
57,707 | 54,910 | (2,349 | ) | 110,268 | |||||||||||
PROPERTY,
PLANT, AND EQUIPMENT
|
||||||||||||||||
Electric
|
153,946 | 15,131 | (4,689 | ) | 164,388 | |||||||||||
Property
under capital lease
|
(374 | ) | - | - | (374 | ) | ||||||||||
Natural
gas
|
1,880 | - | - | 1,880 | ||||||||||||
Construction
work in progress
|
78,859 | 39,768 | 1,774 | 120,401 | ||||||||||||
Nuclear
fuel under capital lease
|
(527,521 | ) | - | - | (527,521 | ) | ||||||||||
Nuclear
fuel
|
509,912 | (9,294 | ) | - | 500,618 | |||||||||||
TOTAL
PROPERTY, PLANT AND EQUIPMENT
|
216,702 | 45,605 | (2,915 | ) | 259,392 | |||||||||||
Less
- accumulated depreciation and amortization
|
93,176 | 20,111 | (3,488 | ) | 109,799 | |||||||||||
PROPERTY,
PLANT AND EQUIPMENT - NET
|
123,526 | 25,494 | 573 | 149,593 | ||||||||||||
DEFERRED
DEBITS AND OTHER ASSETS
|
||||||||||||||||
Regulatory
assets:
|
||||||||||||||||
Regulatory
asset for income taxes - net
|
5,891 | - | - | 5,891 | ||||||||||||
Other
regulatory assets
|
91,281 | - | - | 91,281 | ||||||||||||
Deferred
fuel costs
|
- | - | - | - | ||||||||||||
Goodwill
|
- | - | - | - | ||||||||||||
Accumulated
deferred income taxes
|
8,592 | - | 65,436 | 74,028 | ||||||||||||
Other
|
38,859 | 61,805 | 14,621 | 115,285 | ||||||||||||
TOTAL
|
144,623 | 61,805 | 80,057 | 286,485 | ||||||||||||
TOTAL
ASSETS
|
$ | 233,039 | $ | 148,405 | $ | 363,361 | $ | 744,805 | ||||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Balance Sheet
|
||||||||||||||||
March
31, 2010 vs December 31, 2009
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||||||||||
CURRENT
LIABILITIES
|
||||||||||||||||
Currently
maturing long-term debt
|
$ | 4,986 | $ | (2,529 | ) | $ | 86,000 | $ | 88,457 | |||||||
Notes
payable:
|
||||||||||||||||
Associated
companies
|
(201,773 | ) | - | 201,773 | - | |||||||||||
Other
|
145,467 | - | - | 145,467 | ||||||||||||
Account
payable:
|
||||||||||||||||
Associated
companies
|
10,804 | (1,692 | ) | (9,112 | ) | - | ||||||||||
Other
|
(127,169 | ) | 4,175 | 1,859 | (121,135 | ) | ||||||||||
Customer
deposits
|
2,767 | (250 | ) | - | 2,517 | |||||||||||
Taxes
accrued
|
231,267 | 947,167 | (1,178,434 | ) | - | |||||||||||
Accumulated
deferred income taxes
|
(34,025 | ) | - | (7,459 | ) | (41,484 | ) | |||||||||
Interest
accrued
|
(34,756 | ) | 903 | 2,913 | (30,940 | ) | ||||||||||
Deferred
fuel costs
|
(101,156 | ) | - | - | (101,156 | ) | ||||||||||
Obligations
under capital leases
|
(210,101 | ) | - | - | (210,101 | ) | ||||||||||
Pension
and other postretirement liabilities
|
521 | 158 | - | 679 | ||||||||||||
System
agreement cost equalization
|
110 | - | - | 110 | ||||||||||||
Other
|
97,905 | 36,947 | (1,482 | ) | 133,370 | |||||||||||
TOTAL
|
(215,153 | ) | 984,879 | (903,942 | ) | (134,216 | ) | |||||||||
NON-CURRENT
LIABILITIES
|
||||||||||||||||
Accumulated
deferred income taxes and taxes accrued
|
21,584 | (1,077,776 | ) | 1,540,234 | 484,042 | |||||||||||
Accumulated
deferred investment tax credits
|
(4,263 | ) | - | - | (4,263 | ) | ||||||||||
Obligations
under capital leases
|
(317,613 | ) | - | - | (317,613 | ) | ||||||||||
Other
regulatory liabilities
|
112,538 | - | - | 112,538 | ||||||||||||
Decommissioning
and retirement cost liabilities
|
26,734 | 24,310 | 21 | 51,065 | ||||||||||||
Accumulated
provisions
|
(41,821 | ) | (6,589 | ) | 2 | (48,408 | ) | |||||||||
Pension
and other postretirement liabilities
|
(27,372 | ) | (14,191 | ) | - | (41,563 | ) | |||||||||
Long-term
debt
|
668,902 | 575 | (238,481 | ) | 430,996 | |||||||||||
Other
|
(14,356 | ) | (16,476 | ) | (3,038 | ) | (33,870 | ) | ||||||||
TOTAL
|
424,333 | (1,090,147 | ) | 1,298,738 | 632,924 | |||||||||||
Subsidiaries'
preferred stock without sinking fund
|
- | - | (622 | ) | (622 | ) | ||||||||||
EQUITY
|
||||||||||||||||
Common
Shareholders' Equity:
|
||||||||||||||||
Common
stock, $.01 par value, authorized 500,000,000 shares;
|
||||||||||||||||
issued
254,752,788 shares in 2010 and in 2009
|
- | - | - | - | ||||||||||||
Paid-in
capital
|
- | (100 | ) | 3,482 | 3,382 | |||||||||||
Retained
earnings
|
22,039 | 94,226 | (44,377 | ) | 71,888 | |||||||||||
Accumulated
other comprehensive income (loss)
|
1,820 | 159,547 | (790 | ) | 160,577 | |||||||||||
Less
- treasury stock, at cost
|
- | - | (10,872 | ) | (10,872 | ) | ||||||||||
Total
common shareholders' equity
|
23,859 | 253,673 | (30,813 | ) | 246,719 | |||||||||||
Subsidiaries'
preferred stock without sinking fund
|
- | - | - | - | ||||||||||||
TOTAL
|
23,859 | 253,673 | (30,813 | ) | 246,719 | |||||||||||
TOTAL
LIABILITIES AND EQUITY
|
$ | 233,039 | $ | 148,405 | $ | 363,361 | $ | 744,805 | ||||||||
*Totals
may not foot due to rounding.
|
||||||||||||||||
Entergy
Corporation
|
||||||||||||||||
Consolidating
Income Statement
|
||||||||||||||||
Three
Months Ended March 31, 2010
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
OPERATING
REVENUES
|
||||||||||||||||
Electric
|
$ | 2,007,802 | $ | - | $ | (871 | ) | $ | 2,006,931 | |||||||
Natural
gas
|
96,027 | - | - | 96,027 | ||||||||||||
Competitive
businesses
|
- | 613,776 | 42,613 | 656,389 | ||||||||||||
Total
|
2,103,829 | 613,776 | 41,742 | 2,759,347 | ||||||||||||
OPERATING
EXPENSES
|
||||||||||||||||
Operating
and Maintenance:
|
||||||||||||||||
Fuel,
fuel related expenses, and gas purchased for resale
|
478,055 | 55,111 | 25,502 | 558,668 | ||||||||||||
Purchased
power
|
467,895 | 3,906 | 3,102 | 474,903 | ||||||||||||
Nuclear
refueling outage expenses
|
27,600 | 34,689 | - | 62,289 | ||||||||||||
Other
operation and maintenance
|
435,168 | 246,664 | 20,657 | 702,489 | ||||||||||||
Decommissioning
|
25,420 | 26,134 | 22 | 51,576 | ||||||||||||
Taxes
other than income taxes
|
109,830 | 24,122 | 1,460 | 135,412 | ||||||||||||
Depreciation
and amortization
|
227,547 | 37,690 | 3,967 | 269,204 | ||||||||||||
Other
regulatory charges (credits) - net
|
28,092 | - | - | 28,092 | ||||||||||||
Total
|
1,799,607 | 428,316 | 54,710 | 2,282,633 | ||||||||||||
OPERATING
INCOME
|
304,222 | 185,460 | (12,968 | ) | 476,714 | |||||||||||
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
Allowance
for equity funds used during construction
|
13,296 | - | - | 13,296 | ||||||||||||
Interest
and dividend income
|
37,828 | 42,985 | (32,604 | ) | 48,209 | |||||||||||
Other
than temporary impairment losses
|
- | - | - | - | ||||||||||||
Miscellaneous
- net
|
(995 | ) | (1,708 | ) | 2,181 | (522 | ) | |||||||||
Total
|
50,129 | 41,277 | (30,423 | ) | 60,983 | |||||||||||
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
Interest
on long-term debt
|
122,615 | 38,767 | 5,550 | 166,932 | ||||||||||||
Other
interest - net
|
6,797 | 7,539 | (2,069 | ) | 12,267 | |||||||||||
Allowance
for borrowed funds used during construction
|
(8,001 | ) | - | - | (8,001 | ) | ||||||||||
Total
|
121,411 | 46,306 | 3,481 | 171,198 | ||||||||||||
INCOME
BEFORE INCOME TAXES
|
232,940 | 180,431 | (46,872 | ) | 366,499 | |||||||||||
Income
taxes
|
89,970 | 86,205 | (28,490 | ) | 147,685 | |||||||||||
CONSOLIDATED
NET INCOME
|
142,970 | 94,226 | (18,382 | ) | 218,814 | |||||||||||
Preferred
dividend requirements of subsidiaries
|
4,332 | - | 683 | 5,015 | ||||||||||||
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 138,638 | $ | 94,226 | $ | (19,065 | ) | $ | 213,799 | |||||||
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
BASIC
|
$ | 0.73 | $ | 0.50 | $ | (0.10 | ) | $ | 1.13 | |||||||
DILUTED
|
$ | 0.73 | $ | 0.49 | $ | (0.10 | ) | $ | 1.12 | |||||||
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
BASIC
|
189,202,684 | |||||||||||||||
DILUTED
|
191,283,703 | |||||||||||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Income Statement
|
||||||||||||||||
Three
Months Ended March 31, 2009
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
OPERATING
REVENUES
|
||||||||||||||||
Electric
|
$ | 2,028,156 | $ | - | $ | (1,240 | ) | $ | 2,026,916 | |||||||
Natural
gas
|
74,049 | - | - | 74,049 | ||||||||||||
Competitive
businesses
|
- | 656,187 | 31,960 | 688,147 | ||||||||||||
Total
|
2,102,205 | 656,187 | 30,720 | 2,789,112 | ||||||||||||
OPERATING
EXPENSES
|
||||||||||||||||
Operating
and Maintenance:
|
||||||||||||||||
Fuel,
fuel related expenses, and gas purchased for resale
|
778,401 | 51,466 | 16,465 | 846,332 | ||||||||||||
Purchased
power
|
316,532 | 1,835 | 4,888 | 323,255 | ||||||||||||
Nuclear
refueling outage expenses
|
25,090 | 31,689 | - | 56,779 | ||||||||||||
Other
operation and maintenance
|
422,316 | 199,960 | 22,426 | 644,702 | ||||||||||||
Decommissioning
|
25,037 | 23,686 | 19 | 48,742 | ||||||||||||
Taxes
other than income taxes
|
106,403 | 26,259 | 1,735 | 134,397 | ||||||||||||
Depreciation
and amortization
|
220,360 | 33,639 | 3,853 | 257,852 | ||||||||||||
Other
regulatory charges (credits) - net
|
(29,474 | ) | - | - | (29,474 | ) | ||||||||||
Total
|
1,864,665 | 368,534 | 49,386 | 2,282,585 | ||||||||||||
OPERATING
INCOME
|
237,540 | 287,653 | (18,666 | ) | 506,527 | |||||||||||
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
Allowance
for equity funds used during construction
|
16,947 | - | - | 16,947 | ||||||||||||
Interest
and dividend income
|
43,106 | 29,308 | (26,027 | ) | 46,387 | |||||||||||
Other
than temporary impairment losses
|
- | (15,737 | ) | - | (15,737 | ) | ||||||||||
Miscellaneous
- net
|
(2,722 | ) | (5,058 | ) | (5,519 | ) | (13,299 | ) | ||||||||
Total
|
57,331 | 8,513 | (31,546 | ) | 34,298 | |||||||||||
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
Interest
on long-term debt
|
109,709 | 2,125 | 16,131 | 127,965 | ||||||||||||
Other
interest - net
|
5,543 | 11,082 | 2,668 | 19,293 | ||||||||||||
Allowance
for borrowed funds used during construction
|
(9,812 | ) | - | - | (9,812 | ) | ||||||||||
Total
|
105,440 | 13,207 | 18,799 | 137,446 | ||||||||||||
INCOME
BEFORE INCOME TAXES
|
189,431 | 282,959 | (69,011 | ) | 403,379 | |||||||||||
Income
taxes
|
73,463 | 102,077 | (12,494 | ) | 163,046 | |||||||||||
CONSOLIDATED
NET INCOME
|
115,968 | 180,882 | (56,517 | ) | 240,333 | |||||||||||
Preferred
dividend requirements of subsidiaries
|
4,332 | - | 666 | 4,998 | ||||||||||||
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 111,636 | $ | 180,882 | $ | (57,183 | ) | $ | 235,335 | |||||||
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
BASIC
|
$ | 0.58 | $ | 0.94 | $ | (0.30 | ) | $ | 1.22 | |||||||
DILUTED
|
$ | 0.56 | $ | 0.91 | $ | (0.27 | ) | $ | 1.20 | |||||||
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
BASIC
|
192,593,601 | |||||||||||||||
DILUTED
|
198,058,002 | |||||||||||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Income Statement
|
||||||||||||||||
Three
Months Ended March 31, 2010 vs. 2009
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
OPERATING
REVENUES
|
||||||||||||||||
Electric
|
$ | (20,354 | ) | $ | - | $ | 369 | $ | (19,985 | ) | ||||||
Natural
gas
|
21,978 | - | - | 21,978 | ||||||||||||
Competitive
businesses
|
- | (42,411 | ) | 10,653 | (31,758 | ) | ||||||||||
Total
|
1,624 | (42,411 | ) | 11,022 | (29,765 | ) | ||||||||||
OPERATING
EXPENSES
|
||||||||||||||||
Operating
and Maintenance:
|
||||||||||||||||
Fuel,
fuel related expenses, and gas purchased for resale
|
(300,346 | ) | 3,645 | 9,037 | (287,664 | ) | ||||||||||
Purchased
power
|
151,363 | 2,071 | (1,786 | ) | 151,648 | |||||||||||
Nuclear
refueling outage expenses
|
2,510 | 3,000 | - | 5,510 | ||||||||||||
Other
operation and maintenance
|
12,852 | 46,704 | (1,769 | ) | 57,787 | |||||||||||
Decommissioning
|
383 | 2,448 | 3 | 2,834 | ||||||||||||
Taxes
other than income taxes
|
3,427 | (2,137 | ) | (275 | ) | 1,015 | ||||||||||
Depreciation
and amortization
|
7,187 | 4,051 | 114 | 11,352 | ||||||||||||
Other
regulatory charges (credits )- net
|
57,566 | - | - | 57,566 | ||||||||||||
Total
|
(65,058 | ) | 59,782 | 5,324 | 48 | |||||||||||
OPERATING
INCOME
|
66,682 | (102,193 | ) | 5,698 | (29,813 | ) | ||||||||||
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
Allowance
for equity funds used during construction
|
(3,651 | ) | - | - | (3,651 | ) | ||||||||||
Interest
and dividend income
|
(5,278 | ) | 13,677 | (6,577 | ) | 1,822 | ||||||||||
Other
than temporary impairment losses
|
- | 15,737 | - | 15,737 | ||||||||||||
Miscellaneous
- net
|
1,727 | 3,350 | 7,700 | 12,777 | ||||||||||||
Total
|
(7,202 | ) | 32,764 | 1,123 | 26,685 | |||||||||||
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
Interest
on long-term debt
|
12,906 | 36,642 | (10,581 | ) | 38,967 | |||||||||||
Other
interest - net
|
1,254 | (3,543 | ) | (4,737 | ) | (7,026 | ) | |||||||||
Allowance
for borrowed funds used during construction
|
1,811 | - | - | 1,811 | ||||||||||||
Total
|
15,971 | 33,099 | (15,318 | ) | 33,752 | |||||||||||
INCOME
BEFORE INCOME TAXES
|
43,509 | (102,528 | ) | 22,139 | (36,880 | ) | ||||||||||
Income
taxes
|
16,507 | (15,872 | ) | (15,996 | ) | (15,361 | ) | |||||||||
CONSOLIDATED
NET INCOME
|
27,002 | (86,656 | ) | 38,135 | (21,519 | ) | ||||||||||
Preferred
dividend requirements of subsidiaries
|
- | - | 17 | 17 | ||||||||||||
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 27,002 | $ | (86,656 | ) | $ | 38,118 | $ | (21,536 | ) | ||||||
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
BASIC
|
$ | 0.15 | $ | (0.44 | ) | $ | 0.20 | $ | (0.09 | ) | ||||||
DILUTED
|
$ | 0.17 | $ | (0.42 | ) | $ | 0.17 | $ | (0.08 | ) | ||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Income Statement
|
||||||||||||||||
Twelve
Months Ended March 31, 2010
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
OPERATING
REVENUES
|
||||||||||||||||
Electric
|
$ | 7,862,785 | $ | - | $ | (2,755 | ) | $ | 7,860,030 | |||||||
Natural
gas
|
194,190 | - | - | 194,190 | ||||||||||||
Competitive
businesses
|
- | 2,512,842 | 148,822 | 2,661,664 | ||||||||||||
Total
|
8,056,975 | 2,512,842 | 146,067 | 10,715,884 | ||||||||||||
OPERATING
EXPENSES
|
||||||||||||||||
Operating
and Maintenance:
|
||||||||||||||||
Fuel,
fuel related expenses, and gas purchased for resale
|
1,726,547 | 219,665 | 75,955 | 2,022,167 | ||||||||||||
Purchased
power
|
1,507,780 | 17,711 | 21,360 | 1,546,851 | ||||||||||||
Nuclear
refueling outage expenses
|
107,526 | 139,294 | - | 246,820 | ||||||||||||
Other
operation and maintenance
|
1,849,360 | 895,624 | 63,615 | 2,808,599 | ||||||||||||
Decommissioning
|
100,067 | 101,747 | 83 | 201,897 | ||||||||||||
Taxes
other than income taxes
|
405,926 | 93,928 | 5,020 | 504,874 | ||||||||||||
Depreciation
and amortization
|
933,426 | 145,498 | 15,202 | 1,094,126 | ||||||||||||
Other
regulatory charges (credits) - net
|
35,838 | - | - | 35,838 | ||||||||||||
Total
|
6,666,470 | 1,613,467 | 181,235 | 8,461,172 | ||||||||||||
OPERATING
INCOME
|
1,390,505 | 899,375 | (35,168 | ) | 2,254,712 | |||||||||||
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
Allowance
for equity funds used during construction
|
55,894 | - | - | 55,894 | ||||||||||||
Interest
and dividend income
|
175,227 | 183,741 | (120,488 | ) | 238,480 | |||||||||||
Other
than temporary impairment losses
|
- | (70,363 | ) | - | (70,363 | ) | ||||||||||
Miscellaneous
- net
|
(2,355 | ) | (16,011 | ) | (9,252 | ) | (27,618 | ) | ||||||||
Total
|
228,766 | 97,367 | (129,740 | ) | 196,393 | |||||||||||
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
Interest
on long-term debt
|
476,394 | 45,908 | 37,381 | 559,683 | ||||||||||||
Other
interest - net
|
33,206 | 43,075 | (345 | ) | 75,936 | |||||||||||
Allowance
for borrowed funds used during construction
|
(31,424 | ) | - | - | (31,424 | ) | ||||||||||
Total
|
478,176 | 88,983 | 37,036 | 604,195 | ||||||||||||
INCOME
BEFORE INCOME TAXES
|
1,141,095 | 907,759 | (201,944 | ) | 1,846,910 | |||||||||||
Income
taxes
|
405,188 | 363,394 | (151,203 | ) | 617,379 | |||||||||||
CONSOLIDATED
NET INCOME
|
735,907 | 544,365 | (50,741 | ) | 1,229,531 | |||||||||||
Preferred
dividend requirements of subsidiaries
|
17,329 | - | 2,647 | 19,976 | ||||||||||||
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 718,578 | $ | 544,365 | $ | (53,388 | ) | $ | 1,209,555 | |||||||
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
BASIC
|
$ | 3.76 | $ | 2.84 | $ | (0.28 | ) | $ | 6.32 | |||||||
DILUTED
|
$ | 3.72 | $ | 2.81 | $ | (0.28 | ) | $ | 6.25 | |||||||
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
BASIC
|
191,411,500 | |||||||||||||||
DILUTED
|
193,604,305 | |||||||||||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Income Statement
|
||||||||||||||||
Twelve
Months Ended March 31, 2009
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
OPERATING
REVENUES
|
||||||||||||||||
Electric
|
$ | 10,057,996 | $ | - | $ | (4,147 | ) | $ | 10,053,849 | |||||||
Natural
gas
|
226,511 | - | - | 226,511 | ||||||||||||
Competitive
businesses
|
- | 2,534,080 | 203,695 | 2,737,775 | ||||||||||||
Total
|
10,284,507 | 2,534,080 | 199,548 | 13,018,135 | ||||||||||||
OPERATING
EXPENSES
|
||||||||||||||||
Operating
and Maintenance:
|
||||||||||||||||
Fuel,
fuel related expenses, and gas purchased for resale
|
3,536,222 | 211,239 | 136,135 | 3,883,596 | ||||||||||||
Purchased
power
|
2,162,423 | 10,939 | 20,451 | 2,193,813 | ||||||||||||
Nuclear
refueling outage expenses
|
97,974 | 129,305 | - | 227,279 | ||||||||||||
Other
operation and maintenance
|
1,868,816 | 791,301 | 116,079 | 2,776,196 | ||||||||||||
Decommissioning
|
97,533 | 94,545 | 77 | 192,155 | ||||||||||||
Taxes
other than income taxes
|
423,764 | 93,766 | 5,249 | 522,779 | ||||||||||||
Depreciation
and amortization
|
898,458 | 129,582 | 15,687 | 1,043,727 | ||||||||||||
Other
regulatory charges (credits) - net
|
(4,871 | ) | - | - | (4,871 | ) | ||||||||||
Total
|
9,080,319 | 1,460,677 | 293,678 | 10,834,674 | ||||||||||||
OPERATING
INCOME
|
1,204,188 | 1,073,403 | (94,130 | ) | 2,183,461 | |||||||||||
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
Allowance
for equity funds used during construction
|
52,183 | - | - | 52,183 | ||||||||||||
Interest
and dividend income
|
139,984 | 110,225 | (63,886 | ) | 186,323 | |||||||||||
Other
than temporary impairment losses
|
- | (61,736 | ) | - | (61,736 | ) | ||||||||||
Miscellaneous
- net
|
(5,467 | ) | (15,052 | ) | (3,746 | ) | (24,265 | ) | ||||||||
Total
|
186,700 | 33,437 | (67,632 | ) | 152,505 | |||||||||||
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
Interest
on long-term debt
|
427,352 | 3,270 | 75,098 | 505,720 | ||||||||||||
Other
interest - net
|
33,364 | 50,895 | 35,788 | 120,047 | ||||||||||||
Allowance
for borrowed funds used during construction
|
(29,962 | ) | - | - | (29,962 | ) | ||||||||||
Total
|
430,754 | 54,165 | 110,886 | 595,805 | ||||||||||||
INCOME
BEFORE INCOME TAXES
|
960,134 | 1,052,675 | (272,648 | ) | 1,740,161 | |||||||||||
Income
taxes
|
360,501 | 296,211 | (83,672 | ) | 573,040 | |||||||||||
CONSOLIDATED
NET INCOME
|
599,633 | 756,464 | (188,976 | ) | 1,167,121 | |||||||||||
Preferred
dividend requirements of subsidiaries
|
17,307 | - | 2,662 | 19,969 | ||||||||||||
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 582,326 | $ | 756,464 | $ | (191,638 | ) | $ | 1,147,152 | |||||||
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
BASIC
|
$ | 3.06 | $ | 3.97 | $ | (1.00 | ) | $ | 6.03 | |||||||
DILUTED
|
$ | 2.91 | $ | 3.79 | $ | (0.85 | ) | $ | 5.85 | |||||||
AVERAGE
NUMBER OF COMMON SHARES OUTSTANDING:
|
||||||||||||||||
BASIC
|
190,387,963 | |||||||||||||||
DILUTED
|
199,681,692 | |||||||||||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||||||
Consolidating
Income Statement
|
||||||||||||||||
Twelve
Months Ended March 31, 2010 vs. 2009
|
||||||||||||||||
(Dollars
in thousands)
|
||||||||||||||||
(Unaudited)
|
||||||||||||||||
U.S.
Utilities
|
Entergy
Nuclear
|
Parent
& Other
|
Consolidated
|
|||||||||||||
OPERATING
REVENUES
|
||||||||||||||||
Electric
|
$ | (2,195,211 | ) | $ | - | $ | 1,392 | $ | (2,193,819 | ) | ||||||
Natural
gas
|
(32,321 | ) | - | - | (32,321 | ) | ||||||||||
Competitive
businesses
|
- | (21,238 | ) | (54,873 | ) | (76,111 | ) | |||||||||
Total
|
(2,227,532 | ) | (21,238 | ) | (53,481 | ) | (2,302,251 | ) | ||||||||
OPERATING
EXPENSES
|
||||||||||||||||
Operating
and Maintenance:
|
||||||||||||||||
Fuel,
fuel related expenses, and gas purchased for resale
|
(1,809,675 | ) | 8,426 | (60,180 | ) | (1,861,429 | ) | |||||||||
Purchased
power
|
(654,643 | ) | 6,772 | 909 | (646,962 | ) | ||||||||||
Nuclear
refueling outage expenses
|
9,552 | 9,989 | - | 19,541 | ||||||||||||
Other
operation and maintenance
|
(19,456 | ) | 104,323 | (52,464 | ) | 32,403 | ||||||||||
Decommissioning
|
2,534 | 7,202 | 6 | 9,742 | ||||||||||||
Taxes
other than income taxes
|
(17,838 | ) | 162 | (229 | ) | (17,905 | ) | |||||||||
Depreciation
and amortization
|
34,968 | 15,916 | (485 | ) | 50,399 | |||||||||||
Other
regulatory charges (credits )- net
|
40,709 | - | - | 40,709 | ||||||||||||
Total
|
(2,413,849 | ) | 152,790 | (112,443 | ) | (2,373,502 | ) | |||||||||
OPERATING
INCOME
|
186,317 | (174,028 | ) | 58,962 | 71,251 | |||||||||||
OTHER
INCOME (DEDUCTIONS)
|
||||||||||||||||
Allowance
for equity funds used during construction
|
3,711 | - | - | 3,711 | ||||||||||||
Interest
and dividend income
|
35,243 | 73,516 | (56,602 | ) | 52,157 | |||||||||||
Other
than temporary impairment losses
|
- | (8,627 | ) | - | (8,627 | ) | ||||||||||
Miscellaneous
- net
|
3,112 | (959 | ) | (5,506 | ) | (3,353 | ) | |||||||||
Total
|
42,066 | 63,930 | (62,108 | ) | 43,888 | |||||||||||
INTEREST
AND OTHER CHARGES
|
||||||||||||||||
Interest
on long-term debt
|
49,042 | 42,638 | (37,717 | ) | 53,963 | |||||||||||
Other
interest - net
|
(158 | ) | (7,820 | ) | (36,133 | ) | (44,111 | ) | ||||||||
Allowance
for borrowed funds used during construction
|
(1,462 | ) | - | - | (1,462 | ) | ||||||||||
Total
|
47,422 | 34,818 | (73,850 | ) | 8,390 | |||||||||||
INCOME
BEFORE INCOME TAXES
|
180,961 | (144,916 | ) | 70,704 | 106,749 | |||||||||||
Income
taxes
|
44,687 | 67,183 | (67,531 | ) | 44,339 | |||||||||||
CONSOLIDATED
NET INCOME
|
136,274 | (212,099 | ) | 138,235 | 62,410 | |||||||||||
Preferred
dividend requirements of subsidiaries
|
21 | - | (15 | ) | 7 | |||||||||||
NET
INCOME ATTRIBUTABLE TO ENTERGY CORPORATION
|
$ | 136,253 | $ | (212,099 | ) | $ | 138,250 | $ | 62,403 | |||||||
EARNINGS
PER AVERAGE COMMON SHARE:
|
||||||||||||||||
BASIC
|
$ | 0.70 | $ | (1.13 | ) | $ | 0.72 | $ | 0.29 | |||||||
DILUTED
|
$ | 0.81 | $ | (0.98 | ) | $ | 0.57 | $ | 0.40 | |||||||
*Totals
may not foot due to rounding.
|
Entergy
Corporation
|
||||||||||||
Consolidated
Cash Flow Statement
|
||||||||||||
Three
Months Ended March 31, 2010 vs. 2009
|
||||||||||||
(Dollars
in thousands)
|
||||||||||||
(Unaudited)
|
||||||||||||
2010
|
2009
|
Variance
|
||||||||||
OPERATING
ACTIVITIES
|
||||||||||||
Consolidated
net income
|
$ | 218,814 | $ | 240,333 | $ | (21,519 | ) | |||||
Adjustments
to reconcile consolidated net income to net cash flow
|
||||||||||||
provided
by operating activities:
|
||||||||||||
Reserve
for regulatory adjustments
|
438 | 1,210 | (772 | ) | ||||||||
Other
regulatory charges (credits) - net
|
28,092 | (29,474 | ) | 57,566 | ||||||||
Depreciation,
amortization, and decommissioning, including nuclear fuel
amortization
|
423,432 | 348,444 | 74,988 | |||||||||
Deferred
income taxes, investment tax credits, and non-current taxes
accrued
|
133,533 | 155,029 | (21,496 | ) | ||||||||
Changes
in working capital:
|
||||||||||||
Receivables
|
43,830 | 102,428 | (58,598 | ) | ||||||||
Fuel
inventory
|
(6,324 | ) | (17,631 | ) | 11,307 | |||||||
Accounts
payable
|
(79,250 | ) | (134,008 | ) | 54,758 | |||||||
Taxes
accrued
|
- | (12,784 | ) | 12,784 | ||||||||
Interest
accrued
|
(36,676 | ) | (37,413 | ) | 737 | |||||||
Deferred
fuel
|
964 | 275,508 | (274,544 | ) | ||||||||
Other
working capital accounts
|
19,527 | (120,505 | ) | 140,032 | ||||||||
Provision
for estimated losses and reserves
|
(35,870 | ) | 1,281 | (37,151 | ) | |||||||
Changes
in other regulatory assets
|
(66,248 | ) | (447,882 | ) | 381,634 | |||||||
Changes
in pensions and other postretirement liabilities
|
(40,884 | ) | (29,158 | ) | (11,726 | ) | ||||||
Other
|
70,887 | 79,241 | (8,354 | ) | ||||||||
Net
cash flow provided by operating activities
|
674,265 | 374,619 | 299,646 | |||||||||
INVESTING
ACTIVITIES
|
||||||||||||
Construction/capital
expenditures
|
(447,476 | ) | (455,737 | ) | 8,261 | |||||||
Allowance
for equity funds used during construction
|
13,296 | 16,947 | (3,651 | ) | ||||||||
Nuclear
fuel purchases
|
(65,336 | ) | (118,890 | ) | 53,554 | |||||||
Proceeds
from sale/leaseback of nuclear fuel
|
- | 11,040 | (11,040 | ) | ||||||||
Proceeds
from sale of assets and businesses
|
9,675 | - | 9,675 | |||||||||
Changes
in transition charge account
|
(21,940 | ) | (7,831 | ) | (14,109 | ) | ||||||
NYPA
value sharing payment
|
(72,000 | ) | (72,000 | ) | - | |||||||
Decrease
(increase) in other investments
|
96,416 | 7,339 | 89,077 | |||||||||
Proceeds
from nuclear decommissioning trust fund sales
|
770,781 | 583,166 | 187,615 | |||||||||
Investment
in nuclear decommissioning trust funds
|
(798,864 | ) | (610,836 | ) | (188,028 | ) | ||||||
Net
cash flow used in investing activities
|
(515,448 | ) | (646,802 | ) | 131,354 | |||||||
FINANCING
ACTIVITIES
|
||||||||||||
Proceeds
from the issuance of:
|
||||||||||||
Long-term
debt
|
42,545 | 489,987 | (447,442 | ) | ||||||||
Common
stock and treasury stock
|
6,078 | 927 | 5,151 | |||||||||
Retirement
of long-term debt
|
(100,289 | ) | (215,023 | ) | 114,734 | |||||||
Changes
in credit line borrowings - net
|
(13,368 | ) | 25,000 | (38,368 | ) | |||||||
Dividends
paid:
|
||||||||||||
Common
stock
|
(141,892 | ) | (142,085 | ) | 193 | |||||||
Preferred
stock
|
(5,015 | ) | (4,998 | ) | (17 | ) | ||||||
Net
cash flow provided by (used in) financing activities
|
(211,941 | ) | 153,808 | (365,749 | ) | |||||||
Effect
of exchange rates on cash and cash equivalents
|
607 | 842 | (235 | ) | ||||||||
Net
increase (decrease) in cash and cash equivalents
|
(52,517 | ) | (117,533 | ) | 65,016 | |||||||
Cash
and cash equivalents at beginning of period
|
1,709,551 | 1,920,491 | (210,940 | ) | ||||||||
Cash
and cash equivalents at end of period
|
$ | 1,657,034 | $ | 1,802,958 | $ | (145,924 | ) | |||||
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION:
|
||||||||||||
Cash
paid (received) during the period for:
|
||||||||||||
Interest
- net of amount capitalized
|
$ | 171,145 | $ | 176,892 | $ | (5,747 | ) | |||||
Income
taxes
|
$ | (1,385 | ) | $ | (15,139 | ) | $ | 13,754 | ||||
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 | ) | ||||||
Proceeds
from long-term debt issued for the purpose
|
||||||||||||
of
refunding prior long-term debt
|
$ | 150,000 | - | $ | 150,000 |
Entergy
Corporation
|
||||||||||||
Consolidated
Cash Flow Statement
|
||||||||||||
Twelve
Months Ended March 31, 2010 vs. 2009
|
||||||||||||
(Dollars
in thousands)
|
||||||||||||
(Unaudited)
|
||||||||||||
2010
|
2009
|
Variance
|
||||||||||
OPERATING
ACTIVITIES
|
||||||||||||
Consolidated
net income
|
$ | 1,229,531 | $ | 1,167,121 | $ | 62,410 | ||||||
Adjustments
to reconcile consolidated net income to net cash flow
|
||||||||||||
provided
by operating activities:
|
||||||||||||
Reserve
for regulatory adjustments
|
(1,280 | ) | (4,166 | ) | 2,886 | |||||||
Other
regulatory charges (credits) - net
|
35,839 | (4,871 | ) | 40,710 | ||||||||
Depreciation,
amortization, and decommissioning, including nuclear fuel
amortization
|
1,533,849 | 1,407,975 | 125,874 | |||||||||
Deferred
income taxes, investment tax credits, and non-current taxes
accrued
|
843,188 | 390,993 | 452,195 | |||||||||
Changes
in working capital:
|
||||||||||||
Receivables
|
57,846 | 190,455 | (132,609 | ) | ||||||||
Fuel
inventory
|
30,598 | (2,527 | ) | 33,125 | ||||||||
Accounts
payable
|
40,507 | (166,755 | ) | 207,262 | ||||||||
Taxes
accrued
|
(62,426 | ) | 62,426 | (124,852 | ) | |||||||
Interest
accrued
|
5,711 | (3,827 | ) | 9,538 | ||||||||
Deferred
fuel
|
(202,230 | ) | 432,658 | (634,888 | ) | |||||||
Other
working capital accounts
|
(88,178 | ) | (11,476 | ) | (76,702 | ) | ||||||
Provision
for estimated losses and reserves
|
(49,181 | ) | 9,709 | (58,890 | ) | |||||||
Changes
in other regulatory assets
|
(33,523 | ) | (812,662 | ) | 779,139 | |||||||
Changes
in pensions and other postretirement liabilities
|
60,063 | 816,713 | (756,650 | ) | ||||||||
Other
|
(167,510 | ) | (220,989 | ) | 53,479 | |||||||
Net
cash flow provided by operating activities
|
3,232,804 | 3,250,777 | (17,973 | ) | ||||||||
INVESTING
ACTIVITIES
|
||||||||||||
Construction/capital
expenditures
|
(1,922,984 | ) | (2,294,675 | ) | 371,691 | |||||||
Allowance
for equity funds used during construction
|
55,894 | 52,184 | 3,710 | |||||||||
Nuclear
fuel purchases
|
(471,920 | ) | (372,460 | ) | (99,460 | ) | ||||||
Proceeds
from sale/leaseback of nuclear fuel
|
273,957 | 195,437 | 78,520 | |||||||||
Proceeds
from sale of assets and businesses
|
49,229 | 30,725 | 18,504 | |||||||||
Payment
for purchase of plant
|
- | (210,414 | ) | 210,414 | ||||||||
Insurance
proceeds received for property damages
|
53,760 | 130,114 | (76,354 | ) | ||||||||
Changes
in transition charge account
|
(15,145 | ) | 7,732 | (22,877 | ) | |||||||
NYPA
value sharing payment
|
(72,000 | ) | (72,000 | ) | - | |||||||
Decrease
(increase) in other investments
|
183,231 | (73,468 | ) | 256,699 | ||||||||
Proceeds
from nuclear decommissioning trust fund sales
|
2,758,138 | 1,977,725 | 780,413 | |||||||||
Investment
in nuclear decommissioning trust funds
|
(2,855,200 | ) | (2,020,177 | ) | (835,023 | ) | ||||||
Net
cash flow used in investing activities
|
(1,963,040 | ) | (2,649,277 | ) | 686,237 | |||||||
FINANCING
ACTIVITIES
|
||||||||||||
Proceeds
from the issuance of:
|
||||||||||||
Long-term
debt
|
1,556,027 | 3,401,682 | (1,845,655 | ) | ||||||||
Common
stock and treasury stock
|
33,349 | 31,032 | 2,317 | |||||||||
Retirement
of long-term debt
|
(1,728,435 | ) | (2,263,602 | ) | 535,167 | |||||||
Repurchase
of common stock
|
(613,125 | ) | (354,169 | ) | (258,956 | ) | ||||||
Redemption
of preferred stock
|
(1,847 | ) | - | (1,847 | ) | |||||||
Changes
in credit line borrowings - net
|
(63,368 | ) | 55,000 | (118,368 | ) | |||||||
Dividends
paid:
|
||||||||||||
Common
stock
|
(576,763 | ) | (570,551 | ) | (6,212 | ) | ||||||
Preferred
stock
|
(19,975 | ) | (17,753 | ) | (2,222 | ) | ||||||
Net
cash flow provided by (used in) financing activities
|
(1,414,137 | ) | 281,639 | (1,695,776 | ) | |||||||
Effect
of exchange rates on cash and cash equivalents
|
(1,551 | ) | 4,113 | (5,664 | ) | |||||||
Net
increase (decrease) in cash and cash equivalents
|
(145,924 | ) | 887,252 | (1,033,176 | ) | |||||||
Cash
and cash equivalents at beginning of period
|
1,802,958 | 915,706 | 887,252 | |||||||||
Cash
and cash equivalents at end of period
|
$ | 1,657,034 | $ | 1,802,958 | $ | (145,924 | ) | |||||
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION:
|
||||||||||||
Cash
paid (received) during the period for:
|
||||||||||||
Interest
- net of amount capitalized
|
$ | 562,670 | $ | 605,393 | $ | (42,723 | ) | |||||
Income
taxes
|
$ | 56,811 | $ | 119,938 | $ | (63,127 | ) | |||||
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 | ) | ||||||
Proceeds
from long-term debt issued for the purpose
|
||||||||||||
of
refunding prior long-term debt
|
$ | 150,000 | - | $ | 150,000 | |||||||